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Home My WebLink About20160623AVU to Staff 1 Disk 1.pdfRESULTS OF OPERATIONS Report ID:AVISTA UTILITIES ELECTRIC FEDERAL INCOME TAXES E-FIT-12A For Twelve Months Ended December 31, 2015 Average of Monthly Averages Basis Ref/Basis Description System Washington Idaho Calculation of Taxable Operating Income: E-OPS Operating Revenue 1,006,140,063 674,643,971 331,496,092 E-OPS Less: Operating & Maintenance Expense 617,386,549 405,239,659 212,146,890 E-OPS Less: Book Deprec/Amort and Reg Amortizations 103,000,355 72,045,889 30,954,466 E-OTX Less: Taxes Other than FIT 73,408,557 58,622,956 14,785,601 Net Operating Income Before FIT 212,344,602 138,735,467 73,609,135 E-INT Less: Interest Expense 54,928,820 36,511,830 18,416,990 E-OPS Less: Colstrip 3 AFUDC Reallocation Adj 0 (141,516)141,516 E-SCM Plus: Schedule M Adjustments (124,682,254)(82,193,476)(42,488,778) Taxable Net Operating Income 32,733,528 20,171,677 12,561,851 Tax Rate 35.00%35.00%35.00% Total Federal Income Tax 11,456,735 7,060,087 4,396,648 1 Production Tax Credit (154,304)(101,270)(53,034) 1 Investment Tax Credit - Noxon *0 0 0 Total Net Federal Income Tax 11,302,431 6,958,817 4,343,614 E-DTE Deferred FIT 44,638,240 29,533,536 15,104,704 1 411400 Amortized Investment Tax Credit - Noxon (195,528)(128,325)(67,203) Total Net FIT/Deferred FIT 55,745,143 36,364,028 19,381,115 ALLOCATION RATIOS: E-ALL 1 Production/Transmission Ratio 100.000%65.630%34.370% E-ALL 99 Not Allocated 0.000%0.000%0.000% * Deferred taxes are in Deferred FIT balance Page 1 of 1 Print Date-Time 5/6/2016 10:43 AM RESULTS OF OPERATIONS Report ID:AVISTA UTILITIES ELECTRIC FEDERAL INCOME TAXES E-FIT-12A For Twelve Months Ended December 31, 2015 Average of Monthly Averages Basis Ref/Basis Description System Washington Idaho Calculation of Taxable Operating Income: E-OPS Operating Revenue 1,006,140,063 674,643,971 331,496,092 E-OPS Less: Operating & Maintenance Expense 617,386,549 405,239,659 212,146,890 E-OPS Less: Book Deprec/Amort and Reg Amortizations 103,000,355 72,045,889 30,954,466 E-OTX Less: Taxes Other than FIT 73,408,557 58,622,956 14,785,601 Net Operating Income Before FIT 212,344,602 138,735,467 73,609,135 E-INT Less: Interest Expense 54,928,820 36,511,830 18,416,990 E-OPS Less: Colstrip 3 AFUDC Reallocation Adj 0 (141,516)141,516 E-SCM Plus: Schedule M Adjustments (124,682,254)(82,193,476)(42,488,778) Taxable Net Operating Income 32,733,528 20,171,677 12,561,851 Tax Rate 35.00%35.00%35.00% Total Federal Income Tax 11,456,735 7,060,087 4,396,648 1 Production Tax Credit (154,304)(101,270)(53,034) 1 Investment Tax Credit - Noxon *0 0 0 Total Net Federal Income Tax 11,302,431 6,958,817 4,343,614 E-DTE Deferred FIT 44,638,240 29,533,536 15,104,704 1 411400 Amortized Investment Tax Credit - Noxon (195,528)(128,325)(67,203) Total Net FIT/Deferred FIT 55,745,143 36,364,028 19,381,115 ALLOCATION RATIOS: E-ALL 1 Production/Transmission Ratio 100.000%65.630%34.370% E-ALL 99 Not Allocated 0.000%0.000%0.000% * Deferred taxes are in Deferred FIT balance Page 1 of 1 Print Date-Time 5/6/2016 10:43 AM RESULTS OF OPERATIONS Report ID: AVISTA UTILITIES ELECTRIC ALLOCATION OF OTHER POWER SUPPLY EXPENSES E-557-12A For Twelve Months Ended December 31, 2015 Average of Monthly Averages Basis ***************** SYSTEM ****************************** WASHINGTON *********** ***************** IDAHO ****************** Ref/Basis Account Description Direct Allocated Total Direct Allocated Total Direct Allocated Total 1 557000 Other Expenses 0 5,948,115 5,948,115 0 3,903,748 3,903,748 0 2,044,367 2,044,367 1 557010 Other Power Supply Expense - Financial 0 44,369,572 44,369,572 0 29,119,750 29,119,750 0 15,249,822 15,249,822 1 557150 Fuel - Economic Dispatch 0 (26,828,339) (26,828,339) 0 (17,607,439) (17,607,439) 0 (9,220,900) (9,220,900) 1 557160 Power Supply Expense - Miscellaneous (4,732,562) 1,614 (4,730,948) (2,885,763) 1,059 (2,884,704) (1,846,799) 555 (1,846,244) 99 557161 Unbilled Add-Ons (265,963) 0 (265,963) 229,734 0 229,734 (495,697) 0 (495,697) 1 557170 Broker Fees - Power 0 438,071 438,071 0 287,506 287,506 0 150,565 150,565 1 557171 REC Broker Fees 45,938 34,913 80,851 45,938 22,913 68,851 0 12,000 12,000 1 557172 Trade Reporting 0 5,928 5,928 0 3,891 3,891 0 2,037 2,037 1 557200 Nez Perce 818,702 0 818,702 497,498 0 497,498 321,204 0 321,204 99 557280 Washington ERM Deferred 11,320,333 0 11,320,333 11,320,333 0 11,320,333 0 0 0 99 557270 Other Power Supply Expense - Other Exp 0 0 0 0 0 0 0 0 0 99 557290 Washington ERM Amortization (8,041,471) 0 (8,041,471) (8,041,471) 0 (8,041,471) 0 0 0 1 557312 Lancaster Power Supply Expense Deferred 0 0 0 0 0 0 0 0 0 1 557322 RECs Power Supply Expense Deferred 1,962,996 0 1,962,996 1,962,996 0 1,962,996 0 0 0 99 557324 Def Power Supply Exp-REC Amort (5,362,149) 0 (5,362,149) (5,362,149) 0 (5,362,149) 0 0 0 99 557331 Reardan Wind Costs 0 0 0 0 0 0 0 0 0 99 557380 Idaho PCA Deferred 1,971,630 0 1,971,630 0 0 0 1,971,630 0 1,971,630 99 557390 Idaho PCA Amortization 5,785,695 0 5,785,695 0 0 0 5,785,695 0 5,785,695 1 557395 Optional Renewable Power Expense Offset 0 681 681 0 447 447 0 234 234 1 557610 Other Expenses - Exposure 0 0 0 0 0 0 0 0 0 1 557700 Turbine Gas Bookout Expense 0 2,203,124 2,203,124 0 1,445,910 1,445,910 0 757,214 757,214 1 557711 Turbine Gas Bookout Offset 0 (2,203,124) (2,203,124) 0 (1,445,910) (1,445,910) 0 (757,214) (757,214) 1 557730 Other Power Exp - Intracompany Thermal Gas 0 57,022,714 57,022,714 0 37,424,007 37,424,007 0 19,598,707 19,598,707 TOTAL ACCOUNT 557 3,503,149 80,993,269 84,496,418 (2,232,884) 53,155,882 50,922,998 5,736,033 27,837,387 33,573,420 ALLOCATION RATIOS: E-ALL 1 Production/Transmission Ratio 100.000% 65.630% 34.370% E-ALL 99 Not Allocated 0.000% 0.000% 0.000% Page 1 of 1 Print Date-Time 2/23/2016 12:55 PM RESULTS OF OPERATIONS Report ID: AVISTA UTILITIES ELECTRIC ALLOCATION OF OTHER POWER SUPPLY EXPENSES E-557-12A For Twelve Months Ended December 31, 2015 Average of Monthly Averages Basis ***************** SYSTEM ****************************** WASHINGTON *********** ***************** IDAHO ****************** Ref/Basis Account Description Direct Allocated Total Direct Allocated Total Direct Allocated Total 1 557000 Other Expenses 0 5,948,115 5,948,115 0 3,903,748 3,903,748 0 2,044,367 2,044,367 1 557010 Other Power Supply Expense - Financial 0 44,369,572 44,369,572 0 29,119,750 29,119,750 0 15,249,822 15,249,822 1 557150 Fuel - Economic Dispatch 0 (26,828,339) (26,828,339) 0 (17,607,439) (17,607,439) 0 (9,220,900) (9,220,900) 1 557160 Power Supply Expense - Miscellaneous (4,732,562) 1,614 (4,730,948) (2,885,763) 1,059 (2,884,704) (1,846,799) 555 (1,846,244) 99 557161 Unbilled Add-Ons (265,963) 0 (265,963) 229,734 0 229,734 (495,697) 0 (495,697) 1 557170 Broker Fees - Power 0 438,071 438,071 0 287,506 287,506 0 150,565 150,565 1 557171 REC Broker Fees 45,938 34,913 80,851 45,938 22,913 68,851 0 12,000 12,000 1 557172 Trade Reporting 0 5,928 5,928 0 3,891 3,891 0 2,037 2,037 1 557200 Nez Perce 818,702 0 818,702 497,498 0 497,498 321,204 0 321,204 99 557280 Washington ERM Deferred 11,320,333 0 11,320,333 11,320,333 0 11,320,333 0 0 0 99 557270 Other Power Supply Expense - Other Exp 0 0 0 0 0 0 0 0 0 99 557290 Washington ERM Amortization (8,041,471) 0 (8,041,471) (8,041,471) 0 (8,041,471) 0 0 0 1 557312 Lancaster Power Supply Expense Deferred 0 0 0 0 0 0 0 0 0 1 557322 RECs Power Supply Expense Deferred 1,962,996 0 1,962,996 1,962,996 0 1,962,996 0 0 0 99 557324 Def Power Supply Exp-REC Amort (5,362,149) 0 (5,362,149) (5,362,149) 0 (5,362,149) 0 0 0 99 557331 Reardan Wind Costs 0 0 0 0 0 0 0 0 0 99 557380 Idaho PCA Deferred 1,971,630 0 1,971,630 0 0 0 1,971,630 0 1,971,630 99 557390 Idaho PCA Amortization 5,785,695 0 5,785,695 0 0 0 5,785,695 0 5,785,695 1 557395 Optional Renewable Power Expense Offset 0 681 681 0 447 447 0 234 234 1 557610 Other Expenses - Exposure 0 0 0 0 0 0 0 0 0 1 557700 Turbine Gas Bookout Expense 0 2,203,124 2,203,124 0 1,445,910 1,445,910 0 757,214 757,214 1 557711 Turbine Gas Bookout Offset 0 (2,203,124) (2,203,124) 0 (1,445,910) (1,445,910) 0 (757,214) (757,214) 1 557730 Other Power Exp - Intracompany Thermal Gas 0 57,022,714 57,022,714 0 37,424,007 37,424,007 0 19,598,707 19,598,707 TOTAL ACCOUNT 557 3,503,149 80,993,269 84,496,418 (2,232,884) 53,155,882 50,922,998 5,736,033 27,837,387 33,573,420 ALLOCATION RATIOS: E-ALL 1 Production/Transmission Ratio 100.000% 65.630% 34.370% E-ALL 99 Not Allocated 0.000% 0.000% 0.000% Page 1 of 1 Print Date-Time 2/23/2016 12:55 PM RESULTS OF OPERATIONS Report ID:AVISTA UTILITIES FEDERAL INCOME TAXES--GAS G-FIT-12A For Twelve Months Ended December 31, 2015 Average of Monthly Averages Basis Ref/Basis Description System Washington Idaho Calculation of Taxable Operating Income: G-OPS Operating Revenue 358,250,603 250,883,702 107,366,901 G-OPS Operating & Maintenance Expense 289,300,791 200,633,586 88,667,205 G-OPS Book Deprec/Amort and Reg Amortizations 20,413,017 15,182,045 5,230,972 G-OTX Taxes Other than FIT 17,084,296 14,380,430 2,703,866 Net Operating Income Before FIT 31,452,499 20,687,641 10,764,858 G-INT Less: Interest Expense 10,778,666 7,337,779 3,440,887 G-SCM Schedule M Adjustments (26,351,880)(18,151,774)(8,200,106) Taxable Net Operating Income (5,678,047)(4,801,912)(876,135) Tax Rate 35.00%35.00%35.00% Total Federal Income Tax (1,987,316)(1,680,669)(306,647) G-DTE Deferred FIT 11,419,402 7,837,585 3,581,817 99 411400 Amortized Investment Tax Credit (30,060)(19,884)(10,176) Total FIT/Deferred FIT & ITC 9,402,026 6,137,032 3,264,994 ALLOCATION RATIOS: G-ALL 99 Not Allocated 0.000%0.000%0.000% Page 1 of 1 Print Date-Time: 5/6/2016 2:39 PM RESULTS OF OPERATIONS Report ID:AVISTA UTILITIES FEDERAL INCOME TAXES--GAS G-FIT-12A For Twelve Months Ended December 31, 2015 Average of Monthly Averages Basis Ref/Basis Description System Washington Idaho Calculation of Taxable Operating Income: G-OPS Operating Revenue 358,250,603 250,883,702 107,366,901 G-OPS Operating & Maintenance Expense 289,300,791 200,633,586 88,667,205 G-OPS Book Deprec/Amort and Reg Amortizations 20,413,017 15,182,045 5,230,972 G-OTX Taxes Other than FIT 17,084,296 14,380,430 2,703,866 Net Operating Income Before FIT 31,452,499 20,687,641 10,764,858 G-INT Less: Interest Expense 10,778,666 7,337,779 3,440,887 G-SCM Schedule M Adjustments (26,351,880)(18,151,774)(8,200,106) Taxable Net Operating Income (5,678,047)(4,801,912)(876,135) Tax Rate 35.00%35.00%35.00% Total Federal Income Tax (1,987,316)(1,680,669)(306,647) G-DTE Deferred FIT 11,419,402 7,837,585 3,581,817 99 411400 Amortized Investment Tax Credit (30,060)(19,884)(10,176) Total FIT/Deferred FIT & ITC 9,402,026 6,137,032 3,264,994 ALLOCATION RATIOS: G-ALL 99 Not Allocated 0.000%0.000%0.000% Page 1 of 1 Print Date-Time: 5/6/2016 2:39 PM RESULTS OF OPERATIONS Report ID: AVISTA UTILITIES ELECTRIC UTILITY PLANT E-PLT-12A For Twelve Months Ended December 31, 2015 Average of Monthly Averages Basis *********************SYSTEM ***************** *********** *****WASHINGTON ************** **********************IDAHO ***************** Ref/Basis Account Descriptio Direct Allocated Total Direct Allocated Total Direct Allocated Total PLANT IN SERVICE INTANGIBLE PLANT: 1 182324 CDA Lake CDR Fund - Allocated 0 8,850,000 8,850,000 0 5,808,255 5,808,255 0 3,041,745 3,041,745 1 182325 CDA Lake IPA Fund 0 2,000,000 2,000,000 0 1,312,600 1,312,600 0 687,400 687,400 1 182333 CDA Settlement Costs 0 1,261,062 1,261,062 0 827,635 827,635 0 433,427 433,427 1 182381 CDA Settlement Past Storage 0 34,074,134 34,074,134 0 22,362,854 22,362,854 0 11,711,280 11,711,280 1 302000 Franchises & Consents 602,704 44,049,218 44,651,922 602,704 28,909,502 29,512,206 0 15,139,716 15,139,716 1,4 303000 Misc Intangible Plant- (C-IPL) 153,179 16,794,517 16,947,696 153,179 11,175,375 11,328,554 0 5,619,142 5,619,142 4 303100 Misc Intangible Plant-Mainframe Software (C-IPL) 5,253,874 97,293,489 102,547,363 5,168,689 66,198,490 71,367,179 85,185 31,094,999 31,180,184 4 303110 Misc Intangible Plant-PC Software (C-IPL) 0 3,602,329 3,602,329 0 2,451,025 2,451,025 0 1,151,304 1,151,304 TOTAL INTANGIBLE PLANT 6,009,757 207,924,749 213,934,506 5,924,572 139,045,736 144,970,308 85,185 68,879,013 68,964,198 STEAM PRODUCTION PLANT: 1 310XXX Land & Land Rights 0 3,578,172 3,578,172 0 2,348,354 2,348,354 0 1,229,818 1,229,818 1 311XXX Structures & Improvements 0 130,200,337 130,200,337 0 85,450,481 85,450,481 0 44,749,856 44,749,856 1 312000 Boiler Plant 0 175,690,558 175,690,558 0 115,305,713 115,305,713 0 60,384,845 60,384,845 1 313000 Generators 0 6,770 6,770 0 4,443 4,443 0 2,327 2,327 1 314000 Turbogenerator Units 0 54,094,871 54,094,871 0 35,502,464 35,502,464 0 18,592,407 18,592,407 1 315000 Accessory Electric Equipment 0 27,024,870 27,024,870 0 17,736,422 17,736,422 0 9,288,448 9,288,448 1 316000 Miscellaneous Power Plant Equipment 0 17,057,608 17,057,608 0 11,194,908 11,194,908 0 5,862,700 5,862,700 TOTAL STEAM PRODUCTION PLANT 0 407,653,186 407,653,186 0 267,542,785 267,542,785 0 140,110,401 140,110,401 HYDRAULIC PRODUCTION PLANT: 1 330XXX Land & Land Rights 0 59,797,154 59,797,154 0 39,244,872 39,244,872 0 20,552,282 20,552,282 1 331XXX Structures & Improvements 0 58,338,202 58,338,202 0 38,287,362 38,287,362 0 20,050,840 20,050,840 1 332XXX Reservoirs, Dams, & Waterways 0 146,903,608 146,903,608 0 96,412,838 96,412,838 0 50,490,770 50,490,770 1 333000 Waterwheels, Turbines, & Generators 0 167,804,001 167,804,001 0 110,129,766 110,129,766 0 57,674,235 57,674,235 1 334000 Accessory Electric Equipment 0 41,514,474 41,514,474 0 27,245,949 27,245,949 0 14,268,525 14,268,525 1 335XXX Miscellaneous Power Plant Equipment 0 9,396,805 9,396,805 0 6,167,123 6,167,123 0 3,229,682 3,229,682 1 336000 Roads, Railroads, & Bridges 0 2,679,534 2,679,534 0 1,758,578 1,758,578 0 920,956 920,956 TOTAL HYDRAULIC PRODUCTION PLANT 0 486,433,778 486,433,778 0 319,246,488 319,246,488 0 167,187,290 167,187,290 OTHER PRODUCTION PLANT: 1 340200 Land & Land Rights 0 905,168 905,168 0 594,062 594,062 0 311,106 311,106 1 341000 Structures & Improvements 0 16,772,339 16,772,339 0 11,007,686 11,007,686 0 5,764,653 5,764,653 1 342000 Fuel Holders, Producers, & Accessories 0 21,335,018 21,335,018 0 14,002,172 14,002,172 0 7,332,846 7,332,846 1 343000 Prime Movers 0 23,909,470 23,909,470 0 15,691,785 15,691,785 0 8,217,685 8,217,685 1 344000 Generators 0 208,069,145 208,069,145 0 136,555,780 136,555,780 0 71,513,365 71,513,365 1 344010 Generators - Sola 0 149,670 149,670 0 98,228 98,228 0 51,442 51,442 1 345000 Accessory Electric Equipment 0 20,797,816 20,797,816 0 13,649,607 13,649,607 0 7,148,209 7,148,209 1 345010 Accessory Electric Equipment - Sola 0 33,209 33,209 0 21,795 21,795 0 11,414 11,414 1 346000 Miscellaneous Power Plant Equipment 0 1,570,756 1,570,756 0 1,030,887 1,030,887 0 539,869 539,869 TOTAL OTHER PRODUCTION PLANT 0 293,542,591 293,542,591 0 192,652,002 192,652,002 0 100,890,589 100,890,589 TOTAL PRODUCTION PLANT 0 1,187,629,555 1,187,629,555 0 779,441,275 779,441,275 0 408,188,280 408,188,280 Page 1 of 3 Print Date-Time 2/18/2016 9:43 AM RESULTS OF OPERATIONS Report ID: AVISTA UTILITIES ELECTRIC UTILITY PLANT E-PLT-12A For Twelve Months Ended December 31, 2015 Average of Monthly Averages Basis *********************SYSTEM ***************** *********** *****WASHINGTON ************** **********************IDAHO ***************** Ref/Basis Account Descriptio Direct Allocated Total Direct Allocated Total Direct Allocated Total TRANSMISSION PLANT: 1 350XXX Land & Land Rights 0 20,866,020 20,866,020 0 13,694,369 13,694,369 0 7,171,651 7,171,651 1 351XXX Energy Storage Eq/Computer Software 0 0 0 0 0 0 0 0 0 1 352XXX Structures & Improvements 0 20,585,623 20,585,623 0 13,510,344 13,510,344 0 7,075,279 7,075,279 1 353000 Station Equipment 0 235,356,989 235,356,989 0 154,464,792 154,464,792 0 80,892,197 80,892,197 1 354000 Towers & Fixtures 0 17,139,174 17,139,174 0 11,248,440 11,248,440 0 5,890,734 5,890,734 1 355000 Poles & Fixtures 0 183,756,415 183,756,415 0 120,599,335 120,599,335 0 63,157,080 63,157,080 1 356000 Overhead Conductors & Devices 0 127,098,682 127,098,682 0 83,414,865 83,414,865 0 43,683,817 43,683,817 1 357000 Underground Conduit 0 2,977,125 2,977,125 0 1,953,887 1,953,887 0 1,023,238 1,023,238 1 358000 Underground Conductors & Devices 0 2,333,989 2,333,989 0 1,531,797 1,531,797 0 802,192 802,192 1 359000 Roads & Trails 0 1,953,740 1,953,740 0 1,282,240 1,282,240 0 671,500 671,500 TOTAL TRANSMISSION PLANT 0 612,067,757 612,067,757 0 401,700,069 401,700,069 0 210,367,688 210,367,688 DISTRIBUTION PLANT: 99 360200 Land & Land Rights 4,802,289 0 4,802,289 3,551,811 0 3,551,811 1,250,478 0 1,250,478 99 360400 Land Easements 2,480,155 0 2,480,155 478,864 0 478,864 2,001,291 0 2,001,291 99 361000 Structures & Improvements 19,518,610 0 19,518,610 13,274,752 0 13,274,752 6,243,858 0 6,243,858 3 362000 Station Equipment 123,138,474 1,674,751 124,813,225 78,801,813 1,122,368 79,924,181 44,336,661 552,383 44,889,044 99 363000 Energy Storage Equipment 1,744,842 0 1,744,842 1,744,842 0 1,744,842 0 0 0 99 364000 Poles, Towers, & Fixtures 318,125,859 0 318,125,859 202,112,886 0 202,112,886 116,012,973 0 116,012,973 99 365000 Overhead Conductors & Devices 204,988,960 0 204,988,960 128,921,435 0 128,921,435 76,067,525 0 76,067,525 99 366000 Underground Conduit 93,915,604 0 93,915,604 59,581,656 0 59,581,656 34,333,948 0 34,333,948 99 367000 Underground Conductors & Devices 164,917,142 0 164,917,142 105,786,684 0 105,786,684 59,130,458 0 59,130,458 99 368000 Line Transformers 224,959,057 0 224,959,057 152,343,609 0 152,343,609 72,615,448 0 72,615,448 99 369XXX Services 146,036,715 0 146,036,715 94,299,329 0 94,299,329 51,737,386 0 51,737,386 99 370000 Meters 48,811,471 0 48,811,471 26,659,345 0 26,659,345 22,152,126 0 22,152,126 99 373XXX Street Light & Signal Systems 42,228,631 0 42,228,631 26,372,845 0 26,372,845 15,855,786 0 15,855,786 TOTAL DISTRIBUTION PLANT 1,395,667,809 1,674,751 1,397,342,560 893,929,871 1,122,368 895,052,239 501,737,938 552,383 502,290,321 GENERAL PLANT: (From Report C-GPL) 4 389XXX Land & Land Rights 1,134,708 4,626,561 5,761,269 428,141 3,147,912 3,576,053 706,567 1,478,649 2,185,216 4 390XXX Structures & Improvements 13,425,506 68,641,812 82,067,318 6,716,261 46,703,889 53,420,150 6,709,245 21,937,923 28,647,168 4 391XXX Office Furniture & Equipment 3,383,903 48,560,855 51,944,758 3,299,174 33,040,806 36,339,980 84,729 15,520,049 15,604,778 4 392XXX Transportation Equipment 22,913,046 13,439,416 36,352,462 16,669,816 9,144,179 25,813,995 6,243,230 4,295,237 10,538,467 4 393000 Stores Equipment 273,749 2,634,708 2,908,457 121,431 1,792,655 1,914,086 152,318 842,053 994,371 4 394000 Tools, Shop & Garage Equipment 2,055,367 9,545,404 11,600,771 992,310 6,494,693 7,487,003 1,063,057 3,050,711 4,113,768 4 394100 Electric Charging Stations 0 2,049 2,049 0 1,394 1,394 0 655 655 4 395000 Laboratory Equipment 272,786 762,321 1,035,107 227,773 518,683 746,456 45,013 243,638 288,651 4 396XXX Power Operated Equipment 26,295,865 9,190,193 35,486,058 16,023,837 6,253,007 22,276,844 10,272,028 2,937,186 13,209,214 4 397XXX Communications Equipment 19,848,812 71,867,891 91,716,703 11,984,247 48,898,913 60,883,160 7,864,565 22,968,978 30,833,543 4 398000 Miscellaneous Equipment 6,225 387,012 393,237 3,926 263,323 267,249 2,299 123,689 125,988 TOTAL GENERAL PLANT 89,609,967 229,658,222 319,268,189 56,466,916 156,259,454 212,726,370 33,143,051 73,398,768 106,541,819 TOTAL PLANT IN SERVICE 1,491,287,533 2,238,955,034 3,730,242,567 956,321,359 1,477,568,902 2,433,890,261 534,966,174 761,386,132 1,296,352,306 Page 2 of 3 Print Date-Time 2/18/2016 9:43 AM RESULTS OF OPERATIONS Report ID: AVISTA UTILITIES ELECTRIC UTILITY PLANT E-PLT-12A For Twelve Months Ended December 31, 2015 Average of Monthly Averages Basis *********************SYSTEM ***************** *********** *****WASHINGTON ************** **********************IDAHO ***************** Ref/Basis Account Descriptio Direct Allocated Total Direct Allocated Total Direct Allocated Total ACCUMULATED DEPRECIATION E-ADEP Steam Production Plant 0 (289,514,414) (289,514,414) 0 (190,008,310) (190,008,310) 0 (99,506,104) (99,506,104) E-ADEP Hydro Production Plant 0 (134,772,883) (134,772,883) 0 (88,451,443) (88,451,443) 0 (46,321,440) (46,321,440) E-ADEP Other Production Plant 0 (98,186,107) (98,186,107) 0 (64,439,542) (64,439,542) 0 (33,746,565) (33,746,565) E-ADEP Transmission Plant 0 (197,982,054) (197,982,054) 0 (129,935,622) (129,935,622) 0 (68,046,432) (68,046,432) E-ADEP Distribution Plant (444,236,695) (13,435) (444,250,130) (273,569,080) (9,004) (273,578,084) (170,667,615) (4,431) (170,672,046) E-ADEP General Plant (30,642,847) (79,190,855) (109,833,702) (18,893,048) (53,881,458) (72,774,506) (11,749,799) (25,309,397) (37,059,196) TOTAL ACCUMULATED DEPRECIATION (474,879,542) (799,659,748) (1,274,539,290) (292,462,128) (526,725,379) (819,187,507) (182,417,414) (272,934,369) (455,351,783) ACCUMULATED AMORTIZATION E-AAMT Production/Transmission-Franchises/Misc Intangibles 0 (9,776,089) (9,776,089) 0 (6,416,047) (6,416,047) 0 (3,360,042) (3,360,042) E-AAMT Distribution-Franchises/Misc Intangibles (162,613) 0 (162,613) (162,613) 0 (162,613) 0 0 0 E-AAMT General Plant - 303000 0 (783,180) (783,180) 0 (531,501) (531,501) 0 (251,679) (251,679) E-AAMT Miscellaneous IT Intangible Plant -3031XX (2,283,731) (22,904,376) (25,188,107) (2,248,195) (15,584,138) (17,832,333) (35,536) (7,320,238) (7,355,774) E-AAMT General Plant - 390200, 396200 (120,812) (231,580) (352,392) (117,239) (157,567) (274,806) (3,573) (74,013) (77,586) TOTAL ACCUMULATED AMORTIZATION (2,567,156) (33,695,225) (36,262,381) (2,528,047) (22,689,253) (25,217,300) (39,109) (11,005,972) (11,045,081) TOTAL ACCUMULATED DEPR/AMORT (477,446,698) (833,354,973) (1,310,801,671) (294,990,175) (549,414,632) (844,404,807) (182,456,523) (283,940,341) (466,396,864) ET ELECTRIC UTILITY PLANT before DFIT 1,013,840,835 1,405,600,061 2,419,440,896 661,331,184 928,154,270 1,589,485,454 352,509,651 477,445,791 829,955,442 ACCUMULATED DFIT 12 ADFIT - FAS 109 Electric Plant (182310, 283170) 0 (123,685) (123,685) 0 (81,256) (81,256) 0 (42,429) (42,429) 1 ADFIT - Colstrip PCB (283200) 0 (180,624) (180,624) 0 (118,544) (118,544) 0 (62,080) (62,080) 12 ADFIT - Electric Plant In Service (282900) 0 (402,730,626) (402,730,626) 0 (264,577,912) (264,577,912) 0 (138,152,714) (138,152,714) 4 ADFIT - Common Plant (282900 from C-DTX) 0 (48,010,608) (48,010,608) 0 (32,666,418) (32,666,418) 0 (15,344,190) (15,344,190) 4 ADFIT - Common Plant (283750 from C-DTX) 0 (390,929) (390,929) 0 (265,988) (265,988) 0 (124,941) (124,941) 1 ADFIT - Lake CDA CDR Fund - Allocated (283324) 0 0 0 0 0 0 0 0 0 1 ADFIT - CDA IPA Fund Deposit (283325) 0 0 0 0 0 0 0 0 0 1 ADFIT - CDA Lake Settlement - Allocated (283382) 0 (11,925,947) (11,925,947) 0 (7,826,999) (7,826,999) 0 (4,098,948) (4,098,948) 1 ADFIT - CDA Settlement Costs (283333) 0 375,313 375,313 0 246,318 246,318 0 128,995 128,995 12 ADFIT - Electric portion of Bond Redemptions (283850) 0 (3,479,343) (3,479,343) 0 (2,285,789) (2,285,789) 0 (1,193,554) (1,193,554) TOTAL ACCUMULATED DFIT 0 (466,466,449) (466,466,449) 0 (307,576,588) (307,576,588) 0 (158,889,861) (158,889,861) ET ELECTRIC UTILITY PLANT 1,013,840,835 939,133,612 1,952,974,447 661,331,184 620,577,682 1,281,908,866 352,509,651 318,555,930 671,065,581 ALLOCATION RATIOS: E-AL 1 Production/Transmission Ratio 100.000% 65.630% 34.370% E-AL 3 Direct Distribution Operating Expense 100.000% 67.017% 32.983% E-AL 4 Jurisdictional 4-Factor Ratio 100.000% 68.040% 31.960% E-AL 12 et Electric Plant (before DFIT) - AM 100.000% 65.696% 34.304% E-AL 99 ot Allocated 0.000% 0.000% 0.000% Page 3 of 3 Print Date-Time 2/18/2016 9:43 AM RESULTS OF OPERATIONS Report ID: AVISTA UTILITIES ELECTRIC UTILITY PLANT E-PLT-12A For Twelve Months Ended December 31, 2015 Average of Monthly Averages Basis *********************SYSTEM ***************** *********** *****WASHINGTON ************** **********************IDAHO ***************** Ref/Basis Account Descriptio Direct Allocated Total Direct Allocated Total Direct Allocated Total PLANT IN SERVICE INTANGIBLE PLANT: 1 182324 CDA Lake CDR Fund - Allocated 0 8,850,000 8,850,000 0 5,808,255 5,808,255 0 3,041,745 3,041,745 1 182325 CDA Lake IPA Fund 0 2,000,000 2,000,000 0 1,312,600 1,312,600 0 687,400 687,400 1 182333 CDA Settlement Costs 0 1,261,062 1,261,062 0 827,635 827,635 0 433,427 433,427 1 182381 CDA Settlement Past Storage 0 34,074,134 34,074,134 0 22,362,854 22,362,854 0 11,711,280 11,711,280 1 302000 Franchises & Consents 602,704 44,049,218 44,651,922 602,704 28,909,502 29,512,206 0 15,139,716 15,139,716 1,4 303000 Misc Intangible Plant- (C-IPL) 153,179 16,794,517 16,947,696 153,179 11,175,375 11,328,554 0 5,619,142 5,619,142 4 303100 Misc Intangible Plant-Mainframe Software (C-IPL) 5,253,874 97,293,489 102,547,363 5,168,689 66,198,490 71,367,179 85,185 31,094,999 31,180,184 4 303110 Misc Intangible Plant-PC Software (C-IPL) 0 3,602,329 3,602,329 0 2,451,025 2,451,025 0 1,151,304 1,151,304 TOTAL INTANGIBLE PLANT 6,009,757 207,924,749 213,934,506 5,924,572 139,045,736 144,970,308 85,185 68,879,013 68,964,198 STEAM PRODUCTION PLANT: 1 310XXX Land & Land Rights 0 3,578,172 3,578,172 0 2,348,354 2,348,354 0 1,229,818 1,229,818 1 311XXX Structures & Improvements 0 130,200,337 130,200,337 0 85,450,481 85,450,481 0 44,749,856 44,749,856 1 312000 Boiler Plant 0 175,690,558 175,690,558 0 115,305,713 115,305,713 0 60,384,845 60,384,845 1 313000 Generators 0 6,770 6,770 0 4,443 4,443 0 2,327 2,327 1 314000 Turbogenerator Units 0 54,094,871 54,094,871 0 35,502,464 35,502,464 0 18,592,407 18,592,407 1 315000 Accessory Electric Equipment 0 27,024,870 27,024,870 0 17,736,422 17,736,422 0 9,288,448 9,288,448 1 316000 Miscellaneous Power Plant Equipment 0 17,057,608 17,057,608 0 11,194,908 11,194,908 0 5,862,700 5,862,700 TOTAL STEAM PRODUCTION PLANT 0 407,653,186 407,653,186 0 267,542,785 267,542,785 0 140,110,401 140,110,401 HYDRAULIC PRODUCTION PLANT: 1 330XXX Land & Land Rights 0 59,797,154 59,797,154 0 39,244,872 39,244,872 0 20,552,282 20,552,282 1 331XXX Structures & Improvements 0 58,338,202 58,338,202 0 38,287,362 38,287,362 0 20,050,840 20,050,840 1 332XXX Reservoirs, Dams, & Waterways 0 146,903,608 146,903,608 0 96,412,838 96,412,838 0 50,490,770 50,490,770 1 333000 Waterwheels, Turbines, & Generators 0 167,804,001 167,804,001 0 110,129,766 110,129,766 0 57,674,235 57,674,235 1 334000 Accessory Electric Equipment 0 41,514,474 41,514,474 0 27,245,949 27,245,949 0 14,268,525 14,268,525 1 335XXX Miscellaneous Power Plant Equipment 0 9,396,805 9,396,805 0 6,167,123 6,167,123 0 3,229,682 3,229,682 1 336000 Roads, Railroads, & Bridges 0 2,679,534 2,679,534 0 1,758,578 1,758,578 0 920,956 920,956 TOTAL HYDRAULIC PRODUCTION PLANT 0 486,433,778 486,433,778 0 319,246,488 319,246,488 0 167,187,290 167,187,290 OTHER PRODUCTION PLANT: 1 340200 Land & Land Rights 0 905,168 905,168 0 594,062 594,062 0 311,106 311,106 1 341000 Structures & Improvements 0 16,772,339 16,772,339 0 11,007,686 11,007,686 0 5,764,653 5,764,653 1 342000 Fuel Holders, Producers, & Accessories 0 21,335,018 21,335,018 0 14,002,172 14,002,172 0 7,332,846 7,332,846 1 343000 Prime Movers 0 23,909,470 23,909,470 0 15,691,785 15,691,785 0 8,217,685 8,217,685 1 344000 Generators 0 208,069,145 208,069,145 0 136,555,780 136,555,780 0 71,513,365 71,513,365 1 344010 Generators - Sola 0 149,670 149,670 0 98,228 98,228 0 51,442 51,442 1 345000 Accessory Electric Equipment 0 20,797,816 20,797,816 0 13,649,607 13,649,607 0 7,148,209 7,148,209 1 345010 Accessory Electric Equipment - Sola 0 33,209 33,209 0 21,795 21,795 0 11,414 11,414 1 346000 Miscellaneous Power Plant Equipment 0 1,570,756 1,570,756 0 1,030,887 1,030,887 0 539,869 539,869 TOTAL OTHER PRODUCTION PLANT 0 293,542,591 293,542,591 0 192,652,002 192,652,002 0 100,890,589 100,890,589 TOTAL PRODUCTION PLANT 0 1,187,629,555 1,187,629,555 0 779,441,275 779,441,275 0 408,188,280 408,188,280 Page 1 of 3 Print Date-Time 2/18/2016 9:43 AM RESULTS OF OPERATIONS Report ID: AVISTA UTILITIES ELECTRIC UTILITY PLANT E-PLT-12A For Twelve Months Ended December 31, 2015 Average of Monthly Averages Basis *********************SYSTEM ***************** *********** *****WASHINGTON ************** **********************IDAHO ***************** Ref/Basis Account Descriptio Direct Allocated Total Direct Allocated Total Direct Allocated Total TRANSMISSION PLANT: 1 350XXX Land & Land Rights 0 20,866,020 20,866,020 0 13,694,369 13,694,369 0 7,171,651 7,171,651 1 351XXX Energy Storage Eq/Computer Software 0 0 0 0 0 0 0 0 0 1 352XXX Structures & Improvements 0 20,585,623 20,585,623 0 13,510,344 13,510,344 0 7,075,279 7,075,279 1 353000 Station Equipment 0 235,356,989 235,356,989 0 154,464,792 154,464,792 0 80,892,197 80,892,197 1 354000 Towers & Fixtures 0 17,139,174 17,139,174 0 11,248,440 11,248,440 0 5,890,734 5,890,734 1 355000 Poles & Fixtures 0 183,756,415 183,756,415 0 120,599,335 120,599,335 0 63,157,080 63,157,080 1 356000 Overhead Conductors & Devices 0 127,098,682 127,098,682 0 83,414,865 83,414,865 0 43,683,817 43,683,817 1 357000 Underground Conduit 0 2,977,125 2,977,125 0 1,953,887 1,953,887 0 1,023,238 1,023,238 1 358000 Underground Conductors & Devices 0 2,333,989 2,333,989 0 1,531,797 1,531,797 0 802,192 802,192 1 359000 Roads & Trails 0 1,953,740 1,953,740 0 1,282,240 1,282,240 0 671,500 671,500 TOTAL TRANSMISSION PLANT 0 612,067,757 612,067,757 0 401,700,069 401,700,069 0 210,367,688 210,367,688 DISTRIBUTION PLANT: 99 360200 Land & Land Rights 4,802,289 0 4,802,289 3,551,811 0 3,551,811 1,250,478 0 1,250,478 99 360400 Land Easements 2,480,155 0 2,480,155 478,864 0 478,864 2,001,291 0 2,001,291 99 361000 Structures & Improvements 19,518,610 0 19,518,610 13,274,752 0 13,274,752 6,243,858 0 6,243,858 3 362000 Station Equipment 123,138,474 1,674,751 124,813,225 78,801,813 1,122,368 79,924,181 44,336,661 552,383 44,889,044 99 363000 Energy Storage Equipment 1,744,842 0 1,744,842 1,744,842 0 1,744,842 0 0 0 99 364000 Poles, Towers, & Fixtures 318,125,859 0 318,125,859 202,112,886 0 202,112,886 116,012,973 0 116,012,973 99 365000 Overhead Conductors & Devices 204,988,960 0 204,988,960 128,921,435 0 128,921,435 76,067,525 0 76,067,525 99 366000 Underground Conduit 93,915,604 0 93,915,604 59,581,656 0 59,581,656 34,333,948 0 34,333,948 99 367000 Underground Conductors & Devices 164,917,142 0 164,917,142 105,786,684 0 105,786,684 59,130,458 0 59,130,458 99 368000 Line Transformers 224,959,057 0 224,959,057 152,343,609 0 152,343,609 72,615,448 0 72,615,448 99 369XXX Services 146,036,715 0 146,036,715 94,299,329 0 94,299,329 51,737,386 0 51,737,386 99 370000 Meters 48,811,471 0 48,811,471 26,659,345 0 26,659,345 22,152,126 0 22,152,126 99 373XXX Street Light & Signal Systems 42,228,631 0 42,228,631 26,372,845 0 26,372,845 15,855,786 0 15,855,786 TOTAL DISTRIBUTION PLANT 1,395,667,809 1,674,751 1,397,342,560 893,929,871 1,122,368 895,052,239 501,737,938 552,383 502,290,321 GENERAL PLANT: (From Report C-GPL) 4 389XXX Land & Land Rights 1,134,708 4,626,561 5,761,269 428,141 3,147,912 3,576,053 706,567 1,478,649 2,185,216 4 390XXX Structures & Improvements 13,425,506 68,641,812 82,067,318 6,716,261 46,703,889 53,420,150 6,709,245 21,937,923 28,647,168 4 391XXX Office Furniture & Equipment 3,383,903 48,560,855 51,944,758 3,299,174 33,040,806 36,339,980 84,729 15,520,049 15,604,778 4 392XXX Transportation Equipment 22,913,046 13,439,416 36,352,462 16,669,816 9,144,179 25,813,995 6,243,230 4,295,237 10,538,467 4 393000 Stores Equipment 273,749 2,634,708 2,908,457 121,431 1,792,655 1,914,086 152,318 842,053 994,371 4 394000 Tools, Shop & Garage Equipment 2,055,367 9,545,404 11,600,771 992,310 6,494,693 7,487,003 1,063,057 3,050,711 4,113,768 4 394100 Electric Charging Stations 0 2,049 2,049 0 1,394 1,394 0 655 655 4 395000 Laboratory Equipment 272,786 762,321 1,035,107 227,773 518,683 746,456 45,013 243,638 288,651 4 396XXX Power Operated Equipment 26,295,865 9,190,193 35,486,058 16,023,837 6,253,007 22,276,844 10,272,028 2,937,186 13,209,214 4 397XXX Communications Equipment 19,848,812 71,867,891 91,716,703 11,984,247 48,898,913 60,883,160 7,864,565 22,968,978 30,833,543 4 398000 Miscellaneous Equipment 6,225 387,012 393,237 3,926 263,323 267,249 2,299 123,689 125,988 TOTAL GENERAL PLANT 89,609,967 229,658,222 319,268,189 56,466,916 156,259,454 212,726,370 33,143,051 73,398,768 106,541,819 TOTAL PLANT IN SERVICE 1,491,287,533 2,238,955,034 3,730,242,567 956,321,359 1,477,568,902 2,433,890,261 534,966,174 761,386,132 1,296,352,306 Page 2 of 3 Print Date-Time 2/18/2016 9:43 AM RESULTS OF OPERATIONS Report ID: AVISTA UTILITIES ELECTRIC UTILITY PLANT E-PLT-12A For Twelve Months Ended December 31, 2015 Average of Monthly Averages Basis *********************SYSTEM ***************** *********** *****WASHINGTON ************** **********************IDAHO ***************** Ref/Basis Account Descriptio Direct Allocated Total Direct Allocated Total Direct Allocated Total ACCUMULATED DEPRECIATION E-ADEP Steam Production Plant 0 (289,514,414) (289,514,414) 0 (190,008,310) (190,008,310) 0 (99,506,104) (99,506,104) E-ADEP Hydro Production Plant 0 (134,772,883) (134,772,883) 0 (88,451,443) (88,451,443) 0 (46,321,440) (46,321,440) E-ADEP Other Production Plant 0 (98,186,107) (98,186,107) 0 (64,439,542) (64,439,542) 0 (33,746,565) (33,746,565) E-ADEP Transmission Plant 0 (197,982,054) (197,982,054) 0 (129,935,622) (129,935,622) 0 (68,046,432) (68,046,432) E-ADEP Distribution Plant (444,236,695) (13,435) (444,250,130) (273,569,080) (9,004) (273,578,084) (170,667,615) (4,431) (170,672,046) E-ADEP General Plant (30,642,847) (79,190,855) (109,833,702) (18,893,048) (53,881,458) (72,774,506) (11,749,799) (25,309,397) (37,059,196) TOTAL ACCUMULATED DEPRECIATION (474,879,542) (799,659,748) (1,274,539,290) (292,462,128) (526,725,379) (819,187,507) (182,417,414) (272,934,369) (455,351,783) ACCUMULATED AMORTIZATION E-AAMT Production/Transmission-Franchises/Misc Intangibles 0 (9,776,089) (9,776,089) 0 (6,416,047) (6,416,047) 0 (3,360,042) (3,360,042) E-AAMT Distribution-Franchises/Misc Intangibles (162,613) 0 (162,613) (162,613) 0 (162,613) 0 0 0 E-AAMT General Plant - 303000 0 (783,180) (783,180) 0 (531,501) (531,501) 0 (251,679) (251,679) E-AAMT Miscellaneous IT Intangible Plant -3031XX (2,283,731) (22,904,376) (25,188,107) (2,248,195) (15,584,138) (17,832,333) (35,536) (7,320,238) (7,355,774) E-AAMT General Plant - 390200, 396200 (120,812) (231,580) (352,392) (117,239) (157,567) (274,806) (3,573) (74,013) (77,586) TOTAL ACCUMULATED AMORTIZATION (2,567,156) (33,695,225) (36,262,381) (2,528,047) (22,689,253) (25,217,300) (39,109) (11,005,972) (11,045,081) TOTAL ACCUMULATED DEPR/AMORT (477,446,698) (833,354,973) (1,310,801,671) (294,990,175) (549,414,632) (844,404,807) (182,456,523) (283,940,341) (466,396,864) ET ELECTRIC UTILITY PLANT before DFIT 1,013,840,835 1,405,600,061 2,419,440,896 661,331,184 928,154,270 1,589,485,454 352,509,651 477,445,791 829,955,442 ACCUMULATED DFIT 12 ADFIT - FAS 109 Electric Plant (182310, 283170) 0 (123,685) (123,685) 0 (81,256) (81,256) 0 (42,429) (42,429) 1 ADFIT - Colstrip PCB (283200) 0 (180,624) (180,624) 0 (118,544) (118,544) 0 (62,080) (62,080) 12 ADFIT - Electric Plant In Service (282900) 0 (402,730,626) (402,730,626) 0 (264,577,912) (264,577,912) 0 (138,152,714) (138,152,714) 4 ADFIT - Common Plant (282900 from C-DTX) 0 (48,010,608) (48,010,608) 0 (32,666,418) (32,666,418) 0 (15,344,190) (15,344,190) 4 ADFIT - Common Plant (283750 from C-DTX) 0 (390,929) (390,929) 0 (265,988) (265,988) 0 (124,941) (124,941) 1 ADFIT - Lake CDA CDR Fund - Allocated (283324) 0 0 0 0 0 0 0 0 0 1 ADFIT - CDA IPA Fund Deposit (283325) 0 0 0 0 0 0 0 0 0 1 ADFIT - CDA Lake Settlement - Allocated (283382) 0 (11,925,947) (11,925,947) 0 (7,826,999) (7,826,999) 0 (4,098,948) (4,098,948) 1 ADFIT - CDA Settlement Costs (283333) 0 375,313 375,313 0 246,318 246,318 0 128,995 128,995 12 ADFIT - Electric portion of Bond Redemptions (283850) 0 (3,479,343) (3,479,343) 0 (2,285,789) (2,285,789) 0 (1,193,554) (1,193,554) TOTAL ACCUMULATED DFIT 0 (466,466,449) (466,466,449) 0 (307,576,588) (307,576,588) 0 (158,889,861) (158,889,861) ET ELECTRIC UTILITY PLANT 1,013,840,835 939,133,612 1,952,974,447 661,331,184 620,577,682 1,281,908,866 352,509,651 318,555,930 671,065,581 ALLOCATION RATIOS: E-AL 1 Production/Transmission Ratio 100.000% 65.630% 34.370% E-AL 3 Direct Distribution Operating Expense 100.000% 67.017% 32.983% E-AL 4 Jurisdictional 4-Factor Ratio 100.000% 68.040% 31.960% E-AL 12 et Electric Plant (before DFIT) - AM 100.000% 65.696% 34.304% E-AL 99 ot Allocated 0.000% 0.000% 0.000% Page 3 of 3 Print Date-Time 2/18/2016 9:43 AM RESULTS OF OPERATIONS Report ID: AVISTA UTILITIES ELECTRIC OPERATING STATEMENT E-OPS-12A For Twelve Months Ended December 31, 2015 Average of Monthly Averages Basis ***************** SYSTEM ***************** *************** WASHINGTON ************* ***************** IDAHO ****************** Ref/Basis Account Description Direct Allocate Total Direct Allocate Total Direct Allocate Total REVENUE SALES OF ELECTRICITY: 99 440000 Residential 339,129,378 0 339,129,378 228,952,929 0 228,952,929 110,176,449 0 110,176,449 99 442200 Commercial - Firm & Int. 312,340,143 0 312,340,143 221,104,301 0 221,104,301 91,235,842 0 91,235,842 1 442300 Industrial 116,667,748 0 116,667,748 66,873,283 0 66,873,283 49,794,465 0 49,794,465 99 444000 Public Street & Highway Lighting 7,276,497 0 7,276,497 4,889,678 0 4,889,678 2,386,819 0 2,386,819 99 448000 Interdepartmental Revenue 1,190,014 0 1,190,014 927,600 0 927,600 262,414 0 262,414 99 499XXX Unbilled Revenue (12,604,957) 0 (12,604,957) (8,824,571) 0 (8,824,571) (3,780,386) 0 (3,780,386) TOTAL SALES TO ULTIMATE CUSTOMERS 763,998,823 0 763,998,823 513,923,220 0 513,923,220 250,075,603 0 250,075,603 1 447XXX Sales for Resale 0 133,316,868 133,316,868 0 87,495,860 87,495,860 0 45,821,008 45,821,008 TOTAL SALES OF ELECTRICITY 763,998,823 133,316,868 897,315,691 513,923,220 87,495,860 601,419,080 250,075,603 45,821,008 295,896,611 OTHER OPERATING REVENUE: 99 449100 Provision for Rate Refun (5,620,861) 0 (5,620,861) (3,422,474) 0 (3,422,474) (2,198,387) 0 (2,198,387) 99 451000 Miscellaneous Service Revenue 252,517 0 252,517 154,514 0 154,514 98,003 0 98,003 1 453000 Sales of Water & Water Powe 0 407,336 407,336 0 267,335 267,335 0 140,001 140,001 1 454000 Rent from Electric Propert 2,557,565 74,656 2,632,221 1,558,332 48,997 1,607,329 999,233 25,659 1,024,892 1 456XXX Other Electric Revenues 5,003,637 106,149,522 111,153,159 4,952,256 69,665,931 74,618,187 51,381 36,483,591 36,534,972 TOTAL OTHER OPERATING REVENUE 2,192,858 106,631,514 108,824,372 3,242,628 69,982,263 73,224,891 (1,049,770) 36,649,251 35,599,481 TOTAL ELECTRIC REVENUE 766,191,681 239,948,382 1,006,140,063 517,165,848 157,478,123 674,643,971 249,025,833 82,470,259 331,496,092 Page 1 of 7 Print Date-Time 2/18/2016 9:46 AM RESULTS OF OPERATIONS Report ID: AVISTA UTILITIES ELECTRIC OPERATING STATEMENT E-OPS-12A For Twelve Months Ended December 31, 2015 Average of Monthly Averages Basis ***************** SYSTEM ***************** *************** WASHINGTON ************* ***************** IDAHO ****************** Ref/Basis Account Description Direct Allocate Total Direct Allocate Total Direct Allocate Total EXPENSE STEAM POWER GENERATION EXPENSE: OPERATION 1 500000 Supervision & Engineering 6,320 275,692 282,012 6,320 180,937 187,257 0 94,755 94,755 1 501XXX Fuel 0 30,794,427 30,794,427 0 20,210,382 20,210,382 0 10,584,045 10,584,045 1 502000 Steam Expense 0 5,199,150 5,199,150 0 3,412,202 3,412,202 0 1,786,948 1,786,948 1 505000 Electric Expense 0 1,228,906 1,228,906 0 806,531 806,531 0 422,375 422,375 1 506XXX Miscellaneous Steam Power Generation Op Exp 0 2,967,067 2,967,067 0 1,947,286 1,947,286 0 1,019,781 1,019,781 1 507000 Rent 0 33,667 33,667 0 22,096 22,096 0 11,571 11,571 MAINTENANCE 1 510000 Supervision & Engineering 0 613,157 613,157 0 402,415 402,415 0 210,742 210,742 1 511000 Structures 0 758,347 758,347 0 497,703 497,703 0 260,644 260,644 1 512000 Boiler Plant 0 4,760,690 4,760,690 0 3,124,441 3,124,441 0 1,636,249 1,636,249 1 513000 Electric Plant 0 601,012 601,012 0 394,444 394,444 0 206,568 206,568 1 514XXX Miscellaneous Steam Power Generation Maint Exp 0 954,982 954,982 0 626,755 626,755 0 328,227 328,227 TOTAL STEAM POWER GENERATION EXP 6,320 48,187,097 48,193,417 6,320 31,625,192 31,631,512 0 16,561,905 16,561,905 HYDRAULIC POWER GENERATION EXP: OPERATION 1 535000 Supervision & Engineering 0 2,107,646 2,107,646 0 1,383,248 1,383,248 0 724,398 724,398 1 536000 Water for Powe 0 1,300,900 1,300,900 0 853,781 853,781 0 447,119 447,119 1 537000 Hydraulic Expense 4,353,425 2,848,110 7,201,535 2,815,977 1,869,215 4,685,192 1,537,448 978,895 2,516,343 1 538000 Electric Expense 0 6,559,863 6,559,863 0 4,305,238 4,305,238 0 2,254,625 2,254,625 1 539000 Miscellaneous Hydraulic Power Generation Exp 0 876,509 876,509 0 575,253 575,253 0 301,256 301,256 1 540000 Rent 0 1,374,529 1,374,529 0 902,103 902,103 0 472,426 472,426 1 540100 MT Trust Funds Land Settlement Rents 5,734,731 0 5,734,731 3,716,329 0 3,716,329 2,018,402 0 2,018,402 MAINTENANCE 1 541000 Supervision & Engineering 0 1,616,898 1,616,898 0 1,061,170 1,061,170 0 555,728 555,728 1 542000 Structures 0 326,758 326,758 0 214,451 214,451 0 112,307 112,307 1 543000 Reservoirs, Dams, & Waterways 0 1,375,773 1,375,773 0 902,920 902,920 0 472,853 472,853 1 544000 Electric Plant 0 2,663,275 2,663,275 0 1,747,907 1,747,907 0 915,368 915,368 1 545000 Miscellaneous Hydraulic Plant 0 696,377 696,377 0 457,032 457,032 0 239,345 239,345 TOTAL HYDRO POWER GENERATION EXP 10,088,156 21,746,638 31,834,794 6,532,306 14,272,318 20,804,624 3,555,850 7,474,320 11,030,170 OTHER POWER GENERATION EXPENSE: OPERATION 1 546000 Supervision & Engineering 0 1,179,973 1,179,973 0 774,416 774,416 0 405,557 405,557 1 547XXX Fuel 0 91,777,298 91,777,298 0 60,233,441 60,233,441 0 31,543,857 31,543,857 1 548000 Generation Expense 0 2,016,313 2,016,313 0 1,323,306 1,323,306 0 693,007 693,007 1 549XXX Miscellaneous Other Power Generation Op Exp 0 461,399 461,399 0 302,816 302,816 0 158,583 158,583 1 550000 Rent 0 (33,315) (33,315) 0 (21,865) (21,865) 0 (11,450) (11,450) MAINTENANCE 1 551000 Supervision & Engineering 0 625,187 625,187 0 410,310 410,310 0 214,877 214,877 1 552000 Structures 0 110,380 110,380 0 72,442 72,442 0 37,938 37,938 1 553000 Generating & Electric Equipment 278 2,317,312 2,317,590 278 1,520,852 1,521,130 0 796,460 796,460 1 554XXX Miscellaneous Other Power Generation Maint Exp 0 453,413 453,413 0 297,575 297,575 0 155,838 155,838 TOTAL OTHER POWER GENERATION EXP 278 98,907,960 98,908,238 278 64,913,293 64,913,571 0 33,994,667 33,994,667 Page 2 of 7 Print Date-Time 2/18/2016 9:46 AM RESULTS OF OPERATIONS Report ID: AVISTA UTILITIES ELECTRIC OPERATING STATEMENT E-OPS-12A For Twelve Months Ended December 31, 2015 Average of Monthly Averages Basis ***************** SYSTEM ***************** *************** WASHINGTON ************* ***************** IDAHO ****************** Ref/Basis Account Description Direct Allocate Total Direct Allocate Total Direct Allocate Total OTHER POWER SUPPLY EXPENSE: E-555 555XXX Purchased Powe 0 172,688,007 172,688,007 0 113,335,139 113,335,139 0 59,352,868 59,352,868 1 556000 System Control & Load Dispatching 0 1,049,171 1,049,171 0 688,571 688,571 0 360,600 360,600 E-557 557XXX Other Expense 3,503,149 80,993,269 84,496,418 (2,232,884) 53,155,882 50,922,998 5,736,033 27,837,387 33,573,420 TOTAL OTHER POWER SUPPLY EXPENSE 3,503,149 254,730,447 258,233,596 (2,232,884) 167,179,592 164,946,708 5,736,033 87,550,855 93,286,888 TOTAL PRODUCTION OPERATING EXP 13,597,903 423,572,142 437,170,045 4,306,020 277,990,395 282,296,415 9,291,883 145,581,747 154,873,630 TRANSMISSION OPERATING EXPENSE: OPERATION 1 560000 Supervision & Engineering 0 2,119,618 2,119,618 0 1,391,105 1,391,105 0 728,513 728,513 1 561000 Load Dispatching 0 2,554,257 2,554,257 0 1,676,359 1,676,359 0 877,898 877,898 1 562000 Station Expense 0 532,894 532,894 0 349,738 349,738 0 183,156 183,156 1 562100 Energy Storage Equipment 0 0 0 0 0 0 0 0 0 1 563000 Overhead Line Expense 0 458,587 458,587 0 300,971 300,971 0 157,616 157,616 1 565XXX Transmission of Electricity by Others 0 17,389,891 17,389,891 0 11,412,985 11,412,985 0 5,976,906 5,976,906 1 566000 Miscellaneous Transmission Expense 0 2,162,711 2,162,711 0 1,419,387 1,419,387 0 743,324 743,324 1 567000 Rent 0 153,599 153,599 0 100,807 100,807 0 52,792 52,792 MAINTENANCE 1 568000 Supervision & Engineering 2,875 806,039 808,914 2,280 529,003 531,283 595 277,036 277,631 1 569000 Structures 8,319 729,433 737,752 2,122 478,727 480,849 6,197 250,706 256,903 1 570000 Station Equipment 18,826 1,339,663 1,358,489 18,045 879,221 897,266 781 460,442 461,223 1 570100 Energy Storage Equipment 0 0 0 0 0 0 0 0 0 1 571000 Overhead Lines 19,745 1,127,821 1,147,566 7,699 740,189 747,888 12,046 387,632 399,678 1 572000 Underground Lines 3,046 6,841 9,887 0 4,490 4,490 3,046 2,351 5,397 1 573000 Service Miscellaneous 17,496 90,407 107,903 17,475 59,334 76,809 21 31,073 31,094 TOTAL TRANSMISSION OPERATING EXP 70,307 29,471,761 29,542,068 47,621 19,342,316 19,389,937 22,686 10,129,445 10,152,131 Page 3 of 7 Print Date-Time 2/18/2016 9:46 AM RESULTS OF OPERATIONS Report ID: AVISTA UTILITIES ELECTRIC OPERATING STATEMENT E-OPS-12A For Twelve Months Ended December 31, 2015 Average of Monthly Averages Basis ***************** SYSTEM ***************** *************** WASHINGTON ************* ***************** IDAHO ****************** Ref/Basis Account Description Direct Allocate Total Direct Allocate Total Direct Allocate Total E-DEPX Depreciation Expense-Production 0 26,029,745 26,029,745 0 17,083,322 17,083,322 0 8,946,423 8,946,423 E-DEPX Depreciation Expense-Transmission 0 11,040,922 11,040,922 0 7,246,157 7,246,157 0 3,794,765 3,794,765 E-AMTX Amortization Expense-Franchises/Misc Intangibles 0 1,158,453 1,158,453 0 760,293 760,293 0 398,160 398,160 99 Colstrip 3 AFUDC Reallocation Adj 0 0 0 (141,516) 0 (141,516) 141,516 0 141,516 99 405930 Amortization of Investment in WNP3 Exch Powe 2,450,031 0 2,450,031 2,450,031 0 2,450,031 0 0 0 99 406100 Amort of Acq Adj--Colstrip Common AFUDC 99,047 0 99,047 31,743 0 31,743 67,304 0 67,304 99 407312 Amortization of Lancaster Generation 1,246,667 0 1,246,667 1,246,667 0 1,246,667 0 0 0 1 407320 Amortization of Colstrip Outage Return 0 0 0 0 0 0 0 0 0 99 407322 Amortization of Spokane River Relicense 78,736 0 78,736 72,939 0 72,939 5,797 0 5,797 1 407324 Amortization of CDA CDR Fun 11,065 200,000 211,065 11,065 131,260 142,325 0 68,740 68,740 99 407331 Amortization of BPA Parallel Capacity Support (451,078) 0 (451,078) (287,084) 0 (287,084) (163,994) 0 (163,994) 1 407333 Amortization of CDA Settlement Costs 0 32,719 32,719 0 21,473 21,473 0 11,246 11,246 99 407335 Amortization of ID DSIT 0 0 0 0 0 0 0 0 0 99 407350 Amortization of WA Renewable Energy Credits 0 0 0 0 0 0 0 0 0 99 407351 Amortization of CNC Transmission 0 0 0 0 0 0 0 0 0 99 407360 Amortization of CS2 & COLSTRIP O&M 2,285,964 0 2,285,964 973,692 0 973,692 1,312,272 0 1,312,272 99 407362 Amortization of LiDAR O&M 0 0 0 0 0 0 0 0 0 99 407365 Amortization of Wind Generation 216,701 0 216,701 0 0 0 216,701 0 216,701 99 407380 Amortization of Wartsila Generators 153,156 0 153,156 153,156 0 153,156 0 0 0 1 407382 Amortization of CDA Settlement - Allocate 0 884,086 884,086 0 580,226 580,226 0 303,860 303,860 99 407382 Amortization of CDA Settlement - Direct 183,093 0 183,093 152,118 0 152,118 30,975 0 30,975 99 407391 Amortization of Spokane River TD 290,395 0 290,395 290,395 0 290,395 0 0 0 99 407395 Optional Renewable Power Revenue Offset 228,772 0 228,772 180,441 0 180,441 48,331 0 48,331 99 407403 Amortization of Dissallowed K.F. Plant (134,592) 0 (134,592) (134,592) 0 (134,592) 0 0 0 99 407405 Amortization of Boulder Park Write Off - Idaho (108,531) 0 (108,531) 0 0 0 (108,531) 0 (108,531) 99 407420 Amortization of CS2 Levelized Return 0 0 0 0 0 0 0 0 0 99 407450/407499 Amortization of BPA Residential Exchange Credit (8,123,977) 0 (8,123,977) (5,771,460) 0 (5,771,460) (2,352,517) 0 (2,352,517) 99 407460 Amortization of Deferred CS2 & COLSTRIP O&M (1,304,949) 0 (1,304,949) 0 0 0 (1,304,949) 0 (1,304,949) 99 407462 Amortization of Deferred LiDAR O&M 0 0 0 0 0 0 0 0 0 99 407494 Amortization of Schedule 98 REC Re (258,258) 0 (258,258) (258,258) 0 (258,258) 0 0 0 1 407495 Optional Renew Solar Project Offset 0 (8,416) (8,416) 0 (5,523) (5,523) 0 (2,893) (2,893) 99 407496 Def Palouse Wind & Thornton Sw St 0 0 0 0 0 0 0 0 0 99 407497 Amortization of BPA Settlement 466,716 0 466,716 302,722 0 302,722 163,994 0 163,994 E-OTX Taxes Other Than FIT--Prod & Trans 0 20,958,039 20,958,039 0 13,754,761 13,754,761 0 7,203,278 7,203,278 TOTAL P/T DEPR/AMRT/NON-FIT TAXES (2,671,042) 60,295,548 57,624,506 (727,941) 39,571,969 38,844,028 (1,943,101) 20,723,579 18,780,478 TOTAL PRODUCTION & TRANSMISSION EXPENS 10,997,168 513,339,451 524,336,619 3,625,700 336,904,680 340,530,380 7,371,468 176,434,771 183,806,239 Page 4 of 7 Print Date-Time 2/18/2016 9:46 AM RESULTS OF OPERATIONS Report ID: AVISTA UTILITIES ELECTRIC OPERATING STATEMENT E-OPS-12A For Twelve Months Ended December 31, 2015 Average of Monthly Averages Basis ***************** SYSTEM ***************** *************** WASHINGTON ************* ***************** IDAHO ****************** Ref/Basis Account Description Direct Allocate Total Direct Allocate Total Direct Allocate Total DISTRIBUTION EXPENSES: OPERATION: 3 580000 Supervision & Engineering 1,329,069 2,783,160 4,112,229 983,660 1,865,190 2,848,850 345,409 917,970 1,263,379 3 582000 Station Expense 663,197 78,852 742,049 342,123 52,844 394,967 321,074 26,008 347,082 3 583000 Overhead Line Expense 1,562,123 437,411 1,999,534 1,009,528 293,140 1,302,668 552,595 144,271 696,866 3 584000 Underground Line Expense 1,414,309 23 1,414,332 940,309 15 940,324 474,000 8 474,008 3 584100 Energy Storage Equipment 11,142 0 11,142 11,142 0 11,142 0 0 0 3 585000 Street Light & Signal System Operation Expense 12,587 0 12,587 7,578 0 7,578 5,009 0 5,009 3 586000 Meter Expense 1,895,040 78,534 1,973,574 1,533,641 52,631 1,586,272 361,399 25,903 387,302 3 587000 Customer Installations Expense 509,972 100,624 610,596 272,791 67,435 340,226 237,181 33,189 270,370 3 588000 Miscellaneous Distribution Expense 3,975,947 3,358,793 7,334,740 2,388,979 2,250,962 4,639,941 1,586,968 1,107,831 2,694,799 3 589000 Rent 278 262,408 262,686 278 175,858 176,136 0 86,550 86,550 MAINTENANCE: 3 590000 Supervision & Engineering 760,069 1,407,922 2,167,991 635,760 943,547 1,579,307 124,309 464,375 588,684 3 591000 Structures 380,139 8,157 388,296 226,422 5,467 231,889 153,717 2,690 156,407 3 592000 Station Equipment 901,960 177,702 1,079,662 695,440 119,091 814,531 206,520 58,611 265,131 3 592200 Energy Storage Equipment 0 0 0 0 0 0 0 0 0 3 593000 Overhead Lines 11,037,607 (553,240) 10,484,367 7,207,139 (370,765) 6,836,374 3,830,468 (182,475) 3,647,993 3 594000 Underground Lines 839,424 0 839,424 575,377 0 575,377 264,047 0 264,047 3 595000 Line Transformers 353,307 321,629 674,936 274,539 215,546 490,085 78,768 106,083 184,851 3 596000 Street Light & Signal System Maintenance Exp 692,950 0 692,950 458,582 0 458,582 234,368 0 234,368 3 597000 Meters 25,403 0 25,403 20,023 0 20,023 5,380 0 5,380 3 598000 Miscellaneous Distribution Expense 633,798 439,554 1,073,352 510,126 294,576 804,702 123,672 144,978 268,650 TOTAL DISTRIBUTION OPERATING EXP 26,998,321 8,901,529 35,899,850 18,093,437 5,965,537 24,058,974 8,904,884 2,935,992 11,840,876 E-DEPX Depreciation Expense-Distribution 40,666,652 32,993 40,699,645 25,404,698 22,111 25,426,809 15,261,954 10,882 15,272,836 E-AMTX Amortization Expense-Franchises/Misc Intangibles 26,997 0 26,997 26,997 0 26,997 0 0 0 E-OTX Taxes Other Than FIT--Distribution 52,450,518 0 52,450,518 44,868,195 0 44,868,195 7,582,323 0 7,582,323 TOTAL DISTR DEPR/AMRT/NON-FIT TAXES 93,144,167 32,993 93,177,160 70,299,890 22,111 70,322,001 22,844,277 10,882 22,855,159 TOTAL DISTRIBUTION EXPENSES 120,142,488 8,934,522 129,077,010 88,393,327 5,987,648 94,380,975 31,749,161 2,946,874 34,696,035 Page 5 of 7 Print Date-Time 2/18/2016 9:46 AM RESULTS OF OPERATIONS Report ID: AVISTA UTILITIES ELECTRIC OPERATING STATEMENT E-OPS-12A For Twelve Months Ended December 31, 2015 Average of Monthly Averages Basis ***************** SYSTEM ***************** *************** WASHINGTON ************* ***************** IDAHO ****************** Ref/Basis Account Description Direct Allocate Total Direct Allocate Total Direct Allocate Total CUSTOMER ACCOUNTS EXPENSES: 2 901000 Supervision 0 356,243 356,243 0 233,991 233,991 0 122,252 122,252 2 902000 Meter Reading Expenses 2,898,933 183,688 3,082,621 2,598,834 120,652 2,719,486 300,099 63,036 363,135 E-903 903XXX Customer Records & Collection Expenses 1,180,375 7,615,135 8,795,510 752,267 5,001,849 5,754,116 428,108 2,613,286 3,041,394 2 904000 Uncollectible Accounts 0 3,041,287 3,041,287 0 1,997,609 1,997,609 0 1,043,678 1,043,678 2 905000 Misc Customer Accounts 0 263,646 263,646 0 173,171 173,171 0 90,475 90,475 TOTAL CUSTOMER ACCOUNTS EXPENSES 4,079,308 11,459,999 15,539,307 3,351,101 7,527,272 10,878,373 728,207 3,932,727 4,660,934 CUSTOMER SERVICE & INFO EXPENSES: E-908 908XXX Customer Assistance Expenses 24,109,239 515,442 24,624,681 17,609,905 338,558 17,948,463 6,499,334 176,884 6,676,218 2 909000 Advertising 16,415 863,985 880,400 15,333 567,491 582,824 1,082 296,494 297,576 2 910000 Misc Customer Service & Info Exp 0 107,115 107,115 0 70,356 70,356 0 36,759 36,759 TOTAL CUSTOMER SERVICE & INFO EXP 24,125,654 1,486,542 25,612,196 17,625,238 976,405 18,601,643 6,500,416 510,137 7,010,553 SALES EXPENSES: 2 912000 Demonstrating & Selling Expenses 0 0 0 0 0 0 0 0 0 2 913000 Advertising 0 0 0 0 0 0 0 0 0 2 916000 Miscellaneous Sales Expenses 0 0 0 0 0 0 0 0 0 TOTAL SALES EXPENSES 0 0 0 0 0 0 0 0 0 ADMINISTRATIVE & GENERAL EXPENSES: 4 920000 Salaries 372,974 31,651,900 32,024,874 245,526 21,535,953 21,781,479 127,448 10,115,947 10,243,395 4 921000 Office Supplies & Expenses 99,184 4,130,518 4,229,702 99,184 2,810,404 2,909,588 0 1,320,114 1,320,114 4 922000 Admin Exp Transferred--Credit 0 (118,479) (118,479) 0 (80,613) (80,613) 0 (37,866) (37,866) 4 923000 Outside Services Employe 131,665 9,500,051 9,631,716 62,952 6,463,835 6,526,787 68,713 3,036,216 3,104,929 4 924000 Property Insurance Premium 0 1,313,970 1,313,970 0 894,025 894,025 0 419,945 419,945 4 925XXX Injuries and Damages 22,575 3,450,764 3,473,339 22,418 2,347,900 2,370,318 157 1,102,864 1,103,021 4 926XXX Employee Pensions and Benefits 0 1,594,959 1,594,959 0 1,085,210 1,085,210 0 509,749 509,749 4 927000 Franchise Requirements 3,927 0 3,927 0 0 0 3,927 0 3,927 1 928000 Regulatory Commission Expenses 3,087,053 3,051,444 6,138,497 2,207,247 2,002,663 4,209,910 879,806 1,048,781 1,928,587 4 930000 Miscellaneous General Expenses 132,964 3,502,299 3,635,263 88,228 2,382,964 2,471,192 44,736 1,119,335 1,164,071 4 931000 Rents 9,583 1,007,981 1,017,564 5,383 685,830 691,213 4,200 322,151 326,351 4 935000 Maintenance of General Plant 989,856 9,687,895 10,677,751 563,564 6,591,644 7,155,208 426,292 3,096,251 3,522,543 TOTAL ADMIN & GEN OPERATING EXP 4,849,781 68,773,302 73,623,083 3,294,502 46,719,815 50,014,317 1,555,279 22,053,487 23,608,766 Page 6 of 7 Print Date-Time 2/18/2016 9:46 AM RESULTS OF OPERATIONS Report ID: AVISTA UTILITIES ELECTRIC OPERATING STATEMENT E-OPS-12A For Twelve Months Ended December 31, 2015 Average of Monthly Averages Basis ***************** SYSTEM ***************** *************** WASHINGTON ************* ***************** IDAHO ****************** Ref/Basis Account Description Direct Allocate Total Direct Allocate Total Direct Allocate Total E-DEPX Depreciation Expense-General 1,704,385 15,094,084 16,798,469 1,256,581 10,270,015 11,526,596 447,804 4,824,069 5,271,873 E-AMTX Amortization Expense-General Plant - 303000 0 431,268 431,268 0 293,250 293,250 0 138,018 138,018 E-AMTX Amortization Expense-Miscellaneous IT Intangible 1,046,824 12,690,450 13,737,274 1,031,822 8,634,583 9,666,405 15,002 4,055,867 4,070,869 E-AMTX Amortization Expense-General Plant - 390200, 396200 0 24,346 24,346 0 16,565 16,565 0 7,781 7,781 99 407229 Idaho Earnings Test Amortization (2,709,751) 0 (2,709,751) 0 0 0 (2,709,751) 0 (2,709,751) 99 407468 Project Compass Deferral - ID (2,674,360) 0 (2,674,360) 0 0 0 (2,674,360) 0 (2,674,360) TOTAL A&G DEPR/AMRT/NON-FIT TAXES (2,632,902) 28,240,148 25,607,246 2,288,403 19,214,413 21,502,816 (4,921,305) 9,025,735 4,104,430 TOTAL ADMIN & GENERAL EXPENSES 2,216,879 97,013,450 99,230,329 5,582,905 65,934,228 71,517,133 (3,366,026) 31,079,222 27,713,196 TOTAL EXPENSES BEFORE FIT 161,561,497 632,233,964 793,795,461 118,578,271 417,330,233 535,908,504 42,983,226 214,903,731 257,886,957 NET OPERATING INCOME (LOSS) BEFORE FIT 212,344,602 138,735,467 73,609,135 E-FIT FEDERAL INCOME TAX--Normal Accrual 9,192,557 5,592,294 3,600,263 E-FIT DEFERRED FEDERAL INCOME TAX 44,638,240 29,543,007 15,095,233 E-FIT AMORTIZED ITC - NOXON (195,528)(128,325) (67,203) ELECTRIC NET OPERATING INCOME (LOSS) 158,709,333 103,728,491 54,980,842 ALLOCATION RATIOS: E-AL 1 Production/Transmission Ratio 100.000% 65.630% 34.370% E-AL 2 Number of Customers - AM 100.000% 65.683% 34.317% E-AL 3 Direct Distribution Operating Expense 100.000% 67.017% 32.983% E-AL 4 Jurisdictional 4-Factor Ratio 100.000% 68.040% 31.960% E-AL 99 Not Allocate 0.000% 0.000% 0.000% Page 7 of 7 Print Date-Time 2/18/2016 9:46 AM RESULTS OF OPERATIONS Report ID: AVISTA UTILITIES ELECTRIC OPERATING STATEMENT E-OPS-12A For Twelve Months Ended December 31, 2015 Average of Monthly Averages Basis ***************** SYSTEM ***************** *************** WASHINGTON ************* ***************** IDAHO ****************** Ref/Basis Account Description Direct Allocate Total Direct Allocate Total Direct Allocate Total REVENUE SALES OF ELECTRICITY: 99 440000 Residential 339,129,378 0 339,129,378 228,952,929 0 228,952,929 110,176,449 0 110,176,449 99 442200 Commercial - Firm & Int. 312,340,143 0 312,340,143 221,104,301 0 221,104,301 91,235,842 0 91,235,842 1 442300 Industrial 116,667,748 0 116,667,748 66,873,283 0 66,873,283 49,794,465 0 49,794,465 99 444000 Public Street & Highway Lighting 7,276,497 0 7,276,497 4,889,678 0 4,889,678 2,386,819 0 2,386,819 99 448000 Interdepartmental Revenue 1,190,014 0 1,190,014 927,600 0 927,600 262,414 0 262,414 99 499XXX Unbilled Revenue (12,604,957) 0 (12,604,957) (8,824,571) 0 (8,824,571) (3,780,386) 0 (3,780,386) TOTAL SALES TO ULTIMATE CUSTOMERS 763,998,823 0 763,998,823 513,923,220 0 513,923,220 250,075,603 0 250,075,603 1 447XXX Sales for Resale 0 133,316,868 133,316,868 0 87,495,860 87,495,860 0 45,821,008 45,821,008 TOTAL SALES OF ELECTRICITY 763,998,823 133,316,868 897,315,691 513,923,220 87,495,860 601,419,080 250,075,603 45,821,008 295,896,611 OTHER OPERATING REVENUE: 99 449100 Provision for Rate Refun (5,620,861) 0 (5,620,861) (3,422,474) 0 (3,422,474) (2,198,387) 0 (2,198,387) 99 451000 Miscellaneous Service Revenue 252,517 0 252,517 154,514 0 154,514 98,003 0 98,003 1 453000 Sales of Water & Water Powe 0 407,336 407,336 0 267,335 267,335 0 140,001 140,001 1 454000 Rent from Electric Propert 2,557,565 74,656 2,632,221 1,558,332 48,997 1,607,329 999,233 25,659 1,024,892 1 456XXX Other Electric Revenues 5,003,637 106,149,522 111,153,159 4,952,256 69,665,931 74,618,187 51,381 36,483,591 36,534,972 TOTAL OTHER OPERATING REVENUE 2,192,858 106,631,514 108,824,372 3,242,628 69,982,263 73,224,891 (1,049,770) 36,649,251 35,599,481 TOTAL ELECTRIC REVENUE 766,191,681 239,948,382 1,006,140,063 517,165,848 157,478,123 674,643,971 249,025,833 82,470,259 331,496,092 Page 1 of 7 Print Date-Time 2/18/2016 9:46 AM RESULTS OF OPERATIONS Report ID: AVISTA UTILITIES ELECTRIC OPERATING STATEMENT E-OPS-12A For Twelve Months Ended December 31, 2015 Average of Monthly Averages Basis ***************** SYSTEM ***************** *************** WASHINGTON ************* ***************** IDAHO ****************** Ref/Basis Account Description Direct Allocate Total Direct Allocate Total Direct Allocate Total EXPENSE STEAM POWER GENERATION EXPENSE: OPERATION 1 500000 Supervision & Engineering 6,320 275,692 282,012 6,320 180,937 187,257 0 94,755 94,755 1 501XXX Fuel 0 30,794,427 30,794,427 0 20,210,382 20,210,382 0 10,584,045 10,584,045 1 502000 Steam Expense 0 5,199,150 5,199,150 0 3,412,202 3,412,202 0 1,786,948 1,786,948 1 505000 Electric Expense 0 1,228,906 1,228,906 0 806,531 806,531 0 422,375 422,375 1 506XXX Miscellaneous Steam Power Generation Op Exp 0 2,967,067 2,967,067 0 1,947,286 1,947,286 0 1,019,781 1,019,781 1 507000 Rent 0 33,667 33,667 0 22,096 22,096 0 11,571 11,571 MAINTENANCE 1 510000 Supervision & Engineering 0 613,157 613,157 0 402,415 402,415 0 210,742 210,742 1 511000 Structures 0 758,347 758,347 0 497,703 497,703 0 260,644 260,644 1 512000 Boiler Plant 0 4,760,690 4,760,690 0 3,124,441 3,124,441 0 1,636,249 1,636,249 1 513000 Electric Plant 0 601,012 601,012 0 394,444 394,444 0 206,568 206,568 1 514XXX Miscellaneous Steam Power Generation Maint Exp 0 954,982 954,982 0 626,755 626,755 0 328,227 328,227 TOTAL STEAM POWER GENERATION EXP 6,320 48,187,097 48,193,417 6,320 31,625,192 31,631,512 0 16,561,905 16,561,905 HYDRAULIC POWER GENERATION EXP: OPERATION 1 535000 Supervision & Engineering 0 2,107,646 2,107,646 0 1,383,248 1,383,248 0 724,398 724,398 1 536000 Water for Powe 0 1,300,900 1,300,900 0 853,781 853,781 0 447,119 447,119 1 537000 Hydraulic Expense 4,353,425 2,848,110 7,201,535 2,815,977 1,869,215 4,685,192 1,537,448 978,895 2,516,343 1 538000 Electric Expense 0 6,559,863 6,559,863 0 4,305,238 4,305,238 0 2,254,625 2,254,625 1 539000 Miscellaneous Hydraulic Power Generation Exp 0 876,509 876,509 0 575,253 575,253 0 301,256 301,256 1 540000 Rent 0 1,374,529 1,374,529 0 902,103 902,103 0 472,426 472,426 1 540100 MT Trust Funds Land Settlement Rents 5,734,731 0 5,734,731 3,716,329 0 3,716,329 2,018,402 0 2,018,402 MAINTENANCE 1 541000 Supervision & Engineering 0 1,616,898 1,616,898 0 1,061,170 1,061,170 0 555,728 555,728 1 542000 Structures 0 326,758 326,758 0 214,451 214,451 0 112,307 112,307 1 543000 Reservoirs, Dams, & Waterways 0 1,375,773 1,375,773 0 902,920 902,920 0 472,853 472,853 1 544000 Electric Plant 0 2,663,275 2,663,275 0 1,747,907 1,747,907 0 915,368 915,368 1 545000 Miscellaneous Hydraulic Plant 0 696,377 696,377 0 457,032 457,032 0 239,345 239,345 TOTAL HYDRO POWER GENERATION EXP 10,088,156 21,746,638 31,834,794 6,532,306 14,272,318 20,804,624 3,555,850 7,474,320 11,030,170 OTHER POWER GENERATION EXPENSE: OPERATION 1 546000 Supervision & Engineering 0 1,179,973 1,179,973 0 774,416 774,416 0 405,557 405,557 1 547XXX Fuel 0 91,777,298 91,777,298 0 60,233,441 60,233,441 0 31,543,857 31,543,857 1 548000 Generation Expense 0 2,016,313 2,016,313 0 1,323,306 1,323,306 0 693,007 693,007 1 549XXX Miscellaneous Other Power Generation Op Exp 0 461,399 461,399 0 302,816 302,816 0 158,583 158,583 1 550000 Rent 0 (33,315) (33,315) 0 (21,865) (21,865) 0 (11,450) (11,450) MAINTENANCE 1 551000 Supervision & Engineering 0 625,187 625,187 0 410,310 410,310 0 214,877 214,877 1 552000 Structures 0 110,380 110,380 0 72,442 72,442 0 37,938 37,938 1 553000 Generating & Electric Equipment 278 2,317,312 2,317,590 278 1,520,852 1,521,130 0 796,460 796,460 1 554XXX Miscellaneous Other Power Generation Maint Exp 0 453,413 453,413 0 297,575 297,575 0 155,838 155,838 TOTAL OTHER POWER GENERATION EXP 278 98,907,960 98,908,238 278 64,913,293 64,913,571 0 33,994,667 33,994,667 Page 2 of 7 Print Date-Time 2/18/2016 9:46 AM RESULTS OF OPERATIONS Report ID: AVISTA UTILITIES ELECTRIC OPERATING STATEMENT E-OPS-12A For Twelve Months Ended December 31, 2015 Average of Monthly Averages Basis ***************** SYSTEM ***************** *************** WASHINGTON ************* ***************** IDAHO ****************** Ref/Basis Account Description Direct Allocate Total Direct Allocate Total Direct Allocate Total OTHER POWER SUPPLY EXPENSE: E-555 555XXX Purchased Powe 0 172,688,007 172,688,007 0 113,335,139 113,335,139 0 59,352,868 59,352,868 1 556000 System Control & Load Dispatching 0 1,049,171 1,049,171 0 688,571 688,571 0 360,600 360,600 E-557 557XXX Other Expense 3,503,149 80,993,269 84,496,418 (2,232,884) 53,155,882 50,922,998 5,736,033 27,837,387 33,573,420 TOTAL OTHER POWER SUPPLY EXPENSE 3,503,149 254,730,447 258,233,596 (2,232,884) 167,179,592 164,946,708 5,736,033 87,550,855 93,286,888 TOTAL PRODUCTION OPERATING EXP 13,597,903 423,572,142 437,170,045 4,306,020 277,990,395 282,296,415 9,291,883 145,581,747 154,873,630 TRANSMISSION OPERATING EXPENSE: OPERATION 1 560000 Supervision & Engineering 0 2,119,618 2,119,618 0 1,391,105 1,391,105 0 728,513 728,513 1 561000 Load Dispatching 0 2,554,257 2,554,257 0 1,676,359 1,676,359 0 877,898 877,898 1 562000 Station Expense 0 532,894 532,894 0 349,738 349,738 0 183,156 183,156 1 562100 Energy Storage Equipment 0 0 0 0 0 0 0 0 0 1 563000 Overhead Line Expense 0 458,587 458,587 0 300,971 300,971 0 157,616 157,616 1 565XXX Transmission of Electricity by Others 0 17,389,891 17,389,891 0 11,412,985 11,412,985 0 5,976,906 5,976,906 1 566000 Miscellaneous Transmission Expense 0 2,162,711 2,162,711 0 1,419,387 1,419,387 0 743,324 743,324 1 567000 Rent 0 153,599 153,599 0 100,807 100,807 0 52,792 52,792 MAINTENANCE 1 568000 Supervision & Engineering 2,875 806,039 808,914 2,280 529,003 531,283 595 277,036 277,631 1 569000 Structures 8,319 729,433 737,752 2,122 478,727 480,849 6,197 250,706 256,903 1 570000 Station Equipment 18,826 1,339,663 1,358,489 18,045 879,221 897,266 781 460,442 461,223 1 570100 Energy Storage Equipment 0 0 0 0 0 0 0 0 0 1 571000 Overhead Lines 19,745 1,127,821 1,147,566 7,699 740,189 747,888 12,046 387,632 399,678 1 572000 Underground Lines 3,046 6,841 9,887 0 4,490 4,490 3,046 2,351 5,397 1 573000 Service Miscellaneous 17,496 90,407 107,903 17,475 59,334 76,809 21 31,073 31,094 TOTAL TRANSMISSION OPERATING EXP 70,307 29,471,761 29,542,068 47,621 19,342,316 19,389,937 22,686 10,129,445 10,152,131 Page 3 of 7 Print Date-Time 2/18/2016 9:46 AM RESULTS OF OPERATIONS Report ID: AVISTA UTILITIES ELECTRIC OPERATING STATEMENT E-OPS-12A For Twelve Months Ended December 31, 2015 Average of Monthly Averages Basis ***************** SYSTEM ***************** *************** WASHINGTON ************* ***************** IDAHO ****************** Ref/Basis Account Description Direct Allocate Total Direct Allocate Total Direct Allocate Total E-DEPX Depreciation Expense-Production 0 26,029,745 26,029,745 0 17,083,322 17,083,322 0 8,946,423 8,946,423 E-DEPX Depreciation Expense-Transmission 0 11,040,922 11,040,922 0 7,246,157 7,246,157 0 3,794,765 3,794,765 E-AMTX Amortization Expense-Franchises/Misc Intangibles 0 1,158,453 1,158,453 0 760,293 760,293 0 398,160 398,160 99 Colstrip 3 AFUDC Reallocation Adj 0 0 0 (141,516) 0 (141,516) 141,516 0 141,516 99 405930 Amortization of Investment in WNP3 Exch Powe 2,450,031 0 2,450,031 2,450,031 0 2,450,031 0 0 0 99 406100 Amort of Acq Adj--Colstrip Common AFUDC 99,047 0 99,047 31,743 0 31,743 67,304 0 67,304 99 407312 Amortization of Lancaster Generation 1,246,667 0 1,246,667 1,246,667 0 1,246,667 0 0 0 1 407320 Amortization of Colstrip Outage Return 0 0 0 0 0 0 0 0 0 99 407322 Amortization of Spokane River Relicense 78,736 0 78,736 72,939 0 72,939 5,797 0 5,797 1 407324 Amortization of CDA CDR Fun 11,065 200,000 211,065 11,065 131,260 142,325 0 68,740 68,740 99 407331 Amortization of BPA Parallel Capacity Support (451,078) 0 (451,078) (287,084) 0 (287,084) (163,994) 0 (163,994) 1 407333 Amortization of CDA Settlement Costs 0 32,719 32,719 0 21,473 21,473 0 11,246 11,246 99 407335 Amortization of ID DSIT 0 0 0 0 0 0 0 0 0 99 407350 Amortization of WA Renewable Energy Credits 0 0 0 0 0 0 0 0 0 99 407351 Amortization of CNC Transmission 0 0 0 0 0 0 0 0 0 99 407360 Amortization of CS2 & COLSTRIP O&M 2,285,964 0 2,285,964 973,692 0 973,692 1,312,272 0 1,312,272 99 407362 Amortization of LiDAR O&M 0 0 0 0 0 0 0 0 0 99 407365 Amortization of Wind Generation 216,701 0 216,701 0 0 0 216,701 0 216,701 99 407380 Amortization of Wartsila Generators 153,156 0 153,156 153,156 0 153,156 0 0 0 1 407382 Amortization of CDA Settlement - Allocate 0 884,086 884,086 0 580,226 580,226 0 303,860 303,860 99 407382 Amortization of CDA Settlement - Direct 183,093 0 183,093 152,118 0 152,118 30,975 0 30,975 99 407391 Amortization of Spokane River TD 290,395 0 290,395 290,395 0 290,395 0 0 0 99 407395 Optional Renewable Power Revenue Offset 228,772 0 228,772 180,441 0 180,441 48,331 0 48,331 99 407403 Amortization of Dissallowed K.F. Plant (134,592) 0 (134,592) (134,592) 0 (134,592) 0 0 0 99 407405 Amortization of Boulder Park Write Off - Idaho (108,531) 0 (108,531) 0 0 0 (108,531) 0 (108,531) 99 407420 Amortization of CS2 Levelized Return 0 0 0 0 0 0 0 0 0 99 407450/407499 Amortization of BPA Residential Exchange Credit (8,123,977) 0 (8,123,977) (5,771,460) 0 (5,771,460) (2,352,517) 0 (2,352,517) 99 407460 Amortization of Deferred CS2 & COLSTRIP O&M (1,304,949) 0 (1,304,949) 0 0 0 (1,304,949) 0 (1,304,949) 99 407462 Amortization of Deferred LiDAR O&M 0 0 0 0 0 0 0 0 0 99 407494 Amortization of Schedule 98 REC Re (258,258) 0 (258,258) (258,258) 0 (258,258) 0 0 0 1 407495 Optional Renew Solar Project Offset 0 (8,416) (8,416) 0 (5,523) (5,523) 0 (2,893) (2,893) 99 407496 Def Palouse Wind & Thornton Sw St 0 0 0 0 0 0 0 0 0 99 407497 Amortization of BPA Settlement 466,716 0 466,716 302,722 0 302,722 163,994 0 163,994 E-OTX Taxes Other Than FIT--Prod & Trans 0 20,958,039 20,958,039 0 13,754,761 13,754,761 0 7,203,278 7,203,278 TOTAL P/T DEPR/AMRT/NON-FIT TAXES (2,671,042) 60,295,548 57,624,506 (727,941) 39,571,969 38,844,028 (1,943,101) 20,723,579 18,780,478 TOTAL PRODUCTION & TRANSMISSION EXPENS 10,997,168 513,339,451 524,336,619 3,625,700 336,904,680 340,530,380 7,371,468 176,434,771 183,806,239 Page 4 of 7 Print Date-Time 2/18/2016 9:46 AM RESULTS OF OPERATIONS Report ID: AVISTA UTILITIES ELECTRIC OPERATING STATEMENT E-OPS-12A For Twelve Months Ended December 31, 2015 Average of Monthly Averages Basis ***************** SYSTEM ***************** *************** WASHINGTON ************* ***************** IDAHO ****************** Ref/Basis Account Description Direct Allocate Total Direct Allocate Total Direct Allocate Total DISTRIBUTION EXPENSES: OPERATION: 3 580000 Supervision & Engineering 1,329,069 2,783,160 4,112,229 983,660 1,865,190 2,848,850 345,409 917,970 1,263,379 3 582000 Station Expense 663,197 78,852 742,049 342,123 52,844 394,967 321,074 26,008 347,082 3 583000 Overhead Line Expense 1,562,123 437,411 1,999,534 1,009,528 293,140 1,302,668 552,595 144,271 696,866 3 584000 Underground Line Expense 1,414,309 23 1,414,332 940,309 15 940,324 474,000 8 474,008 3 584100 Energy Storage Equipment 11,142 0 11,142 11,142 0 11,142 0 0 0 3 585000 Street Light & Signal System Operation Expense 12,587 0 12,587 7,578 0 7,578 5,009 0 5,009 3 586000 Meter Expense 1,895,040 78,534 1,973,574 1,533,641 52,631 1,586,272 361,399 25,903 387,302 3 587000 Customer Installations Expense 509,972 100,624 610,596 272,791 67,435 340,226 237,181 33,189 270,370 3 588000 Miscellaneous Distribution Expense 3,975,947 3,358,793 7,334,740 2,388,979 2,250,962 4,639,941 1,586,968 1,107,831 2,694,799 3 589000 Rent 278 262,408 262,686 278 175,858 176,136 0 86,550 86,550 MAINTENANCE: 3 590000 Supervision & Engineering 760,069 1,407,922 2,167,991 635,760 943,547 1,579,307 124,309 464,375 588,684 3 591000 Structures 380,139 8,157 388,296 226,422 5,467 231,889 153,717 2,690 156,407 3 592000 Station Equipment 901,960 177,702 1,079,662 695,440 119,091 814,531 206,520 58,611 265,131 3 592200 Energy Storage Equipment 0 0 0 0 0 0 0 0 0 3 593000 Overhead Lines 11,037,607 (553,240) 10,484,367 7,207,139 (370,765) 6,836,374 3,830,468 (182,475) 3,647,993 3 594000 Underground Lines 839,424 0 839,424 575,377 0 575,377 264,047 0 264,047 3 595000 Line Transformers 353,307 321,629 674,936 274,539 215,546 490,085 78,768 106,083 184,851 3 596000 Street Light & Signal System Maintenance Exp 692,950 0 692,950 458,582 0 458,582 234,368 0 234,368 3 597000 Meters 25,403 0 25,403 20,023 0 20,023 5,380 0 5,380 3 598000 Miscellaneous Distribution Expense 633,798 439,554 1,073,352 510,126 294,576 804,702 123,672 144,978 268,650 TOTAL DISTRIBUTION OPERATING EXP 26,998,321 8,901,529 35,899,850 18,093,437 5,965,537 24,058,974 8,904,884 2,935,992 11,840,876 E-DEPX Depreciation Expense-Distribution 40,666,652 32,993 40,699,645 25,404,698 22,111 25,426,809 15,261,954 10,882 15,272,836 E-AMTX Amortization Expense-Franchises/Misc Intangibles 26,997 0 26,997 26,997 0 26,997 0 0 0 E-OTX Taxes Other Than FIT--Distribution 52,450,518 0 52,450,518 44,868,195 0 44,868,195 7,582,323 0 7,582,323 TOTAL DISTR DEPR/AMRT/NON-FIT TAXES 93,144,167 32,993 93,177,160 70,299,890 22,111 70,322,001 22,844,277 10,882 22,855,159 TOTAL DISTRIBUTION EXPENSES 120,142,488 8,934,522 129,077,010 88,393,327 5,987,648 94,380,975 31,749,161 2,946,874 34,696,035 Page 5 of 7 Print Date-Time 2/18/2016 9:46 AM RESULTS OF OPERATIONS Report ID: AVISTA UTILITIES ELECTRIC OPERATING STATEMENT E-OPS-12A For Twelve Months Ended December 31, 2015 Average of Monthly Averages Basis ***************** SYSTEM ***************** *************** WASHINGTON ************* ***************** IDAHO ****************** Ref/Basis Account Description Direct Allocate Total Direct Allocate Total Direct Allocate Total CUSTOMER ACCOUNTS EXPENSES: 2 901000 Supervision 0 356,243 356,243 0 233,991 233,991 0 122,252 122,252 2 902000 Meter Reading Expenses 2,898,933 183,688 3,082,621 2,598,834 120,652 2,719,486 300,099 63,036 363,135 E-903 903XXX Customer Records & Collection Expenses 1,180,375 7,615,135 8,795,510 752,267 5,001,849 5,754,116 428,108 2,613,286 3,041,394 2 904000 Uncollectible Accounts 0 3,041,287 3,041,287 0 1,997,609 1,997,609 0 1,043,678 1,043,678 2 905000 Misc Customer Accounts 0 263,646 263,646 0 173,171 173,171 0 90,475 90,475 TOTAL CUSTOMER ACCOUNTS EXPENSES 4,079,308 11,459,999 15,539,307 3,351,101 7,527,272 10,878,373 728,207 3,932,727 4,660,934 CUSTOMER SERVICE & INFO EXPENSES: E-908 908XXX Customer Assistance Expenses 24,109,239 515,442 24,624,681 17,609,905 338,558 17,948,463 6,499,334 176,884 6,676,218 2 909000 Advertising 16,415 863,985 880,400 15,333 567,491 582,824 1,082 296,494 297,576 2 910000 Misc Customer Service & Info Exp 0 107,115 107,115 0 70,356 70,356 0 36,759 36,759 TOTAL CUSTOMER SERVICE & INFO EXP 24,125,654 1,486,542 25,612,196 17,625,238 976,405 18,601,643 6,500,416 510,137 7,010,553 SALES EXPENSES: 2 912000 Demonstrating & Selling Expenses 0 0 0 0 0 0 0 0 0 2 913000 Advertising 0 0 0 0 0 0 0 0 0 2 916000 Miscellaneous Sales Expenses 0 0 0 0 0 0 0 0 0 TOTAL SALES EXPENSES 0 0 0 0 0 0 0 0 0 ADMINISTRATIVE & GENERAL EXPENSES: 4 920000 Salaries 372,974 31,651,900 32,024,874 245,526 21,535,953 21,781,479 127,448 10,115,947 10,243,395 4 921000 Office Supplies & Expenses 99,184 4,130,518 4,229,702 99,184 2,810,404 2,909,588 0 1,320,114 1,320,114 4 922000 Admin Exp Transferred--Credit 0 (118,479) (118,479) 0 (80,613) (80,613) 0 (37,866) (37,866) 4 923000 Outside Services Employe 131,665 9,500,051 9,631,716 62,952 6,463,835 6,526,787 68,713 3,036,216 3,104,929 4 924000 Property Insurance Premium 0 1,313,970 1,313,970 0 894,025 894,025 0 419,945 419,945 4 925XXX Injuries and Damages 22,575 3,450,764 3,473,339 22,418 2,347,900 2,370,318 157 1,102,864 1,103,021 4 926XXX Employee Pensions and Benefits 0 1,594,959 1,594,959 0 1,085,210 1,085,210 0 509,749 509,749 4 927000 Franchise Requirements 3,927 0 3,927 0 0 0 3,927 0 3,927 1 928000 Regulatory Commission Expenses 3,087,053 3,051,444 6,138,497 2,207,247 2,002,663 4,209,910 879,806 1,048,781 1,928,587 4 930000 Miscellaneous General Expenses 132,964 3,502,299 3,635,263 88,228 2,382,964 2,471,192 44,736 1,119,335 1,164,071 4 931000 Rents 9,583 1,007,981 1,017,564 5,383 685,830 691,213 4,200 322,151 326,351 4 935000 Maintenance of General Plant 989,856 9,687,895 10,677,751 563,564 6,591,644 7,155,208 426,292 3,096,251 3,522,543 TOTAL ADMIN & GEN OPERATING EXP 4,849,781 68,773,302 73,623,083 3,294,502 46,719,815 50,014,317 1,555,279 22,053,487 23,608,766 Page 6 of 7 Print Date-Time 2/18/2016 9:46 AM RESULTS OF OPERATIONS Report ID: AVISTA UTILITIES ELECTRIC OPERATING STATEMENT E-OPS-12A For Twelve Months Ended December 31, 2015 Average of Monthly Averages Basis ***************** SYSTEM ***************** *************** WASHINGTON ************* ***************** IDAHO ****************** Ref/Basis Account Description Direct Allocate Total Direct Allocate Total Direct Allocate Total E-DEPX Depreciation Expense-General 1,704,385 15,094,084 16,798,469 1,256,581 10,270,015 11,526,596 447,804 4,824,069 5,271,873 E-AMTX Amortization Expense-General Plant - 303000 0 431,268 431,268 0 293,250 293,250 0 138,018 138,018 E-AMTX Amortization Expense-Miscellaneous IT Intangible 1,046,824 12,690,450 13,737,274 1,031,822 8,634,583 9,666,405 15,002 4,055,867 4,070,869 E-AMTX Amortization Expense-General Plant - 390200, 396200 0 24,346 24,346 0 16,565 16,565 0 7,781 7,781 99 407229 Idaho Earnings Test Amortization (2,709,751) 0 (2,709,751) 0 0 0 (2,709,751) 0 (2,709,751) 99 407468 Project Compass Deferral - ID (2,674,360) 0 (2,674,360) 0 0 0 (2,674,360) 0 (2,674,360) TOTAL A&G DEPR/AMRT/NON-FIT TAXES (2,632,902) 28,240,148 25,607,246 2,288,403 19,214,413 21,502,816 (4,921,305) 9,025,735 4,104,430 TOTAL ADMIN & GENERAL EXPENSES 2,216,879 97,013,450 99,230,329 5,582,905 65,934,228 71,517,133 (3,366,026) 31,079,222 27,713,196 TOTAL EXPENSES BEFORE FIT 161,561,497 632,233,964 793,795,461 118,578,271 417,330,233 535,908,504 42,983,226 214,903,731 257,886,957 NET OPERATING INCOME (LOSS) BEFORE FIT 212,344,602 138,735,467 73,609,135 E-FIT FEDERAL INCOME TAX--Normal Accrual 9,192,557 5,592,294 3,600,263 E-FIT DEFERRED FEDERAL INCOME TAX 44,638,240 29,543,007 15,095,233 E-FIT AMORTIZED ITC - NOXON (195,528)(128,325) (67,203) ELECTRIC NET OPERATING INCOME (LOSS) 158,709,333 103,728,491 54,980,842 ALLOCATION RATIOS: E-AL 1 Production/Transmission Ratio 100.000% 65.630% 34.370% E-AL 2 Number of Customers - AM 100.000% 65.683% 34.317% E-AL 3 Direct Distribution Operating Expense 100.000% 67.017% 32.983% E-AL 4 Jurisdictional 4-Factor Ratio 100.000% 68.040% 31.960% E-AL 99 Not Allocate 0.000% 0.000% 0.000% Page 7 of 7 Print Date-Time 2/18/2016 9:46 AM RESULTS OF OPERATIONS Report ID: AVISTA UTILITIE GAS UTILITY PLANT G-PLT-12A For Twelve Months Ended December 31, 201 Average of Monthly Averages Basi Ref/Basis Accoun Descriptio Direc Allocate Tota Direc Allocate Tota Direc Allocate Tota PLANT IN SERVICE INTANGIBLE PLANT 4 303000 Misc Intangible Plant (303000 1,278,452 1,795,338 3,073,790 1,022,594 1,301,602 2,324,196 255,858 493,736 749,594 4 3031XX Misc Intangible IT Plant (3031XX 16,645 29,008,306 29,024,951 0 21,030,732 21,030,732 16,645 7,977,574 7,994,219 TOTAL INTANGIBLE PLAN 1,295,097 30,803,644 32,098,741 1,022,594 22,332,334 23,354,928 272,503 8,471,310 8,743,813 UNDERGROUND STORAGE PLANT: 1 350XXX Land & Land Rights 0 466,806 466,806 0 329,845 329,845 0 136,961 136,961 1 351XXX Structures & Improvement 0 1,704,617 1,704,617 0 1,204,482 1,204,482 0 500,135 500,135 1 352XXX Well 0 18,644,792 18,644,792 0 13,174,410 13,174,410 0 5,470,382 5,470,382 1 353000 Line 0 1,044,478 1,044,478 0 738,028 738,028 0 306,450 306,450 1 354000 Compressor Station Equipmen 0 11,828,225 11,828,225 0 8,357,824 8,357,824 0 3,470,401 3,470,401 1 355000 Measuring & Regulating Equipmen 0 498,885 498,885 0 352,512 352,512 0 146,373 146,373 1 356000 Purification Equipmen 0 403,712 403,712 0 285,263 285,263 0 118,449 118,449 1 357000 Other Equipmen 0 1,808,624 1,808,624 0 1,277,974 1,277,974 0 530,650 530,650 TOTAL UNDERGROUND STORAGE PLAN 0 36,400,139 36,400,139 0 25,720,338 25,720,338 0 10,679,801 10,679,801 DISTRIBUTION PLANT: 6 374200 Land & Land Rights 88,595 0 88,595 63,925 0 63,925 24,670 0 24,670 6 374400 Land & Land Rights 179,924 0 179,924 116,789 0 116,789 63,135 0 63,135 6 375000 Structures & Improvement 896,165 0 896,165 542,253 0 542,253 353,912 0 353,912 6 376000 Mains 270,497,207 2,512,521 273,009,728 175,483,584 1,720,122 177,203,706 95,013,623 792,399 95,806,022 6 378000 Measuring & Reg Station Equip-Genera 5,412,762 127,100 5,539,862 3,265,654 87,015 3,352,669 2,147,108 40,085 2,187,193 6 379000 Measuring & Reg Station Equip-City Gat 6,271,156 0 6,271,156 1,933,238 0 1,933,238 4,337,918 0 4,337,918 6 380000 Service 186,602,117 0 186,602,117 127,047,228 0 127,047,228 59,554,889 0 59,554,889 6 381000 Meter 70,732,546 0 70,732,546 47,776,809 0 47,776,809 22,955,737 0 22,955,737 6 382000 Meter Installation 0 0 0 0 0 0 0 0 0 6 383000 House Regulator 0 0 0 0 0 0 0 0 0 6 384000 House Regulator Installation 0 0 0 0 0 0 0 0 0 6 385000 Industrial Measuring & Reg Sta Equi 3,320,815 0 3,320,815 2,575,612 0 2,575,612 745,203 0 745,203 6 387000 Other Equipmen 0 0 0 0 0 0 0 0 0 TOTAL DISTRIBUTION PLAN 544,001,287 2,639,621 546,640,908 358,805,092 1,807,137 360,612,229 185,196,195 832,484 186,028,679 GENERAL PLANT 4 389XXX Land & Land Rights 681,998 1,269,469 1,951,467 589,062 920,352 1,509,414 92,936 349,117 442,053 4 390XXX Structures & Improvement 4,965,781 17,819,505 22,785,286 3,738,902 12,918,963 16,657,865 1,226,879 4,900,542 6,127,421 4 391XXX Office Furniture & Equipmen 27,114 12,125,206 12,152,320 8,197 8,790,653 8,798,850 18,917 3,334,553 3,353,470 4 392XXX Transportation Equipmen 9,464,635 1,980,283 11,444,918 7,063,015 1,435,685 8,498,700 2,401,620 544,598 2,946,218 4 393000 Stores Equipmen 151,287 610,033 761,320 114,151 442,268 556,419 37,136 167,765 204,901 4 394000 Tools, Shop & Garage Equipmen 2,559,475 4,168,993 6,728,468 1,982,075 3,022,478 5,004,553 577,400 1,146,515 1,723,915 4 395000 Laboratory Equipmen 39,214 395,643 434,857 29,575 286,837 316,412 9,639 108,806 118,445 4 396XXX Power Operated Equipmen 3,843,949 1,109,517 4,953,466 2,858,524 804,389 3,662,913 985,425 305,128 1,290,553 4 397XXX Communications Equipmen 2,262,124 8,615,425 10,877,549 844,838 6,246,097 7,090,935 1,417,286 2,369,328 3,786,614 4 398000 Miscellaneous Equipmen 1,060 85,116 86,176 1,060 61,708 62,768 0 23,408 23,408 TOTAL GENERAL PLAN 23,996,637 48,179,190 72,175,827 17,229,399 34,929,430 52,158,829 6,767,238 13,249,760 20,016,998 TOTAL PLANT IN SERVICE 569,293,021 118,022,594 687,315,615 377,057,085 84,789,239 461,846,324 192,235,936 33,233,355 225,469,291 ************* IDAHO ************************* SYSTEM ********************** WASHINGTON ******** Page 1 of 2 Print Date-Time: 2/18/2016 9:49 AM RESULTS OF OPERATIONS Report ID: AVISTA UTILITIE GAS UTILITY PLANT G-PLT-12A For Twelve Months Ended December 31, 201 Average of Monthly Averages Basi Ref/Basis Accoun Descriptio Direc Allocate Tota Direc Allocate Tota Direc Allocate Tota ************* IDAHO ************************* SYSTEM ********************** WASHINGTON ******** ACCUMULATED DEPRECIATION G-ADEP Underground Storag 0 (13,778,484) (13,778,484) 0 (9,735,877) (9,735,877) 0 (4,042,607) (4,042,607) G-ADEP Distribution Plan (181,960,013) (1,535,620) (183,495,633) (120,571,631) (1,051,316) (121,622,947) (61,388,382) (484,304) (61,872,686) G-ADEP General Plan (7,815,676) (13,754,088) (21,569,764) (5,139,581) (9,971,576) (15,111,157) (2,676,095) (3,782,512) (6,458,607) TOTAL ACCUMULATED DEPRECIATION (189,775,689) (29,068,192) (218,843,881) (125,711,212) (20,758,769) (146,469,981) (64,064,477) (8,309,423) (72,373,900) ACCUMULATED AMORTIZATION G-AAM General Plant - 30300 (182,346) (215,853) (398,199) (129,135) (156,491) (285,626) (53,211) (59,362) (112,573) G-AAM Misc IT Intangible Plant - 3031X (5,378) (7,319,597) (7,324,975) 0 (5,306,634) (5,306,634) (5,378) (2,012,963) (2,018,341) G-AAM Underground Storag 0 (239,973) (239,973) 0 (169,565) (169,565) 0 (70,408) (70,408) G-AAM General Plant - 390200, 39620 (4,598) (45,528) (50,126) (3,634) (33,007) (36,641) (964) (12,521) (13,485) TOTAL ACCUMULATED AMORTIZATIO (192,322) (7,820,951) (8,013,273) (132,769) (5,665,697) (5,798,466) (59,553) (2,155,254) (2,214,807) TOTAL ACCUMULATED DEPR/AMORT (189,968,011) (36,889,143) (226,857,154) (125,843,981) (26,424,466) (152,268,447) (64,124,030) (10,464,677) (74,588,707) NET GAS UTILITY PLANT before DFI 379,325,010 81,133,451 460,458,461 251,213,104 58,364,773 309,577,877 128,111,906 22,768,678 150,880,584 ACCUMULATED DFIT 12 282900 ADFIT - Gas Plant In Servic 0 (81,418,381) (81,418,381) 0 (54,740,020) (54,740,020) 0 (26,678,361) (26,678,361) 4, 12 282900 ADFIT - Common Plant (282900 from C-DTX 0 (13,250,758) (13,250,758) 0 (9,599,990) (9,599,990) 0 (3,650,768) (3,650,768) 4 283750 ADFIT - Common Plant (283750 from C-DTX 0 (107,919) (107,919) 0 (78,240) (78,240) 0 (29,679) (29,679) 12 283850 ADFIT - Gas portion of Bond Redemption 0 (960,494) (960,494) 0 (645,769) (645,769) 0 (314,725) (314,725) TOTAL ACCUMULATED DFIT 0 (95,737,552) (95,737,552) 0 (65,064,019) (65,064,019) 0 (30,673,533) (30,673,533) NET GAS UTILITY PLAN 379,325,010 (14,604,101) 364,720,909 251,213,104 (6,699,246) 244,513,858 128,111,906 (7,904,855) 120,207,051 ALLOCATION RATIOS: G-AL 1 System Contract Deman 100.000% 70.660% 29.340% G-AL 4 Jurisdictional 4-Factor Rati 100.000% 72.499% 27.501% G-AL 6 Actual Therms Purchase 100.000% 68.462% 31.538% G-AL 12 Net Gas Plant (before DFIT) - AM 100.000% 67.233% 32.767% Page 2 of 2 Print Date-Time: 2/18/2016 9:49 AM RESULTS OF OPERATIONS Report ID: AVISTA UTILITIE GAS UTILITY PLANT G-PLT-12A For Twelve Months Ended December 31, 201 Average of Monthly Averages Basi Ref/Basis Accoun Descriptio Direc Allocate Tota Direc Allocate Tota Direc Allocate Tota PLANT IN SERVICE INTANGIBLE PLANT 4 303000 Misc Intangible Plant (303000 1,278,452 1,795,338 3,073,790 1,022,594 1,301,602 2,324,196 255,858 493,736 749,594 4 3031XX Misc Intangible IT Plant (3031XX 16,645 29,008,306 29,024,951 0 21,030,732 21,030,732 16,645 7,977,574 7,994,219 TOTAL INTANGIBLE PLAN 1,295,097 30,803,644 32,098,741 1,022,594 22,332,334 23,354,928 272,503 8,471,310 8,743,813 UNDERGROUND STORAGE PLANT: 1 350XXX Land & Land Rights 0 466,806 466,806 0 329,845 329,845 0 136,961 136,961 1 351XXX Structures & Improvement 0 1,704,617 1,704,617 0 1,204,482 1,204,482 0 500,135 500,135 1 352XXX Well 0 18,644,792 18,644,792 0 13,174,410 13,174,410 0 5,470,382 5,470,382 1 353000 Line 0 1,044,478 1,044,478 0 738,028 738,028 0 306,450 306,450 1 354000 Compressor Station Equipmen 0 11,828,225 11,828,225 0 8,357,824 8,357,824 0 3,470,401 3,470,401 1 355000 Measuring & Regulating Equipmen 0 498,885 498,885 0 352,512 352,512 0 146,373 146,373 1 356000 Purification Equipmen 0 403,712 403,712 0 285,263 285,263 0 118,449 118,449 1 357000 Other Equipmen 0 1,808,624 1,808,624 0 1,277,974 1,277,974 0 530,650 530,650 TOTAL UNDERGROUND STORAGE PLAN 0 36,400,139 36,400,139 0 25,720,338 25,720,338 0 10,679,801 10,679,801 DISTRIBUTION PLANT: 6 374200 Land & Land Rights 88,595 0 88,595 63,925 0 63,925 24,670 0 24,670 6 374400 Land & Land Rights 179,924 0 179,924 116,789 0 116,789 63,135 0 63,135 6 375000 Structures & Improvement 896,165 0 896,165 542,253 0 542,253 353,912 0 353,912 6 376000 Mains 270,497,207 2,512,521 273,009,728 175,483,584 1,720,122 177,203,706 95,013,623 792,399 95,806,022 6 378000 Measuring & Reg Station Equip-Genera 5,412,762 127,100 5,539,862 3,265,654 87,015 3,352,669 2,147,108 40,085 2,187,193 6 379000 Measuring & Reg Station Equip-City Gat 6,271,156 0 6,271,156 1,933,238 0 1,933,238 4,337,918 0 4,337,918 6 380000 Service 186,602,117 0 186,602,117 127,047,228 0 127,047,228 59,554,889 0 59,554,889 6 381000 Meter 70,732,546 0 70,732,546 47,776,809 0 47,776,809 22,955,737 0 22,955,737 6 382000 Meter Installation 0 0 0 0 0 0 0 0 0 6 383000 House Regulator 0 0 0 0 0 0 0 0 0 6 384000 House Regulator Installation 0 0 0 0 0 0 0 0 0 6 385000 Industrial Measuring & Reg Sta Equi 3,320,815 0 3,320,815 2,575,612 0 2,575,612 745,203 0 745,203 6 387000 Other Equipmen 0 0 0 0 0 0 0 0 0 TOTAL DISTRIBUTION PLAN 544,001,287 2,639,621 546,640,908 358,805,092 1,807,137 360,612,229 185,196,195 832,484 186,028,679 GENERAL PLANT 4 389XXX Land & Land Rights 681,998 1,269,469 1,951,467 589,062 920,352 1,509,414 92,936 349,117 442,053 4 390XXX Structures & Improvement 4,965,781 17,819,505 22,785,286 3,738,902 12,918,963 16,657,865 1,226,879 4,900,542 6,127,421 4 391XXX Office Furniture & Equipmen 27,114 12,125,206 12,152,320 8,197 8,790,653 8,798,850 18,917 3,334,553 3,353,470 4 392XXX Transportation Equipmen 9,464,635 1,980,283 11,444,918 7,063,015 1,435,685 8,498,700 2,401,620 544,598 2,946,218 4 393000 Stores Equipmen 151,287 610,033 761,320 114,151 442,268 556,419 37,136 167,765 204,901 4 394000 Tools, Shop & Garage Equipmen 2,559,475 4,168,993 6,728,468 1,982,075 3,022,478 5,004,553 577,400 1,146,515 1,723,915 4 395000 Laboratory Equipmen 39,214 395,643 434,857 29,575 286,837 316,412 9,639 108,806 118,445 4 396XXX Power Operated Equipmen 3,843,949 1,109,517 4,953,466 2,858,524 804,389 3,662,913 985,425 305,128 1,290,553 4 397XXX Communications Equipmen 2,262,124 8,615,425 10,877,549 844,838 6,246,097 7,090,935 1,417,286 2,369,328 3,786,614 4 398000 Miscellaneous Equipmen 1,060 85,116 86,176 1,060 61,708 62,768 0 23,408 23,408 TOTAL GENERAL PLAN 23,996,637 48,179,190 72,175,827 17,229,399 34,929,430 52,158,829 6,767,238 13,249,760 20,016,998 TOTAL PLANT IN SERVICE 569,293,021 118,022,594 687,315,615 377,057,085 84,789,239 461,846,324 192,235,936 33,233,355 225,469,291 ************* IDAHO ************************* SYSTEM ********************** WASHINGTON ******** Page 1 of 2 Print Date-Time: 2/18/2016 9:49 AM RESULTS OF OPERATIONS Report ID: AVISTA UTILITIE GAS UTILITY PLANT G-PLT-12A For Twelve Months Ended December 31, 201 Average of Monthly Averages Basi Ref/Basis Accoun Descriptio Direc Allocate Tota Direc Allocate Tota Direc Allocate Tota ************* IDAHO ************************* SYSTEM ********************** WASHINGTON ******** ACCUMULATED DEPRECIATION G-ADEP Underground Storag 0 (13,778,484) (13,778,484) 0 (9,735,877) (9,735,877) 0 (4,042,607) (4,042,607) G-ADEP Distribution Plan (181,960,013) (1,535,620) (183,495,633) (120,571,631) (1,051,316) (121,622,947) (61,388,382) (484,304) (61,872,686) G-ADEP General Plan (7,815,676) (13,754,088) (21,569,764) (5,139,581) (9,971,576) (15,111,157) (2,676,095) (3,782,512) (6,458,607) TOTAL ACCUMULATED DEPRECIATION (189,775,689) (29,068,192) (218,843,881) (125,711,212) (20,758,769) (146,469,981) (64,064,477) (8,309,423) (72,373,900) ACCUMULATED AMORTIZATION G-AAM General Plant - 30300 (182,346) (215,853) (398,199) (129,135) (156,491) (285,626) (53,211) (59,362) (112,573) G-AAM Misc IT Intangible Plant - 3031X (5,378) (7,319,597) (7,324,975) 0 (5,306,634) (5,306,634) (5,378) (2,012,963) (2,018,341) G-AAM Underground Storag 0 (239,973) (239,973) 0 (169,565) (169,565) 0 (70,408) (70,408) G-AAM General Plant - 390200, 39620 (4,598) (45,528) (50,126) (3,634) (33,007) (36,641) (964) (12,521) (13,485) TOTAL ACCUMULATED AMORTIZATIO (192,322) (7,820,951) (8,013,273) (132,769) (5,665,697) (5,798,466) (59,553) (2,155,254) (2,214,807) TOTAL ACCUMULATED DEPR/AMORT (189,968,011) (36,889,143) (226,857,154) (125,843,981) (26,424,466) (152,268,447) (64,124,030) (10,464,677) (74,588,707) NET GAS UTILITY PLANT before DFI 379,325,010 81,133,451 460,458,461 251,213,104 58,364,773 309,577,877 128,111,906 22,768,678 150,880,584 ACCUMULATED DFIT 12 282900 ADFIT - Gas Plant In Servic 0 (81,418,381) (81,418,381) 0 (54,740,020) (54,740,020) 0 (26,678,361) (26,678,361) 4, 12 282900 ADFIT - Common Plant (282900 from C-DTX 0 (13,250,758) (13,250,758) 0 (9,599,990) (9,599,990) 0 (3,650,768) (3,650,768) 4 283750 ADFIT - Common Plant (283750 from C-DTX 0 (107,919) (107,919) 0 (78,240) (78,240) 0 (29,679) (29,679) 12 283850 ADFIT - Gas portion of Bond Redemption 0 (960,494) (960,494) 0 (645,769) (645,769) 0 (314,725) (314,725) TOTAL ACCUMULATED DFIT 0 (95,737,552) (95,737,552) 0 (65,064,019) (65,064,019) 0 (30,673,533) (30,673,533) NET GAS UTILITY PLAN 379,325,010 (14,604,101) 364,720,909 251,213,104 (6,699,246) 244,513,858 128,111,906 (7,904,855) 120,207,051 ALLOCATION RATIOS: G-AL 1 System Contract Deman 100.000% 70.660% 29.340% G-AL 4 Jurisdictional 4-Factor Rati 100.000% 72.499% 27.501% G-AL 6 Actual Therms Purchase 100.000% 68.462% 31.538% G-AL 12 Net Gas Plant (before DFIT) - AM 100.000% 67.233% 32.767% Page 2 of 2 Print Date-Time: 2/18/2016 9:49 AM RESULTS OF OPERATIONS Report ID: AVISTA UTILITIES GAS OPERATING STATEMENT G-OPS-12A For Twelve Months Ended December 31, 2015 Average of Monthly Averages Basis Ref/Basis Accoun Description Direc Allocate Total Direc Allocate Total Direc Allocate Total REVENUES SALES OF GAS: 99 480000 Residential 139,845,052 0 139,845,052 98,613,917 0 98,613,917 41,231,135 0 41,231,135 99 4812XX Commercial - Firm & Interruptible 70,669,221 0 70,669,221 50,387,262 0 50,387,262 20,281,959 0 20,281,959 99 4813XX Industrial-Fir 3,352,195 0 3,352,195 1,980,198 0 1,980,198 1,371,997 0 1,371,997 99 481400 Interruptible 0 0 0 0 0 0 0 0 0 99 484000 Interdepartmental Revenue 267,952 0 267,952 232,617 0 232,617 35,335 0 35,335 99 499XXX Unbilled Revenue (4,624,197) 0 (4,624,197) (3,172,435) 0 (3,172,435) (1,451,762) 0 (1,451,762) TOTAL SALES TO ULTIMATE CUSTOMERS 209,510,223 0 209,510,223 148,041,559 0 148,041,559 61,468,664 0 61,468,664 OTHER OPERATING REVENUES: 99 483XXX Sales for Resale 133,356,919 0 133,356,919 89,432,389 0 89,432,389 43,924,530 0 43,924,530 4 488000 Miscellaneous Service Revenues 12,502 0 12,502 6,610 0 6,610 5,892 0 5,892 99 4893XX Transportation Revenues 4,600,031 0 4,600,031 4,160,109 0 4,160,109 439,922 0 439,922 99 493000 Rent from Gas Propert 2,445 0 2,445 2,445 0 2,445 0 0 0 4 495XXX Other Gas Revenues 10,556,746 211,737 10,768,483 9,087,083 153,507 9,240,590 1,469,663 58,230 1,527,893 99 496100 Provision for Rate Refun 0 0 0 0 0 0 0 0 0 TOTAL OTHER OPERATING REVENUES 148,528,643 211,737 148,740,380 102,688,636 153,507 102,842,143 45,840,007 58,230 45,898,237 TOTAL GAS REVENUES 358,038,866 211,737 358,250,603 250,730,195 153,507 250,883,702 107,308,671 58,230 107,366,901 PRODUCTION EXPENSES: G-804 804/805 City Gate Purchases 219,933,395 0 219,933,395 149,313,631 0 149,313,631 70,619,764 0 70,619,764 99 808XXX Net Natural Gas Storage Transactions 14,409,617 0 14,409,617 10,548,217 0 10,548,217 3,861,400 0 3,861,400 99 811000 Gas Used for Products Extraction (311,148) 0 (311,148) (210,718) 0 (210,718) (100,430) 0 (100,430) 10 813000 Other Gas Expenses 0 1,116,593 1,116,593 0 765,369 765,369 0 351,224 351,224 99 813010 Gas Technology Institute (GTI) Expenses 93,965 0 93,965 66,183 0 66,183 27,782 0 27,782 TOTAL PRODUCTION EXPENSES 234,125,829 1,116,593 235,242,422 159,717,313 765,369 160,482,682 74,408,516 351,224 74,759,740 UNDERGROUND STORAGE EXPENSES: 1 814000 Supervision & Engineering 0 13,588 13,588 0 9,601 9,601 0 3,987 3,987 1 824000 Other Expenses 0 612,321 612,321 0 432,666 432,666 0 179,655 179,655 1 837000 Other Equipmen 0 586,279 586,279 0 414,265 414,265 0 172,014 172,014 TOTAL UNDERGROUND STORAGE OPER EXP 0 1,212,188 1,212,188 0 856,532 856,532 0 355,656 355,656 G-DEPX Depreciation Expense-Underground Storage 0 621,734 621,734 0 439,317 439,317 0 182,417 182,417 G-AMTX Amortization Expense-Underground Storage 0 228 228 0 161 161 0 67 67 G-OTX Taxes Other Than FIT 0 315,900 315,900 0 223,215 223,215 0 92,685 92,685 TOTAL UG STORAGE DEPR/AMRT/NON-FIT TA 0 937,862 937,862 0 662,693 662,693 0 275,169 275,169 TOTAL UNDERGROUND STORAGE EXPENSES 0 2,150,050 2,150,050 0 1,519,225 1,519,225 0 630,825 630,825 ************ WASHINGTON *********** ************** IDAHO ****************************** SYSTEM ************** Page 1 of 5 Print Date-Time: 2/18/2016 9:48 AM RESULTS OF OPERATIONS Report ID: AVISTA UTILITIES GAS OPERATING STATEMENT G-OPS-12A For Twelve Months Ended December 31, 2015 Average of Monthly Averages Basis Ref/Basis Accoun Description Direc Allocate Total Direc Allocate Total Direc Allocate Total ************ WASHINGTON *********** ************** IDAHO ****************************** SYSTEM ************** DISTRIBUTION EXPENSES: OPERATION 3 870000 Supervision & Engineering 456,229 1,166,712 1,622,941 391,071 824,259 1,215,330 65,158 342,453 407,611 3 871000 Distribution Load Dispatching 0 0 0 0 0 0 0 0 0 3 874000 Mains & Services Expenses 3,309,728 799,462 4,109,190 2,614,460 564,804 3,179,264 695,268 234,658 929,926 3 875000 Measuring & Reg Sta Exp-General 115,792 0 115,792 76,111 0 76,111 39,681 0 39,681 3 876000 Measuring & Reg Sta Exp-Industrial 6,178 0 6,178 4,973 0 4,973 1,205 0 1,205 3 877000 Measuring & Reg Sta Exp-City Gate 126,414 0 126,414 54,160 0 54,160 72,254 0 72,254 3 878000 Meter & House Regulator Expenses 948,292 73,639 1,021,931 802,315 52,024 854,339 145,977 21,615 167,592 3 879000 Customer Installation Expenses 1,979,993 133,471 2,113,464 1,174,146 94,295 1,268,441 805,847 39,176 845,023 3 880000 Other Expenses 1,316,860 669,102 1,985,962 957,805 472,707 1,430,512 359,055 196,395 555,450 3 881000 Rents 5,136 35,826 40,962 5,136 25,310 30,446 0 10,516 10,516 MAINTENANCE 3 885000 Supervision & Engineering 104,216 0 104,216 48,599 0 48,599 55,617 0 55,617 3 887000 Mains 1,270,552 214 1,270,766 904,743 151 904,894 365,809 63 365,872 3 889000 Measuring & Reg Sta Exp-General 266,906 12,152 279,058 207,546 8,585 216,131 59,360 3,567 62,927 3 890000 Measuring & Reg Sta Exp-Industrial 227,722 127 227,849 133,909 90 133,999 93,813 37 93,850 3 891000 Measuring & Reg Sta Exp-City Gate 106,365 0 106,365 42,464 0 42,464 63,901 0 63,901 3 892000 Services 1,849,879 2,636 1,852,515 1,182,327 1,862 1,184,189 667,552 774 668,326 3 893000 Meters & House Regulators 1,528,938 731,933 2,260,871 1,021,952 517,096 1,539,048 506,986 214,837 721,823 3 894000 Other Equipmen 802 185,223 186,025 559 130,856 131,415 243 54,367 54,610 TOTAL DISTRIBUTION OPERATING EXP 13,620,002 3,810,497 17,430,499 9,622,276 2,692,039 12,314,315 3,997,726 1,118,458 5,116,184 G-DEPX Depreciation Expense-Distribution 13,618,478 64,599 13,683,077 9,049,726 44,226 9,093,952 4,568,752 20,373 4,589,125 G-OTX Taxes Other Than FIT 16,768,396 0 16,768,396 14,157,215 0 14,157,215 2,611,181 0 2,611,181 TOTAL DISTR DEPR/AMRT/NON-FIT TAXES 30,386,874 64,599 30,451,473 23,206,941 44,226 23,251,167 7,179,933 20,373 7,200,306 TOTAL DISTRIBUTION EXPENSES 44,006,876 3,875,096 47,881,972 32,829,217 2,736,265 35,565,482 11,177,659 1,138,831 12,316,490 Page 2 of 5 Print Date-Time: 2/18/2016 9:48 AM RESULTS OF OPERATIONS Report ID: AVISTA UTILITIES GAS OPERATING STATEMENT G-OPS-12A For Twelve Months Ended December 31, 2015 Average of Monthly Averages Basis Ref/Basis Accoun Description Direc Allocate Total Direc Allocate Total Direc Allocate Total ************ WASHINGTON *********** ************** IDAHO ****************************** SYSTEM ************** CUSTOMER ACCOUNTS EXPENSES: 2 901000 Supervision 0 222,797 222,797 0 147,719 147,719 0 75,078 75,078 2 902000 Meter Reading Expenses 1,812,119 114,885 1,927,004 1,624,427 76,171 1,700,598 187,692 38,714 226,406 G-903 903XXX Customer Records & Collection Expenses 657,008 4,761,063 5,418,071 440,329 3,156,680 3,597,009 216,679 1,604,383 1,821,062 2 904000 Uncollectible Accounts 0 1,902,041 1,902,041 0 1,261,091 1,261,091 0 640,950 640,950 2 905000 Misc Customer Accounts 0 164,886 164,886 0 109,323 109,323 0 55,563 55,563 TOTAL CUSTOMER ACCOUNTS EXPENSES 2,469,127 7,165,672 9,634,799 2,064,756 4,750,984 6,815,740 404,371 2,414,688 2,819,059 CUSTOMER SERVICE & INFO EXPENSES: G-908 908XXX Customer Assistance Expenses 5,842,343 204,844 6,047,187 5,773,832 135,816 5,909,648 68,511 69,028 137,539 2 909000 Advertising 0 539,942 539,942 0 357,992 357,992 0 181,950 181,950 2 910000 Misc Customer Service & Info Exp 0 66,990 66,990 0 44,416 44,416 0 22,574 22,574 TOTAL CUSTOMER SERVICE & INFO EXP 5,842,343 811,776 6,654,119 5,773,832 538,224 6,312,056 68,511 273,552 342,063 SALES EXPENSES: 2 912000 Demonstrating & Selling Expenses 0 0 0 0 0 0 0 0 0 2 913000 Advertising 0 0 0 0 0 0 0 0 0 2 916000 Miscellaneous Sales Expenses 0 0 0 0 0 0 0 0 0 TOTAL SALES EXPENSES 0 0 0 0 0 0 0 0 0 Page 3 of 5 Print Date-Time: 2/18/2016 9:48 AM RESULTS OF OPERATIONS Report ID: AVISTA UTILITIES GAS OPERATING STATEMENT G-OPS-12A For Twelve Months Ended December 31, 2015 Average of Monthly Averages Basis Ref/Basis Accoun Description Direc Allocate Total Direc Allocate Total Direc Allocate Total ************ WASHINGTON *********** ************** IDAHO ****************************** SYSTEM ************** ADMINISTRATIVE & GENERAL EXPENSES: 4 920000 Salaries 101,413 8,400,506 8,501,919 67,010 6,090,283 6,157,293 34,403 2,310,223 2,344,626 4 921000 Office Supplies & Expenses 2,925 1,114,441 1,117,366 2,925 807,959 810,884 0 306,482 306,482 4 922000 Admin. Expenses Transferred - Credi 0 (18,378) (18,378) 0 (13,324) (13,324) 0 (5,054) (5,054) 4 923000 Outside Services Employe 8,952 2,515,573 2,524,525 8,952 1,823,765 1,832,717 0 691,808 691,808 4 924000 Property Insurance Premiu 0 324,827 324,827 0 235,496 235,496 0 89,331 89,331 4 925XXX Injuries and Damages 6,094 939,613 945,707 6,051 681,210 687,261 43 258,403 258,446 4 926XXX Employee Pensions and Benefits 0 465,473 465,473 0 337,463 337,463 0 128,010 128,010 4 928000 Regulatory Commission Expenses 896,861 209,623 1,106,484 631,106 151,975 783,081 265,755 57,648 323,403 4 930000 Miscellaneous General Expenses 35,892 1,128,128 1,164,020 23,816 817,882 841,698 12,076 310,246 322,322 4 931000 Rents 8,659 256,542 265,201 8,659 185,990 194,649 0 70,552 70,552 4 935000 Maintenance of General Plan 357,873 2,371,747 2,729,620 265,550 1,719,493 1,985,043 92,323 652,254 744,577 TOTAL ADMIN & GEN OPERATING EXP 1,418,669 17,708,095 19,126,764 1,014,069 12,838,192 13,852,261 404,600 4,869,903 5,274,503 G-DEPX Depreciation Expense-General Plan 370,370 3,616,317 3,986,687 253,962 2,621,793 2,875,755 116,408 994,524 1,110,932 G-AMTX Amortization Expense - General Plant - 303000 30,281 119,007 149,288 24,862 86,279 111,141 5,419 32,728 38,147 G-AMTX Amortization Expense - Misc IT Intangible Plant - 303 2,768 3,666,016 3,668,784 0 2,657,825 2,657,825 2,768 1,008,191 1,010,959 G-AMTX Amortization Expense-General Plant - 390200, 396200 0 5,371 5,371 0 3,894 3,894 0 1,477 1,477 99 407025 WA GRC Jackson Prairie O&M Deferral 0 0 0 0 0 0 0 0 0 99 407229 Idaho Earnings Test Amortization (1,029,610) 0 (1,029,610) 0 0 0 (1,029,610) 0 (1,029,610) 99 407335 DSIT Amortization - ID 0 0 0 0 0 0 0 0 0 99 407425 WA GRC Jackson Prairie Deferral 0 0 0 0 0 0 0 0 0 99 407468 Project Compass Deferral - ID (672,542) 0 (672,542) 0 0 0 (672,542) 0 (672,542) TOTAL A&G DEPR/AMRT/NON-FIT TAXES (1,298,733) 7,406,711 6,107,978 278,824 5,369,791 5,648,615 (1,577,557) 2,036,920 459,363 TOTAL ADMIN & GENERAL EXPENSES 119,936 25,114,806 25,234,742 1,292,893 18,207,983 19,500,876 (1,172,957) 6,906,823 5,733,866 TOTAL EXPENSES BEFORE FIT 286,564,111 40,233,993 326,798,104 201,678,011 28,518,050 230,196,061 84,886,100 11,715,943 96,602,043 NET OPERATING INCOME (LOSS) BEFORE FIT 31,452,499 20,687,641 10,764,858 G-FIT FEDERAL INCOME TAX (2,389,625) (1,953,595) (436,030) G-FIT DEFERRED FEDERAL INCOME TAX 11,419,402 7,841,592 3,577,810 G-FIT AMORTIZED INVESTMENT TAX CREDIT (30,060) (19,884) (10,176) GAS NET OPERATING INCOME (LOSS) 22,452,782 14,819,528 7,633,254 Page 4 of 5 Print Date-Time: 2/18/2016 9:48 AM RESULTS OF OPERATIONS Report ID: AVISTA UTILITIES GAS OPERATING STATEMENT G-OPS-12A For Twelve Months Ended December 31, 2015 Average of Monthly Averages Basis Ref/Basis Accoun Description Direc Allocate Total Direc Allocate Total Direc Allocate Total ************ WASHINGTON *********** ************** IDAHO ****************************** SYSTEM ************** ALLOCATION RATIOS: G-ALL 1 System Contract Deman 100.000% 70.660% 29.340% G-ALL 2 Number of Customers - AMA 100.000% 66.302% 33.698% G-ALL 3 Direct Distribution Operating Expense 100.000% 70.648% 29.352% G-ALL 4 Jurisdictional 4-Factor Ratio 100.000% 72.499% 27.501% G-ALL 10 Actual Annual Throughpu 100.000% 68.545% 31.455% G-ALL 99 Not Allocate 0.000% 0.000% 0.000% Page 5 of 5 Print Date-Time: 2/18/2016 9:48 AM RESULTS OF OPERATIONS Report ID: AVISTA UTILITIES GAS OPERATING STATEMENT G-OPS-12A For Twelve Months Ended December 31, 2015 Average of Monthly Averages Basis Ref/Basis Accoun Description Direc Allocate Total Direc Allocate Total Direc Allocate Total REVENUES SALES OF GAS: 99 480000 Residential 139,845,052 0 139,845,052 98,613,917 0 98,613,917 41,231,135 0 41,231,135 99 4812XX Commercial - Firm & Interruptible 70,669,221 0 70,669,221 50,387,262 0 50,387,262 20,281,959 0 20,281,959 99 4813XX Industrial-Fir 3,352,195 0 3,352,195 1,980,198 0 1,980,198 1,371,997 0 1,371,997 99 481400 Interruptible 0 0 0 0 0 0 0 0 0 99 484000 Interdepartmental Revenue 267,952 0 267,952 232,617 0 232,617 35,335 0 35,335 99 499XXX Unbilled Revenue (4,624,197) 0 (4,624,197) (3,172,435) 0 (3,172,435) (1,451,762) 0 (1,451,762) TOTAL SALES TO ULTIMATE CUSTOMERS 209,510,223 0 209,510,223 148,041,559 0 148,041,559 61,468,664 0 61,468,664 OTHER OPERATING REVENUES: 99 483XXX Sales for Resale 133,356,919 0 133,356,919 89,432,389 0 89,432,389 43,924,530 0 43,924,530 4 488000 Miscellaneous Service Revenues 12,502 0 12,502 6,610 0 6,610 5,892 0 5,892 99 4893XX Transportation Revenues 4,600,031 0 4,600,031 4,160,109 0 4,160,109 439,922 0 439,922 99 493000 Rent from Gas Propert 2,445 0 2,445 2,445 0 2,445 0 0 0 4 495XXX Other Gas Revenues 10,556,746 211,737 10,768,483 9,087,083 153,507 9,240,590 1,469,663 58,230 1,527,893 99 496100 Provision for Rate Refun 0 0 0 0 0 0 0 0 0 TOTAL OTHER OPERATING REVENUES 148,528,643 211,737 148,740,380 102,688,636 153,507 102,842,143 45,840,007 58,230 45,898,237 TOTAL GAS REVENUES 358,038,866 211,737 358,250,603 250,730,195 153,507 250,883,702 107,308,671 58,230 107,366,901 PRODUCTION EXPENSES: G-804 804/805 City Gate Purchases 219,933,395 0 219,933,395 149,313,631 0 149,313,631 70,619,764 0 70,619,764 99 808XXX Net Natural Gas Storage Transactions 14,409,617 0 14,409,617 10,548,217 0 10,548,217 3,861,400 0 3,861,400 99 811000 Gas Used for Products Extraction (311,148) 0 (311,148) (210,718) 0 (210,718) (100,430) 0 (100,430) 10 813000 Other Gas Expenses 0 1,116,593 1,116,593 0 765,369 765,369 0 351,224 351,224 99 813010 Gas Technology Institute (GTI) Expenses 93,965 0 93,965 66,183 0 66,183 27,782 0 27,782 TOTAL PRODUCTION EXPENSES 234,125,829 1,116,593 235,242,422 159,717,313 765,369 160,482,682 74,408,516 351,224 74,759,740 UNDERGROUND STORAGE EXPENSES: 1 814000 Supervision & Engineering 0 13,588 13,588 0 9,601 9,601 0 3,987 3,987 1 824000 Other Expenses 0 612,321 612,321 0 432,666 432,666 0 179,655 179,655 1 837000 Other Equipmen 0 586,279 586,279 0 414,265 414,265 0 172,014 172,014 TOTAL UNDERGROUND STORAGE OPER EXP 0 1,212,188 1,212,188 0 856,532 856,532 0 355,656 355,656 G-DEPX Depreciation Expense-Underground Storage 0 621,734 621,734 0 439,317 439,317 0 182,417 182,417 G-AMTX Amortization Expense-Underground Storage 0 228 228 0 161 161 0 67 67 G-OTX Taxes Other Than FIT 0 315,900 315,900 0 223,215 223,215 0 92,685 92,685 TOTAL UG STORAGE DEPR/AMRT/NON-FIT TA 0 937,862 937,862 0 662,693 662,693 0 275,169 275,169 TOTAL UNDERGROUND STORAGE EXPENSES 0 2,150,050 2,150,050 0 1,519,225 1,519,225 0 630,825 630,825 ************ WASHINGTON *********** ************** IDAHO ****************************** SYSTEM ************** Page 1 of 5 Print Date-Time: 2/18/2016 9:48 AM RESULTS OF OPERATIONS Report ID: AVISTA UTILITIES GAS OPERATING STATEMENT G-OPS-12A For Twelve Months Ended December 31, 2015 Average of Monthly Averages Basis Ref/Basis Accoun Description Direc Allocate Total Direc Allocate Total Direc Allocate Total ************ WASHINGTON *********** ************** IDAHO ****************************** SYSTEM ************** DISTRIBUTION EXPENSES: OPERATION 3 870000 Supervision & Engineering 456,229 1,166,712 1,622,941 391,071 824,259 1,215,330 65,158 342,453 407,611 3 871000 Distribution Load Dispatching 0 0 0 0 0 0 0 0 0 3 874000 Mains & Services Expenses 3,309,728 799,462 4,109,190 2,614,460 564,804 3,179,264 695,268 234,658 929,926 3 875000 Measuring & Reg Sta Exp-General 115,792 0 115,792 76,111 0 76,111 39,681 0 39,681 3 876000 Measuring & Reg Sta Exp-Industrial 6,178 0 6,178 4,973 0 4,973 1,205 0 1,205 3 877000 Measuring & Reg Sta Exp-City Gate 126,414 0 126,414 54,160 0 54,160 72,254 0 72,254 3 878000 Meter & House Regulator Expenses 948,292 73,639 1,021,931 802,315 52,024 854,339 145,977 21,615 167,592 3 879000 Customer Installation Expenses 1,979,993 133,471 2,113,464 1,174,146 94,295 1,268,441 805,847 39,176 845,023 3 880000 Other Expenses 1,316,860 669,102 1,985,962 957,805 472,707 1,430,512 359,055 196,395 555,450 3 881000 Rents 5,136 35,826 40,962 5,136 25,310 30,446 0 10,516 10,516 MAINTENANCE 3 885000 Supervision & Engineering 104,216 0 104,216 48,599 0 48,599 55,617 0 55,617 3 887000 Mains 1,270,552 214 1,270,766 904,743 151 904,894 365,809 63 365,872 3 889000 Measuring & Reg Sta Exp-General 266,906 12,152 279,058 207,546 8,585 216,131 59,360 3,567 62,927 3 890000 Measuring & Reg Sta Exp-Industrial 227,722 127 227,849 133,909 90 133,999 93,813 37 93,850 3 891000 Measuring & Reg Sta Exp-City Gate 106,365 0 106,365 42,464 0 42,464 63,901 0 63,901 3 892000 Services 1,849,879 2,636 1,852,515 1,182,327 1,862 1,184,189 667,552 774 668,326 3 893000 Meters & House Regulators 1,528,938 731,933 2,260,871 1,021,952 517,096 1,539,048 506,986 214,837 721,823 3 894000 Other Equipmen 802 185,223 186,025 559 130,856 131,415 243 54,367 54,610 TOTAL DISTRIBUTION OPERATING EXP 13,620,002 3,810,497 17,430,499 9,622,276 2,692,039 12,314,315 3,997,726 1,118,458 5,116,184 G-DEPX Depreciation Expense-Distribution 13,618,478 64,599 13,683,077 9,049,726 44,226 9,093,952 4,568,752 20,373 4,589,125 G-OTX Taxes Other Than FIT 16,768,396 0 16,768,396 14,157,215 0 14,157,215 2,611,181 0 2,611,181 TOTAL DISTR DEPR/AMRT/NON-FIT TAXES 30,386,874 64,599 30,451,473 23,206,941 44,226 23,251,167 7,179,933 20,373 7,200,306 TOTAL DISTRIBUTION EXPENSES 44,006,876 3,875,096 47,881,972 32,829,217 2,736,265 35,565,482 11,177,659 1,138,831 12,316,490 Page 2 of 5 Print Date-Time: 2/18/2016 9:48 AM RESULTS OF OPERATIONS Report ID: AVISTA UTILITIES GAS OPERATING STATEMENT G-OPS-12A For Twelve Months Ended December 31, 2015 Average of Monthly Averages Basis Ref/Basis Accoun Description Direc Allocate Total Direc Allocate Total Direc Allocate Total ************ WASHINGTON *********** ************** IDAHO ****************************** SYSTEM ************** CUSTOMER ACCOUNTS EXPENSES: 2 901000 Supervision 0 222,797 222,797 0 147,719 147,719 0 75,078 75,078 2 902000 Meter Reading Expenses 1,812,119 114,885 1,927,004 1,624,427 76,171 1,700,598 187,692 38,714 226,406 G-903 903XXX Customer Records & Collection Expenses 657,008 4,761,063 5,418,071 440,329 3,156,680 3,597,009 216,679 1,604,383 1,821,062 2 904000 Uncollectible Accounts 0 1,902,041 1,902,041 0 1,261,091 1,261,091 0 640,950 640,950 2 905000 Misc Customer Accounts 0 164,886 164,886 0 109,323 109,323 0 55,563 55,563 TOTAL CUSTOMER ACCOUNTS EXPENSES 2,469,127 7,165,672 9,634,799 2,064,756 4,750,984 6,815,740 404,371 2,414,688 2,819,059 CUSTOMER SERVICE & INFO EXPENSES: G-908 908XXX Customer Assistance Expenses 5,842,343 204,844 6,047,187 5,773,832 135,816 5,909,648 68,511 69,028 137,539 2 909000 Advertising 0 539,942 539,942 0 357,992 357,992 0 181,950 181,950 2 910000 Misc Customer Service & Info Exp 0 66,990 66,990 0 44,416 44,416 0 22,574 22,574 TOTAL CUSTOMER SERVICE & INFO EXP 5,842,343 811,776 6,654,119 5,773,832 538,224 6,312,056 68,511 273,552 342,063 SALES EXPENSES: 2 912000 Demonstrating & Selling Expenses 0 0 0 0 0 0 0 0 0 2 913000 Advertising 0 0 0 0 0 0 0 0 0 2 916000 Miscellaneous Sales Expenses 0 0 0 0 0 0 0 0 0 TOTAL SALES EXPENSES 0 0 0 0 0 0 0 0 0 Page 3 of 5 Print Date-Time: 2/18/2016 9:48 AM RESULTS OF OPERATIONS Report ID: AVISTA UTILITIES GAS OPERATING STATEMENT G-OPS-12A For Twelve Months Ended December 31, 2015 Average of Monthly Averages Basis Ref/Basis Accoun Description Direc Allocate Total Direc Allocate Total Direc Allocate Total ************ WASHINGTON *********** ************** IDAHO ****************************** SYSTEM ************** ADMINISTRATIVE & GENERAL EXPENSES: 4 920000 Salaries 101,413 8,400,506 8,501,919 67,010 6,090,283 6,157,293 34,403 2,310,223 2,344,626 4 921000 Office Supplies & Expenses 2,925 1,114,441 1,117,366 2,925 807,959 810,884 0 306,482 306,482 4 922000 Admin. Expenses Transferred - Credi 0 (18,378) (18,378) 0 (13,324) (13,324) 0 (5,054) (5,054) 4 923000 Outside Services Employe 8,952 2,515,573 2,524,525 8,952 1,823,765 1,832,717 0 691,808 691,808 4 924000 Property Insurance Premiu 0 324,827 324,827 0 235,496 235,496 0 89,331 89,331 4 925XXX Injuries and Damages 6,094 939,613 945,707 6,051 681,210 687,261 43 258,403 258,446 4 926XXX Employee Pensions and Benefits 0 465,473 465,473 0 337,463 337,463 0 128,010 128,010 4 928000 Regulatory Commission Expenses 896,861 209,623 1,106,484 631,106 151,975 783,081 265,755 57,648 323,403 4 930000 Miscellaneous General Expenses 35,892 1,128,128 1,164,020 23,816 817,882 841,698 12,076 310,246 322,322 4 931000 Rents 8,659 256,542 265,201 8,659 185,990 194,649 0 70,552 70,552 4 935000 Maintenance of General Plan 357,873 2,371,747 2,729,620 265,550 1,719,493 1,985,043 92,323 652,254 744,577 TOTAL ADMIN & GEN OPERATING EXP 1,418,669 17,708,095 19,126,764 1,014,069 12,838,192 13,852,261 404,600 4,869,903 5,274,503 G-DEPX Depreciation Expense-General Plan 370,370 3,616,317 3,986,687 253,962 2,621,793 2,875,755 116,408 994,524 1,110,932 G-AMTX Amortization Expense - General Plant - 303000 30,281 119,007 149,288 24,862 86,279 111,141 5,419 32,728 38,147 G-AMTX Amortization Expense - Misc IT Intangible Plant - 303 2,768 3,666,016 3,668,784 0 2,657,825 2,657,825 2,768 1,008,191 1,010,959 G-AMTX Amortization Expense-General Plant - 390200, 396200 0 5,371 5,371 0 3,894 3,894 0 1,477 1,477 99 407025 WA GRC Jackson Prairie O&M Deferral 0 0 0 0 0 0 0 0 0 99 407229 Idaho Earnings Test Amortization (1,029,610) 0 (1,029,610) 0 0 0 (1,029,610) 0 (1,029,610) 99 407335 DSIT Amortization - ID 0 0 0 0 0 0 0 0 0 99 407425 WA GRC Jackson Prairie Deferral 0 0 0 0 0 0 0 0 0 99 407468 Project Compass Deferral - ID (672,542) 0 (672,542) 0 0 0 (672,542) 0 (672,542) TOTAL A&G DEPR/AMRT/NON-FIT TAXES (1,298,733) 7,406,711 6,107,978 278,824 5,369,791 5,648,615 (1,577,557) 2,036,920 459,363 TOTAL ADMIN & GENERAL EXPENSES 119,936 25,114,806 25,234,742 1,292,893 18,207,983 19,500,876 (1,172,957) 6,906,823 5,733,866 TOTAL EXPENSES BEFORE FIT 286,564,111 40,233,993 326,798,104 201,678,011 28,518,050 230,196,061 84,886,100 11,715,943 96,602,043 NET OPERATING INCOME (LOSS) BEFORE FIT 31,452,499 20,687,641 10,764,858 G-FIT FEDERAL INCOME TAX (2,389,625) (1,953,595) (436,030) G-FIT DEFERRED FEDERAL INCOME TAX 11,419,402 7,841,592 3,577,810 G-FIT AMORTIZED INVESTMENT TAX CREDIT (30,060) (19,884) (10,176) GAS NET OPERATING INCOME (LOSS) 22,452,782 14,819,528 7,633,254 Page 4 of 5 Print Date-Time: 2/18/2016 9:48 AM RESULTS OF OPERATIONS Report ID: AVISTA UTILITIES GAS OPERATING STATEMENT G-OPS-12A For Twelve Months Ended December 31, 2015 Average of Monthly Averages Basis Ref/Basis Accoun Description Direc Allocate Total Direc Allocate Total Direc Allocate Total ************ WASHINGTON *********** ************** IDAHO ****************************** SYSTEM ************** ALLOCATION RATIOS: G-ALL 1 System Contract Deman 100.000% 70.660% 29.340% G-ALL 2 Number of Customers - AMA 100.000% 66.302% 33.698% G-ALL 3 Direct Distribution Operating Expense 100.000% 70.648% 29.352% G-ALL 4 Jurisdictional 4-Factor Ratio 100.000% 72.499% 27.501% G-ALL 10 Actual Annual Throughpu 100.000% 68.545% 31.455% G-ALL 99 Not Allocate 0.000% 0.000% 0.000% Page 5 of 5 Print Date-Time: 2/18/2016 9:48 AM Home > Regulated Industries > Utilities > Energy > Customer Deposit Interest Rates Customer Deposit Interest Rates LAWS AND RULES Utilities General - Tariffs and Contracts - WAC 480-80 Water Companies - WAC 480-110 Telecom Companies - WAC 480-120 Electric Companies - WAC 480-100 Gas Companies - WAC 480-90 Solid Waste Companies - WAC 480-70 Commission rules set the customer deposit interest rate at the level of the one-year Treasury Constant Maturity, as calculated by the U.S. Treasury and published in the Federal Reserve's Statistical Release H.15. Telephone and Water Companies As of Jan. 1, the interest rate that telephone and water companies must pay on the deposits they hold for their customers is .15 percent. For each calendar year, telephone and water company rules use the rate as of Nov. 15 of the previous year. Because Nov. 15, 2014, was Saturday, the rate used is the rate of the next business day, Nov. 17, 2014. Gas, Electric and Solid Waste Companies As of Jan. 1, the interest rate that gas, electric, and solid waste companies must pay on the deposits they hold for their customers is .16 percent. Gas, electric, and solid waste company rules use the rate as of Jan. 15. The 2015 rate was determined as of Jan. 15. Documents Page 1 of 1Customer Deposit Interest Rates 11 11 201http://www.utc.wa.gov/regulatedindustries/utilities/energy/pages/customerdepositinterest ... Home > Regulated Industries > Utilities > Energy > Customer Deposit Interest Rates Customer Deposit Interest Rates LAWS AND RULES Utilities General - Tariffs and Contracts - WAC 480-80 Water Companies - WAC 480-110 Telecom Companies - WAC 480-120 Electric Companies - WAC 480-100 Gas Companies - WAC 480-90 Solid Waste Companies - WAC 480-70 Commission rules set the customer deposit interest rate at the level of the one-year Treasury Constant Maturity, as calculated by the U.S. Treasury and published in the Federal Reserve's Statistical Release H.15. Telephone and Water Companies As of Jan. 1, the interest rate that telephone and water companies must pay on the deposits they hold for their customers is .15 percent. For each calendar year, telephone and water company rules use the rate as of Nov. 15 of the previous year. Because Nov. 15, 2014, was Saturday, the rate used is the rate of the next business day, Nov. 17, 2014. Gas, Electric and Solid Waste Companies As of Jan. 1, the interest rate that gas, electric, and solid waste companies must pay on the deposits they hold for their customers is .16 percent. Gas, electric, and solid waste company rules use the rate as of Jan. 15. The 2015 rate was determined as of Jan. 15. Documents Page 1 of 1Customer Deposit Interest Rates 11 11 201http://www.utc.wa.gov/regulatedindustries/utilities/energy/pages/customerdepositinterest ... Miscellaneous Restating Adjustment Non-Utility Removals Miscellaneous Restating Adjustment Service/Jurisdiction Reclassifications Miscellaneous Restating Adjustment Retro Union Pay Miscellaneous Restating Adjustment Plane Reclassification Miscellaneous Restating Adjustment BOD Meeting Expenses Miscellaneous Restating Adjustment Non-Utility Removals Miscellaneous Restating Adjustment Service/Jurisdiction Reclassifications Miscellaneous Restating Adjustment Retro Union Pay Miscellaneous Restating Adjustment Plane Reclassification Miscellaneous Restating Adjustment BOD Meeting Expenses Miscellaneous Restating Adjustment Non-Utility Removals Miscellaneous Restating Adjustment Service/Jurisdiction Reclassifications Miscellaneous Restating Adjustment Retro Union Pay Miscellaneous Restating Adjustment Plane Reclassification Miscellaneous Restating Adjustment BOD Meeting Expenses Miscellaneous Restating Adjustment Non-Utility Removals Miscellaneous Restating Adjustment Service/Jurisdiction Reclassifications Miscellaneous Restating Adjustment Retro Union Pay Miscellaneous Restating Adjustment Plane Reclassification Miscellaneous Restating Adjustment BOD Meeting Expenses Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 03/21/2016 CASE NO: UE-160228 & UG-160229 WITNESS: N/A REQUESTER: NW Industrial Gas Users’ RESPONDER: Paul Kimball TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: NWIGU – 001 TELEPHONE: (509) 495-4584 EMAIL: paul.kimball@avistacorp.com REQUEST: Please provide a copy of Avista Corporation’s responses to data requests from all other parties. RESPONSE: Avista has not responded to any data requests at this time, but Avista will provide copies of data requests, along with corresponding data responses, from all parties to this proceeding as they are received. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 03/21/2016 CASE NO: UE-160228 & UG-160229 WITNESS: N/A REQUESTER: NW Industrial Gas Users’ RESPONDER: Paul Kimball TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: NWIGU – 001 TELEPHONE: (509) 495-4584 EMAIL: paul.kimball@avistacorp.com REQUEST: Please provide a copy of Avista Corporation’s responses to data requests from all other parties. RESPONSE: Avista has not responded to any data requests at this time, but Avista will provide copies of data requests, along with corresponding data responses, from all parties to this proceeding as they are received. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/14/2016 CASE NO: UE-160228 & UG-160229 WITNESS: Joseph Miller REQUESTER: NWIGU RESPONDER: Joe Miller TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: NWIGU – 2.1 TELEPHONE: (509) 495-4546 EMAIL: joe.miller@avistacorp.com REQUEST: At page 10, lines 21-23 of his direct testimony, Exhibit No. ___(JDM-1T), he states the following: Other system facilities that serve all customers are classified by the peak and average ratio that reflects the system load factor, then allocated by coincident peak demand and throughput, respectively. Please provide the following information for the instant proceeding on an electronic spreadsheet with all formulas intact: a. Describe all system facilities that are allocated by the average and peak allocation factor. Include a list of all FERC plant and expense accounts allocated by the average and peak factor in your response. b. For each rate class, provide its respective peak allocation factor, average allocation factor, and average and peak allocation factor. c. For each rate class, provide its coincident peak day demand and average day demand. d. Identify the system load factor and system coincident peak day demand. RESPONSE: a. Please see Exhibit No. JDM-2, pages 7-9. b. Please see the workpaper labeled JDM-G-108 for a complete listing of all allocation factors. The peak allocation factors are derived from the demand study which can be found in the workpapers beginning on page JDM-G-64. c. Please see the attachment labeled “NWIGU_DR_2.1 Attachment A”. d. Please see the attachment labeled “NWIGU_DR_2.1 Attachment A” or the workpaper labeled JDM- G-64. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/14/2016 CASE NO: UE-160228 & UG-160229 WITNESS: Joseph Miller REQUESTER: NWIGU RESPONDER: Joe Miller TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: NWIGU – 2.1 TELEPHONE: (509) 495-4546 EMAIL: joe.miller@avistacorp.com REQUEST: At page 10, lines 21-23 of his direct testimony, Exhibit No. ___(JDM-1T), he states the following: Other system facilities that serve all customers are classified by the peak and average ratio that reflects the system load factor, then allocated by coincident peak demand and throughput, respectively. Please provide the following information for the instant proceeding on an electronic spreadsheet with all formulas intact: a. Describe all system facilities that are allocated by the average and peak allocation factor. Include a list of all FERC plant and expense accounts allocated by the average and peak factor in your response. b. For each rate class, provide its respective peak allocation factor, average allocation factor, and average and peak allocation factor. c. For each rate class, provide its coincident peak day demand and average day demand. d. Identify the system load factor and system coincident peak day demand. RESPONSE: a. Please see Exhibit No. JDM-2, pages 7-9. b. Please see the workpaper labeled JDM-G-108 for a complete listing of all allocation factors. The peak allocation factors are derived from the demand study which can be found in the workpapers beginning on page JDM-G-64. c. Please see the attachment labeled “NWIGU_DR_2.1 Attachment A”. d. Please see the attachment labeled “NWIGU_DR_2.1 Attachment A” or the workpaper labeled JDM- G-64. Page 1 of 2 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/14/2016 CASE NO: UE-160228 & UG-160229 WITNESS: Joseph Miller/Jody Morehouse REQUESTER: NWIGU RESPONDER: Tom Pardee/Eric Scott TYPE: Data Request DEPT: Gas Supply REQUEST NO.: NWIGU – 2.2 TELEPHONE: 509-495-2159/509-495-4001 EMAIL: tom.pardee@avistacorp.com eric.scott@avistacorp.com REQUEST: Please provide Mr. Miller’s understanding of how Avista designs the transmission capacity of its system. Specifically, please answer the following: a. Does Mr. Miller agree that the transmission capacity has to be adequate to meet customers’ firm peak day coincident demands for gas in order for those customers to receive firm service every day of the year including the peak day? Please explain your answer. b. Does Mr. Miller agree that if the Company designed its transmission capacity on its system to meet average day demand, then the Company’s transmission system capacity would not have adequate capacity to provide service to customers on the coincident peak day demand? Please explain your answer. c. Does Mr. Miller agree that if transmission main capacity entitlements to customers are based on their contribution to coincident peak day demand, then they will have the right to use that much capacity every day of the year including the day of the coincident peak demand? Please explain your answer. RESPONSE: As stated in the Company’s IRP in greater detail (Exhibit JM-2, p. 70) Avista has contracted for a sufficient amount of diversified firm pipeline capacity (i.e., transmission capacity) from various receipt and delivery points (including delivery from storage facilities) so that firm deliveries to Avista’s distribution system will meet peak day demand. We believe the combination of firm transportation rights to our service territory, storage facilities, and access to liquid supply basins will ensure peak supplies are available to our core customers. Non-core customers, i.e., those customers served on Schedules 146 and 148, contract for their own interstate pipeline transportation. Once non-core customer natural gas is delivered to Avista’s distribution system, that natural gas is then considered to be firm natural gas1. Only then is Schedule 131/132 natural gas considered to be interruptible or non-firm, and the Company does not include that load in its design day requirements. a. Yes. Avista contracts for firm transportation rights and designs its natural gas systems to meet the peak day needs of its firm customers. This includes its distribution system and also the upstream 1 All costs associated with commodity and interstate pipeline capacity are tracked through the Purchased Gas Cost Adjustment (PGA) mechanism and are not recovered in base rates. Page 2 of 2 supply resources for those customers under tariffs in which gas supply is inclusive (i.e., Schedule 150). b. If Avista contracted for firm transportation rights and designed its distribution system to meet only the needs of an average day demand, the system would not be sufficient to provide firm service to its customers in the event of a peak day. c. Entitlements are not based on customer’s contribution to peak day demand. Should an event arise where Avista determines it cannot meet all firm service requirements on its distribution system, it may issue an entitlement, curtailment, or interruption in accordance with the approved “Contingency Plan for Firm Service Gas Curtailment” tariff (Schedule 182). As it relates to entitlements that may occur on an interstate pipeline, all shippers on that pipeline may be subject to entitlements based on the shippers confirmed nominations and actual flows for that day. It is not based upon a customer’s contribution to the peak day demand on the distribution system. Page 1 of 2 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/14/2016 CASE NO: UE-160228 & UG-160229 WITNESS: Joseph Miller/Jody Morehouse REQUESTER: NWIGU RESPONDER: Tom Pardee/Eric Scott TYPE: Data Request DEPT: Gas Supply REQUEST NO.: NWIGU – 2.2 TELEPHONE: 509-495-2159/509-495-4001 EMAIL: tom.pardee@avistacorp.com eric.scott@avistacorp.com REQUEST: Please provide Mr. Miller’s understanding of how Avista designs the transmission capacity of its system. Specifically, please answer the following: a. Does Mr. Miller agree that the transmission capacity has to be adequate to meet customers’ firm peak day coincident demands for gas in order for those customers to receive firm service every day of the year including the peak day? Please explain your answer. b. Does Mr. Miller agree that if the Company designed its transmission capacity on its system to meet average day demand, then the Company’s transmission system capacity would not have adequate capacity to provide service to customers on the coincident peak day demand? Please explain your answer. c. Does Mr. Miller agree that if transmission main capacity entitlements to customers are based on their contribution to coincident peak day demand, then they will have the right to use that much capacity every day of the year including the day of the coincident peak demand? Please explain your answer. RESPONSE: As stated in the Company’s IRP in greater detail (Exhibit JM-2, p. 70) Avista has contracted for a sufficient amount of diversified firm pipeline capacity (i.e., transmission capacity) from various receipt and delivery points (including delivery from storage facilities) so that firm deliveries to Avista’s distribution system will meet peak day demand. We believe the combination of firm transportation rights to our service territory, storage facilities, and access to liquid supply basins will ensure peak supplies are available to our core customers. Non-core customers, i.e., those customers served on Schedules 146 and 148, contract for their own interstate pipeline transportation. Once non-core customer natural gas is delivered to Avista’s distribution system, that natural gas is then considered to be firm natural gas1. Only then is Schedule 131/132 natural gas considered to be interruptible or non-firm, and the Company does not include that load in its design day requirements. a. Yes. Avista contracts for firm transportation rights and designs its natural gas systems to meet the peak day needs of its firm customers. This includes its distribution system and also the upstream 1 All costs associated with commodity and interstate pipeline capacity are tracked through the Purchased Gas Cost Adjustment (PGA) mechanism and are not recovered in base rates. Page 2 of 2 supply resources for those customers under tariffs in which gas supply is inclusive (i.e., Schedule 150). b. If Avista contracted for firm transportation rights and designed its distribution system to meet only the needs of an average day demand, the system would not be sufficient to provide firm service to its customers in the event of a peak day. c. Entitlements are not based on customer’s contribution to peak day demand. Should an event arise where Avista determines it cannot meet all firm service requirements on its distribution system, it may issue an entitlement, curtailment, or interruption in accordance with the approved “Contingency Plan for Firm Service Gas Curtailment” tariff (Schedule 182). As it relates to entitlements that may occur on an interstate pipeline, all shippers on that pipeline may be subject to entitlements based on the shippers confirmed nominations and actual flows for that day. It is not based upon a customer’s contribution to the peak day demand on the distribution system. Page 1 of 2 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/14/2016 CASE NO: UE-160228 & UG-160229 WITNESS: Joseph Miller REQUESTER: NWIGU RESPONDER: Terrence Browne TYPE: Data Request DEPT: Gas Engineering REQUEST NO.: NWIGU – 2.3 TELEPHONE: (509) 495-8551 EMAIL: Terrence.browne@avistacorp.com REQUEST: With regard to the direct testimony of Joseph D. Miller, please provide Mr. Miller’s understanding of Avista’s distribution main system planning by specifically answering the following questions: a. Does Mr. Miller agree that the distribution main capacity must be designed to meet the demands of the group of customers that take service on the distribution loop? Please explain your answer. b. Does Mr. Miller agree that the length of pipe necessary to connect all customers to the system is dependent on the number of customers and location of customers on the distribution loop? Please explain your answer. c. Does Mr. Miller agree that there is a minimum size pipe that Avista uses in order to provide safe and reliable gas service to its distribution customers? Please explain your answer. d. Does Mr. Miller agree that Avista will use its minimum size pipe, rather than a smaller pipe, if the demand on a specific distribution loop could be served from a pipe smaller than Avista’s designed minimum size pipe? Please explain your answer. e. Does Mr. Miller agree that, from an administrative and economies of scale basis, the minimum pipe size design in the distribution system helps to minimize the cost of distribution service? Please explain your answer. RESPONSE: A. The distribution main capacity is designed to meet at least all customer demands along the “downstream path” of the main. The “downstream path” may include one or many mains that dead-end, or loop back into other mains. In addition to customer demand, the distribution main capacity may be designed to include future or anticipated customer demand along the “downstream path” B. The length of pipe is determined by customer location, but “independent” of number of customers. It is the size of pipe that is dependent on the number of customers and their location. The length of pipe is the same whether the demand at the end is from one customer or several. The size of the pipe, however, will be determined based on the number of customers and their location. If the concentration of customer load is located at the end of the main, the main may have to be larger in order to maintain enough pressure to move the gas farther down the main. Page 2 of 2 C. Avista’s choice of main sizes are 2”, 4”, 6”, 8”, 10”, and occasionally 12”. Avista’s minimum size of main is calculated using SynerGEE 7.0 distribution modeling tool. If demand is minimal, Avista will install 2”, which represents our minimum main size1. D. Yes. Please see the response to part (C) above. E. Yes. Economies of scale may be achieved by having a more limited inventory maintained by the Company. The Company otherwise does not have to maintain an extensive inventory of differing pipe sizes which can help to minimize the cost of distribution service. By installing the smallest size main to accommodate current and anticipated demand, Avista mitigates the need to replace/upsize mains in the future. 1 In most instances, the smallest main sizes (1/2 & 3/4 inch) are service pipe that were later converted to main due to additional customers. Page 1 of 2 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/14/2016 CASE NO: UE-160228 & UG-160229 WITNESS: Joseph Miller REQUESTER: NWIGU RESPONDER: Terrence Browne TYPE: Data Request DEPT: Gas Engineering REQUEST NO.: NWIGU – 2.3 TELEPHONE: (509) 495-8551 EMAIL: Terrence.browne@avistacorp.com REQUEST: With regard to the direct testimony of Joseph D. Miller, please provide Mr. Miller’s understanding of Avista’s distribution main system planning by specifically answering the following questions: a. Does Mr. Miller agree that the distribution main capacity must be designed to meet the demands of the group of customers that take service on the distribution loop? Please explain your answer. b. Does Mr. Miller agree that the length of pipe necessary to connect all customers to the system is dependent on the number of customers and location of customers on the distribution loop? Please explain your answer. c. Does Mr. Miller agree that there is a minimum size pipe that Avista uses in order to provide safe and reliable gas service to its distribution customers? Please explain your answer. d. Does Mr. Miller agree that Avista will use its minimum size pipe, rather than a smaller pipe, if the demand on a specific distribution loop could be served from a pipe smaller than Avista’s designed minimum size pipe? Please explain your answer. e. Does Mr. Miller agree that, from an administrative and economies of scale basis, the minimum pipe size design in the distribution system helps to minimize the cost of distribution service? Please explain your answer. RESPONSE: A. The distribution main capacity is designed to meet at least all customer demands along the “downstream path” of the main. The “downstream path” may include one or many mains that dead-end, or loop back into other mains. In addition to customer demand, the distribution main capacity may be designed to include future or anticipated customer demand along the “downstream path” B. The length of pipe is determined by customer location, but “independent” of number of customers. It is the size of pipe that is dependent on the number of customers and their location. The length of pipe is the same whether the demand at the end is from one customer or several. The size of the pipe, however, will be determined based on the number of customers and their location. If the concentration of customer load is located at the end of the main, the main may have to be larger in order to maintain enough pressure to move the gas farther down the main. Page 2 of 2 C. Avista’s choice of main sizes are 2”, 4”, 6”, 8”, 10”, and occasionally 12”. Avista’s minimum size of main is calculated using SynerGEE 7.0 distribution modeling tool. If demand is minimal, Avista will install 2”, which represents our minimum main size1. D. Yes. Please see the response to part (C) above. E. Yes. Economies of scale may be achieved by having a more limited inventory maintained by the Company. The Company otherwise does not have to maintain an extensive inventory of differing pipe sizes which can help to minimize the cost of distribution service. By installing the smallest size main to accommodate current and anticipated demand, Avista mitigates the need to replace/upsize mains in the future. 1 In most instances, the smallest main sizes (1/2 & 3/4 inch) are service pipe that were later converted to main due to additional customers. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/14/2016 CASE NO: UE-160228 & UG-160229 WITNESS: Joseph Miller REQUESTER: NWIGU RESPONDER: Joe Miller TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: NWIGU – 2.4 TELEPHONE: (509) 495-4546 EMAIL: joe.miller@avistacorp.com REQUEST: At page 10, lines 19-20 of his direct testimony, Exhibit No. ___(JDM-1T), Mr. Miller states that natural gas commodity-related main investment has been segregated into large, medium, and small mains. Please explain how the Company has segregated its mains into large, medium and small components and list what main sizes are included in each component. RESPONSE: Please refer to Exhibit No. ___(JDM-1T), page 11 - 18, which describes the Company’s rationale for segregating mains into large, medium and small components as well as the main sizes included in each component. In addition, please refer to the workpaper labeled JDM-G-52. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/14/2016 CASE NO: UE-160228 & UG-160229 WITNESS: Joseph Miller REQUESTER: NWIGU RESPONDER: Joe Miller TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: NWIGU – 2.4 TELEPHONE: (509) 495-4546 EMAIL: joe.miller@avistacorp.com REQUEST: At page 10, lines 19-20 of his direct testimony, Exhibit No. ___(JDM-1T), Mr. Miller states that natural gas commodity-related main investment has been segregated into large, medium, and small mains. Please explain how the Company has segregated its mains into large, medium and small components and list what main sizes are included in each component. RESPONSE: Please refer to Exhibit No. ___(JDM-1T), page 11 - 18, which describes the Company’s rationale for segregating mains into large, medium and small components as well as the main sizes included in each component. In addition, please refer to the workpaper labeled JDM-G-52. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/14/2016 CASE NO: UE-160228 & UG-160229 WITNESS: Joseph Miller REQUESTER: NWIGU RESPONDER: Terrence Browne TYPE: Data Request DEPT: Gas Engineering REQUEST NO.: NWIGU – 2.5 TELEPHONE: (509) 495-8551 EMAIL: Terrence.browne@avistacorp.com REQUEST: Please identify by rate schedule the number of customers served by each size of main during the test year. RESPONSE: The Company has not conducted such analysis and therefore is unable to provide the requested information. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/14/2016 CASE NO: UE-160228 & UG-160229 WITNESS: Joseph Miller REQUESTER: NWIGU RESPONDER: Terrence Browne TYPE: Data Request DEPT: Gas Engineering REQUEST NO.: NWIGU – 2.5 TELEPHONE: (509) 495-8551 EMAIL: Terrence.browne@avistacorp.com REQUEST: Please identify by rate schedule the number of customers served by each size of main during the test year. RESPONSE: The Company has not conducted such analysis and therefore is unable to provide the requested information. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/14/2016 CASE NO: UE-160228 & UG-160229 WITNESS: Joseph Miller REQUESTER: NWIGU RESPONDER: Joe Miller TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: NWIGU – 2.6 TELEPHONE: (509) 495-4546 EMAIL: joe.miller@avistacorp.com REQUEST: At page 12, lines 18-20 of his direct testimony, Exhibit No. ___(JDM-1T), Mr. Miller explains that “Large usage customers that take service from small mains have their associated throughput and coincident peak demand assigned to the small main allocation factors.” Please describe how these customers take service from the Company and what size distribution mains they utilize in taking service from the Company. RESPONSE: Please see the attachment labeled “NWIGU_DR_2.6 Attachment A” which details by large customer, the size and type of distribution main. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/14/2016 CASE NO: UE-160228 & UG-160229 WITNESS: Joseph Miller REQUESTER: NWIGU RESPONDER: Joe Miller TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: NWIGU – 2.6 TELEPHONE: (509) 495-4546 EMAIL: joe.miller@avistacorp.com REQUEST: At page 12, lines 18-20 of his direct testimony, Exhibit No. ___(JDM-1T), Mr. Miller explains that “Large usage customers that take service from small mains have their associated throughput and coincident peak demand assigned to the small main allocation factors.” Please describe how these customers take service from the Company and what size distribution mains they utilize in taking service from the Company. RESPONSE: Please see the attachment labeled “NWIGU_DR_2.6 Attachment A” which details by large customer, the size and type of distribution main. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/14/2016 CASE NO: UE-160228 & UG-160229 WITNESS: Joseph Miller REQUESTER: NWIGU RESPONDER: Joe Miller TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: NWIGU – 2.7 TELEPHONE: (509) 495-4546 EMAIL: joe.miller@avistacorp.com REQUEST: Please identify the number of large usage customers referenced in NWIGU 1.6 by rate schedule who take service from small mains. RESPONSE: As described in direct testimony, Exhibit No.___(JDM-1T), page 12, line 6, small main is defined as being less than two inches. Based on the Company’s definition of small main, there are no large usage customers who take service from small mains. All large customers (Schedules 131/132 and 146) are excluded from the commodity related portion (throughput) of small main. See the Company’s response to NWIGU – 2.6 for a detailed customer listing of the specific size of distribution main each large customer takes service from. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/14/2016 CASE NO: UE-160228 & UG-160229 WITNESS: Joseph Miller REQUESTER: NWIGU RESPONDER: Joe Miller TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: NWIGU – 2.7 TELEPHONE: (509) 495-4546 EMAIL: joe.miller@avistacorp.com REQUEST: Please identify the number of large usage customers referenced in NWIGU 1.6 by rate schedule who take service from small mains. RESPONSE: As described in direct testimony, Exhibit No.___(JDM-1T), page 12, line 6, small main is defined as being less than two inches. Based on the Company’s definition of small main, there are no large usage customers who take service from small mains. All large customers (Schedules 131/132 and 146) are excluded from the commodity related portion (throughput) of small main. See the Company’s response to NWIGU – 2.6 for a detailed customer listing of the specific size of distribution main each large customer takes service from. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/14/2016 CASE NO: UE-160228 & UG-160229 WITNESS: Joseph Miller REQUESTER: NWIGU RESPONDER: Joe Miller TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: NWIGU – 2.8 TELEPHONE: (509) 495-4546 EMAIL: joe.miller@avistacorp.com REQUEST: At page 12, lines 1-4 of his direct testimony, Exhibit No. ____(JDM-1T), Mr. Miller explains that the demand related allocation of mains does not attempt to separate distribution main based on pipe size. Please explain the Company’s rationale for this methodology. RESPONSE: The portion of main investment classified as demand related is allocated to all rate schedules on the basis of each schedule’s contribution to the system peak demand. As was described in testimony, all pipes, regardless of size, create capacity on the system. In particular, on a peak day, the capacity created by all sizes of pipe would be utilized in order to serve the peak demands of all customers and therefore the Company believes it would be inappropriate to attempt to separate distribution main based on pipe size for the peak demand allocation. The purpose of the peak demand allocation under the peak and average approach is to reflect cost causation based on the way the system is designed, which is to meet peak demand. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/14/2016 CASE NO: UE-160228 & UG-160229 WITNESS: Joseph Miller REQUESTER: NWIGU RESPONDER: Joe Miller TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: NWIGU – 2.8 TELEPHONE: (509) 495-4546 EMAIL: joe.miller@avistacorp.com REQUEST: At page 12, lines 1-4 of his direct testimony, Exhibit No. ____(JDM-1T), Mr. Miller explains that the demand related allocation of mains does not attempt to separate distribution main based on pipe size. Please explain the Company’s rationale for this methodology. RESPONSE: The portion of main investment classified as demand related is allocated to all rate schedules on the basis of each schedule’s contribution to the system peak demand. As was described in testimony, all pipes, regardless of size, create capacity on the system. In particular, on a peak day, the capacity created by all sizes of pipe would be utilized in order to serve the peak demands of all customers and therefore the Company believes it would be inappropriate to attempt to separate distribution main based on pipe size for the peak demand allocation. The purpose of the peak demand allocation under the peak and average approach is to reflect cost causation based on the way the system is designed, which is to meet peak demand. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/14/2016 CASE NO: UE-160228 & UG-160229 WITNESS: Joseph Miller REQUESTER: NWIGU RESPONDER: Terrence Browne TYPE: Data Request DEPT: Gas Engineering REQUEST NO.: NWIGU – 2.9 TELEPHONE: (509) 495-8551 EMAIL: Terrence.browne@avistacorp.com REQUEST: Please provide the following information: a. The minimum gas distribution main size of the Avista system. b. The gas distribution main size most representative of the Avista system. c. Total length in feet of each gas distribution main size on the Avista system. d. Total length in feet of the gas distribution main system. e. Cost per foot (material and non-material) to install each gas distribution main size in part c. above. f. The plant accounting cost for each gas distribution main size in part c. above. RESPONSE: a. Please refer to Company witness Miller’s workpaper labeled JDM-G-53 for a complete listing of main segregated by size and type. In most instances, the smallest main sizes (1/2 & 3/4 inch) are service pipe that were later converted to main due to additional customers. Avista’s current practice for installing minimum size main is to install 2” pipe, which represents the minimum size main under current standards. b. 2 inch main is the most representative of Avista’s system. c. Please refer to the workpaper labeled JDM-G-53. d. Please refer to the workpaper labeled JDM-G-53. e. The cost per foot can vary from $10 to $175, based on pipe material (steel or plastic), size, terrain (soil, rocky, sandy, etc), the method of installation (plow, trench, underground bore), and customer participation (may provide all or partial ditch). Other variables can affect cost as well. The lowest cost for the most common size (2”, 4”, 6”) main extensions are: 2” = $10/ft, 4” = 13$/ft, and 6” = $20/ft. These costs are most reflective of plastic pipe operating at distribution pressure less than 60 psig, installed in soil. Refer to the workpaper labeled JDM-G-54 for the 2015 average cost per foot of installed distribution main. f. Please refer to the attachment labeled “NWIGU_DR_2.9 Attachment A” which details the plant accounting cost for all distribution main by vintage year. Please note that the Company does not track distribution main by size and is therefore unable to provide the costs at the requested level of detail. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/14/2016 CASE NO: UE-160228 & UG-160229 WITNESS: Joseph Miller REQUESTER: NWIGU RESPONDER: Terrence Browne TYPE: Data Request DEPT: Gas Engineering REQUEST NO.: NWIGU – 2.9 TELEPHONE: (509) 495-8551 EMAIL: Terrence.browne@avistacorp.com REQUEST: Please provide the following information: a. The minimum gas distribution main size of the Avista system. b. The gas distribution main size most representative of the Avista system. c. Total length in feet of each gas distribution main size on the Avista system. d. Total length in feet of the gas distribution main system. e. Cost per foot (material and non-material) to install each gas distribution main size in part c. above. f. The plant accounting cost for each gas distribution main size in part c. above. RESPONSE: a. Please refer to Company witness Miller’s workpaper labeled JDM-G-53 for a complete listing of main segregated by size and type. In most instances, the smallest main sizes (1/2 & 3/4 inch) are service pipe that were later converted to main due to additional customers. Avista’s current practice for installing minimum size main is to install 2” pipe, which represents the minimum size main under current standards. b. 2 inch main is the most representative of Avista’s system. c. Please refer to the workpaper labeled JDM-G-53. d. Please refer to the workpaper labeled JDM-G-53. e. The cost per foot can vary from $10 to $175, based on pipe material (steel or plastic), size, terrain (soil, rocky, sandy, etc), the method of installation (plow, trench, underground bore), and customer participation (may provide all or partial ditch). Other variables can affect cost as well. The lowest cost for the most common size (2”, 4”, 6”) main extensions are: 2” = $10/ft, 4” = 13$/ft, and 6” = $20/ft. These costs are most reflective of plastic pipe operating at distribution pressure less than 60 psig, installed in soil. Refer to the workpaper labeled JDM-G-54 for the 2015 average cost per foot of installed distribution main. f. Please refer to the attachment labeled “NWIGU_DR_2.9 Attachment A” which details the plant accounting cost for all distribution main by vintage year. Please note that the Company does not track distribution main by size and is therefore unable to provide the costs at the requested level of detail. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/14/2016 CASE NO: UE-160228 & UG-160229 WITNESS: Joseph Miller REQUESTER: NWIGU RESPONDER: Terrence Browne TYPE: Data Request DEPT: Gas Engineering REQUEST NO.: NWIGU – 2.10 TELEPHONE: (509) 495-8551 EMAIL: Terrence.browne@avistacorp.com REQUEST: With respect to Mr. Miller’s direct testimony at page 13, lines 10-17, please provide the following information: a. Identify all instances on the Avista system where the capacity of a 2-inch main is used to supply gas to a main that is 4 inches or larger under normal operating conditions. b. Please explain how a customer served by a main 4 inches or larger causes the Company to invest in a 2-inch main capacity on the Avista system. c. Is the capacity available on the Company’s 2-inch main system adequate to serve the peak day demand of all customers presently served by mains 4 inches and larger? Please explain your answer. d. What is the normal operating pressure of the Company’s 2-inch system of mains? e. What is the maximum pressure the Company can safely operate its system of 2 inch mains? f. At what pressure would the Company have to operate its system of 2-inch mains in order to meet the peak day demand of its system via only its system of 2-inch mains? RESPONSE: a. The Company has not conducted such analysis and is therefore unable to provide the requested information. b. In a complex, heavily networked and connected system, it is quite likely that a 4” main could be fed from a 2”. In this same network, flow direction can change day to day, even hour to hour depending upon customer usage. This means that a 4” could be flowing into a 2” one day and vice versa the next. c. If we replace all 4” pipe with 2”, we would not have the capacity needed to serve the peak day demand of all customers. d. The majority of 2” main (not all) operates at a Maximum Allowable Operating Pressure (MAOP) of 60 psig. e. The pressure of each system cannot be higher than the system’s MAOP (Maximum Allowable Operating Pressure). There are several different system MAOPs that exist throughout Washington. f. The Company has not conducted such analysis and is therefore unable to provide the requested information. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/14/2016 CASE NO: UE-160228 & UG-160229 WITNESS: Joseph Miller REQUESTER: NWIGU RESPONDER: Terrence Browne TYPE: Data Request DEPT: Gas Engineering REQUEST NO.: NWIGU – 2.10 TELEPHONE: (509) 495-8551 EMAIL: Terrence.browne@avistacorp.com REQUEST: With respect to Mr. Miller’s direct testimony at page 13, lines 10-17, please provide the following information: a. Identify all instances on the Avista system where the capacity of a 2-inch main is used to supply gas to a main that is 4 inches or larger under normal operating conditions. b. Please explain how a customer served by a main 4 inches or larger causes the Company to invest in a 2-inch main capacity on the Avista system. c. Is the capacity available on the Company’s 2-inch main system adequate to serve the peak day demand of all customers presently served by mains 4 inches and larger? Please explain your answer. d. What is the normal operating pressure of the Company’s 2-inch system of mains? e. What is the maximum pressure the Company can safely operate its system of 2 inch mains? f. At what pressure would the Company have to operate its system of 2-inch mains in order to meet the peak day demand of its system via only its system of 2-inch mains? RESPONSE: a. The Company has not conducted such analysis and is therefore unable to provide the requested information. b. In a complex, heavily networked and connected system, it is quite likely that a 4” main could be fed from a 2”. In this same network, flow direction can change day to day, even hour to hour depending upon customer usage. This means that a 4” could be flowing into a 2” one day and vice versa the next. c. If we replace all 4” pipe with 2”, we would not have the capacity needed to serve the peak day demand of all customers. d. The majority of 2” main (not all) operates at a Maximum Allowable Operating Pressure (MAOP) of 60 psig. e. The pressure of each system cannot be higher than the system’s MAOP (Maximum Allowable Operating Pressure). There are several different system MAOPs that exist throughout Washington. f. The Company has not conducted such analysis and is therefore unable to provide the requested information. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/10/2016 CASE NO: UE-160228 & UG-160229 WITNESS: Patrick Ehrbar REQUESTER: NW Industrial Gas Users’ RESPONDER: Patrick Ehrbar TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: NWIGU – 2.11 TELEPHONE: (509) 495-8620 EMAIL: pat.ehrbar@avistacorp.com REQUEST: Please describe how Schedule 132 – Interruptible Service – allows for greater utilization of the Company’s transmission capacity relative to the transmission system’s design day capacity. RESPONSE: As it relates to interstate pipeline capacity (where the costs associated with pipeline capacity are tracked through the Purchased Gas Cost Adjustment mechanism), Avista plans its system to support firm customer needs based on a peak day weather event as set forth in the Integrated Resource Plan. Under normal weather conditions, there is unutilized capacity which the Company will optimize for the benefit of customers (i.e., purchase gas at one basin and sell at a different basin utilizing unused pipeline capacity at a higher price). Interruptible service offers the opportunity to utilize this capacity, to ensure that firm customers will have access to the capacity on a peak day. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/10/2016 CASE NO: UE-160228 & UG-160229 WITNESS: Patrick Ehrbar REQUESTER: NW Industrial Gas Users’ RESPONDER: Patrick Ehrbar TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: NWIGU – 2.11 TELEPHONE: (509) 495-8620 EMAIL: pat.ehrbar@avistacorp.com REQUEST: Please describe how Schedule 132 – Interruptible Service – allows for greater utilization of the Company’s transmission capacity relative to the transmission system’s design day capacity. RESPONSE: As it relates to interstate pipeline capacity (where the costs associated with pipeline capacity are tracked through the Purchased Gas Cost Adjustment mechanism), Avista plans its system to support firm customer needs based on a peak day weather event as set forth in the Integrated Resource Plan. Under normal weather conditions, there is unutilized capacity which the Company will optimize for the benefit of customers (i.e., purchase gas at one basin and sell at a different basin utilizing unused pipeline capacity at a higher price). Interruptible service offers the opportunity to utilize this capacity, to ensure that firm customers will have access to the capacity on a peak day. Page 1 of 2 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/15/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Elizabeth Andrews REQUESTER: NW Industrial Gas Users RESPONDER: Tara Knox/Annette Brandon TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: NWIGU – 2.12 TELEPHONE: (509) 495-4325/4324 EMAIL: tara.knox@avistacorp.com annette.brandon@avistacorp.com REQUEST: Concerning Ms. Andrews’ Exhibit No. ___(EMA-3), page 4, line 3, Other Revenues, please provide the following: a. A breakout of all the sources of “Other Revenues” including rider adjustments, Sales for Resale, and other sources. b. Expenses related to each source of Other Revenues. c. Please describe the Company’s Sales for Resale business function and identify how the gas cost and revenue are established in Sales for Resale transactions. d. Concerning Sales for Resale transactions, please identify the amount of margin (revenue less gas cost) Avista has earned on Sales for Resale over the last five years. Show the annual Sales for Resale margin during this period. RESPONSE: a. There are two values for Other Revenues on page 4, line 3 of Exhibit__(EMA-3). The value in column [A] of $5,696,000 is adjusted in column [C] resulting in the 2017 proposed amount of $283,000 shown in columns [E], [H], and [K]. The following table shows the requested breakout of the column [A] value notating the items eliminated in column [C]. Description Column [A] value Notes 488000 Miscellaneous Service Revenue $7,633 returned check charges, after hours connect charges, disconnect charges, etc. 493000 Rent From Gas Property 495000 Other Gas Revenue - Misc sale of scrap materials 495328 Residential Decoupling Deferred Revenue $4,494,120 Eliminated in column [C] Pro Forma revenue adj Page 2 of 2 495328 Non-Residential Decoupling Deferred Revenue $918,892 Eliminated in column [C] Pro Forma revenue adj Total b. The Company does not separately identify specific expenses associated with these items. c. The Company purchases natural gas for its distribution customers in wholesale markets at multiple supply basins in the western United States and western Canada. Purchased natural gas can be transported through six inter-connected pipelines on which Avista holds firm contractual transportation rights. These contracts provide access to both US and Canadian- sourced natural gas supply. In addition, the Company is a 1/3 owner of the Jackson Prairie Storage facility located in Chehalis Washington. Currently, Avista owns a total of 8,528,013 Dth of firm working gas. Washington/Idaho customers are allocated approximately 7,700,000 Dth of this capacity. This diverse makeup of transportation and storage resources provides an opportunity for the Company to optimize these resources, to the extent they are not required to serve load. Each day, the Natural Gas Department forecasts the amount of gas required to serve load for the following day. To the extent there is unutilized capacity on the pipeline the Company will “optimize” this resource provided favorable economic conditions exist. For instance, we may purchase at AECO at one price, transport via Gas Transmission Northwest Pipeline, and sell at Malin or Kingsgate for a higher price thereby locking in that benefit for customers. Sales for Resale transactions (purchases and sales) are primarily allocated based on actual load for each day, taking into account pipeline resource availability. Storage optimization purchases and sales are allocated 90% Washington/Idaho and 10% Oregon based on currently contracted working capacity. Sales for Resale is part of the Company’s annual Purchase Gas Adjustment and is not included in the current General Rate Case. Sales for Resale are consolidated with natural gas purchase gas costs and removed in the pro-forma revenue adjustment. Please see Miller testimony (JDM-1T) beginning on page 6. d. The majority of sales for resale transactions are part of an overall purchase/sale transaction which combines the result of all transactions on a given day. The Company typically does not directly tie an individual purchase to an individual sale due to the inherent flow dynamics of the pipeline. Therefore, we do not track the margin by deal or by individual jurisdiction. However, the overall benefit of the optimization is captured in the deferral process and passed back to customers via the amortization mechanism within the Purchase Gas Adjustment filing. Page 1 of 2 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/15/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Elizabeth Andrews REQUESTER: NW Industrial Gas Users RESPONDER: Tara Knox/Annette Brandon TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: NWIGU – 2.12 TELEPHONE: (509) 495-4325/4324 EMAIL: tara.knox@avistacorp.com annette.brandon@avistacorp.com REQUEST: Concerning Ms. Andrews’ Exhibit No. ___(EMA-3), page 4, line 3, Other Revenues, please provide the following: a. A breakout of all the sources of “Other Revenues” including rider adjustments, Sales for Resale, and other sources. b. Expenses related to each source of Other Revenues. c. Please describe the Company’s Sales for Resale business function and identify how the gas cost and revenue are established in Sales for Resale transactions. d. Concerning Sales for Resale transactions, please identify the amount of margin (revenue less gas cost) Avista has earned on Sales for Resale over the last five years. Show the annual Sales for Resale margin during this period. RESPONSE: a. There are two values for Other Revenues on page 4, line 3 of Exhibit__(EMA-3). The value in column [A] of $5,696,000 is adjusted in column [C] resulting in the 2017 proposed amount of $283,000 shown in columns [E], [H], and [K]. The following table shows the requested breakout of the column [A] value notating the items eliminated in column [C]. Description Column [A] value Notes 488000 Miscellaneous Service Revenue $7,633 returned check charges, after hours connect charges, disconnect charges, etc. 493000 Rent From Gas Property 495000 Other Gas Revenue - Misc sale of scrap materials 495328 Residential Decoupling Deferred Revenue $4,494,120 Eliminated in column [C] Pro Forma revenue adj Page 2 of 2 495328 Non-Residential Decoupling Deferred Revenue $918,892 Eliminated in column [C] Pro Forma revenue adj Total b. The Company does not separately identify specific expenses associated with these items. c. The Company purchases natural gas for its distribution customers in wholesale markets at multiple supply basins in the western United States and western Canada. Purchased natural gas can be transported through six inter-connected pipelines on which Avista holds firm contractual transportation rights. These contracts provide access to both US and Canadian- sourced natural gas supply. In addition, the Company is a 1/3 owner of the Jackson Prairie Storage facility located in Chehalis Washington. Currently, Avista owns a total of 8,528,013 Dth of firm working gas. Washington/Idaho customers are allocated approximately 7,700,000 Dth of this capacity. This diverse makeup of transportation and storage resources provides an opportunity for the Company to optimize these resources, to the extent they are not required to serve load. Each day, the Natural Gas Department forecasts the amount of gas required to serve load for the following day. To the extent there is unutilized capacity on the pipeline the Company will “optimize” this resource provided favorable economic conditions exist. For instance, we may purchase at AECO at one price, transport via Gas Transmission Northwest Pipeline, and sell at Malin or Kingsgate for a higher price thereby locking in that benefit for customers. Sales for Resale transactions (purchases and sales) are primarily allocated based on actual load for each day, taking into account pipeline resource availability. Storage optimization purchases and sales are allocated 90% Washington/Idaho and 10% Oregon based on currently contracted working capacity. Sales for Resale is part of the Company’s annual Purchase Gas Adjustment and is not included in the current General Rate Case. Sales for Resale are consolidated with natural gas purchase gas costs and removed in the pro-forma revenue adjustment. Please see Miller testimony (JDM-1T) beginning on page 6. d. The majority of sales for resale transactions are part of an overall purchase/sale transaction which combines the result of all transactions on a given day. The Company typically does not directly tie an individual purchase to an individual sale due to the inherent flow dynamics of the pipeline. Therefore, we do not track the margin by deal or by individual jurisdiction. However, the overall benefit of the optimization is captured in the deferral process and passed back to customers via the amortization mechanism within the Purchase Gas Adjustment filing. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/14/2016 CASE NO: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: NWIGU RESPONDER: Joe Miller TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: NWIGU – 2.13 TELEPHONE: (509) 495-4546 EMAIL: joe.miller@avistacorp.com REQUEST: Concerning Ms. Andrews’ and Mr. Miller’s development of jurisdictional gas utility revenues, operating expenses, and rate base, please provide a complete worksheet showing total Avista Gas Operations’ cost of service, and jurisdictional allocation factors used to separate Washington Retail’s cost of service between all of Avista’s retail and wholesale jurisdictions. Please provide this work paper on an electronic spreadsheet with all formulae intact. RESPONSE: Please refer to the previously provided electronic workpapers for Company witness Smith under the folder labeled “Results of Operations” and the specific file labeled “12A-2015.09_Avista Gas North Pull”. For the development of the jurisdictional allocators refer to the Smith electronic workpaper folder labeled “Allocation Factors”. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/14/2016 CASE NO: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: NWIGU RESPONDER: Joe Miller TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: NWIGU – 2.13 TELEPHONE: (509) 495-4546 EMAIL: joe.miller@avistacorp.com REQUEST: Concerning Ms. Andrews’ and Mr. Miller’s development of jurisdictional gas utility revenues, operating expenses, and rate base, please provide a complete worksheet showing total Avista Gas Operations’ cost of service, and jurisdictional allocation factors used to separate Washington Retail’s cost of service between all of Avista’s retail and wholesale jurisdictions. Please provide this work paper on an electronic spreadsheet with all formulae intact. RESPONSE: Please refer to the previously provided electronic workpapers for Company witness Smith under the folder labeled “Results of Operations” and the specific file labeled “12A-2015.09_Avista Gas North Pull”. For the development of the jurisdictional allocators refer to the Smith electronic workpaper folder labeled “Allocation Factors”. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/10/2016 CASE NO: UE-160228 & UG-160229 WITNESS: Elizabeth Andrews REQUESTER: Public Counsel RESPONDER: Paul Kimball TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: PC – 001 TELEPHONE: (509) 495-4584 EMAIL: paul.kimball@avistacorp.com REQUEST: Please provide paper copies of your responses to all data requests for information from all parties in this action to: Simon J. ffitch Office of the Attorney General Public Counsel 800 Fifth Avenue #2000 Seattle, WA 98104-3188 Please provide electronic copies of all documents to Simon ffitch, simonf@atg.wa.gov, Lisa Gafken, lisa.gafken@atg.wa.gov, Mary Kimball, maryk2@atg.wa.gov, Stefanie Johnson, stefaniej@atg.wa.gov, Chanda Mak, chandam@atg.wa.gov and Kym Bostelle, kymh@atg.wa.gov. RESPONSE: Avista has provided and will continue to provide copies of data requests, along with corresponding data responses, from all parties to this proceeding as they are completed. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/10/2016 CASE NO: UE-160228 & UG-160229 WITNESS: Elizabeth Andrews REQUESTER: Public Counsel RESPONDER: Paul Kimball TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: PC – 001 TELEPHONE: (509) 495-4584 EMAIL: paul.kimball@avistacorp.com REQUEST: Please provide paper copies of your responses to all data requests for information from all parties in this action to: Simon J. ffitch Office of the Attorney General Public Counsel 800 Fifth Avenue #2000 Seattle, WA 98104-3188 Please provide electronic copies of all documents to Simon ffitch, simonf@atg.wa.gov, Lisa Gafken, lisa.gafken@atg.wa.gov, Mary Kimball, maryk2@atg.wa.gov, Stefanie Johnson, stefaniej@atg.wa.gov, Chanda Mak, chandam@atg.wa.gov and Kym Bostelle, kymh@atg.wa.gov. RESPONSE: Avista has provided and will continue to provide copies of data requests, along with corresponding data responses, from all parties to this proceeding as they are completed. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/08/2016 CASE NO: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: Public Counsel RESPONDER: Jeanne Pluth TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: PC – 002 TELEPHONE: (509) 495-2204 EMAIL: jeanne.pluth@avistacorp.com REQUEST: Please provide Avista total electric (all jurisdictions) per books year-end balance sheets and income statements for each year 2007 through 2015 by Federal Energy Regulatory Commission (FERC) account. In this response, provide in tabular format with FERC accounts for each row and individual years for each column. Please provide in hardcopy as well as executable electronic (Excel) format. RESPONSE: The Company does not maintain a balance sheet by service or jurisdiction. The balance sheet accounts by FERC account for December 31, 2007 – 2015 has been provided at PC_DR_002-Attachment A. Please see PC_DR_002-Attachment B for the electric and natural gas income statements for 2007- 2015. To provide the individual years in tabular format, the trial balance was used to generate these reports by service. The Results of Operations reports that present the income statements by service and jurisdiction that are used by the state commissions and are the basis for the Company’s Commission Basis Report and the test years in general rate cases may not agree to PC_DR_002- Attachment B. The Results of Operations reports may have been adjusted to remove material, non- recurring or out-of-period expenses. In addition, the Company computes federal income tax expense for the Results of Operations reports by using net income for each service/jurisdiction. The electric Results of Operations reports have been provided in Company’s response to PC_DR_003. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/08/2016 CASE NO: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: Public Counsel RESPONDER: Jeanne Pluth TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: PC – 002 TELEPHONE: (509) 495-2204 EMAIL: jeanne.pluth@avistacorp.com REQUEST: Please provide Avista total electric (all jurisdictions) per books year-end balance sheets and income statements for each year 2007 through 2015 by Federal Energy Regulatory Commission (FERC) account. In this response, provide in tabular format with FERC accounts for each row and individual years for each column. Please provide in hardcopy as well as executable electronic (Excel) format. RESPONSE: The Company does not maintain a balance sheet by service or jurisdiction. The balance sheet accounts by FERC account for December 31, 2007 – 2015 has been provided at PC_DR_002-Attachment A. Please see PC_DR_002-Attachment B for the electric and natural gas income statements for 2007- 2015. To provide the individual years in tabular format, the trial balance was used to generate these reports by service. The Results of Operations reports that present the income statements by service and jurisdiction that are used by the state commissions and are the basis for the Company’s Commission Basis Report and the test years in general rate cases may not agree to PC_DR_002- Attachment B. The Results of Operations reports may have been adjusted to remove material, non- recurring or out-of-period expenses. In addition, the Company computes federal income tax expense for the Results of Operations reports by using net income for each service/jurisdiction. The electric Results of Operations reports have been provided in Company’s response to PC_DR_003. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/08/2016 CASE NO: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: Public Counsel RESPONDER: Jeanne Pluth TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: PC – 003 TELEPHONE: (509) 495-2204 EMAIL: jeanne.pluth@avistacorp.com REQUEST: Please provide Avista Washington electric per books year-end balance sheets and income statements for each year 2007 through 2015 by Federal Energy Regulatory Commission (FERC) account. In this response, provide in tabular format with FERC accounts for each row and individual years for each column. Please provide in hardcopy as well as executable electronic (Excel) format. RESPONSE: As explained in the Company’s response to PC_DR_002, the Company does not maintain a balance sheet by service or jurisdiction. The balance sheet accounts by FERC account for December 31, 2007 – 2015 have been provided at PC_DR_002-Attachment A. The Company prepares Results of Operations (ROO) reports that provides an income statement by service and jurisdiction. Each month, 3 reports are prepared: 1) Electric (Washington and Idaho); 2) Gas North (Washington and Idaho) and 3) Gas South (Oregon). Each month’s report is saved in Excel format, so it is not possible to produce a Washington electric ROO report in tabular format for all of the years requested. Rather, the annual electric reports have been provided, as follows: Year Attachment Each excel spreadsheet for each year’s report has multiple tabs and pages, therefore, electronic files only have been provided. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/08/2016 CASE NO: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: Public Counsel RESPONDER: Jeanne Pluth TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: PC – 003 TELEPHONE: (509) 495-2204 EMAIL: jeanne.pluth@avistacorp.com REQUEST: Please provide Avista Washington electric per books year-end balance sheets and income statements for each year 2007 through 2015 by Federal Energy Regulatory Commission (FERC) account. In this response, provide in tabular format with FERC accounts for each row and individual years for each column. Please provide in hardcopy as well as executable electronic (Excel) format. RESPONSE: As explained in the Company’s response to PC_DR_002, the Company does not maintain a balance sheet by service or jurisdiction. The balance sheet accounts by FERC account for December 31, 2007 – 2015 have been provided at PC_DR_002-Attachment A. The Company prepares Results of Operations (ROO) reports that provides an income statement by service and jurisdiction. Each month, 3 reports are prepared: 1) Electric (Washington and Idaho); 2) Gas North (Washington and Idaho) and 3) Gas South (Oregon). Each month’s report is saved in Excel format, so it is not possible to produce a Washington electric ROO report in tabular format for all of the years requested. Rather, the annual electric reports have been provided, as follows: Year Attachment Each excel spreadsheet for each year’s report has multiple tabs and pages, therefore, electronic files only have been provided. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/08/2016 CASE NO: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: Public Counsel RESPONDER: Jeanne Pluth TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: PC – 004 TELEPHONE: (509) 495-2204 EMAIL: jeanne.pluth@avistacorp.com REQUEST: Please provide Avista total gas (all jurisdictions) per books year-end balance sheets and income statements for each year 2007 through 2015 by Federal Energy Regulatory Commission (FERC) account. In this response, provide in tabular format with FERC accounts for each row and individual years for each column. Please provide in hardcopy as well as executable electronic (Excel) format. RESPONSE: As explained in the Company’s response to PC_DR_002, the Company does not maintain a balance sheet by service or jurisdiction. The balance sheet accounts by FERC account for December 31, 2007 – 2015 has been provided at PC_DR_002-Attachment A. Please see the Company’s response to PC_DR_002-Attachment B for the electric and natural gas income statements for 2007-2015. To provide the individual years in tabular format, the trial balance was used to generate these reports by service. The Results of Operations reports that present the income statements by service and jurisdiction that are used by the state commissions and are the basis for the Company’s Commission Basis Report and the test years in general rate cases may not agree to PC_DR_002-Attachment B. The Results of Operations reports may have been adjusted to remove material, non-recurring or out-of-period expenses. In addition, the Company computes federal income tax expense for the Results of Operations reports by using net income for each service/jurisdiction. The natural gas Results of Operations reports have been provided in the Company’s response to PC_DR_005. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/08/2016 CASE NO: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: Public Counsel RESPONDER: Jeanne Pluth TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: PC – 004 TELEPHONE: (509) 495-2204 EMAIL: jeanne.pluth@avistacorp.com REQUEST: Please provide Avista total gas (all jurisdictions) per books year-end balance sheets and income statements for each year 2007 through 2015 by Federal Energy Regulatory Commission (FERC) account. In this response, provide in tabular format with FERC accounts for each row and individual years for each column. Please provide in hardcopy as well as executable electronic (Excel) format. RESPONSE: As explained in the Company’s response to PC_DR_002, the Company does not maintain a balance sheet by service or jurisdiction. The balance sheet accounts by FERC account for December 31, 2007 – 2015 has been provided at PC_DR_002-Attachment A. Please see the Company’s response to PC_DR_002-Attachment B for the electric and natural gas income statements for 2007-2015. To provide the individual years in tabular format, the trial balance was used to generate these reports by service. The Results of Operations reports that present the income statements by service and jurisdiction that are used by the state commissions and are the basis for the Company’s Commission Basis Report and the test years in general rate cases may not agree to PC_DR_002-Attachment B. The Results of Operations reports may have been adjusted to remove material, non-recurring or out-of-period expenses. In addition, the Company computes federal income tax expense for the Results of Operations reports by using net income for each service/jurisdiction. The natural gas Results of Operations reports have been provided in the Company’s response to PC_DR_005. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/08/2016 CASE NO: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: Public Counsel RESPONDER: Jeanne Pluth TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: PC – 005 TELEPHONE: (509) 495-2204 EMAIL: jeanne.pluth@avistacorp.com REQUEST: Please provide Avista Washington gas per books year-end balance sheets and income statements for each year 2007 through 2015 by Federal Energy Regulatory Commission (FERC) account. In this response, provide in tabular format with FERC accounts for each row and individual years for each column. Please provide in hardcopy as well as executable electronic (Excel) format. RESPONSE: As explained in the Company’s response to PC_DR_002, the Company does not maintain a balance sheet by service or jurisdiction. The balance sheet accounts by FERC account for December 31, 2007 – 2015 have been provided at PC_DR_002-Attachment A. The Company prepares Results of Operations (ROO) reports that provides an income statement by service and jurisdiction. Each month, 3 reports are prepared: 1) Electric (Washington and Idaho); 2) Gas North (Washington and Idaho) and 3) Gas South (Oregon). Each month’s report is saved in Excel format, so it is not possible to produce a Washington natural gas ROO report in tabular format for all of the years requested. Rather, the annual natural gas reports for Gas North have been provided, as follows: Year Attachment Each excel spreadsheet for each year’s report has multiple tabs and pages, therefore, electronic files only have been provided. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/08/2016 CASE NO: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: Public Counsel RESPONDER: Jeanne Pluth TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: PC – 005 TELEPHONE: (509) 495-2204 EMAIL: jeanne.pluth@avistacorp.com REQUEST: Please provide Avista Washington gas per books year-end balance sheets and income statements for each year 2007 through 2015 by Federal Energy Regulatory Commission (FERC) account. In this response, provide in tabular format with FERC accounts for each row and individual years for each column. Please provide in hardcopy as well as executable electronic (Excel) format. RESPONSE: As explained in the Company’s response to PC_DR_002, the Company does not maintain a balance sheet by service or jurisdiction. The balance sheet accounts by FERC account for December 31, 2007 – 2015 have been provided at PC_DR_002-Attachment A. The Company prepares Results of Operations (ROO) reports that provides an income statement by service and jurisdiction. Each month, 3 reports are prepared: 1) Electric (Washington and Idaho); 2) Gas North (Washington and Idaho) and 3) Gas South (Oregon). Each month’s report is saved in Excel format, so it is not possible to produce a Washington natural gas ROO report in tabular format for all of the years requested. Rather, the annual natural gas reports for Gas North have been provided, as follows: Year Attachment Each excel spreadsheet for each year’s report has multiple tabs and pages, therefore, electronic files only have been provided. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/08/2016 CASE NO: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: Public Counsel RESPONDER: Jeanne Pluth TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: PC – 006 TELEPHONE: (509) 495-2204 EMAIL: jeanne.pluth@avistacorp.com REQUEST: Please provide Avista total consolidated per books year-end balance sheets and income statements for each year 2007 through 2015 by Federal Energy Regulatory Commission (FERC) account. In this response, provide in tabular format with FERC accounts for each row and individual years for each column. Please provide in hardcopy as well as executable electronic (Excel) format. RESPONSE: Please see the Company’s response to PC_DR_002 Attachment A for the balance sheets and PC_DR_006 Attachment A for the income statements. The net income of the subsidiaries of Avista Corp. are shown in PC_DR_006 Attachment A in separate FERC accounts under “non-utility” in FERC Accounts 418XXX. Further detail for all subsidiaries is not electronically available. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/08/2016 CASE NO: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: Public Counsel RESPONDER: Jeanne Pluth TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: PC – 006 TELEPHONE: (509) 495-2204 EMAIL: jeanne.pluth@avistacorp.com REQUEST: Please provide Avista total consolidated per books year-end balance sheets and income statements for each year 2007 through 2015 by Federal Energy Regulatory Commission (FERC) account. In this response, provide in tabular format with FERC accounts for each row and individual years for each column. Please provide in hardcopy as well as executable electronic (Excel) format. RESPONSE: Please see the Company’s response to PC_DR_002 Attachment A for the balance sheets and PC_DR_006 Attachment A for the income statements. The net income of the subsidiaries of Avista Corp. are shown in PC_DR_006 Attachment A in separate FERC accounts under “non-utility” in FERC Accounts 418XXX. Further detail for all subsidiaries is not electronically available. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/13/2016 CASE NO: UE-160228 & UG-160229 WITNESS: Elizabeth Andrews REQUESTER: Public Counsel RESPONDER: Liz Andrews TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: PC – 007 TELEPHONE: (509) 495-8601 EMAIL: liz.andrews@avistacorp.com REQUEST: Please provide Washington Commission Basis Reports for electric operations for the years 2007 through 2010. RESPONSE: Please see PC_DR_007 – Attachments A-D, provided in electronic format only. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/13/2016 CASE NO: UE-160228 & UG-160229 WITNESS: Elizabeth Andrews REQUESTER: Public Counsel RESPONDER: Liz Andrews TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: PC – 007 TELEPHONE: (509) 495-8601 EMAIL: liz.andrews@avistacorp.com REQUEST: Please provide Washington Commission Basis Reports for electric operations for the years 2007 through 2010. RESPONSE: Please see PC_DR_007 – Attachments A-D, provided in electronic format only. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/13/2016 CASE NO: UE-160228 & UG-160229 WITNESS: Elizabeth Andrews REQUESTER: Public Counsel RESPONDER: Liz Andrews TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: PC – 008 TELEPHONE: (509) 495-8601 EMAIL: liz.andrews@avistacorp.com REQUEST: Please provide Washington Commission Basis Reports for gas operations for the years 2007 through 2010. RESPONSE: Please see PC_DR_008 – Attachments A-D, provided in electronic format only. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/13/2016 CASE NO: UE-160228 & UG-160229 WITNESS: Elizabeth Andrews REQUESTER: Public Counsel RESPONDER: Liz Andrews TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: PC – 008 TELEPHONE: (509) 495-8601 EMAIL: liz.andrews@avistacorp.com REQUEST: Please provide Washington Commission Basis Reports for gas operations for the years 2007 through 2010. RESPONSE: Please see PC_DR_008 – Attachments A-D, provided in electronic format only. 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184 PC_DR_009 Attachment A Page 183 of 184 PC_DR_009 Attachment A Page 184 of 184 THIS FILING IS Item 1: IBJ An Initial (Original) Submission OR D Resubmission No. Form 2 Approved OMB No.1902-0028 (Expires 09/30/2017) Form 3-Q Approv~d OMB No.1902-0205 (Expires 11/30/2016) FERC FINANCIAL REPORT FERC FORM No. 2: Annual Report of Major Natural Gas Companies and Supplemental Form 3-Q: Quarterly Financial Report These reports are mandatory under the Natural Gas Act, Sections 1 O(a), and 16 and 18 CFR Parts 260.1 and 260.300. Failure to report may result in criminal fines, civil penalties, and other sanctions as provided by law. The Federal Energy Regulatory Commission does not consider these reports to be of a confidential nature. Exact Legal Name of Respondent (Company) Avista Corporation FERC FORM No. 2/3Q (02-04) Year/Period of Report End of 2015/04 PC_DR_009 Attachment B Page 1 of 177 QUARTERLY/ANNUAL REPORT OF MAJOR NATURAL GAS COMPANIES IDENTIFICATION 01 Exact Legal Name of Respondent Avista Corporation 03 Previous Name and Date of Change (If name changed during year) 04 Address of Principal Office at End of Year (Street, City, State, Zip Code) 1411 East Mission Avenue, Spokane, WA 99207 Year/Period of Report End of 2015/04 06 Title of Contact Person 05 Name of Contact Person Ryan Krasselt VP, Controller, Prin. Acctg Officer 07 Address of Contact Person (Street, City, State, Zip Code) 1411 East Mission Avenue, Spokane, WA 99207 08 Telephone of Contact Person, Including Area Code 509-495-2273 This Report Is: (1) [K]An Original (2) DA Resubmission ANNUAL CORPORATE OFFICER CERTIFICATION The undersigned officer certifies that: 1 O Date of Report (Mo, Da, Yr) 04/15/2016 I have examined this report and to the best of my knowledge, information, and belief all statements of fact contained in this report are correct statements of the business affairs of the respondent and the financial statements, and other financial information contained in this report, conform in all material respects to the Uniform System of Accounts. 11 Name 12 Title Ryan Krasselt VP, Controller, Prin. Acctg Officer 13Signature () I/ 14DateSigned Ryan Krasselt l~ L . l~ ft;,..._~IJ _.,t,)\ 04/15/2016 Title 18, U.S.C. 1001, ~kes it a crime for any person knowingly and willingly to make to any Agency or Department of the United States any false, fictitious or fraudulent statements as to any matter within its jurisdiction. FERC FORM NO. 2/3Q (02-04) Page PC_DR_009 Attachment B Page 2 of 177 Name of Respondent This wort Is: Date of Report Year/Period of Report Avista Corporation (1) X An Original (Mo, Da, Yr) (2) DA Resubmission 04/15/2016 End of 2015/04 List of Schedules (Natural Gas Company) Enter in column (d) the terms "none," "not applicable," or "NA" as appropriate, where no information or amounts have been reported for certain pages. Omit pages where the responses are "none," "not applicable," or "NA." .. Title of Schedule Reference Date Revised Remarks Line Page No. No. (a) (b) (c) (d) GENERAL CORPORATE INFORMATION AND FINANCIAL STATEMENTS 1 General Information 101 2 Control Over Respondent 102 3 Corporations Controlled by Respondent 103 4 Security Holders and Voting Powers 107 5 Important Changes During the Year 108 6 Comparative Balance Sheet 110-113 7 Statement of Income for the Year 114-116 8 Statement of Accumulated Comprehensive Income and Hedging Activities 117 9 Statement of Retained Earnings for the Year 118-119 10 Statements of Cash Flows 120-121 11 Notes to Financial Statements 122 BALANCE SHEET SUPPORTING SCHEDULES (Assets and Other Debits) 12 Summary of Utility Plant and Accumulated Provisions for Depreciation, Amortization, and Depletion 200-201 13 Gas Plant in Service 204-209 14 Gas Property and Capacity Leased from Others 212 15 Gas Property and Capacity Leased to Others 213 16 Gas Plant Held for Future Use 214 17 Construction Work in Progress-Gas 216 18 Non-Traditional Rate Treatment Afforded New Projects 217 19 General Description of Construction Overhead Procedure 218 20 Accumulated Provision for Depreciation of Gas Utility Plant 219 21 Gas Stored 220 22 Investments 222-223 23 Investments in Subsidiary Companies 224-225 24 Prepayments 230 25 Extraordinary Property Losses 230 26 Unrecovered Plant and Regulatory Study Costs 230 27 Other Regulatory Assets 232 28 Miscellaneous Deferred Debits 233 29 Accumulated Deferred Income Taxes 234-235 BALANCE SHEET SUPPORTING SCHEDULES (Liabilities and Other Credits) 30 Capital Stock 250-251 31 Capital Stock Subscribed, Capital Stock Liability for Conversion, Premium on Capital Stock, and Installments Received on Capital Stock 252 32 Other Paid-in Capital 253 33 Discount on Capital Stock 254 34 Capital Stock Expense 254 35 Securities issued or Assumed and Securities Refunded or Retired During the Year 255 36 Long-Term Debt 256-257 37 Unamortized Debt Expense, Premium, and Discount on Long-Term Debt 258-259 FERC FORM NO. 2 (REV 12-07) Page 2 PC_DR_009 Attachment B Page 3 of 177 Name of Respondent This ooort Is: Date of Report Year/Period of Report Avista Corporation (1) X An Original (Mo, Da, Yr) (2) DA Resubmission 04/15/2016 End of 2015/04 List of Schedules (Natural Gas Company) (continued) Enter in column (d) the terms "none," "not applicable," or "NA" as appropriate, where no information or amounts have been reported for certain pages. Omit pages where the responses are "none," "not applicable," or "NA." Title of Schedule Reference Date Revised Remarks Line Page No. No. (a) (b) (c) (d) 38 Unamortized Loss and Gain on Reacquired Debt 260 39 Reconciliation of Reported Net Income with Taxable Income for Federal Income Taxes 261 40 Taxes Accrued, Prepaid, and Charged During Year 262-263 41 Miscellaneous Current and Accrued Liabilities 268 42 Other Deferred Credits 269 43 Accumulated Deferred Income Taxes-Other Property 274-275 44 Accumulated Deferred Income Taxes-Other 276-277 45 Other Regulatory Liabilities 278 INCOME ACCOUNT SUPPORTING SCHEDULES 46 Monthly Quantity & Revenue Data by Rate Schedule 299 47 Gas Operating Revenues 300-301 48 Revenues from Transportation of Gas of Others Through Gathering Facilities 302-303 49 Revenues from Transportation of Gas of Others Through Transmission Facilities 304-305 50 Revenues from Storage Gas of Others 306-307 51 Other Gas Revenues 308 52 Discounted Rate Services and Negotiated Rate Services 313 53 Gas Operation and Maintenance Expenses 317-325 54 Exchange and Imbalance Transactions 328 55 Gas Used in Utility Operations 331 56 Transmission and Compression of Gas by Others 332 57 Other Gas Supply Expenses 334 58 Miscellaneous General Expenses-Gas 335 59 Depreciation, Depletion, and Amortization of Gas Plant 336-338 60 Particulars Concerning Certain Income Deduction and Interest Charges Accounts 340 COMMON SECTION 61 Regulatory Commission Expenses 350-351 62 Employee Pensions and Benefits (Account 926) 352 63 Distribution of Salaries and Wages 354-355 64 Charges for Outside Professional and Other Consultative Services 357 65 Transactions with Associated (Affiliated) Companies 358 GAS PLANT STATISTICAL DATA 66 Compressor Stations 508-509 67 Gas Storage Projects 512-513 68 Transmission Lines 514 69 Transmission System Peak Deliveries 518 70 Auxiliary Peaking Facilities 519 71 Gas Account-Natural Gas 520 72 Shipper Supplied Gas for the Current Quarter 521 73 System Map 522 74 Footnote Reference 551 75 Footnote Text 552 76 Stockholder's Reports (check appropriate box) D Four copies will be submitted D No annual report to stockholders is prepared FERC FORM NO. 2 (REV 12-07) Page 3 PC_DR_009 Attachment B Page 4 of 177 Name of Respondent Avista Corporation This ~ort Is: (1) ~An Original (2) DA Resubmission General Information Date of Report (Mo, Da, Yr) 04/15/2016 Year/Period of Report End of 2015/04 1. Provide name and title of officer having custody of the general corporate books of account and address of office where the general corporate books are kept and address of office where any other corporate books of account are kept, if different from that where the general corporate books are kept. Ryan Krasselt, Vice President and Controller, Principal Accounting Officer 1411 E Mission Avenue Spokane, WA 99207 2. Provide the name of the State under the laws of which respondent is incorporated and date of incorporation. If incorporated under a special law, give reference to such law. If not incorporated, state that fact and give the type of organization and the date organized. State of Washington, Incorporated March 15, 1889 3. If at any time during the year the property of respondent was held by a receiver or trustee, give (a) name of receiver or trustee, (b) date such receiver or trustee took possession, (c) the authority by which the receivership or trusteeship was created, and (d) date when possession by receiver or trustee ceased. Not Applicable 4. State the classes of utility and other services furnished by respondent during the year in each State in which the respondent operated. Electric service in the states of Washington, Idaho and Montana Natural gas service in the states of Washington, Idaho and Oregon 5. Have you engaged as the principal accountant to audit your financial statements an accountant who is not the principal accountant for your previous year's certified financial statements? (1) D Yes ... Enter the date when such independent accountant was initially engaged: (2) IBJ No FERC FORM NO. 2 (12-96) Page 101 PC_DR_009 Attachment B Page 5 of 177 This Page Intentionally Left Blank PC_DR_009 Attachment B Page 6 of 177 Name of Respondent This ~ort Is: Date of Report Year/Period of Report Avista Corporation (1) X An Original (Mo, Da, Yr) (2) DA Resubmission 04/15/2016 End of 2015/04 Corporations Controlled by Respondent 1. Report below the names of all corporations, business trusts, and similar organizations, controlled directly or indirectly by respondent at any time during the year. If control ceased prior to end of year, give particulars (details) in a footnote. 2. If control was by other means than a direct holding of voting rights, state in a footnote the manner in which control was held, naming any intermediaries involved. 3. If control was held jointly with one or more other interests, state the fact in a footnote and name the other interests. 4. In column (b) designate type of control of the respondent as "D" for direct, an "I" for indirect, or a "J" for joint control. --------------------------- DEFINITIONS --------------------------- 1. See the Uniform System of Accounts for a definition of control. 2. Direct control is that which is exercised without interposition of an intermediary. 3. Indirect control is that which is exercised by the interposition of an intermediary that exercises direct control. 4. Joint control is that in which neither interest can effectively control or direct action without the consent of the other, as where the voting control is equally divided between two holders, or each party holds a veto power over the other. Joint control may exist by mutual agreement or understanding between two or more parties who together have control within the meaning of the definition of control in the Uniform System of Accounts, regardless of the relative voting rights of each party. Line Name of Company Controlled Type of Control Kind of Business Percent Voting Footnote No. Stock Owned Reference (a) (b) (c) (d) (e) 1 Avista Capital D Parent to the Company's 100 Not used 2 subsidiaries 3 Avista Development I Maintains investment portfolio incl Real 100 Not used Estate. 4 Avista Energy I Inactive 100 Not used 5 Pentzer Corporation I Parent of Bay Area Mfg and Penture 100 Not used Venture Hldngs 6 Bay Area Manufacturing I Holding co of AM&D dba MetalFX 100 Not used 7 Advanced Manufacturing & Development I Custom mfg of electronic enclosures 83 Not used 8 dba MetalFX Not used 9 Spokane Energy, LLC D Owns an elec. capacity contrt. See 100 Not used Footnote. 10 Avista Capital II D Affliliated business trust issue pref trust 100 Not used sec 11 Avista Northwest Resources, LLC I Owns an interest in a venture fund 100 Not used investment 12 Steam Plant Square, LLC I Commercial office and Retail leasing 85 Not used 13 Courtyard Office Center, LLC I Commercial office and retail leasing 100 Not used 14 Steam Plant Brew Pub, LLC I Restaurant Operations 85 Not used 15 16 Alaska Energy and Resources Company D Parent company of Alaska operations 100 Not used 17 Alaska Electric Light and Power Company I Utiltiy operations based in the city and 100 Not used borough 18 Of Juneau, AK 19 AJT Mining Properties, Inc I Inactive mining company holding 100 Not used certain properties 20 Snettisham Electric Company I Holds certain rights to purchase the 100 Not used Snettisham 21 Hydroelectric project in the city & borough of 22 Juneau, AK 23 pallx, Inc I Liquefied Natural Gas Operations. 100 Not used See Footnote 24 25 FERC FORM NO. 2 (12-96) Page 103 PC_DR_009 Attachment B Page 7 of 177 Name of Respondent This Report is: Date of Report Year/Period of Report (1) 6 An Original (Mo, Da, Yr) Avista Corporation (2) _A Resubmission 04/15/2016 2015/04 FOOTNOTE DATA !Schedule Page: 103 Line No.: 9 Column: a S okane Ener was dissolved as of Jul , 23 2015. Notice of cancellation was sent to The State of Delaware. !Schedule Page: 103 Line No.: 23 Column: a a subsidiary of Avista Capital, launched in 2014 to explore markets that could be served with liquefied natural gas (LNG), primarily in western North America. I FERC FORM NO. 2 (12-96) Page 552.1 PC_DR_009 Attachment B Page 8 of 177 Name of Respondent This IBJort Is: Date of Report Year/Period of Report Avista Corporation (1) X An Original (Mo, Da, Yr) (2) DA Resubmission 04/15/2016 End of 2015/04 Security Holders and Voting Powers 1. Give the names and addresses of the 10 security holders of the respondent who, at the date of the latest closing of the stock book or compilation of list of stockholders of the respondent, prior to the end of the year, had the highest voting powers in the respondent, and state the number of votes that each could cast on that date if a meeting were held. If any such holder held in trust, give in a footnote the known particulars of the trust (whether voting trust, etc.), duration of trust, and principal holders of beneficiary interests in the trust. If the company did not close the stock book or did not compile a list of stockholders within one year prior to the end of the year, or if since it compiled the previous list of stockholders, some other class of security has become vested with voting rights, then show such 10 security holders as of the close of the year. Arrange the names of the security holders in the order of voting power, commencing with the highest. Show in column (a) the titles of officers and directors included in such list of 10 security holders. 2. If any security other than stock carries voting rights, explain in a supplemental statement how such security became vested with voting rights and give other important details concerning the voting rights of such security. State whether voting rights are actual or contingent; if contingent, describe the contingency. 3. If any class or issue of security has any special privileges in the election of directors, trustees or managers, or in the determination of corporate action by any method, explain briefly in a footnote. 4. Furnish details concerning any options, warrants, or rights outstanding at the end of the year for others to purchase securities of the respondent or any securities or other assets owned by the respondent, including prices, expiration dates, and other material information relating to exercise of the options, warrants, or rights. Specify the amount of such securities or assets any officer, director, associated company, or any of the 10 largest security holders is entitled to purchase. This instruction is inapplicable to convertible securities or to any securities substantially all of which are outstanding in the hands of the general public where the options, warrants, 1. Give date of the latest closing of the stock 2. State the total number of votes cast at the latest general 3. Give the date and place of book prior to end of year, and, in a footnote, state meeting prior to the end of year for election of directors of the such meeting: the purpose of such closing: respondent and number of such votes cast by proxy. 54563176 May 7, 2015 11/19/2015 Total: Spokane, Washington By Proxy: 54563176 VOTING SECURITIES 4. Number of votes as of (date): 11/19/2015 Line Name (Title) and Address of Total Votes Common Stock Preferred Stock Other No. Security Holder (a) (b) (c) (d) (e) 5 TOT AL votes of all voting securities 62,358,017 62,358,017 6 TOTAL number of security holders 8,819 8,819 7 TOTAL votes of security holders listed below 1,031,786 1,031,786 8 Computershare Trust Company NA as escrow agent for: 9 George Barclay Corbus, Arvada, CO 343,168 343,168 10 William A Corbus, Juneau, AK 300,000 300,000 11 Malcolm A Menzies, Juneau, AK 113,301 113,301 12 Gary Ely, Liberty Lake, WA 56,984 56,984 13 Mark T Thies, Spokane, WA 40,594 40,594 14 Marian Durkin, Spokane, WA 39,621 39,621 15 Niels F Larsen & Wilhelmine J Larsen Jt Ten, Juneau, AK 39,312 39,312 16 Jane N MacKinnon, Juneau, AK 37,347 37,347 17 Dennis P Vermillion, Spokane, WA 29,381 29,381 18 19 20 FERC FORM NO. 2 (12-96) Page 107 PC_DR_009 Attachment B Page 9 of 177 Name of Respondent This Report is: Date of Report Year/Period of Report (1) 6 An Original (Mo, Da, Yr) Avista Corporation (2) A Resubmission 04/15/2016 2015/04 FOOTNOTE DATA !Schedule Page: 107 Line No.: 1 Column: 1 To pay the 12/15/2015 dividend. I FERC FORM NO. 2 (12-96) Page 552.1 PC_DR_009 Attachment B Page 10 of 177 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Avista Corporation (2) A Resubmission 04/15/2016 2015/04 Important Changes During the QuarterNear Give details concerning the matters indicated below. Make the statements explicit and precise, and number them in accordance with the inquiries. Answer each inquiry. Enter "none" or "not applicable" where applicable. If the answer is given elsewhere in the report, refer to the schedule in which it appears. 1. Changes in and important additions to franchise rights: Describe the actual consideration and state from whom the franchise rights were acquired. If the franchise rights were acquired without the payment of consideration, state that fact. 2. Acquisition of ownership in other companies by reorganization, merger, or consolidation with other companies: Give names of companies involved, particulars concerning the transactions, name of the Commission authorizing the transaction, and reference to Commission authorization. 3. Purchase or sale of an operating unit or system: Briefly describe the property, and the related transactions, and cite Commission authorization, if any was required. Give date journal entries called for by Uniform System of Accounts were submitted to the Commission. 4. Important leaseholds (other than leaseholds for natural gas lands) that have been acquired or given, assigned or surrendered: Give effective dates, lengths of terms, names of parties, rents, and other conditions. State name of Commission authorizing lease and give reference to such authorization. 5. Important extension or reduction of transmission or distribution system: State territory added or relinquished and date operations began or ceased and cite Commission authorization, if any was required. State also the approximate number of customers added or lost and approximate annual revenues of each class of service. Each natural gas company must also state major new continuing sources of gas made available to it from purchases, development, purchase contract or otherwise, giving location and approximate total gas volumes available, period of contracts, and other parties to any such arrangements, etc. 6. Obligations incurred or assumed by respondent as guarantor for the performance by another of any agreement or obligation, including ordinary commercial paper maturing on demand or not later than one year after date of issue: State on behalf of whom the obligation was assumed and amount of the obligation. Cite Commission authorization if any was required. 7. Changes in articles of incorporation or amendments to charter: Explain the nature and purpose of such changes or amendments. 8. State the estimated annual effect and nature of any important wage scale changes during the year. 9. State briefly the status of any materially important legal proceedings pending at the end of the year, and the results of any such proceedings culminated during the year. 10. Describe briefly any materially important transactions of the respondent not disclosed elsewhere in this report in which an officer, director, security holder, voting trustee, associated company or known associate of any of these persons was a party or in which any such person had a material interest. 11. Estimated increase or decrease in annual revenues caused by important rate changes: State effective date and approximate amount of increase or decrease for each revenue classification. State the number of customers affected. 12. Describe fully any changes in officers, directors, major security holders and voting powers of the respondent that may have occurred during the reporting period. 13. In the event that the respondent participates in a cash management program(s) and its proprietary capital ratio is less than 30 percent please describe the significant events or transactions causing the proprietary capital ratio to be less than 30 percent, and the extent to which the respondent has amounts loaned or money advanced to its parent, subsidiary, or affiliated companies through a cash management program(s). Additionally, please describe plans, if any to regain at least a 30 percent proprietary ratio. 1. None 2. None 3. None 4. None 5. None 6. Avista Corp. has a committed line of credit with various financial institutions in the total amount of $400.0 million that expires in April 2019. Balances outstanding (including letters of credit) under the Company's revolving committed lines of credit were as follows as of December 31, 2015 and December 31, 2014 (dollars in thousands): December 31, December 31, 2015 2014 Balance outstanding at end of period $105,000 $105,000 Letters of credit outstanding at end of period $44,595 $32,579 In December 2015, Avista Corp. issued $100.0 million of first mortgage bonds to five institutional investors in a private placement transaction. The first mortgage bonds bear an interest rate of 4.37 percent and mature in 2045. The total net proceeds from the sale of the new bonds were used to repay a potiion of the borrowings outstanding under the Company's $400.0 million committed line of credit and for general corporate purposes. The debt issuance was approved I FERC FORM NO. 2 (12-96) 108.1 PC_DR_009 Attachment B Page 11 of 177 Name of Respondent This Report is: Date of Report Year/Period of Report (1) ~An Original (Mo, Da, Yr) Avista Corporation (2) A Resubmission 04/15/2016 2015/04 Important Changes During the QuarterNear by regulatory commissions as follows:WUTC (Docket No. U-111176 Order 02) IPUC (Case No. AVU-U-11-01 Order No. 3233 8) and the OPUC (Docket UF 4294 Order No. 15-305). 7. None 8. Average annual wage increases were 2.4% for non-exempt employees effective February 23, 2015. Average annual wage increases were 3.0% for exempt employees effective February 23, 2015. Officers received average increases of 3.3% effective February 23, 2015. Ce1iain bargaining unit employees received increases of 3.0% effective March 26, 2015. 9. Reference is made to Note 16 of the Notes to Financial Statements. 10. None 11. Washington General Rate Cases 2014 General Rate Cases In November 2014, the UTC approved an all-pmiy settlement agreement related to Avista Corp.'s electric and natural gas general rate cases filed in February 2014 and new rates became effective on January 1, 2015. The settlement was designed to increase annual electric base revenues by $12.3 million, or 2.5 percent, inclusive of a $5.3 million power supply update as required in the settlement agreement (explained below). The settlement was designed to increase annual natural gas base revenues by $8.5 million, or 5.6 percent. The settlement agreement also included the implementation of decoupling mechanisms for electric and natural gas and a related after-the-fact earnings test, which are discussed in further detail in Note 17 of the Notes to Financial Statements. Specific capital structure ratios and the cost of capital components were not agreed to in the settlement agreement. The revenue increases in the settlement were not tied to the 7.32 percent rate of return on rate base (ROR) used in conjunction with the after-the fact earnings test. The electric and natural gas revenue increases were negotiated numbers, with each pmiy using its own set of assumptions underlying its agreement to the revenue increases. The parties agreed that the 7.32 percent ROR will be used to calculate the AFUDC and other purposes. 2015 General Rate Cases In January 2016, the Company received an order (Order 05) that concluded its electric and natural gas general rate cases that were originally filed with the UTC in February 2015. New electric and natural gas rates were effective on January 11,2016. The UTC approved rates designed to provide a 1.6 percent, or $8.1 million decrease in electric base revenue, and a 7.4 percent, or $10. 8 million increase in natural gas base revenue. The UTC also approved an ROR on rate base of 7 .29 percent, with a common equity ratio of 48.5 percent and a 9.5 percent return on equity (ROE). Throughout the rate case process, certain circumstances and costs changed, causing A vista Corp. to revise our overall proposed rate requests downward, especially for our electric operations. The Company's need for electric rate relief was reduced primarily due to the following: • a decrease in power supply costs of approximately $24.0 million caused by the continuing decline in the price of natural gas used to run the Company's natural gas-fired generation and lower contract costs associated with a new PPA from Chelan PUD, I FERC FORM NO. 2 (12-96) 108.2 PC_DR_009 Attachment B Page 12 of 177 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo1 Da1 Yr) Avista Corporation (2) _ A Resubmission 04/15/2016 2015/04 Important Changes During the QuarterNear • updated information related to federal tax adjustments and state allocations, • the delay in the expected completion date of the Nine Mile hydroelectric generation project upgrade from late 2015 to late 2016, and • a delay of the start date to begin amortization of existing electric meters from 2016 to a future year, associated with Avista Corp.'s proposed AMI project. ·- The natural gas revenue increase approved by the UTC is related to the Company's ownership and operating costs to run the natural gas business. Changes in the commodity costs of natural gas for natural gas customers are reflected in Avista Corp.'s annual PGA, which is generally effective November 1st each year. On November 1, 2015 natural gas customers' bills were reduced approximately 15 percent related to the decline in the market price of natural gas. In responsive testimony filed by the UTC Staff in July 2015 in the Company's electric and natural gas general rate cases, they recommended a disallowance of $12. 7 million (Washington's share) of the costs associated with the replacement of the Company's customer information and work management systems (Project Compass) primarily related to the delay in the completion of the project. In the January 6, 2016 UTC order, they approved the full recovery of Washington's portion of Project Compass costs. UTC Issues Order Denying Industrial Customers of Northwest Utilities I Public Counsel Joint Motion for Clarification, UTC Staff Motion to Reconsider and UTC Staff Motion to Reopen Record On February 19, 2016, the UTC issued an order (Order 06) denying the Motions summarized below and affirmed their original January 2016 order of an $ 8 .1 million decrease in electric base revenue, thus finalizing A vista Corp's 2015 electric and natural gas general rate cases. On January 19, 2016, the Industrial Customers ofNorthwest Utilities (ICNU) and the Public Counsel Unit of the Washington State Office of the Attorney General (PC) filed a Joint Motion for Clarification with the UTC. In its Motion for Clarification, ICNU and PC requested that the UTC clarify the calculation of the electric attrition adjustment and the end-result revenue decrease of $8.1 million. ICNU and PC provided their own calculations in their Motion, and suggested that the revenue decrease should have been $19.8 million based on their reading of the UTC's Order. On January 19, 2016, the UTC Staff, which is a separate party in the general rate case proceedings from the UTC Advisory Staff that supports the Commissioners, filed a Motion to Reconsider with the UTC. In its Motion to Reconsider, the Staff provided calculations and explanations that suggested that the electric revenue decrease should have been a revenue decrease of $27.4 million instead of$8.1 million, based on its reading of the UTC's Order. Further, on February 4, 2016, the UTC Staff filed a Motion to Reopen Record for the Limited Purpose of Receiving into Evidence Instruction on Use and Application of Staffs Attrition Model, and sought to supplement the record "to incorporate all aspects of the Company' Power Cost Update." Within this Motion, UTC Staff updated its suggested electric revenue decrease to $19.6 million. None of the patiies in their Motions raised issues with the UTC's decision on the natural gas revenue increase of I FERC FORM NO. 2 (12-96) 108.3 PC_DR_009 Attachment B Page 13 of 177 Name of Respondent This Report is: Date of Report Year/Period of Report ( 1) ~An Original (Mo, Da, Yr) Avista Corporation (2) A Resubmission 04/15/2016 2015/04 Important Changes During the QuarterNear $10. 8 million. PC Petition for Judicial Review On March 18, 2016, PC filed in Thurston County Superior Court a Petition for Judicial Review of the UTC's January 2016 Order 05 and February 2016 Order 06. Order 05 approved new electric and natural gas rates that became effective on January 11, 2016. In its March 2016 Petition for Judicial Review, PC seeks judicial review of five aspects of Order 05 and Order 06, alleging, among other things, that ( 1) the UTC exceeded its statutory authority by setting rates for A vista Corp.'s natural gas and electric services based on amounts for utility plant and facilities that are not "used and useful" in providing utility service to customers; (2) the UTC acted arbitrarily and capriciously in granting an attrition adjustment for Avista Corp.'s electric operations after finding that the Company did not meet the newly articulated standard regarding attrition adjustments; (3) the UTC erred in applying the "end results test" to set rates for Avista Corp.'s electric operations that are not supported by the record; (4) the UTC did not correct its calculation of Avista Corp.'s electric rates after significant errors were brought to its attention; and (5) the UTC's calculation of Avista Corp.'s electric rates lacks substantial evidence. PC is requesting that the Comi (1) vacate or set aside portions of the UTC's orders; (2) identify the errors contained in the UTC's orders; (3) find that the rates approved in Order 05 and reaffirmed in Order 06 are unlawful and not fair, just and reasonable; ( 4) remand the matter to the UTC for further proceedings consistent with these rulings, including a determination of A vista Corp.' s revenue requirement for electric and natural gas services; and ( 5) find the customers are entitled to a refund. The new rates established by Order 05 will continue in effect while the Petition· for Judicial Review is being considered. The Company believes the UTC's Order 05 and Order 06 finalizing the electric and natural gas general rate cases provide a reasonable end result for all parties. If the outcome of the judicial review were to result in an electric rate reduction greater than the decrease ordered by the UTC, it may not provide Avista Corp. with a reasonable opp01iunity to earn the rate of return authorized by the UTC. 2016 General Rate Cases On February 19, 2016, Avista Corp. filed electric and natural gas general rates cases with the UTC. The Company's proposal includes an 18-month rate plan, with new rates taking effect on January 1, 2017 and January 1, 2018. Under this plan, the Company would not file a future rate case for new rates to be effective prior to July 1, 2018. The 201 7 increase, if approved, would increase overall base electric rates 7. 8 percent (designed to increase annual electric revenues by $38.6 million) and overall base natural gas rates 5.0 percent (designed to increase annual natural gas revenues by $4.4 million). In addition, the Company has requested a second step increase effective January 1, 2018, which would increase overall base electric rates by 3.9 percent (designed to increase annual electric revenues by $10.3 million) and overall base natural I FERC FORM NO. 2 (12-96) 108.4 I PC_DR_009 Attachment B Page 14 of 177 Name of Respondent This Report is: Date of Report Year/Period of Report (1) 6 An Original (Mo, Da, Yr) Avista Corporation (2) A Resubmission 04/15/2016 2015/04 Important Changes During the QuarterNear ·- gas rates by 1.8 percent (designed to increase annual natural gas revenues by $0.9 million). Avista Corp. has proposed to offset the electric increase, for the period January through June 2018, with available ERM dollars. As a result, customers would not see an electric general rate case bill increase in 2018 prior to July 1, 2018. The requests are bas:~d on a proposed ROR of 7 .64 percent with a common equity ratio of 48.5 percent and a 9 .9 percent ROE. The UTC has up to 11 months to review the filings and issue a decision. Idaho General Rate Cases 2014 Rate Plan Extension Avista Corp. did not file new general rate cases in Idaho in 2014; instead, the Company developed an extension to the 2013 and 2014 rate plan and reached a settlement agreement with all interested parties. In September 2014, the IPUC approved the settlement, which reflected agreement among all interested parties, for a one-year extension to the Company's current rate plan, which was set to expire on December 31, 2014. Under the approved extension, base retail rates remained unchanged through December 31, 2015. The settlement provided an estimated $3. 7 million increase in pre-tax income by reducing planned expenses in 2015 for the Company's Idaho operations. 2015 General Rate Cases In December 2015, the IPUC approved a settlement agreement between Avista Corp. and all interested parties related to its electric and natural gas general rate cases, which were originally filed with the IPUC on June 1, 2015. New rates were effective on January 1, 2016. The settlement agreement is designed to increase annual electric base revenues by $1.7 million or 0.7 percent and annual natural gas base revenues by $2.5 million or 3 .5 percent. The settlement is based on a ROR of 7.42 percent with a common equity ratio of 50 percent and a 9.5 percent ROE. The settlement agreement also reflects the following: • the discontinuation of the after-the-fact earnings test (provision for earnings sharing) that was originally agreed to as part of the settlement of our 2012 electric and natural gas general rate cases, and • the implementation of electric and natural gas Fixed Cost Adjustment mechanisms, as discussed in Note 17 of the Notes to Financial Statements. Oregon General Rate Cases 2014 General Rate Case In January 2015, Avista Corp. filed an all-party settlement agreement with the OPUC related to our natural gas general rate case, which was originally filed in September 2014. On February 23, 2015, the OPUC issued an order rejecting the all-party settlement agreement. The OPUC expressed concerns related to, among other things, various rate design issues. In March 2015, Avista Corp. filed an amended all-party settlement agreement with the OPUC which addressed the I FERC FORM NO. 2 (12-96) 108.5 PC_DR_009 Attachment B Page 15 of 177 Name of Respondent This Report is: Date of Report Year/Period of Report (1) ~An Original (Mo, Da, Yr) Avista Corporation (2) A Resubmission 04/15/2016 2015/04 Important Changes During the QuarterNear OPUC's concerns regarding the initial settlement agreement. The amended settlement agreement was designed to increase base natural gas revenues by $5.3 million. Included in this base rate increase is $0.3 million in base revenues that we are already receiving from customers through a separate rate adjustment. Therefore, the net increase in base revenues was $5.0 million, or 4.9 percent on a billed basis. The patiies requested that new retail rates become effective on April 16, 2015. On April 9, 2015, the OPUC issued an Order approving the amended settlement agreement as filed. This settlement agreement provided for an overall authorized ROR of 7 .516 percent with a common equity ratio of 51 percent and a 9.5 percent ROE. 2015 General Rate Case On February 29, 2016, the OPUC issued an order concluding the Company's natural gas general rate case, which was originally filed with OPUC in May 2015. The OPUC order approved rates designed to increase overall billed natural gas rates by 4.9 percent (designed to increase annual natural gas revenues by $4.5 million). New rates went into effect on March 1, 2016. The final OPUC order incorporated the two patiial settlement agreements described in further detail below. The OPUC order provides for an overall authorized ROR of 7.458 percent with a common equity ratio of 50 percent and a 9.4 percent ROE. In November 2015, Avista Corp. and all patiies to the natural gas general rate case reached agreement on certain issues, and a partial settlement agreement was filed with the OPUC on November 6, 2015. The partial settlement agreement reduced the requested natural gas revenue increase from $8.6 million to $6.7 million or 6.3 percent (on a billed basis). The partial settlement resolved a number of issues including the calculation of state income taxes for rate-making purposes, wages and salaries, the revenue forecast for the rate period, and working capital. In addition, the November patiial settlement agreement included a provision for the implementation of a decoupling mechanism, similar to the Washington and Idaho mechanisms described in Note 17 of the Notes to Financial Statements. The Decoupling Mechanism has an initial term concluding in September 2019. On January 19, 2016, the Company entered into an additional all-party partial settlement to further reduce the revenue increase request to $6 .1 million or 5. 7 percent (on a billed basis), related to updated information related to deferred taxes and its effect on rate base. These agreements did not resolve the remaining issues, such as, the appropriate ROE and capital structure, the appropriate level of additions to rate base, and medical and pension expenses. In addition, the OPUC staff filed testimony which included a recommendation to disallow $1.2 million (Oregon's share) of Project Compass costs primarily related to the delay in the full completion of the project. In the February 29, 2016 OPUC order, the OPUC approved the full recovery of Oregon's portion of Project Compass costs, as well as the capital investment included in the Company's case. The reductions to the Company's revenue requirement related to employee incentives, pension expense, and the reduction in the Company's proposed cost of capital. 12. Effective February 2015, Kevin J Christie was promoted to Vice President of Customer Solutions. He had previously held various other management and staff positions with the Company since 2005. Effective October 1, 2015, Christy Burmeister-Smith, fonner Vice President, Controller and Principal Accounting Officer retired. Ryan Krasselt, formerly the Director of Risk Management was selected to fill Christy's role upon her retirement. I FERC FORM NO. 2 (12-96) 108.6 PC_DR_009 Attachment B Page 16 of 177 Name of Respondent This Report is: Date of Report Year/Period of Report (1) ~An Original (Mo, Da, Yr) Avista Corporation (2) _ A Resubmission 04/15/2016 2015/04 Important Changes During the Quarter/Year Ryan has previously held various other finance and accounting management and staff positions with the Company for 14 years. On September 8, 2015, Ed Schlect, was appointed Vice President and Chief Strategy Officer. Ed was the former Executive Vice President of Corporate Development at Ecova, A vista Corp. 's former unregulated subsidiary. Roger Woodworth, previously Vice President and Chief Strategy Officer was promoted to President of Avista Development, an A vista Corp. subsidiary, in support of economic development within the Company's utility service areas. On December 1, 2015, Don Kopczynski, Vice President, Energy Delivery and Customer Service retired. Heather Rosentrater, formerly Avista's Director of Electrical Engineering and Grid Modernization, was selected to fill Don's role upon his retirement. Heather has previously held various other management and staff positions with the Company for 19 years. 13. Proprietary capital is not less than 3 0 percent. I FERC FORM NO. 2 (12-96) 108.7 PC_DR_009 Attachment B Page 17 of 177 This Page Intentionally Left Blank PC_DR_009 Attachment B Page 18 of 177 Name of Respondent This ooort Is: Date of Report Year/Period of Report Avista Corporation (1) X An Original (Mo, Da, Yr) (2) DA Resubmission 04/15/2016 End of 2015/04 Comparative Balance Sheet (Assets and Other Debits) Line Title of Account Reference Current Year End of Prior Year No. Page Number Quarter/Year Balance End Balance (c) 12/31 (a) (b) (d) 1 UTILITY PLANT 2 Utility Plant (101-106, 114) 200-201 4,923, 194,978 4,513, 148,224 3 Construction Work in Progress (107) 200-201 190, 108,665 223,330,993 4 TOTAL Utility Plant (Total of lines 2 and 3) 200-201 5, 113,303,643 4,736,479,217 5 (Less) Accum. Provision for Depr., Amort., Depl. (108, 111, 115) 1,680,907,938 1,573,767,832 6 Net Utility Plant (Total of line 4 less 5) 3,432, 395, 705 3, 162, 711,385 7 Nuclear Fuel (120.1 thru 120.4, and 120.6) 0 0 8 (Less) Accum. Provision for Amort., of Nuclear Fuel Assemblies (120.5) 0 0 9 Nuclear Fuel (Total of line 7 less 8) 0 0 10 Net Utility Plant (Total of lines 6 and 9) 3,432,395, 705 3,162,711,385 11 Utility Plant Adjustments (116) 122 0 0 12 Gas Stored-Base Gas ( 117 .1) 220 6,992,076 6,992,076 13 System Balancing Gas (117.2) 220 0 0 14 Gas Stored in Reservoirs and Pipelines-Noncurrent (117.3) 220 0 0 15 Gas Owed to System Gas ( 117.4) 220 0 0 16 OTHER PROPERTY AND INVESTMENTS 17 Nonutility Property (121) 2,740,379 5,288,635 18 (Less) Accum. Provision for Depreciation and Amortization (122) 201,768 194,911 19 Investments in Associated Companies (123) 222-223 11,547,000 12,047,000 20 Investments in Subsidiary Companies (123.1) 224-225 157,515,280 148,255,851 21 (For Cost of Account 123.1 See Footnote Page 224, line 40) 22 Noncurrent Portion of Allowances 0 0 23 Other Investments (124) 222-223 23,760,324 11,525,386 24 Sinking Funds (125) 0 0 25 Depreciation Fund (126) 0 0 26 Amortization Fund -Federal (127) 0 0 27 Other Special Funds (128) 20,755,670 11,488,865 28 Long-Term Portion of Derivative Assets (175) 22,687 0 29 Long-Term Portion of Derivative Assets -Hedges (176) 0 0 30 TOTAL Other Property and Investments (Total of lines 17-20, 22-29) 216, 139,572 188,410,826 31 CURRENT AND ACCRUED ASSETS 32 Cash (131) 2,074, 149 1,535, 172 33 Special Deposits (132-134) 14,430,708 6,832,649 34 Working Funds (135) 691,896 971,206 35 Temporary Cash Investments (136) 222-223 204,231 15,508,864 36 Notes Receivable (141) 0 0 37 Customer Accounts Receivable (142) 160,488,098 163,095,696 38 Other Accounts Receivable (143) 5,500,743 5,091,552 39 (Less) Accum. Provision for Uncollectible Accounts -Credit (144) 4,469,344 4,828,572 40 Notes Receivable from Associated Companies (145) 0 0 41 Accounts Receivable from Associated Companies (146) 469,096 401, 126 42 Fuel Stock (151) 3,293,585 4,116,727 43 Fuel Stock Expenses Undistributed (152) 0 0 FERC FORM NO. 2 (REV 06-04) Page 110 PC_DR_009 Attachment B Page 19 of 177 Name of Respondent This ~ort ls: Date of Report Year/Period of Report Avista Corporation (1) X An Original (Mo, Da, Yr) (2) DA Resubmission 04/15/2016 End of 2015/04 Comparative Balance Sheet (Assets and Other Debits)(continued) Line Title of Account Reference Current Year End of Prior Year No. Page Number Quarter/Year Balance End Balance (c) 12/31 (a) (b) (d) 44 Residuals (Elec) and Extracted Products (Gas) (153) 0 0 45 Plant Materials and Operating Supplies (154) 33,931,771 29,419,472 46 Merchandise (155) 0 0 47 Other Materials and Supplies (156) 0 0 48 Nuclear Materials Held for Sale (157) 0 0 49 Allowances (158.1 and 158.2) 0 0 50 (Less) Noncurrent Portion of Allowances 0 0 51 Stores Expense Undistributed (163) 0 0 52 Gas Stored Underground-Current (164.1) 220 12,774,487 28,731,498 53 Liquefied Natural Gas Stored and Held for Processing (164.2 thru 164.3) 220 0 0 54 Prepayments (165) 230 10,580,934 13,368,084 55 Advances for Gas (166 thru 167) 0 0 56 Interest and Dividends Receivable (171) 39,738 31,080 57 Rents Receivable (172) 1,749,949 1,740,695 58 Accrued Utility Revenues (173) 0 0 59 Miscellaneous Current and Accrued Assets (174) 527,051 614,449 60 Derivative Instrument Assets (175) 706,117 1,524,582 61 (Less) Long-Term Portion of Derivative Instrument Assets (175) 22,687 0 62 Derivative Instrument Assets -Hedges (176) 0 460,316 63 (Less) Long-Term Portion of Derivative Instrument Assests -Hedges (176) 0 0 64 TOTAL Current and Accrued Assets (Total of lines 32 thru 63) 242,970,522 268,614,596 65 DEFERRED DEBITS 66 Unamortized Debt Expense (181) 11,527,001 12,476,292 67 Extraordinary Property Losses (182.1) 230 0 0 68 Unrecovered Plant and Regulatory Study Costs (182.2) 230 0 0 69 Other Regulatory Assets (182.3) 232 573,031,070 576,247,558 70 Preliminary Survey and Investigation Charges (Electric)(183) 467,080 165,866 71 Preliminary Survey and Investigation Charges (Gas)(183.1 and 183.2) 0 0 72 Clearing Accounts (184) 527 28,145 73 Temporary Facilities (185) 0 0 74 Miscellaneous Deferred Debits (186) 233 26,759,597 11,803,983 75 Deferred Losses from Disposition of Utility Plant (187) 0 0 76 Research, Development, and Demonstration Expend. (188) 0 0 77 Unamortized Loss on Reacquired Debt (189) 15,520,432 17,356,781 78 Accumulated Deferred Income Taxes (190) 234-235 136,036, 119 123,261,474 79 Unrecovered Purchased Gas Costs (191) ( 17,880,236) ( 3,921,214) 80 TOTAL Deferred Debits (Total of lines 66 thru 79) 7 45,461,590 737,418,885 81 TOTAL Assets and Other Debits (Total of lines 10-15,30,64,and 80) 4,643,959,465 4,364, 147,768 FERC FORM NO. 2 (REV 06-04) Page 111 PC_DR_009 Attachment B Page 20 of 177 Name of Respondent This 'IB:Jort Is: Date of Report Year/Period of Report Avista Corporation (1) X An Original (Mo, Da, Yr) (2) DA Resubmission 04/15/2016 End of 2015/04 Comparative Balance Sheet (Liabilities and Other Credits) Line Title of Account Reference Current Year Prior Year No. Page Number End of End Balance Quarter/Year 12/31 (a) (b) Balance (d) 1 PROPRIETARY CAPITAL 2 Common Stock Issued (201) 250-251 984,603,843 984,400,740 3 Preferred Stock Issued (204) 250-251 0 0 4 Capital Stock Subscribed (202, 205) 252 0 0 5 Stock Liability for Conversion (203, 206) 252 0 0 6 Premium on Capital Stock (207) 252 0 0 7 Other Paid-In Capital (208-211) 253 ( 9,506,476) ( 9,520,161) 8 Installments Received on Capital Stock (212) 252 0 0 9 (Less) Discount on Capital Stock (213) 254 0 0 10 (Less) Capital Stock Expense (214) 254 ( 29,238,213) ( 25,079, 123) 11 Retained Earnings (215, 215.1, 216) 118-119 536,821,476 507,257,161 12 Unappropriated Undistributed Subsidiary Earnings (216.1) 118-119 ( 5,881,619) ( 15,658,553) 13 (Less) Reacquired Capital Stock (217) 250-251 0 0 14 Accumulated Other Comprehensive Income (219) 117 ( 6,649,771) ( 7,887,881) 15 TOTAL Proprietary Capital (Total of lines 2 thru 14) 1,528,625,666 1,483,670,429 16 LONG TERM DEBT 17 Bonds (221) 256-257 1,536,700,000 1,436,700,000 18 (Less) Reacquired Bonds (222) 256-257 83,700,000 83,700,000 19 Advances from Associated Companies (223) 256-257 51,547,000 51,547,000 20 Other Long-Term Debt (224) 256-257 0 0 21 Unamortized Premium on Long-Term Debt (225) 258-259 177,666 186,550 22 (Less) Unamortized Discount on Long-Term Debt-Dr (226) 258-259 1, 134,563 1,308,604 23 (Less) Current Portion of Long-Term Debt 0 0 24 TOTAL Long-Term Debt (Total of lines 17 thru 23) 1,503,590, 103 1,403,424,946 25 OTHER NONCURRENT LIABILITIES 26 Obligations Under Capital Leases-Noncurrent (227) 3,274,583 0 27 Ac?umulated Provision for Property Insurance (228.1) 0 0 28 Accumulated Provision for Injuries and Damages (228.2) 239,910 240,000 29 Accumulated Provision for Pensions and Benefits (228.3) 201,453,549 189,489, 100 30 Accumulated Miscellaneous Operating Provisions (228.4) 0 0 31 Accumulated Provision for Rate Refunds (229) 11,476,706 5,855,845 FERC FORM NO. 2 (REV 06-04) Page 112 PC_DR_009 Attachment B Page 21 of 177 Name of Respondent This wort Is: Date of Report Year/Period of Report Avista Corporation (1) X An Original (Mo, Da, Yr) (2) DA Resubmission 04/15/2016 End of 2015/04 Comparative Balance Sheet (Liabilities and Other Credits)(continued) Line Title of Account Reference Current Year Prior Year No. Page Number End of End Balance Quarter/Year 12/31 (a) (b) Balance (d) 32 Long-Term Portion of Derivative Instrument Liabilities 52,248,445 22,093,166 33 Long-Term Portion of Derivative Instrument Liabilities -Hedges 0 40,857,456 34 Asset Retirement Obligations (230) 15,996,704 3,028,391 35 TOTAL Other Noncurrent Liabilities (Total of lines 26 thru 34) 284,689,897 261,563,958 36 CURRENT AND ACCRUED LIABILITIES 37 Current Portion of Long-Term Debt 0 0 38 Notes Payable (231) 105,000,000 105,000,000 39 Accounts Payable (232) 109,244,954 111,077,010 40 Notes Payable to Associated Companies (233) 22, 177,680 9,934,843 41 Accounts Payable to Associated Companies (234) 18,798 714,039 42 Customer Deposits (235) 3,273,927 4,977,259 43 Taxes Accrued (236) 262-263 7, 186,818 ( 10, 725,297) 44 Interest Accrued (237) 14,179,517 13,595,667 45 Dividends Declared (238) 0 0 46 Matured Long-Term Debt (239) 0 0 47 Matured Interest (240) 0 0 48 Tax Collections Payable (241) 1,759,040 50,226 49 Miscellaneous Current and Accrued Liabilities (242) 268 57,577,117 57,483,998 50 Obligations Under Capital Leases-Current (243) 871,667 4, 193,852 51 Derivative Instrument Liabilities (244) 85,797,553 40,138,121 52 (Less) Long-Term Portion of Derivative Instrument Liabilities 52,248,445 22,093,166 53 Derivative Instrument Liabilities -Hedges (245) 0 48,202,046 54 (Less) Long-Term Portion of Derivative Instrument Liabilities -Hedges 0 40,857,456 55 TOTAL Current and Accrued Liabilities (Total of lines 37 thru 54) 354,838,626 321,691,142 56 DEFERRED CREDITS 57 Customer Advances for Construction (252) 2, 161,687 1,864,508 58 Accumulated Deferred Investment Tax Credits (255) 12,639, 187 12,157,507 59 Deferred Gains from Disposition of Utility Plant (256) 0 0 60 Other Deferred Credits (253) 269 39,790,303 21,269,740 61 Other Regulatory Liabilities (254) 278 40,976,484 48,834,355 62 Unamortized Gain on Reacquired Debt (257) 260 1,966,507 2,096,044 63 Accumulated Deferred Income Taxes -Accelerated Amortization (281) 0 0 64 Accumulated Deferred Income Taxes -Other Property (282) 646,870,366 582,721,352 65 Accumulated Deferred Income Taxes -Other (283) 227,810,639 224,853,787 66 TOTAL Deferred Credits (Total of lines 57 thru 65) 972,215, 173 893,797,293 67 TOTAL Liabilities and Other Credits (Total of lines 15,24,35,55,and 66) 4,643,959,465 4,364, 147,768 FERC FORM NO. 2 (REV 06-04) Page 113 PC_DR_009 Attachment B Page 22 of 177 Name of Respondent This 0ort Is: Date of Report Year/Period of Report Avista Corporation (1) X An Original (Mo, Da, Yr) (2) DA Resubmission 04/15/2016 End of 2015/04 Statement of Income Quarterly 1. Enter in column (d) the balance for the reporting quarter and in column (e) the balance for the same three month period for the prior year. 2. Report in column (f) the quarter to date amounts for electric utility function; in column (h) the quarter to date amounts for gas utility, and in G) the quarter to date amounts fo~ other utility function for the current year quarter. 3. Report in column (g) the quarter to date amounts for el~ctric utility function; in column (i) the quarter to date amounts for gas utility, and in (k) the quarter to date amounts for other utility function for the prior year quarter. 4. If additional columns are needed place them in a footnote. Annual or Quarterly, if applicable 5. Do not report fourth quarter data in columns (e) and (f) 6. Report amounts for accounts 412 and 413, Revenues and Expenses from Utility Plant Leased to Others, in another utility columnin a similar manner to a utility department. Spread the amount(s) over lines 2 thru 26 as appropriate. Include these amounts in columns (c) and (d) totals. 7. Report amounts in account 414, Other Utility Operating Income, in the same manner as accounts 412 and 413 above. 8. Report data for lines 8, 1 O and 11 for Natural Gas companies using accounts 404.1, 404.2, 404.3, 407.1 and 407.2. 9. Use page 122 for important notes regarding the statement of income for any account thereof. 10. Give concise explanations concerning unsettled rate proceedings where a contingency exists such that refunds of a material amount may need to be made to the utility's customers or which may result in material refund to the utility with respect to power or gas purchases. State for each year effected the gross revenues or costs to which the contingency relates and the tax effects together with an explanation of the major factors which affect the rights of the utility to retain such revenues or recover amounts paid with respect to power or gas purchases. 11 Give concise explanations concerning significant amounts of any refunds made or received during the year resulting from settlement of any rate proceeding affecting revenues received or costs incurred for power or gas purches, and a summary of the adjustments made to balance sheet, income, and expense accounts. 12. If any notes appearing in the report to stokholders are applicable to the Statement of Income, such notes may be included at page 122. 13. Enter on page 122 a concise explanation of only those changes in accounting mehods made during the year which had an effect on net income, including the basis of allocations and apportionments from those used in the preceding year. Also, give the appropriate dollar effect of such changes. 14. Explain in a footnote if the previous year's/quarter's figures are different from that reported in prior reports. 15. If the columns are insufficient for reporting additional utility departments, supply the appropriate account titles report the information in a footnote to this schedule. Title of Account Reference Total Total Current Three Prior Three Page Current Year to Prior Year to Date Months Ended Months Ended Number Date Balance Balance Quarterly Only Quarterly Only Line (a) for Quarter/Year for Quarter/Year No Fourth Quarter No Fourth Quarter No. (b) (c) (d) (e) (~ 1 UTILITY OPERATING INCOME 2 Gas Operating Revenues (400) 300-301 3 Operating Expenses 4 Operation Expenses (401) 317-325 980,245,446 1,034,794,124 0 0 5 Maintenance Expenses (402) 317-325 64,022,756 65,573,481 0 0 6 Depreciation Expense ( 403) 336-338 122,488,709 112,562,200 0 0 7 Depreciation Expense for Asset Retirement Costs ( 403.1) 336-338 0 0 0 0 8 Amortization and Depletion of Utility Plant ( 404-405) 336-338 21,544,004 16,874,247 0 0 9 Amortization of Utility Plant Acu. Adjustment (406) 336-338 99,047 ·99,047 0 0 10 Amor!. of Prop. Losses, Un recovered Plant and Reg. Study Costs (407.1) 0 0 0 0 11 Amortization of Conversion Expenses (407.2) 0 0 0 0 12 Regulatory Debits (407.3) 1,619,427 1,871.414 0 0 13 (Less) Regulatory Credits (407.4) 12,818,909 10,536,841 0 0 14 Taxes Other than Income Taxes ( 408.1) 262-263 95,109,798 93,076,918 0 0 15 Income Taxes-Federal (409.1) 262-263 5,601,404 ( 55, 133,870) 0 0 16 Income Taxes-Other (409.1) 262-263 919,149 ( 1,858,807) 0 0 17 Provision ofDeferred Income Taxes (410.1) 234-235 65,371,809 135,547,906 0 0 18 (Less) Provision for Deferred Income Taxes-Credit (411.1) 234-235 2,423,024 4,060,583 0 0 19 Investment Tax Credit Adjustment-Net (411.4) 481,680 ( 229,524) 0 0 20 (Less) Gains from Disposition of Utility Plant (411.6) 0 0 0 0 21 Losses from Disposition of Utility Plant ( 411.7) 0 0 0 0 22 (Less) Gains from Disposition of Allowances ( 411.8) 0 0 0 0 23 Losses from Disposition of Allowances (411.9) 0 0 0 0 24 Accretion Expense ( 411.10) 0 0 0 0 25 TOT AL Utility Operating Expenses (Total of lines 4 thru 24) 1,342,261,296 1,388,579,712 0 0 26 Net Utility Operating Income (Total of lines 2 less 25) (Carry forward to page 116, line 27) 188,282,443 184,396,429 0 0 FERC FORM NO. 2 (REV 06-04) Page 114 PC_DR_009 Attachment B Page 23 of 177 Name of Respondent Avista Corporation Elec. Utility Current Year to Date Line (in dollars) No. (g) 4 567,238,063 5 50,148,482 6 95,895,130 7 0 8 16,519,997 9 99,047 10 0 11 0 12 2,650,525 13 12,146,367 14 72,133,173 15 10,884,847 16 936,622 17 54,107,931 18 2,599,365 19 511,740 20 0 21 0 22 0 23 0 24 0 25 856,379,825 26 149,760,236 FERC FORM NO. 2 (REV 06-04) Elec. Utility Previous Year to Date (in dollars) (h) 584,239,618 51,160,378 89,097,411 0 13,008,487 99,047 0 0 1,535,950 10,108,656 69,580,534 ( 27,894,913) ( 716,972) 94,097,395 4,203,362 195,528) 0 0 0 0 0 859,699,389 155,404,484 This ~ort Is: (1) ~An Original (2) DA Resubmission Statement of Income Gas Utility Gas Utility Current Previous Year to Date Year to Date (in dollars) (i) (in dollars) U) 413,007,383 450,554,506 13,874,274 14,413,103 26,593,579 23,464,789 0 0 5,024,007 3,865,760 0 0 0 0 0 0 1,031,098) 335,464 672,542 428,185 22,976,625 23,496,384 ( 5,283,443) ( 27,238,957) ( 17,473) ( 1,141,835) 11,263,878 41,450,511 ( 176,341) ( 142,779) ( 30,060) ( 33,996) 0 0 0 0 0 0 0 0 0 0 485,881,471 528,880,323 38,522,207 28,991,945 Page 115 Date of Report (Mo, Da, Yr) 04/15/2016 Other Utility Current Year to Date (in dollars) (k) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Year/Period of Report End of 2015/04 Other Utility Previous Year to Date (in dollars) (I) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 PC_DR_009 Attachment B Page 24 of 177 Name of Respondent Avista Corporation Title of Account Line (a) No. 27 Net Utility Operating Income (Carried forward from page 114) 28 OTHER INCOME AND DEDUCTIONS 29 Other Income 30 Nonutility Operating Income 31 Revenues form Merchandising, Jobbing and Contract Work (415) 32 (Less) Costs and Expense of Merchandising, Job & Contract Work (416) 33 Revenues from Nonutility Operations (417) 34 (Less) Expenses ofNonutility Operations (417.1) 35 Nonoperating Rental Income (418) 36 Equity in Earnings of Subsidiary Companies ( 418. 1) 37 Interest and Dividend Income (419) 38 Allowance for Other Funds Used During Construction (419. 1) 39 Miscellaneous Nonoperating Income (421) 40 Gain on Disposition of Property (421.1) 41 TOTAL Other Income (Total oflines 31thru40) 42 Other Income Deductions 43 Loss on Disposition of Property (421.2) 44 Miscellaneous Amortization (425) 45 Donations (426.1) 46 Life Insurance (426.2) 47 Penalties (426.3) 48 Expenditures for Certain Civic, Political and Related Activities (426.4) 49 Other' Deductions (426.5) 50 TOT AL Other Income Deductions (Total of lines 43 thru 49) 51 Taxes Applic. to Other Income and Deductions 52 Taxes Other than Income Taxes (408.2) 53 Income Taxes-Federal (409.2) 54 Income Taxes-Other (409.2) 55 Provision for Deferred Income Taxes (410.2) 56 (Less) Provision for Deferred Income Taxes-Credit (411.2) 5 7 Investment Tax Credit Adjustments-Net ( 411.5) 58 (Less) Investment Tax Credits (420) 59 TOTAL Taxes on Other Income and Deductions (Total of lines 52-58) 60 Net Other Income and Deductions (Total of lines 41, 50, 59) 61 INTEREST CHARGES 62 Interest on Long-Term Debt (427) 63 Amortization of Debt Disc. and Expense (428) 64 Amortization of Loss on Reacquired Debt ( 428.1) 65 (Less) Amortization of Premium on Debt-Credit (429) 66 (Less) Amortization of Gain on Reacquired Debt-Credit (429. 1) 67 Interest on Debt to Associated Companies (430) 68 Other Interest Expense (431) 69 (Less) Allowance for Borrowed Funds Used During Construction-Credit (432) 70 Net Interest Charges (Total of lines 62 thru 69) 71 Income Before Extraordinary Items (Total of lines 27,60 and 70) 72 EXTRAORDINARY ITEMS 73 Extraordinary Income (434) 7 4 (Less) Extraordinary Deductions (435) 7 5 Net Extraordinary Items (Total of line 73 less line 7 4) 76 Income Taxes-Federal and Other (409.3) 77 Extraordinary Items after Taxes (Total of line 75 less line 76) 78 Net Income (Total of lines 71 and 77) FERC FORM NO. 2 (REV 06-04) This ~Ort Is: (1) ~An Original (2) DA Resubmission Date of Report (Mo, Da, Yr) 04/15/2016 Year/Period of Report End of 2015/04 Statement of Income( continued) Reference Total Total Current Three Prior Three Page Current Year to Prior Year to Date Months Ended Months Ended Number Date Balance Balance Quarterly Only Quarterly Only for Quarter/Year for Quarter/Year No Fourth Quarter No Fourth Quarter (b) (c) (d) (e) (n I I I I I I · I I I I I I I I I 0 0 0 0 0 0 0 0 17,531) 9,566,840 9,837,245 939) 1,100) 119 11,164,785 82,361,715 645,403 1,845,367 7,961,552 8,678,360 795,424 0 0 142,552 290,479 11,141,937 83,320,045 I I I I I 38,668 340 3,208,021 3,879,397 3,079,994 2,060,570 70,316 24,718) 1,625,650 1,679,329 1,386,500 3,295,162 340 9,370,481 10,928,408 I I I I I 262-263 202,511 150,614 262-263 715,329) 314,356) 262-263 886,632) 2,579,615 0 234-235 1,006,935 1,467,880) 0 234-235 5,704,734 6,039,386 0 0 0 0 0 6,097,249) 5,091,393) 0 7,868,705 77,483,030 0 I I I I I 69,747,769 67,341,170 0 0 258-259 419,914 424,830 0 0 3,004,198 3,219,369 0 0 258-259 8,883 8,883 0 0 0 0 0 340 605,274 0 340 2,636,227 2,037,957 3,480,392 3,911,170 0 72,924,107 69, 103,273 0 123,227,041 192, 776, 186 I I I I I 0 0 262-263 123,227,041 192,776, 186 Page 116 PC_DR_009 Attachment B Page 25 of 177 This Page Intentionally Left Blank PC_DR_009 Attachment B Page 26 of 177 Name of Respondent This wort Is: Date of Report Year/Period of Report Avista Corporation (1) An Original (Mo, Da, Yr) End of 2015/04 (2) DA Resubmission 04/15/2016 Statement of Accumulated Comprehensive Income and Hedging Activities 1. Report in columns (b) (c) and (e) the amounts of accumulated other comprehensive income items, on a net-of-tax basis, where appropriate. 2. Report in columns (f) and (g) the amounts of other categories of other cash flow hedges. 3. For each category of hedges that have been accounted for as "fair value hedges", report the accounts affected and the related amounts in a footnote. Unrealized Gains Minimum Pension Foreign Currency Other Line and Losses on liabililty Adjustment Hedges Adjustments No. Item available-for-sale (net amount) securities (a) (b) (c) (d) (e) 1 Balance of Account 219 at Beginning of Preceding Year ( 1,585,855) ( 4,234,075) 2 Preceding Quarter/Year to Date Reclassifications from Account 219 to Net Income 460,497 3 Preceding Quarter/Year to Date Changes in Fair Value 1, 125,358 ( 3,653,806) 4 Total (lines 2 and 3) 1,585,855 ( 3,653,806) 5 Balance of Account 219 at End of Preceding Quarter/Year ( 7,887,881) 6 Balance of Account 219 at Beginning of Current Year ( 7,887,881) 7 Current Quarter/Year to Date Reclassifications from Account 219 to Net Income 8 Current Quarter/Year to Date Changes in Fair Value 1,238, 110 9 Total (lines 7 and 8) 1,238, 110 10 Balance of Account 219 at End of Current Quarter/Year ( 6,649,771) I FERC FORM NO. 2 (NEW 06-02) Page 117 PC_DR_009 Attachment B Page 27 of 177 Name of Respondent Avista Corporation This ~Ort Is: (1) ~An Original (2) DA Resubmission Date of Report (Mo, Da, Yr) 04/15/2016 Statement of Accumulated Com rehensive Income and Hed in Activities continued Line No. 2 3 4 5 6 7 8 9 10 Other Cash Flow Hedges Interest Rate Swaps FERC FORM NO. 2 (NEW 06-02) Other Cash Flow Hedges (Insert Category) (g) Totals for each category of items recorded in Account 219 (h) 5,819,930) 460,497 2,528,448) 2,067,951) 7,887,881) 7,887,881) 1,238, 110 1,238, 110 6,649,771) Page 117a Net Income (Carried Forward from Page 116, Line 78) (i) Year/Period of Report End of 2015/04 Total Comprehensive Income PC_DR_009 Attachment B Page 28 of 177 Name of Respondent Avista Corporation This ~Ort Is: (1) 12$_JAn Original (2) DA Resubmission Statement of Retained Earnings Date of Report (Mo, Da, Yr) 04/15/2016 1. Report all changes in appropriated retained earnings, unappropriated retained earnings, and unappropriated undistributed subsidiary earnings for the year. Year/Period of Report End of 2015/04 2. Each credit and debit during the year should be identified as to the retained earnings account in which recorded (Accounts 433, 436-439 inclusive). Show the contra primary account affected in column (b). 3. State the purpose and amount for each reservation or appropriation of retained earnings. 4. List first Account 439, Adjustments to Retained Earnings, reflecting adjustments to the opening balance of retained earnings. Follow by credit, then debit items, in that order. 5. Show dividends for each class and series of capital stock. Line No. 2 3 4 5 6 7 8 Item (a) UNAPPROPRIATED RETAINED EARNINGS Balance-Beginning of Period Changes (Identify by prescribed retained earnings accounts) Adjustments to Retained Earnings (Account 439) TOTAL Credits to Retained Earnings (Account 439) (footnote details) TOTAL Debits to Retained Earnings (Account 439) (footnote details) Balance Transferred from Income (Acct 433 less Acct 418 .1) Appropriations of Retained Earnings (Account 436) TOTAL Appropriations of Retained Earnings (Account 436) (footnote details) 9 Dividends Declared-Preferred Stock (Account 437) 1 O TOTAL Dividends Declared-Preferred Stock (Account 437) (footnote details) 11 Dividends Declared-Common Stock (Account 438) 12 TOTAL Dividends Declared-Common Stock (Account 438) (footnote details) 13 Transfers from Account 216.1, Unappropriated Undistributed Subsidiary Earnings 14 Balance-End of Period (Total of lines 1, 4, 5, 6, 8, 10, 12, and 13) 15 APPROPRIATED RETAINED EARNINGS (Account215) 16 TOTAL Appropriated Retained Earnings (Account 215) (footnote details) 17 APPROPRIATED RETAINED EARNINGS-AMORTIZATION RESERVE, FEDERAL (Account 18 TOTAL Appropriated Retained Earnings-Amortization Reserve, Federal (Account 19 TOTAL Appropriated Retained Earnings (Accounts 215, 215.1) (Total of lines 20 TOTAL Retained Earnings (Accounts 215, 215.1, 216) (Total of lines 14 and 1 21 UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (Account216.1) Report only on an Annual Basis no Quarterly 22 Balance-Beginning of Year (Debit or Credit) 23 Equity in Earnings for Year (Credit) (Account 418.1) 24 (Less) Dividends Received (Debit) 25 Other Changes (Explain) 26 Balance-End of Year Contra Primary Account Affected (b) Current Quarter Year to Date Balance (c) Previous Quarter Year to Date Balance (d) ----------------~~ 1,488,991) 39,369,910) 112,062,256 109,678,973 5,158,174) 4,555,754) 5,918,024) 82,361,715 1,387,851) 92,102,244) 5,881,619) 15,658,553) FERC FORM NO. 2 (REV 06-04) Page 118-119 PC_DR_009 Attachment B Page 29 of 177 This Page Intentionally Left Blank PC_DR_009 Attachment B Page 30 of 177 Name of Respondent This ~Ort Is: (1) ~An Original (2) DA Resubmission Avista Corporation Statement of Cash Flows Date of Report (Mo, Da, Yr) 04/15/2016 Year/Period of Report End of 2015/Q4 (1) Codes to be used:(a) Net Proceeds or Payments;(b)Bonds, debentures and other long-term debt; (c) Include commercial paper; and (d) Identify separately such items as investments, fixed assets, intangibles, etc. (2) Information about noncash investing and financing activities must be provided in the Notes to the Financial statements. Also provide a reconciliation between "Cash and Cash Equivalents at End of Period" with related amounts on the Balance Sheet. (3) Operating Activities -Other: Include gains and losses pertaining to operating activities only. Gains and losses pertaining to investing and financing activities should be reported in those activities. Show in the Notes to the Financials the amounts of interest paid (net of amount capitalized) and income taxes paid. (4) Investing Activities: Include at Other (line 25) net cash outflow to acquire other companies. Provide a reconciliation of assets acquired with liabilities assumed in the Notes to the Financial Statements. Do not include on this statement the dollar amount of leases capitalized per the USofA General Instruction 20; instead provide a reconciliation of the dollar amount of leases capitalized with the plant cost. Line No. Description (See Instructions for explanation of codes) (a) Net Cash Flow from Operating Activities 2 Net Income (Line 78(c) on page 116) 3 Noncash Charges (Credits) to Income: 4 Depreciation and Depletion 5 Amortization of deferred power and gas costs, debt expense and exchange power 6 Deferred Income Taxes (Net) 7 lnvestmentTax Credit Adjustments (Net) 8 Net (Increase) Decrease in Receivables 9 Net (Increase) Decrease in Inventory 10 Net (Increase) Decrease in Allowances Inventory 11 Net Increase (Decrease) in Payables and Accrued Expenses 12 Net (Increase) Decrease in Other Regulatory Assets 13 Net Increase (Decrease) in Other Regulatory Liabilities 14 (Less) Allowance for Other Funds Used During Construction 15 (Less) Undistributed Earnings from Subsidiary Companies 16 Other (footnote details): 17 Net Cash Provided by (Used in) Operating Activities 18 (Total of Lines 2 thru 16) 19 20 Cash Flows from Investment Activities: 21 Construction and Acquisition of Plant (including land): 22 Gross Additions to Utility Plant (less nuclear fuel) 23 Gross Additions to Nuclear Fuel 24 Gross Additions to Common Utility Plant 25 Gross Additions to Nonutility Plant 26 (Less) Allowance for Other Funds Used During Construction 27 Other (footnote details): 28 Cash Outflows for Plant (Total of lines 22 thru 27) 29 30 Acquisition of Other Noncurrent Assets ( d) 31 Proceeds from Disposal of Noncurrent Assets ( d) 32 Federal and state grant payments received 33 Investments in and Advances to Assoc. and Subsidiary Companies 34 Contributions and Advances from Assoc. and Subsidiary Companies 35 Disposition of Investments in (and Advances to) 36 Associated and Subsidiary Companies 37 Cash paid for acquisition 38 Purchase of Investment Securities (a) 39 Proceeds from Sales of Investment Securities (a) FERC FORM NO. 2 (REV 06-04) Page 120 Current Year to Date Quarter/Year 138,235,780 27,223,055 53,931, 102 481,680 3,884,715) 12,267,853 6,880,544 4, 114,779) 2,007,784 7,961,552 ( 381,174,406) ( 381, 174,406) 272,897 2,730, 166 94,643) Previous Year to Date Quarter/Year 126,986,417 8,525,668) 123, 968, 809 229,524) 17,645,850 19,413,226) 40,191,116) 10,925,414 4,616,847 ( 323,931, 192) ( 323,931, 192) 2,529,902 4,697,090) PC_DR_009 Attachment B Page 31 of 177 Name of Respondent Avista Corporation This ~ort Is: (1) ~An Original (2) DA Resubmission Statement of Cash Flows (continued) Line No. Description (See Instructions for explanation of codes) (a) 40 Loans Made or Purchased 41 Collections on Loans 42 Restricted cash 43 Net (Increase) Decrease in Receivables 44 Net (Increase) Decrease in Inventory 45 Net (Increase) Decrease in Allowances Held for Speculation 46 Net Increase (Decrease) in Payables and Accrued Expenses 47 Changes in other property and investments 48 Net Cash Provided by (Used in) Investing Activities 49 (Total of lines 28 thru 47) 50 51 Cash Flows from Financing Activities: 52 Proceeds from Issuance of: 53 Long-Term Debt (b) 54 Preferred Stock 55 Common Stock 56 Other (footnote details): 57 Net Increase in Short-term Debt (c) 58 Cash received for settlement of interest rate swap agreements 59 Cash Provided by Outside Sources (Total of lines 53 thru 58) 60 61 Payments for Retirement of: 62 Long-Term Debt (b) 63 Preferred Stock 64 Common Stock 65 Other 66 Net Decrease in Short-Term Debt (c) 67 Premium paid to repurchase long-term debt 68 Dividends on Preferred Stock 69 Dividends on Common Stock 70 Net Cash Provided by (Used in) Financing Activities 71 (Total of lines 59 thru 69) 72 73 Net Increase (Decrease) in Cash and Cash Equivalents 74 (Total of line 18, 49 and 71) 75 76 Cash and Cash Equivalents at Beginning of Period 77 78 Cash and Cash Equivalents at End of Period FERG FORM NO. 2 (REV 06-04) Page 120a Date of Report (Mo, Da, Yr) 04/15/2016 Current Year to Date Quarter/Year 62,284) 7,992,961) 100,000,000 1,559,840 101,559,840 82,396,801) Year/Period of Report End of 2015/Q4 Previous Year to Date Quarter/Year· 94,098 373,865) 60,000,000 4,059,874 5,429,000 69,488,874 ( 79,855,898) ( 1,403,511) 66,000,000) 78,313,788) PC_DR_009 Attachment B Page 32 of 177 Name of Respondent This Report is: (1) X An Original Avista Corporation (2) A Resubmission FOOTNOTE DATA !Schedule Page: 120 Line No.: 16 Column: c Power and natural gas deferrals Change in special deposits Change in other current assets Non-cash stock compensation Cash paid for foreign currency hedges Allowance for doubtful accounts Change in other non-current assets and liabilities Change in Coyote Springs 2 O&M L TSA Prelim survey and investigation costs Tax shortfalls from stock com ensation Schedule Pa e: 120 Line No.: 16 Column: b 1, 104,752 (23,301,320) (5,671,849) 6,006,850 20,692 5,200,000 (15,740,101) ( 1, 082,230) 709,287 513,385 Power and natural gas deferrals Change in special deposits Change in other current assets Non-cash stock compensation 1,121,287 (13 f 301, 265) Other non-current assets and liabilities Allowance for doubtful accounts Amortization of Spokane Energy contract Change in Coyote Springs 2 O&M LTSA Preliminary survey and investigation costs Gain on sale of property and equipment Other !Schedule Page: 120 Line No.: 34 Column: c Notes receivable from subsidiaries 15,444,378 Dividends received from subsidiaries 197,000,000 !Schedule Page: 120 Line No.: 34 Column: b Notes receivable from subsidiaries 12, 185,571 Dividends received from subsidiaries 2,000,000 !Schedule Page: 120 Line No.: 65 Column: b Minimum tax withholdings for share based compensation Cash paid for settlement of interest rate swap Long-term debt issuance costs Excess tax benefits !Schedule Page: 120 Line No.: 65 Column: c Long-term debt issuance costs (1,510,532) Excess tax benefits 107,021 2,856,640 6,913,619 5,891,691 5,749,995 9,499,494 (2 f 260 f 661) (301,214) (142,552) (2 f 587) (1,831,678) (9,326,000) . (593,969) 180,430 I FERC FORM NO. 2 (12-96) Page 552.1 Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2016 2015/04 PC_DR_009 Attachment B Page 33 of 177 This Page Intentionally Left Blank PC_DR_009 Attachment B Page 34 of 177 Name of Respondent This Report is: Date of Report Year/Period of Report (1) 6 An Original (Mo, Da, Yr) Avista Corporation (2) A Resubmission 04/15/2016 2015/04 Notes to Financial Statements 1. Provide important disclosures regarding the Balance Sheet, Statement of Income for the Year, Statement of Retained Earnings for the Year, and Statement of Cash Flow, or any account thereof. Classify the disclosures according to each financial statement, providing a subheading for each statement except where a disclosure is applicable to more than one statement. The disclosures must be on the same subject matters and in the same level of detail that would be required if the respondent issued general purpose financial statements to the public or shareholders. 2. Furnish details as to any significant contingent assets or liabilities existing at year end, and briefly explain any action initiated by the Internal Revenue Service involving possible assessment of additional income taxes of material amount, or a claim for refund of income taxes of a material amount initiated by the utility. Also, briefly explain any dividends in arrears on cumulative preferred stock. 3. Furnish details on the respondent's pension plans, post-retirement benefits other than pensions (PBOP) plans, and post-employment benefit plans as required by instruction no. 1 and, in addition, disclose for each individual plan the current year's cash contributions. Furnish details on the accounting for the plans and any changes in the method of accounting for them. Include details on the accounting for transition obligations or assets, gains or losses, the amounts deferred and the expected recovery periods. Also, disclose any current year's plan or trust curtailments, terminations, transfers, or reversions of assets. Entities that participate in multiemployer postretirement benefit plans (e.g. parent company sponsored pension plans) disclose in addition to the required disclosures for the consolidated plan, (1) the amount of cost recognized in the respondent's financial statements for each plan for the period presented, and (2) the basis for determining the respondent's share of the total plan costs. 4. Furnish details on the respondent's asset retirement obligations (ARO) as required by instruction no. 1 and, in addition, disclose the amounts recovered through rates to settle such obligations. Identify any mechanism or account in which recovered funds are being placed (i.e. trust funds, insurance policies, surety bonds). Furnish details on the accounting for the asset retirement obligations and any changes in the measurement or method of accounting for the obligations. Include details on the accounting for settlement of the obligations and any gains or losses expected or incurred on the settlement. 5. Provide a list of all environmental credits received during the reporting period. 6. Provide a summary of revenues and expenses for each tracked cost and special surcharge. 7. Where Account 189, Unamortized Loss on Reacquired Debt, and 257, Unamortized Gain on Reacquired Debt, are not used, give an explanation, providing the rate treatment given these item. See General Instruction 17 of the Uniform System of Accounts. 8. Explain concisely any retained earnings restrictions and state the amount of retained earnings affected by such restrictions. 9. Disclose details on any significant financial changes during the reporting year to the respondent or the respondent's consolidated group that directly affect the respondent's gas pipeline operations, including: sales, transfers or mergers of affiliates, investments in new partnerships, sales of gas pipeline facilities or the sale of ownership interests in the gas pipeline to limited partnerships, investments in related industries (i.e., production, gathering), major pipeline investments, acquisitions by the parent corporation(s), and distributions of capital. 10. Explain concisely unsettled rate proceedings where a contingency exists such that the company may need to refund a material amount to the utility's customers or that the utility may receive a material refund with respect to power or gas purchases. State for each year affected the gross revenues or costs to which the contingency relates and the tax effects and explain the major factors that affect the rights of the utility to retain such revenues or to recover amounts paid with respect to power and gas purchases. 11. Explain concisely significant amounts of any refunds made or received during the year resulting from settlement of any rate proceeding affecting revenues received or costs incurred for power or gas purchases, and summarize the adjustments made to balance sheet, income, and expense accounts. 12. Explain concisely only those significant changes in accounting methods made during the year which had an effect on net income, including the basis of allocations and apportionments from those used in the preceding year. Also give the approximate dollar effect of such changes. 13. For the 3Q disclosures, respondent must provide in the notes sufficient disclosures so as fo make the interim information not misleading. Disclosures which would substantially duplicate the disclosures contained in the most recent FERC Annual Report may be omitted. 14. For the 3Q disclosures, the disclosures shall be provided where events subsequent to the end of the most recent year have occurred which have a material effect on the respondent. Respondent must include in the notes significant changes since the most recently completec:l year in such items as: accounting principles and practices; estimates inherent in the preparation of the financial statements; status of long-term contracts; capitalization including significant new borrowings or modifications of existing financing agreements; and changes resulting from business combinations or dispositions. However were material contingencies exist, the disclosure of such matters shall be provided even though a significant change since year end may not have occurred. 15. Finally, if the notes to the financial statements relating to the respondent appearing in the annual report to the stockholders are applicable and furnish the data required by the above instructions, such notes may be included herein. NOTES TO FINANCIAL STATEMENTS NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Nature of Business Avista Corp. is primarily an electric and natural gas utility with certain other business ventures. Avista Corp. provides electric distribution and transmission, and natural gas distribution services in parts of eastern Washington and northern Idaho. Avista Corp. also provides natural gas distribution service in parts of northeastern and southwestern Oregon. Avista Corp. has electric generating facilities in Washington, Idaho, Oregon and Montana. Avista Corp. also supplies electricity to a small number of customers in Montana, most of whom are employees who operate Avista Corp. 's Noxon Rapids generating facility. On July 1, 2014, Avista Corp. acquired AERC, and as of that date, AERC became a wholly-owned subsidiary of Avista Corp. The I FERC FORM NO. 2/3-Q (REV 12-07) 122.1 PC_DR_009 Attachment B Page 35 of 177 Name of Respondent This Report is: Date of Report Year/Period of Report (1) ~An Original (Mo, Da, Yr) Avista Corporation (2) A Resubmission 04/15/2016 2015/04 Notes to Financial Statements primary subsidiary of AERC is AEL&P, comprising regulated electric utility operations in Juneau, Alaska. There are no AERC earnings included in the overall results of Avista Corp. prior to July 1, 2014. See Note 3 for information regarding the acquisition of AERC. Avista Capital, a wholly owned subsidiary of Avista Corp., is the parent company of all of the subsidiary companies except AERC. During the first half of2014 and prior, Avista Capital's subsidiaries included Ecova, which was an 80.2 percent owned subsidiary prior to its disposition on June 30, 2014. Ecova was a provider of energy efficiency and other facility information and cost management programs and services for multi-site customers and utilities throughout North America. See Note 4 for information regarding the disposition of Ecova. Basis of Reporting The financial statements include the assets, liabilities, revenues and expenses of the Company and have been prepared in accordance with the accounting requirements of the Federal Energy Regulatory Commission (FERC) as set forth in its applicable Uniform System of Accounts and published accounting releases, which is a comprehensive basis of accounting other than accounting principles generally accepted in the United States of America (U.S. GAAP). As required by the FERC, the Company accounts for its investment in majority-owned subsidiaries on the equity method rather than consolidating the assets, liabilities, revenues, and expenses of these subsidiaries, as required by U.S. GAAP. The accompanying financial statements include the Company's proportionate share of utility plant and related operations resulting from its interests in jointly owned plants. In addition, under the requirements of the FERC, there are differences from U.S. GAAP in the presentation of (I) current portion oflong-term debt (2) assets and liabilities for cost of removal of assets, (3) assets held for sale, ( 4) regulatory assets and liabilities, (5) deferred income taxes associated with accounts other than utility property, plant and equipment, (6) comprehensive income, (7) unamortized debt issuance costs and (8) operating revenues and resource costs associated with settled energy contracts that are "booked out" (not physically delivered). Use of Estimates The preparation of the financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported for assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts ofrevenues and expenses during the reporting period. Significant estimates include: • determining the market value of energy commodity derivative assets and liabilities, • pension and other postretirement benefit plan obligations, • contingent liabilities, • goodwill impairment testing, • recoverability of regulatory assets, and • unbilled revenues. Changes in these estimates and assumptions are considered reasonably possible and may have a material effect on the financial statements and thus actual results could differ from the amounts reported and disclosed herein. System of Accounts The accounting records of the Company's utility operations are maintained in accordance with the uniform system of accounts prescribed by the FERC and adopted by the state regulatory commissions in Washington, Idaho, Montana and Oregon. Regulation I FERC FORM NO. 2/3-Q (REV 12-07) 122.2 PC_DR_009 Attachment B Page 36 of 177 Name of Respondent This Report is: Date of Report Year/Period of Report (1) 6 An Original (Mo, Da, Yr) Avista Corporation (2) A Resubmission 04/15/2016 2015/04 Notes to Financial Statements The Company is subject to state regulation in Washington, Idaho, Montana and Oregon. The Company is also subject to federal regulation primarily by the FERC, as well as various other federal agencies with regulatory oversight of particular aspects of its operations. Operating Revenues Operating revenues related to the sale of energy are recorded when service is rendered or energy is delivered to customers. The determination of the energy sales to individual customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each calendar month, the amount of energy delivered to customers since the date of the last meter reading is estimated and the corresponding unbilled revenue is estimated and recorded. Our estimate of unbilled revenue is based on: • the number of customers, • current rates, • meter reading dates, • actual native load for electricity, • actual throughput for natural gas, and • electric line losses and natural gas system losses. Any difference between actual and estimated revenue is automatically corrected in the following month when the actual meter reading and customer billing occurs. Accounts receivable includes unbilled energy revenues of the following amounts as of December 31 (dollars in thousands): 2015 2014 Unbilled accounts receivable $ 59,405 $ 78,007 Depreciation For utility operations, depreciation expense is estimated by a method of depreciation accounting utilizing composite rates for utility plant. Such rates are designed to provide for retirements of properties at the expiration of their service lives. For utility operations, the ratio of depreciation provisions to average depreciable property was as follows for the years ended December 31: 2015 Ratio of depreciation to average depreciable property 3.09% The average service lives for the following broad categories of utility plant in service are (in years): Electric thermal/other production Hydroelectric production Electric transmission Electric distribution I FERC FORM NO. 2/3-Q (REV 12-07) 122.3 2014 2.97% Avista Corp. 40 79 57 36 PC_DR_009 Attachment B Page 37 of 177 Name of Respondent This Report is: Date of Report Year/Period of Report (1) 6 An Original (Mo, Da, Yr) Avista Corporation (2) _A Resubmission 04/15/2016 2015/04 Notes to Financial Statements Natural gas distribution property 45 Taxes Other Than Income Taxes Taxes other than income taxes include state excise taxes, city occupational and franchise taxes, real and personal property taxes and certain other taxes not based on net income. These taxes are generally based on revenues or the value of property. Utility related taxes collected from customers (primarily state excise taxes and city utility taxes) are recorded as operating revenue and expense and totaled the following amounts for the years ended December 31 (dollars in thousands): 2015 2014 Utility taxes $ 57,716 $ 57,599 Allowance for Funds Used During Construction The AFUDC represents the cost of both the debt and equity funds used to finance utility plant additions during the construction period. As prescribed by regulatory authorities, AFUDC is capitalized as a part of the cost of utility plant and the debt component is credited against total interest expense in the Statements of Income in the line item "capitalized interest." The equity component ofAFUDC is included in the Statement ofincome in the line item "other income-net." The Company is permitted, under established regulatory rate practices, to recover the capitalized AFUDC, and a reasonable return thereon, through its inclusion in rate base and the provision for depreciation after the related utility plant is placed in service. Cash inflow related to AFUDC does not occur until the related utility plant is placed in service and included in rate base. The effective AFUDC rate was the following for the years ended December 31: 2015 2014 Effective AFUDC rate 7.32% 7.64% Income Taxes A deferred income tax asset or liability is determined based on the enacted tax rates that will be in effect when the differences between the financial statement carrying amounts and tax basis of existing assets and liabilities are expected to be reported in the Company's consolidated income tax returns. The deferred income tax expense for the period is equal to the net change in the deferred income tax asset and liability accounts from the beginning to the end of the period. The effect on deferred income taxes from a change in tax rates is recognized in income in the period that includes the enactment date. Deferred income tax liabilities and regulatory assets are established for income tax benefits flowed through to customers. The Company recognizes the effect of state tax credits, which are generated from utility plant, as they are utilized. The Company did not incur any penalties on income tax positions in 2015 or 2014. The Company would recognize interest accrued related to income tax positions as interest expense and any penalties incurred as other income deductions. Stock-Based Compensation The Company currently issues three types of stock-based compensation awards -restricted shares, market-based awards and performance-based awards. Historically, these stock compensation awards have not been material to the Company's overall financial results. Compensation cost relating to share-based payment transactions is recognized in the Company's financial statements based on the fair value of the equity or liability instruments issued and recorded over the requisite service period. The Company recorded stock-based compensation expense (included in other operating expenses) and income tax benefits in the Statements of Income of the following amounts for the years ended December 31 (dollars in thousands): 2015 2014 I FERC FORM NO. 2/3-Q (REV 12-07) 122.4 PC_DR_009 Attachment B Page 38 of 177 Name of Respondent Avista Corporation Stock-based compensation expense Income tax benefits This Report is: (1) XAn Original (2) A Resubmission Notes to Financial Statements Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2016 $ 6,914 $ 2,420 2015/04 6,007 2,102 .. Restricted share awards vest in equal thirds each year over a three-year period and are payable in Avista Corp. common stock at the end of each year if the service condition is met. In addition to the service condition, the Company must meet a return on equity target in order for the CEO's restricted shares to vest. Restricted stock is valued at the close of market of the Company's common stock on the grant date. Total Shareholder Return (TSR) awards are market-based awards and Cumulative Earnings Per Share (CEPS) awards are performance awards. CEPS awards were first granted in 2014. Both types of awards vest after a period of three years and are payable in cash or Avista Corp. common stock at the end of the three-year period. The method of settlement is at the discretion of the Company and historically the Company has settled these awards through issuance of A vista Corp. common stock and intends to continue this practice. Both types of awards entitle the recipients to dividend equivalent rights, are subject to forfeiture under certain circumstances, and are subject to meeting specific market or performance conditions. Based on the level of attainment of the market or performance conditions, the amount of cash paid or common stock issued will range from 0 to 200 percent of the initial awards granted. Dividend equivalent rights are accumulated and paid out only on shares that eventually vest and have met the market and performance conditions. For both the TSR awards and the CEPS awards, the Company accounts for them as equity awards and compensation cost for these awards is recognized over the requisite service period, provided that the requisite service period is rendered. For TSR awards, ifthe market-condition is not met at the end of the three-year service period, there will be no change in the cumulative amount of compensation cost recognized, since the awards are still considered vested even though the market metric was not met. For CEPS awards, at the end of the three-year service period, if the internal performance metric of cumulative earnings per share is not met, all compensation cost for these awards is reversed as these awards are not considered vested. The fair value of each TSR award is estimated on the date of grant using a statistical model that incorporates the probability of meeting the market targets based on historical returns relative to a peer group. The estimated fair value of the equity component of CEPS awards was estimated on the date of grant as the share price of A vista Corp. common stock on the date of grant, less the net present value of the estimated dividends over the three-year period. The following table summarizes the number of grants~ vested and unvested shares, earned shares (based on market metrics), and other pertinent information related to the Company's stock compensation awards for the years ended December 31: Restricted Shares Shares granted during the year Shares vested during the year Unvested shares at end of year Unrecognized compensation expense at end of year (in thousands) TSRAwards TSR shares granted during the year TSR shares vested during the year TSR shares earned based on market metrics Unvested TSR shares at end of year I FERC FORM NO. 2/3-Q (REV 12-07) 122.5 $ 2015 58,302 (60,379) 106,091 1,705 116,435 (171,334) 222,734 223,697 2014 62,075 (52,899) 112,042 $ 1,349 117,550 (167,584) 97,199 287,834 PC_DR_009 Attachment B Page 39 of 177 Name of Respondent This Report is: Date of Report Year/Period of Report (1) 6 An Original (Mo, Da, Yr) Avista Corporation (2) A Resubmission 04/15/2016 2015/04 Notes to Financial Statements Unrecognized compensation expense (in thousands) $ 3,219 $ 2,833 CEPS Awards CEPS shares granted during the year 58,259 59,025 Unvested CEPS shares at end of year 111,887 58,017 Unrecognized compensation expense (in thousands) $ 1,840 $ 1,577 Outstanding TSR and CEPS share awards include a dividend component that is paid in cash. This component of the share grants is accounted for as a liability award. These liability awards are revalued on a quarterly basis taking into account the number of awards outstanding, historical dividend rate, the change in the value of the Company's common stock relative to an external benchmark (TSR awards only) and the amount of CEPS earned to-date compared to estimated CEPS over the performance period (CEPS awards only). Over the life of these awards, the cumulative amount of compensation expense recognized will match the actual cash paid. As of December 31, 2015 and 2014, the Company had recognized cumulative compensation expense and a liability of $1.5 million and $1.3 million, respectively, related to the dividend component on the outstanding and unvested share grants. Cash and Cash Equivalents For the purposes of the Statements of Cash Flows, the Company considers all temporary investments with a maturity of three months or less when purchased to be cash equivalents. Allowance for Doubtful Accounts The Company maintains an allowance for doubtful accounts to provide for estimated and potential losses on accounts receivable. The Company determines the allowance for utility and other customer accounts receivable based on historical write-offs as compared to accounts receivable and operating revenues. Additionally, the Company establishes specific allowances for certain individual accounts. Utility Plant in Service The cost of additions to utility plant in service, including an allowance for funds used during construction and replacements of units of property and improvements, is capitalized. The cost of depreciable units of property retired plus the cost of removal less salvage is charged to accumulated depreciation. Asset Retirement Obligations The Company records the fair value of a liability for an asset retirement obligation (ARO) in the period in which it is incurred. When the liability is initially recorded, the associated costs of the ARO are capitalized as part of the carrying amount of the related long-lived asset. The liability is accreted to its present value each period and the related capitalized costs are depreciated over the useful life of the related asset. In addition, if there are changes in the estimated timing or estimated costs of the AROs, adjustments are recorded during the period new information becomes available as an increase or decrease to the liability, with the offset recorded to the related long-lived asset. Upon retirement of the asset, the Company either settles the ARO for its recorded amount or incurs a gain or loss. The Company records regulatory assets and liabilities for the difference between asset retirement costs currently recovered in rates and AR Os recorded since asset retirement costs are recovered through rates charged to customers (see Note 7 for further discussion of the Company's asset retirement obligations). Derivative Assets and Liabilities Derivatives are recorded as either assets or liabilities on the Balance Sheets measured at estimated fair value. In certain defined conditions, a derivative may be specifically designated as a hedge for a particular exposure. The accounting for a derivative depends I FERC FORM NO. 2/3-Q (REV 12-07) 122.6 PC_DR_009 Attachment B Page 40 of 177 Name of Respondent This Report is: Date of Report Year/Period of Report (1) 6 An Original (Mo, Da, Yr) Avista Corporation (2) A Resubmission 04/15/2016 2015/04 Notes to Financial Statements on the intended use of such derivative and the resulting designation. The UTC and the IPUC issued accounting orders authorizing Avista Corp. to offset energy commodity derivative assets or liabilities with a regulatory asset or liability. This accounting treatment is intended to defer the recognition of mark-to-market gains and losses on energy commodity transactions until the period of delivery. The orders provide for Avista Corp. to not recognize the unrealized gain or loss on utility derivative commodity instruments in the Statements of Income. Realized gains or losses are recognized in the periods of delivery, subject to approval for recovery through retail rates. Realized gains and losses, subject to regulatory approval, result in adjustments to retail rates through purchased gas cost adjustments, the ERM in Washington, the PCA mechanism in Idaho, and periodic general rates cases. Regulatory assets are assessed regularly and are probable for recovery through future rates. Substantially all forward contracts to purchase or sell power and natural gas are recorded as derivative assets or liabilities at estimated fair value with an offsetting regulatory asset or liability. Contracts that are not considered derivatives are accounted for on the accrual basis until they are settled or realized, unless there is a decline in the fair value of the contract that is determined to be other-than-temporary. For interest rate swap agreements, each period Avista Corp. records all mark-to-market gains and losses as assets and liabilities and records offsetting regulatory assets and liabilities, such that there is no income statement impact. Upon settlement of interest rate swaps, the regulatory asset or liability (included as part of long-term debt) is amortized as a component of interest expense over the term of the associated debt. While the Company has not received any formal accounting orders from the various state commissions allowing for the offset of interest rate swap assets and liabilities with regulatory assets and liabilities, the Company has deemed this accounting treatment appropriate and future recovery probable due to the regulatory precedents set in prior general rate cases and the fact that the state commissions view interest rate swap derivatives as risk management tools similar to energy commodity derivatives. As of December 31, 2015, the Company has multiple master netting agreements with a variety of entities that allow for cross-commodity netting of derivative agreements with the same counterparty (i.e. power derivatives can be netted with natural gas derivatives) under ASC 815-10-45. The Company does not have any agreements which allow for cross-affiliate netting among multiple affiliated legal entities. The Company nets all derivative instruments when allowed by. the agreement for presentation in the Balance Sheets. Fair Value Measurements Fair value represents the price that would be received when selling an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. Energy commodity derivative assets and liabilities, deferred compensation assets, as well as derivatives related to interest rate swap agreements and foreign currency exchange contracts, are reported at estimated fair value on the Balance Sheets. See Note 14 for the Company's fair value disclosures. Regulatory Deferred Charges and Credits The Company prepares its financial statements in accordance with regulatory accounting practices because: • rates for regulated services are established by or subject to approval by independent third-party regulators, • the regulated rates are designed to recover the cost of providing the regulated services, and • in view of demand for the regulated services and the level of competition, it is reasonable to assume that rates can be charged to and collected from customers at levels that will recover costs. Regulatory accounting practices require that certain costs and/or obligations (such as incurred power and natural gas costs not currently included in rates, but expected to be recovered or refunded in the future), are reflected as deferred charges or credits on the Balance Sheets. These costs and/or obligations are not reflected in the Statements oflncome until the period during which matching I FERC FORM NO. 2/3-Q (REV 12-07) 122.7 PC_DR_009 Attachment B Page 41 of 177 Name of Respondent This Report is: Date of Report Year/Period of Report (1) 6 An Original (Mo, Da, Yr) Avista Corporation (2) A Resubmission 04/15/2016 2015/04 Notes to Financial Statements revenues are recognized. The Company also has decoupling revenue deferrals, which began in 2015. As opposed to cost deferrals which are not recognized in the Statements of Income until they are included in rates, decoupling revenue is recognized in the Statements of Income during the period it occurs (i.e. during the period of revenue shortfall or excess due to fluctuations in customer usage), subject to certain limitations, and a regulatory asset/liability is established which will be surcharged or rebated to customers in future periods. GAAP requires that for any alternative regulatory revenue program, like decoupling, the revenue must be collected from customers within 24 months of the deferral to qualify for recognition in the current period Statement of Income. Any amounts included in the Company's decoupling program that won't be collected from customers within 24 months are not recorded in the financial statements until the period in which revenue recognition criteria are met. This could ultimately result in more decoupling reV,enue being collected from customers over the life of the decoupling program than what is deferred and recognized in the current period financial statements. If at some point in the future the Company determines that it no longer meets the criteria for continued application of regulatory accounting practices for all or a portion of its regulated operations, the Company could be: • required to write off its regulatory assets, and • precluded from the future deferral of costs or decoupled revenues not recovered through rates at the time such amounts are incurred, even if the Company expected to recover these amounts from customers in the future. Investment in Exchange Power-Net The investment in exchange power represents the Company's previous investment in Washington Public Power Supply System Project 3 (WNP-3), a nuclear project that was terminated prior to completion. Under a settlement agreement with the Bonneville Power Administration in 1985, Avista Corp. began receiving power in 1987, for a 32.5-year period, related to its investment in WNP-3. Through a settlement agreement with the UTC in the Washington jurisdiction, A vista Corp. is amortizing the recoverable portion of its investment in WNP-3 (recorded as investment in exchange power) over a 32.5-year period that began in 1987. For the Idaho jurisdiction, A vista Corp. fully amortized the recoverable portion of its investment in exchange power. Unamortized Debt Expense Unamortized debt expense includes debt issuance costs that are amortized over the life of the related debt. Unamortized Loss on Reacquired Debt For the Company's Washington regulatory jurisdiction and for any debt repurchases beginning in 2007 in all jurisdictions, premiums paid to repurchase debt are amortized over the remaining life of the original debt that was repurchased or, if new debt is issued in connection with the repurchase, these costs are amortized over the life of the new debt. In the Company's other regulatory jurisdictions, premiums paid to repurchase debt prior to 2007 are being amortized over the average remaining maturity of outstanding debt when no new debt was issued in connection with the debt repurchase. These costs are recovered through retail rates as a component of interest expense. Appropriated Retained Earnings In accordance with the hydroelectric licensing requirements of section 10( d) of the Federal Power Act (FP A), the Company maintains an appropriated retained earnings account for any earnings in excess of the specified rate of return on the Company's investment in the licenses for its various hydroelectric projects. Per section lO(d) of the FPA, the Company must maintain these excess earnings in an appropriated retained earnings account until the termination of the licensing agreements or apply them to reduce the net investment in the licenses of the hydroelectric projects at the discretion of the FERC. The Company typically calculates the earnings in excess of the specified rate ofreturn on an annual basis, usually during the second quarter. I FERC FORM NO. 2/3-Q (REV 12-07) 122.8 PC_DR_009 Attachment B Page 42 of 177 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Avista Corporation (2) A Resubmission 04/15/2016 2015/04 Notes to Financial Statements The appropriated retained earnings amounts included in retained earnings were as follows as of December 31 (dollars in thousands): 2015 2014 Appropriated retained earnings $ 19,428 $ 14,270 Operating Leases The Company has multiple lease arrangements involving various assets, with minimum terms ranging from 1 to 45 years. Future minimum lease payments required under operating leases having initial or remaining noncancelable lease terms in excess of one year were not material as of December 31, 2015. Equity in Earnings of Subsidiaries The Company records all the earnings from its subsidiaries under the equity method. The Company had the following equity in earnings of its subsidiaries for the years ended December 31 (dollars in thousands): A vista Capital $ Alaska Energy and Resources Company Total equity in earnings of subsidiary companies $ 2015 4,857 $ 6,308 11,165 $ 2014 79,183 3,179 82,362 Avista Capital, a wholly owned subsidiary of Avista Corp., is the parent company of all of the subsidiary companies, except AERC (and its subsidiaries). Avista Capital's subsidiaries and investments include sheet metal fabrication, venture fund investments, real estate investments, a company that explores markets that could be served with LNG and Ecova prior to its disposition on June 30, 2014. AERC, a wholly-owned subsidiary of Avista Corp. acquired on July 1, 2014, is the patent company to all the Alaska subsidiary companies. The primary subsidiary of AERC is AEL&P, comprising the regulated utility operations in Alaska. Also, AERC owns AJT Mining Properties, Inc., an inactive mining company holding certain properties. Subsequent Events Management has evaluated the impact of events occurring after December 31, 2015 up to February 24, 2016, the date that Avista Corp. 's U.S. GAAP financial statements were issued and has updated such evaluation for disclosure purposes through April 15, 2016. These financial statements include all necessary adjustments and disclosures resulting from these evaluations. Contingencies The Company has unresolved regulatory, legal and tax issues which have inherently uncertain outcomes. The Company accrues a loss contingency if it is probable that a liability has been incurred and the amount of the loss or impairment can be reasonably estimated. The Company also discloses losses that do not meet these conditions for accrual, if there is a reasonable possibility that a material loss may be incurred. As of December 31, 2015, the Company has not recorded any significant amounts related to unresolved contingencies. See Note 16 for further discussion of the Company's commitments and contingencies. NOTE 2. NEW ACCOUNTING STANDARDS In April 2014, the FASB issued ASU No. 2014-08, "Presentation of Financial Statements (Topic 205) and Property, Plant, and I FERC FORM NO. 2/3-Q (REV 12-07) 122.9 PC_DR_009 Attachment B Page 43 of 177 Name of Respondent This Report is: Date of Report Year/Period of Report (1) 6 An Original (Mo, Da, Yr) Avista Corporation (2) A Resubmission 04/15/2016 2015/04 Notes to Financial Statements Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity." This ASU amends the definition of a discontinued operation and requires entities to provide additional disclosures about discontinued operations as well as disposal transactions that do not meet the discontinued-operations criteria. ASU 2014-08 makes it more difficult for a disposal transaction to qualify as a discontinued operation. In addition, the ASU requires entities to reclassify assets and liabilities of a discontinued operation for all comparative periods presented in the Balance Sheet rather than just the current period, and it requires additional disclosures on the face of the Statement of Cash Flows regarding dis~ontinued operations. This ASU became effective for periods beginning on or after December 15, 2014; however, early adoption was permitted. The Company evaluated this standard and determined that it would not early adopt this standard. Since the disposition ofEcova occurred before the effective date of this standard, and the Company did not early adopt this standard, there is no impact on the Company's fmancial condition, results of operations and cash flows in the current year. In May 2014, the FASB issued ASU No. 2014-09, "Revenue from Contracts with Customers (Topic 606)," which outlines a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. The core principle of the revenue model is that an entity identifies the various performance obligations in a contract, allocates the transaction price among the performance obligations and recognizes revenue as the entity satisfies the performance obligations. This ASU was originally effective· for periods beginning after December 15, 2016 and early adoption is not permitted. In August 2015, the FASB issued ASU 2015-14 Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date," which deferred the effective date of ASU 2014-09 for one year, with adoption as of the original date permitted. However, while this ASU is not effective until 2018, it will require retroactive application to all periods presented in the fmancial statements. As such, at adoption in 2018, amounts in 2016 and 2017 may have to be revised or a cumulative adjustment to opening retained earnings may have to be recorded. The Company is evaluating this standard and cannot, at this time, estimate the potential impact on its future fmancial condition, results of operations and cash flows. In February 2015, the FASB issued ASU No. 2015-02, "Consolidation (Topic 810): Amendments to the Consolidation Analysis." This ASU significantly changes the consolidation analysis required under GAAP, including the identification of variable interest entities (VIE). The ASU also removes the defe1Tal of the VIE analysis related to investments in certain investment funds, which will result in a different consolidation evaluation for these types of investments. This ASU is effective for periods beginning on or after December 15, 2015; however, early adoption is permitted. The Company evaluated this standard and determined that it will not early adopt this standard. The Company is evaluating this standard and cannot, at this time, estimate the potential impact on its future fmancial condition, results of operations and cash flows. In April 2015, the FASB issued ASU No. 2015-05, "Intangibles -Goodwill and Other -Internal-Use Software (Subtopic 350-40): Customer's Accounting for Fees Paid in a Cloud Computing Arrangement." This ASU provides guidance on how organizations should account for fees paid in a cloud computing arrangement, including helping organizations understand whether their arrangement includes a software license. If the arrangement includes a software license, the software license would be accounted for in a manner consistent with internal-use software. If a cloud-computing arrangement does not include a software license, the customer is required to account for the arrangement as a service contract. This ASU is effective for periods beginning on or after December 15, 2015; however, early adoption is permitted. The Company evaluated this standard and determined that it will not early adopt this standard. Upon adoption, an entity can elect to apply this ASU prospectively or retroactively and disclose the method selected. The Company is evaluating this standard and cannot, at this time, estimate the potential impact on its future fmancial condition, results of operations and cash flows. In May 2015, the FASB issued ASU No. 2015-07, "Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent)." This ASU removes, from the fair value hierarchy, investments for which the practical expedient is used to measure fair value at net asset value (NA V). Instead, an entity is required to include those investments as a reconciling line item so that the total fair value amount of investments in the disclosure is consistent I FERG FORM NO. 2/3-Q (REV 12-07) 122.10 PC_DR_009 Attachment B Page 44 of 177 Name of Respondent This Report is: Date of Report Year/Period of Report (1) 6 An Original (Mo, Da, Yr) Avista Corporation (2) A Resubmission 04/15/2016 2015/04 Notes to Financial Statements ·- with the amount on the balance sheet. Further, entities must provide certain disclosures for investments for which they elect to use the NAV practical expedient to determine fair value. This ASU is effective for periods beginning on or after December 15, 2015 and early adoption is permitted. The Company evaluated this standard and determined that it will early adopt this standard as of December 31, 2015. As required, this ASU is being applied retrospectively to all periods presented. The adoption of this standard did not affect the Company's future financial condition, results of operations and cash flows; however, it did affect the Company's disclosures. See Note 8 and 14 for the expanded disclosures surrounding the adoption of this ASU. In February 2016, the FASB issued ASU 2016-02 "Leases (Topic 842)." This ASU introduces a new lessee model that brings most leases on the balance sheet. The standard also aligns certain of the underlying principles of the new lessor model with those in ASC 606, the FASB's new revenue recognition standard. Furthermore, the ASU addresses other concerns related to the current leases model; for example, eliminating the required use of bright-line tests in current GAAP for determining lease classification (operating leases versus capital leases). This ASU also includes enhanced disclosures surrounding leases. This ASU is effective for periods beginning on or after December 15, 2018; however, early adoption is permitted. The Company evaluated this standard and determined that it will not early adopt this standard as of December 31, 2015. Upon adoption, this ASU must be applied using a modified retrospective approach. The modified retrospective approach includes a number of optional practical expedients that entities may elect to apply. The Company is evaluating this standard and cannot, at this time, estimate the potential impact on its future financial condition, results of operations and cash flows. NOTE 3. BUSINESS ACQUISITIONS Alaska Energy and Resources Company On July 1, 2014, the Company acquired AERC, based in Juneau, Alaska, and as of that date, AERC became a wholly-owned subsidiary of Avista Corp. The primary subsidiary of AERC is AEL&P, a regulated utility which provides electric services to approximately 17,000 customers in the City and Borough of Juneau (Juneau), Alaska as of December 31, 2015. In addition to the regulated utility, AERC owns AJT Mining, which is an inactive mining company holding certain properties. The purpose of the acquisition was to expand and diversify Avista Corp.'s energy assets and deliver long-term value to its customers, communities and investors. In connection with the closing, on July 1, 2014 Avista Corp. issued 4,500,014 new shares of common stock to the shareholders of AERC based on a contractual formula that resulted in a price of $32.46 per share, reflecting a purchase price of $170.0 million, plus acquired cash, less outstanding debt and other closing adjustments. The $32.46 price per share of Avista Corp. common stock was determined based on the average closing stock price of Avista Corp. common stock for the 10 consecutive trading days immediately preceding, but not including, the trading day prior to July 1, 2014. This value was used solely for determining the number of shares to issue based on the adjusted contract closing price (see reconciliation below). The fair value of the consideration transferred at the closing date was based on the closing stock price of A vista Corp. common stock on July 1, 2014, which was $33.35 per share. On October 1, 2014, a working capital adjustment was made in accordance with the agreement and plan of merger which resulted in Avista Corp. issuing an additional 1,427 shares of common stock to the shareholders of AERC. The number of shares issued on October 1, 2014 was based on the same contractual formula described above. The fair value of the new shares issued in October was $30.71 per share, which was the closing stock price of Avista Corp. common stock on that date. The contract acquisition price and the fair value of consideration transferred for AERC were as follows (in thousands, except "per share" and number of shares data): I FERC FORM NO. 2/3-Q (REV 12-07) 122.11 PC_DR_009 Attachment B Page 45 of 177 Name of Respondent This Report is: Date of Report (1) ~An Original Avista Corporation (2) A Resubmission Notes to Financial Statements Contract acquisition price (using the calculated $32.46 per share common stock price) Gross contract price Acquired cash Acquired debt (excluding capital lease obligation) Other closing adjustments (including the working capital adjustment) Total adjusted contract price Fair value of consideration transferred Avista Corp. common stock (4,500,014 shares at $33.35 per share) Avista Corp. common stock (1,427 shares at $30.71 per share) Cash Fair value of total consideration transferred (Mo, Da, Yr) 04/15/2016 $ $ $ $ Year/Period of Report 2015/04 170,000 19,704 (38,832) 37 150,909 150,075 44 4,792 154,911 The assets acquired and liabilities assumed related to the AERC transaction are not included in the FERC Balance Sheets. The information below is presented for information purposes only. The fair value of assets acquired and liabilities assumed as of July 1, 2014 (after consideration of the working capital adjustment and the income tax true-ups during the second quarter of 2015) were as follows (in thousands): Assets acquired: Current Assets: Cash Accounts receivable -gross totals $3,928 Materials and supplies Other current assets Total current assets Utility Property: Utility plant in service Utility property under long-term capital lease Construction work in progress Total utility property Other Non-cwTent Assets: Non-utility property Electric plant held for future use Goodwill ( 1) Other deferred charges and non-current assets I FERC FORM NO. 2/3-Q (REV 12-07) July 1, 2014 $ 19,704 3,851 2,017 999 26,571 113,964 71,007 3,440 188,411 6,660 3,711 52,426 5,368 122.12 PC_DR_009 Attachment B Page 46 of 177 Name of Respondent This Report is: Date of Report Year/Period of Report (1) 6 An Original (Mo, Da, Yr) Avista Corporation (2) A Resubmission 04/15/2016 2015/04 Notes to Financial Statements Total other non-current assets 68,165 Total assets $ 283,147 Liabilities Assumed: Current Liabilities: Accounts payable $ 700 Current portion of long-term debt and capital lease obligations 3,773 Other current liabilities ( 1) 2,807 Total current liabilities 7,280 Long-tenn debt 37,227 Capital lease obligations 68,840 Other non-current liabilities and deferred credits (1) 14,889 Total liabilities $ 128,236 Total net assets acquired $ 154,911 (1) During the second quarter of2015, AEL&P recorded a reduction to goodwill of approximately $0.3 million due to income tax related adjustments. After consideration of the goodwill adjustment in the second quarter of 2015, the transaction resulted in a total amount of goodwill of $52.4 million. The goodwill associated with this acquisition is not deductible for tax purposes. The majority of AERC's operations are subject to the rate-setting authority of the RCA and are accounted for pursuant to GAAP, including the accounting guidance for regulated operations. The rate-setting and cost recovery provisions currently in place for AERC's regulated operations provide revenues derived from costs, including a return on investment, of assets and liabilities included in rate base. Due to this regulation, the fair values of AERC's assets and liabilities subject to these rate-setting provisions are assumed to approximate their carrying values. There were not any identifiable intangible assets associated with this acquisition. The excess of the purchase consideration over the estimated fair values of the assets acquired and liabilities assumed was recognized as goodwill at the acquisition date. The goodwill reflects the value paid for the expected continued growth of a rate-regulated business located in a defined service area with a constructive regulatory environment, the attractiveness of stable, growing cash flows, as well as providing a platform for potential future growth outside of the rate-regulated electric utility in Alaska and potential additional utility investment. NOTE 4. DISCONTINUED OPERATIONS On June 30, 2014, Avista Capital, completed the sale of its interest in Ecova to Cofely USA Inc., an indirect subsidiary of GDF SUEZ, a French multinational utility company, and an unrelated party to Avista Corp. The sales price was $335.0 million in cash, less the payment of debt and other customary closing adjustments. At the closing of the transaction on June 30, 2014, Ecova became a wholly-owned subsidiary of Cofely USA Inc. and the Company has not had and will not have any further involvement with Ecova after such date. The purchase price of $335.0 million, as adjusted, was divided among the security holders ofEcova, including minority shareholders, option holders and a warrant holder, pro rata based on ownership. Approximately $16.8 million (5 percent of the purchase price) was held in escrow for 15 months from the closing of the transaction to satisfy certain indemnification obligations under the merger agreement (Escrow). An additional $1.0 million was held in escrow pending resolution of adjustments to working capital. The I FERG FORM NO. 2/3-Q (REV 12-07) 122.13 PC_DR_009 Attachment B Page 47 of 177 Name of Respondent This Report is: Date of Report Year/Period of Report (1) ~An Original (Mo, Da, Yr) Avista Corporation (2) A Resubmission 04/15/2016 2015/04 Notes to Financial Statements indemnification escrow and the working capital adjustment escrow amounts above represent the full amounts to be divided among all security holders pro rata based on ownership. As expected, no claims were made against the Escrow as of September 30, 2015 (the end of the claims period) and accordingly, all Escrow amounts were released in October 2015 and the Company received its full portion of the Escrow proceeds together with the remainder of the working capital adjustment escrow for a total amount of $13.8 million. After consideration of the escrow amounts received, the sales transaction provided cash proceeds to Avista Corp., net of debt, payment to option and minority holders, income taxes and transaction expenses, of $143.7 million and resulted in a net gain of $74.8 million. Almost all of the net gain was recognized in 2014 with some true-ups during 2015. The summary of cash proceeds associated with the sales transaction are as follows (in thousands): Reconciliation of Gross Proceeds Contract price Closing adjustments Litigation settlement at Ecova Gross proceeds from sale ( 1) Cash sold in the transaction Gross proceeds from sale of Ecova, net of cash sold (2) Reconciliation of total net proceeds Gross proceeds from sale ( 1) Repayment of long-term bonowings under committed line of credit Payment to option holders and redeemable noncontrolling interests Payment to noncontrolling interests Transaction expenses withheld from proceeds Net proceeds to Avista Capital (prior to tax payments) (2) Tax payments made in 2014 Tax payments made in 2015 Total net proceeds related to sales transaction $ $ $ $ 335,000 4,103 588 339,691 (95,932) 243,759 339,691 (40,000) (20,871) (54,179) (5,461) 219,180 (74,842) (590) 143,748 (1) Of this total amount, approximately $16.8 million was held in escrow for 15 months from the transaction closing date for any indemnity claims and an additional $1.0 million was held in escrow pending resolution of adjustments to working capital. Both of these escrow accounts were resolved during 2015. (2) Of the total gross proceeds and total net proceeds received, approximately $229.9 million and $205.4 million was received in 2014, respectively, with the remainder being received in 2015. NOTE 5. DERIVATIVES AND RISK MANAGEMENT Energy Commodity Derivatives Avista Corp. is exposed to market risks relating to changes in electricity and natural gas commodity prices and certain other fuel prices. I FERC FORM NO. 2/3-Q (REV 12-07) 122.14 PC_DR_009 Attachment B Page 48 of 177 Name of Respondent This Report is: Date of Report Year/Period of Report (1) 6 An Original (Mo, Da, Yr) Avista Corporation (2) A Resubmission 04/15/2016 2015/04 Notes to Financial Statements Market risk is, in general, the risk of fluctuation in the market price of the commodity being traded and is influenced primarily by supply and demand. Market risk includes the fluctuation in the market price of associated derivative commodity instruments. Avista Corp. utilizes derivative instruments, such as forwards, futures, swaps and options in order to manage the various risks relating to these commodity price exposures. The Company has an energy resources risk policy and control procedures to manage these risks. As part of the Company's resource procurement and management operations in the electric business, the Company engages in an ongoing process of resource optimization, which involves the economic selection from available energy resources to serve the Company's load obligations and the use of these resources to capture available economic value. The Company transacts in wholesale markets by selling and purchasing electric capacity and energy, fuel for electric generation, and derivative contracts related to capacity, energy and fuel. Such transactions are part of the process of matching resources with load obligations and hedging the related financial risks. These transactions range from terms of intra-hour up to multiple years. As part of its resource procurement and management of its natural gas business, Avista Corp. makes continuing projections of its natural gas loads and assesses available natural gas resources including natural gas storage availability. Natural gas resource planning typically includes peak requirements, low and average monthly requirements and delivery constraints from natural gas supply locations to Avista Corp.' s distribution system. However, daily variations in natural gas demand can be significantly different than monthly demand projections. On the basis of these projections, Avista Corp. plans and executes a series of transactions to hedge a portion of its projected natural gas requirements through forward market transactions and derivative instruments. These transactions may extend as much as four natural gas operating years (November through October) into the future. Avista Corp. also leaves a significant portion of its natural gas supply requirements unhedged for purchase in short-term and spot markets. The following table presents the underlying energy commodity derivative volumes as of December 31, 2015 that are expected to be settled in each respective year (in thousands ofMWhs and mmBTUs): Purchases Sales Electric Derivatives Gas Derivatives Electric Derivatives Gas Derivatives Physical (1) Financial (1) Physical (1) Financial (1) Physical (1) Financial (1) Physical (1) Financial (1) Year MWh MWh mmBTUs mmBTUs MWh MWh mmBTUs mmBTUs 2016 407 1,954 17,252 142,693 280 2,656 3,182 112,233 2017 397 97 675 49,200 255 483 1,360 26,965 2018 397 15,118 286 1,360 2,738 2019 235 305 6,935 158 1,345 2020 455 905 1,430 Thereafter 1,060 (1) Physical transactions represent commodity transactions in which Avista Corp. will take or make delivery of either electricity or natural gas; financial transactions represent derivative instruments with delivery of cash in the amount of gain or loss but with no physical delivery of the commodity, such as futures, swaps, options, or forward contracts. The electric and natural gas derivative contracts above will be included in either power supply costs or natural gas supply costs during the period they are settled and will be included in the various recovery mechanisms (ERM, PCA, and PGAs ), or in the general rate case process, and are expected to be collected through retail rates from customers. Foreign Currency Exchange Contracts A significant portion of Avista Corp.' s natural gas supply (including fuel for power generation) is obtained from Canadian sources. I FERC FORM NO. 2/3-Q (REV 12-07) 122.15 PC_DR_009 Attachment B Page 49 of 177 Name of Respondent This Report is: Date of Report Year/Period of Report (1) 6 An Original (Mo, Da, Yr) Avista Corporation (2) A Resubmission 04/15/2016 2015/Q4 Notes to Financial Statements Most of those transactions are executed in U.S. dollars, which avoids foreign currency risk. A portion of Avista Corp.'s short-term natural gas transactions and long-term Canadian transportation contracts are committed based on Canadian currency prices and settled within 60 days with U.S. dollars. Avista Corp. hedges a portion of the foreign currency risk by purchasing Canadian currency exchange contracts when such commodity transactions are initiated. This risk has not had a material effect on the Company's financial condition, results of operations or cash flows and these differences in cost related to currency fluctuations were included with natural gas supply costs for ratemaking. The following table summarizes the foreign currency hedges that the Company has entered into as of December 31 (dollars in thousands): Number of contracts Notional amount (in United States dollars) Notional amount (in Canadian dollars) Interest Rate Swap Agreements $ 2015 24 1,463 $ 2,002 2014 18 5,474 6,198 Avista Corp. is affected by fluctuating interest rates related to a portion of its existing debt, and future borrowing requirements. The Company hedges a portion of its interest rate risk with fmancial derivative instruments, which may include interest rate swaps and U.S. Treasury lock agreements. These interest rate swaps and U.S. Treasury lock agreements are considered economic hedges against fluctuations in future cash flows associated with anticipated debt issuances. The following table summarizes the interest rate swaps that the Company has outstanding as of the balance sheet date indicated below (dollars in thousands): Mandatory Cash Settlement Balance Sheet Date Number of Contracts Notional Amount Date December 31, 2015 6 115,000 2016 3 45,000 2017 11 245,000 2018 2 30,000 2019 20,000 2022 December 31, 2014 5 75,000 2015 5 95,000 2016 3 45,000 2017 9 205,000 2018 During the third quarter 2015, in connection with the execution of a purchase agreement for bonds that the Company issued in December 2015, the Company cash-settled five interest rate swap contracts (notional aggregate amount of $75.0 million) and paid a total of $9.3 million. The interest rate swap contracts were settled in connection with the pricing of $100.0 million of Avista Corp. first mortgage bonds that were issued in December 2015 (see Note 12). Upon settlement of interest rate swaps, the regulatory asset or liability is amortized as a component of interest expense over the term of the associated debt. The fair value of outstanding interest rate swaps can vary significantly from period to period depending on the total notional amount of swaps outstanding and fluctuations in market interest rates compared to the interest rates fixed by the swaps. The Company would be required to make cash payments to settle the interest rate swaps if the fixed rates are higher than prevailing market rates at the date of I FERC FORM NO. 2/3-Q (REV 12-07) 122.16 PC_DR_009 Attachment B Page 50 of 177 Name of Respondent This Report is: Date of Report Year/Period of Report (1) ~An Original (Mo, Da, Yr) Avista Corporation (2) A Resubmission 04/15/2016 2015/Q4 Notes to Financial Statements settlement. Conversely, the Company receives cash to settle its interest rate swaps when prevailing market rates at the time of settlement exceed the fixed swap rates. Summary of Outstanding Derivative Instruments The amounts recorded on the Balance Sheet as of December 31, 2015 and December 31, 2014 reflect the offsetting of derivative assets and liabilities where a legal right of offset exists. The following table presents the fair values and locations of derivative instruments recorded on the Balance Sheet as of December 31, 2015 (in thousands): Fair Value Net Asset (Liability) Gross Gross Collateral in Balance Derivative Balance Sheet Location Sheet Foreign currency Derivative instrument liabilities current $ 2 $ (19) $ -$ (17) contracts Interest rate Long-term portion of derivative assets 23 23 contracts Interest rate Derivative instrument liabilities current 118 (23,262) 3,880 (19,264) contracts Interest rate Long-tenn portion of derivative instrument 1,407 (62,236) 30,150 (30,679) contracts liabilities Commodity Derivative instrument assets current 1,236 (553) 683 contracts Commodity Derivative instrument liabilities current 67,466 (85,409) 3,675 (14,268) contracts Commodity Long-term portion of derivative liabilities 6,613 (39,033) 10,851 (21,569) contracts Total derivative instruments recorded on the balance sheet $ 76,865 $ (210,512) $ 48,556 $ (85,091) The following table presents the fair values and locations of derivative instruments recorded on the Balance Sheet as of December 31, 2014 (in thousands): Derivative Foreign currency contracts Interest rate contracts Balance Sheet Location Derivative instrument liabilities -Hedges Derivative instrument assets -Hedges I FERC FORM NO. 2/3-Q (REV 12-07) Gross $ I $ 966 122.17 Fair Value Gross Collateral (21) $ - $ (506) Net Asset (Liability) in Balance Sheet (20) 460 PC_DR_009 Attachment B Page 51 of 177 Name of Respondent This Report is: Date of Report Year/Period of Report (1) 6 An Original (Mo, Da, Yr) Avista Corporation (2) A Resubmission 04/15/2016 2015/04 Notes to Financial Statements Interest rate Derivative instrument liabilities -Hedges (7,325) (7,325) contracts Interest rate Long-term portion of derivative liabilities -(69,737) 28,880 (40,857) contracts Hedges Commodity Derivative instrument assets current 2,063 (538) 1,525 contracts Commodity Long-term portion of derivative assets 66,421 (97,586) 13,120 (18,045) contracts Commodity Long-term portion of derivative liabilities 29,594 (54,077) 2,390 (22,093) contracts Total derivative instruments recorded on the balance sheet $ 99,045 $ (229,790) $ 44,390 $ (86,355) Exposure to Demands/or Collateral The Company's derivative contracts often require collateral (in the form of cash or letters of credit) or other credit enhancements, or reductions or terminations of a portion of the contract through cash settlement, in the event of a downgrade in the Company's credit ratings or changes in market prices. In periods of price volatility, the level of exposure can change significantly. As a result, sudden and significant demands may be made against the Company's credit facilities and cash. The Company actively monitors the exposure to possible collateral calls and takes steps to mitigate capital requirements. The following table presents the Company's collateral outstanding related to its derivative instruments as of as of December 31 (in thousands): Energy commodity derivatives Cash collateral posted Letters of credit outstanding Balance sheet offsetting (cash collateral against net derivative positions) Interest rate swaps Cash collateral posted Letters of credit outstanding Balance sheet offsetting (cash collateral against net derivative positions) ·$ 2015 28,716 $ 28,200 14,526 34,030 9,600 34,030 2014 20,565 14,500 15,510 28,880 10,900 28,880 Certain of the Company's derivative instruments contain provisions that require the Company to maintain an "investment grade" credit rating from the major credit rating agencies. If the Company's credit ratings were to fall below "investment grade," it would be in violation of these provisions, and the counterparties to the derivative instruments could request immediate payment or demand immediate and ongoing collateralization on derivative instruments in net liability positions. The following table presents the aggregate fair value of all derivative instruments with credit-risk-related contingent features that are in a liability position and the amount of additional collateral the Company could be required to post as of December 31 (in thousands): I FERC FORM NO. 2/3-Q (REV 12-07) 122.18 PC_DR_009 Attachment B Page 52 of 177 Name of Respondent This Report is: ( 1) X An Original Avista Corporation (2) A Resubmission Notes to Financial Statements Energy commodity derivatives Liabilities with credit-risk-related contingent features Additional collateral to post Interest rate swaps Liabilities with credit-risk-related contingent features Additional collateral to post Credit Risk Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2016 2015 $ 7,090 $ 6,980 85,498 18,750 2015/04 2014 12,911 16,227 77,568 19,404 Credit risk relates to the potential losses that the Company would incur as a result of non-performance by counterparties of their contractual obligations to deliver energy or make financial settlements. The Company often extends credit to counterparties and customers and is exposed to the risk that it may not be able to collect amounts owed to the Company. Credit risk includes potential counterparty default due to circumstances: • relating directly to it, • caused by market price changes, and • relating to other market participants that have a direct or indirect relationship with such counterparty. Changes in market prices may dramatically alter the size of credit risk with counterparties, even when conservative credit limits are established. Should a counterparty fail to perform, the Company may be required to honor the underlying commitment or to replace existing contracts with contracts at then-current market prices. The Company enters into bilateral transactions with various counterparties. The Company also transacts in energy and related derivative instruments through clearinghouse exchanges. In addition, the Company has concentrations of credit risk related to geographic location as it operates in the western United States and western Canada. These concentrations of counterparties and concentrations of geographic location may impact the Company's overall exposure to credit risk because the counterparties may be similarly affected by changes in conditions. The Company maintains credit support agreements with certain counterparties and margin calls are periodically made and/or received. Margin calls are triggered when exposures exceed contractual limits or when there are changes in a counterparty's creditworthiness. Price movements in electricity and natural gas can generate exposure levels in excess of these contractual limits. Negotiating for collateral in the form of cash, letters of credit, or performance guarantees is common industry practice. NOTE 6. JOINTLY OWNED ELECTRIC FACILITIES The Company has a 15 percent ownership interest in a twin-unit coal-fired generating facility, Colstrip, located in southeastern Montana, and provides financing for its ownership interest in the project. The Company's share ofrelated fuel costs as well as operating expenses for plant in service are included in the corresponding accounts in the Statements of Income. The Company's share of utility plant in service for Colstrip and accumulated depreciation were as follows as of December 31 (dollars in thousands): 2015 2014 Utility plant in service $ 362,199 $ 350,518 I FERC FORM NO. 2/3-Q (REV 12-07) 122.19 PC_DR_009 Attachment B Page 53 of 177 Name of Respondent This Report is: Date of Report Year/Period of Report (1) ~An Original (Mo, Da, Yr) Avista Corporation (2) A Resubmission 04/15/2016 2015/04 Notes to Financial Statements Accumulated depreciation (243,363) (239,845) NOTE 7. ASSET RETIREMENT OBLIGATIONS See Note 1 for a discussion of the Company's accounting policy associated with AROs. Specifically, the Company has recorded liabilities for future AROs to: • restore coal ash containment ponds at Colstrip, • cap a landfill at the Kettle Falls Plant, • remove plant and restore the land at the Coyote Springs 2 site at the termination of the land lease, and • dispose of PCBs in certain transformers. Due to an inability to estimate a range of settlement dates, the Company cannot estimate a liability for the: • removal and disposal of certain transmission and distribution assets, and • abandonment and decommissioning of certain hydroelectric generation and natural gas storage facilities. On April 17, 2015, the EPA published a final rule regarding CCRs, also termed coal combustion byproducts or coal ash in the Federal Register and this rule became effective on October 15, 2015. Colstrip, of which Avista Corp. is a 15 percent owner of units 3 and 4, produces this byproduct. The rule establishes technical requirements for CCR landfills and surface impoundments under Subtitle D of the Resource Conservation and Recovery Act, the nation's primary law for regulating solid waste. The Company, in conjunction with the other Colstrip owners, is developing a multi-year compliance plan to strategically address the new CCR requirements and existing State obligations while maintaining operational stability. Duringthe second quarter of2015, the operator of Colstrip provided an initial cost estimate of the expected retirement costs associated with complying with the new CCR rule and this estimate was subsequently updated during the fourth qumier of2015. Based on the initial assessments, Avista Corp. recorded an increase to its ARO of $12.5 million during 2015 with a corresponding increase in the cost basis of the utility plant. The actual asset retirement costs related to the new CCR rule requirements may vary substantially from the estimates used to record the increased obligation due to uncertainty about the compliance strategies that will be used and the preliminary nature of available data used to estimate costs, such as the quantity of coal ash present at certain sites and the volume of fill that will be needed to cap and cover certain impoundments. Avista Corp. will coordinate with the plant operator and continue to gather additional data in future periods to make decisions about compliance strategies and the timing of closure activities. As additional information becomes available, Avista Corp. will update the ARO for these changes in estimates, which could be material. The Company expects to seek recovery of any increased costs related to complying with the new rule through customer rates. The following table documents the changes in the Company's asset retirement obligation during the years ended December 31 (dollars in thousands): Asset retirement obligation at beginning of year Liabilities incurred Liabilities settled Accretion expense (income) Asset retirement obligation at end of year I FERC FORM NO. 2/3-Q (REV 12-07) $ $ 122.20 2015 3,028 $ 12,539 (29) 459 15,997 $ 2014 2,859 (41) 210 3,028 PC_DR_009 Attachment B Page 54 of 177 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Avista Corporation (2) _ A Resubmission 04/15/2016 2015/04 Notes to Financial Statements NOTE 8. PENSION PLANS AND OTHER POSTRETIREMENT BENEFIT PLANS The Company has a defined benefit pension plan covering the majority of all regular full-time employees at Avista Corp. that were hired prior to January 1, 2014. Individual benefits under this plan are based upon the employee's years of service, date of hire and average compensation as specified in the plan. Non-union employees hired on or after January 1, 2014 participate in a defined contribution 401 (k) plan in lieu of a defined benefit pension plan. The Company's funding policy is to contribute at least the minimum amounts that are required to be funded under the Employee Retirement Income Security Act, but not more than the maximum amounts that are currently deductible for income tax purposes. The Company contributed $12.0 million in cash to the pension plan in 2015, $32.0 million in 2014 and $44.3 million in 2013. The Company expects to contribute $12.0 million in cash to the pension plan in 2016. The Company also has a SERP that provides additional pension benefits to executive officers and certain key employees of the Company. The SERP is intended to provide benefits to individuals whose benefits under the defined benefit pension plan are reduced due to the application of Section 415 of the Internal Revenue Code of 1986 and the deferral of salary under deferred compensation plans. The liability and expense for this plan are included as pension benefits in the tables included in this Note. The Company expects that benefit payments under the pension plan and the SERP will total (dollars in thousands): 2016 2017 2018 2019 2020 Total 2021-2025 Expected benefit payments $ 29,182 $ 30,260 $ 31,332 $ 32,804 $ 34,430 $ 189,919 The expected long-term rate of return on plan assets is based on past performance and economic forecasts for the types of investments held by the plan. In selecting a discount rate, the Company considers yield rates for highly rated corporate bond portfolios with maturities similar to that of the expected tenn of pension benefits. The Company provides certain health care and life insurance benefits for eligible retired employees that were hired prior to January 1, 2014. The Company accrues the estimated cost ofpostretirement benefit obligations during the years that employees provide services. The liability and expense of this plan are included as other postretirement benefits. Non-union employees hired on or after January 1, 2014, will have access to the retiree medical plan upon retirement; however, Avista Corp. will no longer provide a contribution toward their medical premium. The Company has a Health Reimbursement Arrangement (HRA) to provide employees with tax-advantaged funds to pay for allowable medical expenses upon retirement. The amount earned by the employee is fixed on the retirement date based on the employee's years of service and the ending salary. The liability and expense of the HRA are included as other postretirement benefits. The Company provides death benefits to beneficiaries of executive officers who die during their term of office or after retirement. Under the plan, an executive officer's designated beneficiary will receive a payment equal to twice the executive officer's annual base salary at the time of death (or if death occurs after retirement, a payment equal to twice the executive officer's total annual pension benefit). The liability and expense for this plan are included as other postretirement benefits. The Company expects that benefit payments under other postretirement benefit plans will total (dollars in thousands): 2016 2017 2018 2019 2020 Total 2021-2025 Expected benefit payments $ 7,345 $ 7,522 $ 7,713 $ 7,933 $ 6,907 $ 36,560 The Company expects to contribute $7.3 million to other postretirement benefit plans in 2016, representing expected benefit payments to be paid during the year excluding the Medicare Part D subsidy. The Company uses a December 31 measurement date for its pension I FERC FORM NO. 2/3-Q (REV 12-07) 122.21 PC_DR_009 Attachment B Page 55 of 177 Name of Respondent This Report is: Date of Report Year/Period of Report (1) ~An Original (Mo, Da, Yr) Avista Corporation (2) A Resubmission 04/15/2016 2015/04 Notes to Financial Statements and other postretirement benefit plans. The following table sets forth the pension and other postretirement benefit plan disclosures as of December 31, 2015 and 2014 and the components of net periodic benefit costs for the years ended December 31, 2015, 2014 and 2013 (dollars in thousands): Other Post- Pension Benefits retirement Benefits 2015 2014 2015 2014 Change in benefit obligation: Benefit obligation as of beginning of year $ 634,674 $ 527,004 $ 127,989 $ 108,249 Service cost 19,791 15,757 2,925 1,844 Interest cost 26,117 26,224 5,158 5,226 Actuarial (gain)/loss (35,790) 97,128 12,668 18,714 Plan change (228) (1,000) Transfer of accrued vacation 437 Cumulative adjustment to reclassify liability (1,521) Benefits paid (31,061) (31,439) (7,424) (6,481) Benefit obligation as of end of year $ 613,503 $ 634,674 $ 138,795 $ 127,989 Change in plan assets: Fair value of plan assets as of beginning of year $ 539,311 $ 481,502 $ 31,312 $ 29,732 Actual return on plan assets (4,305) 55,974 (444) 1,580 Employer contributions 12,000 32,000 Benefits paid . (29,772) (30,165) . Fair value of plan assets as of end of year $ 517,234 $ 539,311 $ 30,868 $ 31,312 Funded status $ (96,269) $ (95,363) $ (107,927) $ (96,677) Unrecognized net actuarial loss 162,961 175,596 92,433 82,421 Unrecognized prior service cost 25 256 (10,180) (10,379) Prepaid (accrued) benefit cost 66,717 80,489 (25,674) (24,635) Additional liability (162,986) (175,852) (82,253) (72,042) Accrued benefit liability $ (96,269) $ (95,363) $ (107,927) $ (96,677) Accumulated pension benefit obligation $ 542,209 $ 551,615 I FERC FORM NO. 2/3-Q (REV 12-07) 122.22 PC_DR_009 Attachment B Page 56 of 177 Name of Respondent This Report is: Date of Report Year/Period of Report (1) 6 An Original (Mo, Da, Yr) Avista Corporation (2) A Resubmission 04/15/2016 2015/04 Notes to Financial Statements Other Post- Pension Benefits retirement Benefits 2015 2014 Accumulated postretirement benefit obligation: For retirees $ For fully eligible employees $ For other participants $ Included in accumulated other comprehensive loss (income) (net of tax): Unrecognized prior service cost Unrecognized net actuarial loss Total Less regulatory asset Accumulated other comprehensive loss (income) for unfunded benefit obligation for pensions and other postretirement benefit plans Weighted average assumptions as of December 31: Discount rate for benefit obligation Discount rate for annual expense Expected long-term return on plan assets Rate of compensation increase Medical cost trend pre-age 65 -initial Medical cost trend pre-age 65 -ultimate Ultimate medical cost trend year pre-age 65 Medical cost trend post-age 65 -initial Medical cost trend post-age 65 -ultimate Ultimate medical cost trend year post-age 65 Components of net periodic benefit I FERG FORM NO. 2/3-Q (REV 12-07) Pension Benefits 2015 2014 $ $ 122.23 16 $ 105,925 105,941 (99,414) 6,527 $ 166 $ 114,138 114,304 (106,484) 7,820 $ Pension Benefits 2015 2014 4.57% 4.21% 4.21% 5.10% 5.30% 6.60% 4.87% 4.87% Other Postretirement Benefits 2015 2014 2015 65,652 $ 34,498 $ 38,645 $ (6,617) $ 60,081 53,464 (53,341) 123 $ Other Post- 2014 58,276 31,843 37,870 (6,747) 53,574 46,827 (46,759) 68 retirement Benefits 2015 2014 4.57% 4.16% 4.16% 5.02% 6.36% 6.40% 7.00% 7.00% 5.00% 5.00% 2022 2021 7.00% 7.00% 5.00% 5.00% 2023 2022 PC_DR_009 Attachment B Page 57 of 177 Name of Respondent Avista Corporation cost: Service cost Interest cost Expected return on plan assets Amortization of prior service cost Net loss recognition Net periodic benefit cost Plan Assets $ $ This Report is: (1) X An Original (2) A Resubmission Notes to Financial Statements 19,791 $ 15,757 $ 2,925 26,117 26,224 5,158 (28,299) (32,131) (1,991) 2 22 (1,199) 9,451 4,731 5,095 27,062 $ 14,603 $ 9,988 Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2016 2015/04 $ 1,844 5,226 (1,903) (1, 116) 4,289 $ 8,340 The Finance Committee of the Company's Board of Directors approves investment policies, objectives and strategies that seek an appropriate return for the pension plan and other postretirement benefit plans and reviews and approves changes to the investment and funding policies. The Company has contracted with investment consultants who are responsible for managing/monitoring the individual investment managers. The investment managers' performance and related individual fund performance is periodically reviewed by an internal benefits committee and by the Finance Committee to monitor compliance with investment policy objectives and strategies. Pension plan assets are invested in mutual funds, trusts and partnerships that hold marketable debt and equity securities, real estate, absolute return and commodity funds. In seeking to obtain the desired return to fund the pension plan, the investment consultant recommends allocation percentages by asset classes. These recommendations are reviewed by the internal benefits committee, which then recommends their adoption by the Finance Committee. The Finance Committee has established target investment allocation percentages by asset classes and also investment ranges for each asset class. The target investment allocation percentages are typically the midpoint of the established range. The target investment allocation percentages by asset classes are indicated in the table below: Equity securities Debt securities Real estate Absolute return 2015 27% 58% 6% 9% 2014 27% 58% 6% 9% The fair value of pension plan assets invested in debt and equity securities was based primarily on fair value (market prices). The fair value of investment securities traded on a national securities exchange is determined based on the reported last sales price; securities traded in the over-the-counter market are valued at the last reported bid price. Investment securities for which market prices are not readily available or for which market prices do not represent the value at the time of pricing, the investment manager estimates fair value based upon other inputs (including valuations of securities that are comparable in coupon, rating, maturity and industry). Investments in common/collective trust funds are presented at estimated fair value, which is determined based on the unit value of the fund. Unit value is determined by an independent trustee, which sponsors the fund, by dividing the fund's net assets by its units outstanding at the valuation date. The Company's investments in common/collective trusts have redemption limitations that permit quarterly redemptions following notice requirements of 45 to 60 days. The fair values of the closely held investments and partnership interests are based upon the allocated share of the fair value of the underlying assets as well as the allocated share of the undistributed profits and losses, including realized and unrealized gains and losses. Most of the Company's investments in closely held investments and partnership interests have redemption limitations that range from bi-monthly to semi-annually following redemption notice I FERC FORM NO. 2/3-Q (REV 12-07) 122.24 PC_DR_009 Attachment B Page 58 of 177 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Avista Corporation (2) A Resubmission 04/15/2016 2015/04 Notes to Financial Statements requirements of 60 to 90 days. One investment in a partnership has a lock-up for redemption currently expiring in 2022 and is subject to extension. The fair value of pension plan assets invested in real estate was determined by the investment manager based on three basic approaches: • properties are externally appraised on an annual basis by independent appraisers, additional appraisals may be perfonned as warranted by specific asset or market conditions, • property valuations are reviewed quarterly and adjusted as necessary, and • loans are reflected at fair value. The fair value of pension plan assets was determined as of December 31, 2015 and 2014. Effective December 31, 2015, the Company adopted ASU No. 2015-07, "Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent)," which removed from the fair value hierarchy, investments for which the practical expedient is used to measure fair value at net asset value (NA V). In prior years, the Company held investments fair valued using NA V and these amounts were included as level 3 items. This ASU was adopted retrospectively; therefore, the 2014 amounts have been reclassified to conform to the 2015 presentation. Also, since these amounts are no longer included in the fair value hierarchy as level 3 items, the level 3 reconciliations are no longer applicable and have been excluded from this footnote. The following table discloses by level within the fair value hierarchy (see Note 14 for a description of the fair value hierarchy) of the pension plan's assets measured and reported as of December 31, 2015 at fair value (dollars in thousands): Level 1 Cash equivalents $ Fixed income securities: U.S. government issues Corporate issues International issues Municipal issues Mutual funds: U.S. equity securities International equity securities Absolute return (1) Plan assets measured at NA V (not subject to hierarchy disclosure) Common/collective trusts: Real estate Partnership/closely held investments: Absolute return (1) Private equity funds (2) I FERC FORM NO. 2/3-Q (REV 12-07) 122.25 86 87,678 40,343 13,996 Level2 Level3 $ 10,641 $ 47,845. 187,308 34,458 22,416 $ Total 10,727 47,845 187,308 34,458 22,416 87,678 40,343 13,996 24,147 38,302 73 PC_DR_009 Attachment B Page 59 of 177 Name of Respondent This Report is: Date of Report Year/Period of Report (1) 6 An Original (Mo, Da, Yr) Avista Corporation (2) A Resubmission 04/15/2016 2015/04 Notes to Financial Statements Real estate 9,941 Total $ 142,103 $ 302,668 $ $ 517,234 The following table discloses by level within the fair value hierarchy (see Note 14 for a description of the fair value hierarchy) of the pension plan's assets measured and reported as of December 31, 2014 at fair value (dollars in thousands): Level 1 Level2 Level 3 Total Cash equivalents $ $ 3,138 $ $ 3,138 Fixed income securities: U.S. government issues 19,681 19,681 Corporate issues 104,959 104,959 International issues 19,935 19,935 Municipal issues 2,762 7,788 10,550 Mutual funds: Fixed income securities 157,415 8 157,423 U.S. equity securities 103,203 103,203 International equity securities 40,838 40,838 Absolute return (1) 15,334 15,334 Plan assets measured at NAV (not subject to hierarchy disclosure) Common/collective trusts: Real estate 21,303 Partnership/closely held investments: Absolute return (1) 36,114 Private equity funds (2) 73 Real estate 6,760 Total $ 464,127 $ 10,934 $ $ 539,311 (1) This category invests in multiple strategies to diversify risk and reduce volatility. The strategies include: (a) event driven, relative value, convertible, and fixed income arbitrage, (b) distressed investments, ( c) long/short equity and fixed income, and ( d) market neutral strategies. (2) This category includes private equity funds that invest primarily in U.S. companies. The fair value of other postretirement plan assets invested in debt and equity securities was based primarily on market prices. The fair value of investment securities traded on a national securities exchange is determined based on the last reported sales price; securities traded in the over-the-counter market are valued at the last reported bid price. Investment securities for which market prices are not readily available or for which market prices do not represent the value at the time of pricing, are fair-valued by the investment manager based upon other inputs (including valuations of securities that are comparable in coupon, rating, maturity and industry). The target asset allocation was 60 percent equity securities and 40 percent debt securities in both 2015 and 2014. I FERC FORM NO. 2/3-Q (REV 12-07) 122.26 PC_DR_009 Attachment B Page 60 of 177 Name of Respondent This Report is: Date of Report Year/Period of Report (1) ~An Original (Mo, Da, Yr) Avista Corporation (2) A Resubmission 04/15/2016 2015/04 Notes to Financial Statements The fair value of other postretirement plan assets was determined as of December 31, 2015 and 2014. The following table discloses by level within the fair value hierarchy (see Note 14 for a description of the fair value hierarchy) of other postretirement plan assets measured and reported as of December 31, 2015 at fair value (dollars in thousands): Level 1 Level2 Level3 Total Cash equivalents $ $ 9 $ $ 9 Mutual funds: Fixed income securities 12,000 12,000 U.S. equity securities 13,224 13,224 International equity securities 5,635 5,635 Total $ 30,859 $ 9 $ $ 30,868 The following table discloses by level within the fair value hierarchy (see Note 14 for a description of the fair value hierarchy) of other postretirement plan assets measured and reported as of December 31, 2014 at fair value (dollars in thousands): Level 1 Level2 Level3 Total Cash equivalents $ $ 3 $ $ 3 Mutual funds: Fixed income securities 11,968 11,968 U.S. equity securities 13,210 13,210 International equity securities 6, 131 6,131 Total $ 31,309 $ 3 $ $ 31,312 Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-percentage-point increase in the assumed health care cost trend rate for each year would increase the accumulated postretirement benefit obligation as of December 31, 2015 by $9.7 million and the service and interest cost by $0.5 million. A one-percentage-point decrease in the assumed health care cost trend rate for each year would decrease the accumulated postretirement benefit obligation as of December 31, 2015 by $7.5 million and the service and interest cost by $0.4 million. 401 (k) Plans and Executive Deferral Plan Avista Corp. has a salary deferral 401 (k) plans that is a defined contribution plans and cover substantially all employees. Employees can make contributions to their respective accounts in the plans on a pre-tax basis up to the maximum amount permitted by law. The Company matches a portion of the salary deferred by each participant according to the schedule in the respective plan. Employer matching contributions were as follows for the years ended December 31 (dollars in thousands): 2015 2014 Employer 401(k) matching contributions $ 7,875 $ 6,741 The Company has an Executive Deferral Plan. This plan allows executive officers and other key employees the opportunity to defer I FERC FORM NO. 2/3-Q (REV 12-07) 122.27 PC_DR_009 Attachment B Page 61 of 177 Name of Respondent This Report is: Date of Report Year/Period of Report (1) 6 An Original (Mo, Da, Yr) Avista Corporation (2) A Resubmission 04/15/2016 2015/04 Notes to Financial Statements until the earlier of their retirement, termination, disability or death, up to 75 percent of their base salary and/or up to 100 percent of their incentive payments. Deferred compensation funds are held by the Company in a Rabbi Trust. There were deferred compensation assets and corresponding deferred compensation liabilities on the Balance Sheets of the following amounts as of December 31 (dollars in thousands): 2015 2014 Deferred compensation assets and liabilities $ 8,093 $ 8,677 NOTE 9. ACCOUNTING FOR INCOME TAXES Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes and tax credit carryforwards .. The realization of deferred income tax assets is dependent upon the ability to generate taxable income in future periods. The Company evaluated available evidence supporting the realization of its deferred income tax assets and determined it is more likely than not that deferred income tax assets will be realized. As of December 31, 2015, the Company had $15.3 million of state tax credit carryforwards of which it is expected $2.9 million will expire unused; the Company has reflected the net amount of$12.4 million as an asset at December 31, 2015. State tax credits expire from 2019 to 2028. The Company and its eligible subsidiaries file consolidated federal income tax returns. The Company also files state income tax returns in certain jurisdictions, including Idaho, Oregon and Montana. Subsidiaries are charged or credited with the tax effects of their operations on a stand-alone basis. The Internal Revenue Service (IRS) has completed its examination of all tax years through 2011 and all issues were resolved related to these years. The IRS has not completed an examination of the Company's 2012 and 2014 federal income tax returns. The Company believes that any open tax years for federal or state income taxes will not result in adjustments that would be significant to the financial statements. The Company had net regulatory assets related to the probable recovery of certain deferred income tax liabilities from customers through future rates as of December 31 (dollars in thousands): Regulatory assets for deferred income taxes Regulatory liabilities for deferred income taxes NOTE 10. ENERGY PURCHASE CONTRACTS $ 2015 101,240 $ 17,609 2014 100,412 14,534 Avista Corp. has contracts for the purchase of fuel for thennal generation, natural gas for resale and various agreements for the purchase or exchange of electric energy with other entities. The termination dates of the contracts range from one month to the year 2042. Total expenses for power purchased, natural gas purchased, fuel for generation and other fuel costs, which are included in utility resource costs in the Statements oflncome, were as follows for the years ended December 31 (dollars in thousands): 2015 2014 Utility power resources $ 511,937 $ 556,915 The following table details Avista Corp. 's future contractual commitments for power resources (including transmission contracts) and I FERC FORM NO. 2/3-Q (REV 12-07) 122.28 PC_DR_009 Attachment B Page 62 of 177 Name of Respondent This Report is: (1) 6 An Original Avista Corporation (2) _A Resubmission Notes to Financial Statements natural gas resources (including transportation contracts) (dollars in thousands): Power resources Natural gas resources 2016 $ 261,560 $ 79,335 2017 168,831 $ 64,400 2018 149,375 $ 65,144 2019 145,074 $ 57,105 Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2016 2015/04 2020 Thereafter Total 104,688 $ 45,446 838,536 $ 1,668,064 427,435 738,865 Total $ 340,895 $ 233,231 $ 214,519 $ 202,179 $ 150,134 $ 1,265,971 $ 2,406,929 These energy purchase contracts were entered into as part of Avista Corp.' s obligation to serve its retail electric and natural gas customers' energy requirements, including contracts entered into for resource optimization. As a result, these costs are recovered either through base retail rates or adjustments to retail rates as part of the power and natural gas cost deferral and recovery mechanisms. The above future contractual commitments for power resources include fixed contractual amounts related to the Company's contracts with certain PUDs to purchase portions of the output of certain generating facilities. Although Avista Corp. has no investment in the PUD generating facilities, the fixed contracts obligate Avista Corp. to pay certain minimum amounts whether or not the facilities are operating. The cost of power obtained under the contracts, including payments made when a facility is not operating, is included in utility resource costs in the Statements of Income. The contractual amounts included above consist of A vista Corp.' s share of existing debt service cost and its proportionate share of the variable operating expenses of these projects. The minimum amounts payable under these contracts are based in part on the proportionate share of the debt service requirements of the PUD's revenue bonds for which the Company is indirectly responsible. The Company's total future debt service obligation associated with the revenue bonds outstanding at December 31, 2015 (principal and interest) was $72.0 million. In addition, Avista Corp. has operating agreements, settlements and other contractual obligations related to its generating facilities and transmission and distribution services. The following table details future contractual commitments under these agreements (dollars in thousands): 2016 2017 2018 2019 2020 Thereafter Total Contractual obligations $ 33,694 $ 31,134 $ 26,405 $ 31,117 $ 31,811 $ 192,295 $ 346,456 NOTE 11. NOTES PAYABLE A vista Corp. Avista Corp. has a committed line of credit with various financial institutions in the total amount of $400.0 million that expires in April 2019. The Company has the option to request an extension for an additional one or two years beyond April 2019, provided, 1) that no event of default has occurred and is continuing prior to the requested extension and 2) the remaining term of agreement, including the requested extension period, does not exceed five years. The committed line of credit is secured by non-transferable first mortgage bonds of the Company issued to the agent bank that would only become due and payable in the event, and then only to the extent, that the Company defaults on its obligations under the committed line of credit. The committed line of credit agreement contains customary covenants and default provisions. The credit agreement has a covenant which does not permit the ratio of "consolidated total debt" to "consolidated total capitalization" of Avista Corp. to be greater than 65 percent at any time. As of December 31, 2015, the Company was in compliance with this covenant. Balances outstanding and interest rates of borrowings (excluding letters of credit) under the Company's revolving committed lines of credit were as follows as of December 31 (dollars in thousands): 2015 2014 I FERC FORM NO. 2/3-Q (REV 12-07) 122.29 PC_DR_009 Attachment B Page 63 of 177 Name of Respondent Avista Corporation Balance outstanding at end of period Letters of credit outstanding at end of period Average interest rate at end of period This Report is: (1) ~An Original (2) A Resubmission Notes to Financial Statements Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2016 2015/04 $ 105,000 $ 105,000 $ 44,595 $ 32,579 1.18% 0.93% As of December 31, 2015 and 2014, the borrowings outstanding under Avista Corp.'s committed line of credit were classified as short-term borrowings on the Balance Sheet. NOTE 12. BONDS The following details long-term debt outstanding as of December 31 (dollars in thousands): Maturity Interest Year Description Rate 2015 2014 2016 First Mortgage Bonds 0.84% $ 90,000 $ 90,000 2018 First Mortgage Bonds 5.95% 250,000 250,000 2018 Secured Medium-Tenn Notes 7.39%-7.45% 22,500 22,500 2019 First Mortgage Bonds 5.45% 90,000 90,000 2020 First Mortgage Bonds 3.89% 52,000 52,000 2022 First Mortgage Bonds 5.13% 250,000 250,000 2023 Secured Medium-Term Notes 7.18%-7.54% 13,500 13,500 2028 Secured Medium-Term Notes 6.37% 25,000 25,000 2032 Secured Pollution Control Bonds (1) (1) 66,700 66,700 2034 Secured Pollution Control Bonds (1) (1) 17,000 17,000 2035 First Mortgage Bonds 6.25% 150,000 150,000 2037 First Mortgage Bonds 5.70% 150,000 150,000 2040 First Mortgage Bonds 5.55% 35,000 35,000 2041 First Mortgage Bonds 4.45% 85,000 85,000 2044 First Mortgage Bonds 4.11% 60,000 60,000 2045 First Mortgage Bonds (2) 4.37% 100,000 2047 First Mortgage Bonds 4.23% 80,000 80,000 Total secured bonds 1,536,700 1,436,700 Secured Pollution Control Bonds held by A vista Corporation ( 1) (83,700) (83,700) Total long-term debt $ 1,453,000 $ 1,353,000 (1) In December 2010, $66.7 million and $17.0 million of the City of Forsyth, Montana Pollution Control Revenue Refunding Bonds (Avista Corporation Colstrip Project) due in 2032 and 2034, respectively, which had been held by Avista Corp. since 2008 and 2009, respectively, were refunded by new bond issues (Series 2010A and Series 2010B). The new bonds were not I FERG FORM NO. 2/3-Q (REV 12-07) 122.30 PC_DR_009 Attachment B Page 64 of 177 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Avista Corporation (2) _ A Resubmission 04/15/2016 2015/Q4 Notes to Financial Statements offered to the public and were purchased by Avista Corp. due to market conditions. The Company expects that at a later date, subject to market conditions, these bonds may be remarketed to unaffiliated investors. So long as Avista Corp. is the holder of these bonds, the bonds will not be reflected as an asset or a liability on Avista Corp. 's Balance Sheets. (2) In December 2015, Avista Corp. issued $100.0 million of first mortgage bonds to five institutional investors in a private placement transaction. The first mortgage bonds bear an interest rate of 4.37 percent and mature in 2045. The total net proceeds from the sale of the new bonds were used to repay a portion of the borrowings outstanding under the Company's $400.0 million committed line of credit and for general corporate purposes. The following table details future long-term debt maturities including advances from associated companies (see Note 13) (dollars in thousands): 2016 2017 2018 2019 2020 Thereafter Total Debt maturities $ 90,000 $ -$ 272,500 $ 90,000 $ 52,000 $ 1,000,047 $ 1,504,547 Substantially all utility properties owned by A vista Corp. are subject to the lien of the A vista Corp.' s mortgage indenture. Under the Mortgage and Deed of Trust securing the Company's First Mortgage Bonds (including Secured Medium-Term Notes), the Company may issue additional First Mortgage Bonds in an aggregate principal amount equal to the sum of: 1) 66-2/3 percent of the cost or fair value (whichever is lower) of property additions which have not previously been made the basis of any application under the Mortgage, or 2) an equal principal amount ofretired First Mortgage Bonds which have not previously been made the basis of any application under the Mortgage, or 3) deposit of cash. However, the Company may not issue any additional First Mortgage Bonds (with certain exceptions in the case of bonds issued on the basis ofretired bonds) unless the Company's "net earnings" (as defined in the Mortgage) for any period of 12 consecutive calendar months out of the preceding 18 calendar months were at least twice the annual interest requirements on all mortgage securities at the time outstanding, including the First Mortgage Bonds to be issued, and on all indebtedness of prior rank. As of December 31, 2015, property additions and retired bonds would have allowed, and the net earnings test would not have prohibited, the issuance of $1.1 billion in aggregate principal amount of additional first mortgage bonds at A vista Corp. See Note 11 for infonnation regarding first mortgage bonds issued to secure the Company's obligations under its committed line of credit agreement. NOTE 13. ADVANCES FROM ASSOCIATED COMPANIES In 1997, the Company issued Floating Rate Junior Subordinated Deferrable Interest Debentures, Series B, with a principal amount of $51.5 million to Avista Capital II, an affiliated business trust formed by the Company. Avista Capital II issued $50.0 million of Preferred Trust Securities with a floating distribution rate of LIBOR plus 0.875 percent, calculated and reset quarterly. The distribution rates paid were as follows during the years ended December 31: Low distribution rate High distribution rate Distribution rate at the end of the year 2015 1.11 % 1.29% 1.29% 2014 1.10% 1.11% 1.11% Concurrent with the issuance of the Preferred Trust Securities, Avista Capital II issued $1.5 million of Common Trust Securities to the Company. These debt securities may be redeemed at the option of Avista Capital II at any time and mature on June 1, 2037. In December 2000, the Company purchased $10.0 million of these Preferred Trust Securities. I FERC FORM NO. 2/3-Q (REV 12-07) 122.31 PC_DR_009 Attachment B Page 65 of 177 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Avista Corporation (2) _A Resubmission 04/15/2016 2015/04 Notes to Financial Statements The Company owns 100 percent of A vista Capital II and has solely and unconditionally guaranteed the payment of distributions on, and redemption price and liquidation amount for, the Preferred Trust Securities to the extent that A vista Capital II has funds available for such payments from the respective debt securities. Upon maturity or prior redemption of such debt securities, the Preferred Trust Securities will be mandatorily redeemed. NOTE 14. FAIR VALUE The canying values of cash and cash equivalents, special deposits, accounts and notes receivable, accounts payable and notes payable are reasonable estimates of their fair values. Bonds and advances from associated companies are reported at canying value on the Balance Sheets. The fair value hierarchy prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are defmed as follows: Level 1 -Quoted prices are available in active markets for identical assets or liabilities. Active markets are those in which transactions for the asset or liability occur with sufficient frequency and volume to provide pricing information on an ongoing basis. Level 2 -Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Level 3 -Pricing inputs include significant inputs that are generally unobservable from objective sources. These inputs may be used with internally developed methodologies that result in management's best estimate of fair value. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company's assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. The determination of the fair values incorporates various factors that not only include the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits and letters ofcredit), but also the impact of Avista Corp. 's nonperformance risk on its liabilities. The following table sets forth the canying value and estimated fair value of the Company's financial instruments not reported at estimated fair value on the Balance Sheets as of December 31 (dollars in thousands): Bonds (Level 2) Bonds (Level 3) Advances from associated companies (Level 3) I FERC FORM NO. 2/3-Q (REV 12-07) 2015 Carrying Value $ 951,000 $ 502,000 51,547 122.32 Estimated Fair Value 1,055,797 505,768 36,083 2014 Carrying Estimated Value Fair Value $ 951,000 $ 1,118,972 402,000 432,728 51,547 38,582 PC_DR_009 Attachment B Page 66 of 177 Name of Respondent This Report is: Date of Report Year/Period of Report (1) ~An Original (Mo, Da, Yr) Avista Corporation (2) A Resubmission 04/15/2016 2015/04 Notes to Financial Statements These estimates of fair value of long-term debt and long-term debt to affiliated trusts were primarily based on available market information, which generally consists of estimated market prices from third party brokers for debt with similar risk and terms. The price ranges obtained from the third party brokers consisted of par values of 7 0. 00 to 119. 7 0, where a par value of 100. 00 represents the carrying value recorded on the Balance Sheets. Level 2 long-term debt represents publicly issued bonds with quoted market prices; however, due to their limited trading activity, they are classified as level 2 because brokers must generate quotes and make estimates if there is no trading activity near a period end. Level 3 long-term debt consists of private placement bonds and Advances from associated companies, which typically have no secondary trading activity. Fair values in Level 3 are estimated based on market prices from third party brokers using secondary market quotes for debt with similar risk and terms to generate quotes for A vista Corp. bonds. The following table discloses by level within the fair value hierarchy the Company's assets and liabilities measured and reported on the Balance Sheets as of December 31, 2015 and 2014 at fair value on a recurring basis (dollars in thousands): December 31, 2015 Assets: Energy commodity derivatives Level 3 energy commodity derivatives: Natural gas exchange agreements Foreign currency derivatives Interest rate swaps Deferred compensation assets: Fixed income securities Equity securities Total Liabilities: Energy commodity derivatives Level 3 energy commodity derivatives: Natural gas exchange agreement Power exchange agreement Power option agreement Interest rate swaps Foreign currency derivatives Total I FERC FORM NO. 2/3-Q (REV 12-07) $ $ $ $ Level 1 Level2 -$ 74,637 $ 2 1,548 1,727 5,761 7,488 $ 76,187 $ -$ 97,193 $ 85,498 19 $ 182,710 $ 122.33 Level3 Counterparty and Cash Collateral Netting (1) -$ (73,954) $ 678 678 $ -$ 5,717 21,961 124 27,802 $ (678) (2) (74,634) $ (88,480) $ (678) (2) (89,160) $ Total 683 1,548 1,727 5,761 9,719 8,713 5,039 21,961 124 85,498 17 121,352 PC_DR_009 Attachment B Page 67 of 177 Name of Respondent Avista Corporation December 31, 2014 Assets: Energy commodity derivatives Level 3 energy commodity derivatives: Natural gas exchange agreement Foreign currency derivatives Interest rate swaps Deferred compensation assets: Fixed income securities Equity securities Total Liabilities: Energy commodity derivatives Level 3 energy commodity derivatives: Natural gas exchange agreement Power exchange agreement Power option agreement Foreign currency derivatives Interest rate swaps Total $ $ $ $ This Report is: ( 1) ~An Original (2) _A Resubmission Notes to Financial Statements Level 1 - $ 1,793 6,074 7,867 $ -$ $ Level 2 96,729 $ 966 97,696 $ 127,094 $ 21 77,568 204,683 $ Date of Report Year/Period of Report (Mo, Da, Yr) 04/15/2016 Level3 Counterparty and Cash Collateral Netting (1) - $ (95,204) $ 1,349 1,349 $ (1,349) (1) (506) (97,060) $ - $ (110,714) $ 1,384 (1,349) 23,299 424 (1) (29,386) 25,107 $ (141,450) $ 2015/04 Total 1,525 460 1,793 6,074 9,852 16,380 35 23,299 424 20 48,182 88,340 ·- ( 1) The Company is permitted to net derivative assets and derivative liabilities with the same counterparty when a legally enforceable master netting agreement exists. In addition, the Company nets derivative assets and derivative liabilities against any payables and receivables for cash collateral held or placed with these same counterparties. Avista Corp. enters into forward contracts to purchase or sell a specified amount of energy at a specified time, or during a specified period, in the future. These contracts are entered into as part of Avista Corp.' s management of loads and resources and certain contracts are considered derivative instruments. The difference between the amount of derivative assets and liabilities disclosed in respective levels and the amount of derivative assets and liabilities disclosed on the Balance Sheets is due to netting arrangements with ce1iain counterparties. The Company uses quoted market prices and forward price curves to estimate the fair value of utility derivative commodity instruments included in Level 2. In particular, electric derivative valuations are performed using market quotes, adjusted for periods in between quotable periods. Natural gas derivative valuations are estimated using New York Mercantile Exchange (NYMEX) pricing for similar instruments, adjusted for basin differences, using market quotes. Where observable inputs are available for substantially the full term of the contract, the derivative asset or liability is included in Level 2. I FERG FORM NO. 2/3-Q (REV 12-07) 122.34 PC_DR_009 Attachment B Page 68 of 177 Name of Respondent This Report is: Date of Report Year/Period of Report (1) 6 An Original (Mo, Da, Yr) Avista Corporation (2) A Resubmission 04/15/2016 2015/04 Notes to Financial Statements To establish fair values for interest rate swaps, the Company uses forward market curves for interest rates for the term of the swaps and discounts the cash flows back to present value using an appropriate discount rate. The discount rate is calculated by third party brokers according to the terms of the swap agreements and evaluated by the Company for reasonableness, with consideration given to the potential non-performance risk by the Company. Future cash flows of the interest rate swaps are equal to the fixed interest rate in the swap compared to the floating market interest rate multiplied by the notional amount for each period. To establish fair value for foreign currency derivatives, the Company uses forward market {)Urves for Canadian dollars against the US dollar and multiplies the difference between the locked-in price and the market price by the notional amount of the derivative. Forward foreign currency market curves are provided by third party brokers. The Company's credit spread is factored into the locked-in price of the foreign exchange contracts. Deferred compensation assets and liabilities represent funds held by the Company in a Rabbi Trust for an executive deferral plan. These funds consist of actively traded equity and bond funds with quot~d prices in active markets. The balance disclosed in the table above excludes cash and cash equivalents of $0.6 million as of December 31, 2015 and $0.8 million as of December 31, 2014. Level 3 Fair Value Under the power exchange agreement the Company purchases power at a price that is based on the on the average operating and maintenance (O&M) charges from three surrogate nuclear power plants around the country. To estimate the fair value of this agreement the Company estimates the difference between the purchase price based on the future O&M charges and forward prices for energy. The Company compares the Level 2 brokered quotes and forward price curves described above to an internally developed forward price which is based on the average O&M charges from the three surrogate nuclear power plants for the current year. Because the nuclear power plant O&M charges are only known for one year, all forward years are estimated assuming an annual escalation. In addition to the forward price being estimated using unobservable inputs, the Company also estimates the volumes of the transactions that will take place in the future based on historical average transaction volumes per delivery year (November to April). Significant increases or decreases in any of these inputs in isolation would result in a significantly higher or lower fair value measurement. Generally, a change in the current year O&M charges for the surrogate plants is accompanied by a directionally similar change in O&M charges in future years. There is generally not a correlation between external market prices and the O&M charges used to develop the internal forward price. For the power commodity option agreement, the Company uses the Black-Scholes-Merton valuation model to estimate the fair value, and this model includes significant inputs not observable or corroborated in the market. These inputs include: 1) the strike price (which is an internally derived price based on a combination of generation plant heat rate factors, natural gas market pricing, delivery and other O&M charges), 2) estimated delivery volumes, and 3) volatility rates for periods beyond January 2018. Significant increases or decreases in any of these inputs in isolation would result in a significantly higher or lower fair value measurement. Generally, changes in overall commodity market prices and volatility rates are accompanied by directionally similar changes in the strike price and volatility assumptions used in the calculation. For the natural gas commodity exchange agreement, the Company uses the same Level 2 brokered quotes described above; however, the Company also estimates the purchase and sales volumes (within contractual limits) as well as the timing of those transactions. Changing the timing of volume estimates changes the timing of purchases and sales, impacting which brokered quote is used. Because the brokered quotes can vary significantly from period to period, the unobservable estimates of the timing and volume of transactions can have a significant impact on the calculated fair value. The Company currently estimates volumes and timing of transactions based on a most likely scenario using historical data. Historically, the timing and volume of transactions have not been highly correlated with market prices and market volatility. I FERC FORM NO. 2/3-Q (REV 12-07) 122.35 PC_DR_009 Attachment B Page 69 of 177 Name of Respondent This Report is: Date of Report Year/Period of Report (1) 6 An Original (Mo, Da, Yr) Avista Corporation (2) A Resubmission 04/15/2016 2015/04 Notes to Financial Statements The following table presents the quantitative information which was used to estimate the fair values of the Level 3 assets and liabilities above as of December 31, 2015 (dollars in thousands): Power exchange agreement Power option agreement Natural gas exchange agreement $ Fair Value (Net) at December 3 1, 2015 (21,961) (124) (5,039) Valuation Technique Surrogate facility pricing Black-Scholes- Merton Internally derived weighted average cost of gas Unobservable Input Range O&M charges $33.52-$43.65/MWh (1) Escalation factor 3% -2016 to 2019 Transaction volumes 233,054 -397,030 MWhs Strike price $35.43/MWh -2016 $48.78/MWh -2019 Delivery volumes 157,517 -285,979 MWhs Volatility rates 0.20 (2) Forward purchase prices $1.67 -$2.84/mmBTU Forward sales prices $1.88 -$3.68/mmBTU Purchase volumes 115,000 -310,000 mmBTUs Sales volumes 30,000 -310,000 mmBTUs (1) The average O&M charges for the delivery year beginning in November 2015 were $3 9 .27 per MWh. For ratemaking purposes the average O&M charges to be included for recovery in retail rates vary slightly between regulatory jurisdictions. The average O&M charges for the delivery year beginning in 2015 are $43.52 for Washington and $39.27 for Idaho. (2) The estimated volatility rate of 0.20 is compared to actual quoted volatility rates of 0.37 for 2016 to 0.24 in January 2018. Avista Corp.'s risk management department and accounting department are responsible for developing the valuation methods described above and both groups report to the Chief Financial Officer. The valuation methods, significant inputs and resulting fair values described above are reviewed on at least a quarterly basis by the risk management department and the accounting department to ensure they provide a reasonable estimate of fair value each reporting period. The following table presents activity for energy commodity derivative assets (liabilities) measured at fair value using significant unobservable inputs (Level 3) for the years ended December 31 (dollars in thousands): I FERC FORM NO. 2/3-Q (REV 12-07) Natural Gas Exchange Agreement 122.36 Power Exchange Agreement Power Option Agreement Total PC_DR_009 Attachment B Page 70 of 177 Name of Respondent This Report is: Date of Report Year/Period of Report (1) 6 An Original (Mo, Da, Yr) Avista Corporation (2) A Resubmission 04/15/2016 2015/04 Notes to Financial Statements Year ended December 31, 2015: Balance as ofJanuary 1, 2015 $ (35) $ (23,299) $ (424) $ (23,758) Total gains or losses (realized/unrealized): Included in regulatory assets/liabilities ( 1) (6,008) (6,198) 300 (11,906) Settlements 1,004 7,536 8,540 Ending balance as of December 31, 2015 (2) $ (5,039) $ (21,961) $ (124) $ (27,124) Year ended December 31, 2014: Balance as of January 1, 2014 $ (1,219) $ (14,441) $ (775) $ (16,435) Total gains or losses (realized/unrealized): Included in regulatory assets/liabilities ( 1) 3,873 (10,002) 351 (5,778) Settlements (2,689) 1,144 (1,545) Ending balance as of December 31, 2014 (2) $ (35) $ (23,299) $ (424) $ (23,758) (1) All gains and losses are included in other regulatory assets and liabilities. There were no gains and losses included in either net income or other comprehensive income during any of the periods presented in the table above. (2) There were no purchases, issuances or transfers from other categories of any derivatives instruments during the periods presented in the table above. NOTE 15. COMMON STOCK The Company had a Direct Stock Purchase and Dividend Reinvestment Plan under which the Company's shareholders could automatically reinvest their dividends and make optional cash payments for the purchase of the Company's common stock at current market value. This plan was terminated by the Company in 2014. The payment of dividends on common stock could be limited by: • certain covenants applicable to preferred stock (when outstanding) contained in the Company's Restated Articles of Incorporation, as amended (currently there are no preferred shares outstanding), • certain covenants applicable to the Company's outstanding long-term debt and committed line of credit agreements, • the hydroelectric licensing requirements of section 10( d) of the FP A (see Note 1 ), and. • certain requirements under the Public Utility Commission of Oregon (OPUC) approval of the AERC acquisition. As of July 1, 2015 (one year following the acquisition date), the OPUC does not permit one-time or special dividends from AERC to A vista Corp. and does not permit A vista Corp.' s total equity to total capitalization to be less than 40 percent, without approval from the OPUC. However, the OPUC approval does allow for regular distributions of AERC earnings to Avista Corp. as long as AERC remains sufficiently capitalized and insured. The Company declared the following dividends for the year ended December 31: 2015 2014 Dividends paid per common share $ 1.32 $ 1.27 I FERC FORM NO. 2/3-Q (REV 12-07) 122.37 PC_DR_009 Attachment B Page 71 of 177 Name of Respondent This Report is: Date of Report Year/Period of Report (1) ~An Original (Mo, Da, Yr) Avista Corporation (2) A Resubmission 04/15/2016 2015/04 Notes to Financial Statements Under the covenant applicable to the Company's committed line of credit agreement, which does not permit the ratio of"consolidated total debt" to "consolidated total capitalization" to be greater than 65 percent at any time, the amount of retained earnings available for dividends at December 31, 2015 was limited to approximately $3 85 .3 million. Under the requirements of the OPUC approval of the AERC acquisition as outlined above, the amount available for dividends at December 31, 2015 was limited to approximately $231.0 million. The Company has 10 million authorized shares of preferred stock. The Company did not have any preferred stock outstanding as of December 31, 2015 and 2014. Stock Repurchase Programs During 2014, Avista Corp.'s Board of Directors approved a program to repurchase up to 4 million shares of the Company's outstanding common stock (2014 program). Repurchases of common stock under this program began on July 7, 2014 and the program expired on December 31, 2014. Repurchases were made in the open market or in privately negotiated transactions. Under the 2014 program the Company repurchased 2,529,615 shares at a total cost of $79.9 million and an average cost of $31.57 per share. The Company did not make any repurchases under this program subsequent to October 2014. Avista Corp. initiated a second stock repurchase program on January 2, 2015 that expired on March 31, 2015 for the repurchase of up to 800,000 shares of the Company's outstanding common stock (first quarter 2015 program). The number of shares repurchased through the first quarter 2015 program was in addition to the number of shares repurchased under the 2014 program, which expired on December 31, 2014. Under the first quarter 2015 program, the Company repurchased 89,400 shares at a total cost of $2.9 million and an average cost of $32.66 per share. All repurchased shares under the 2014 program and the first quarter 2015 program reverted to the status of authorized but unissued shares. NOTE 16. COMMITMENTS AND CONTINGENCIES In the course of its business, the Company becomes involved in various claims, controversies, disputes and other contingent matters, including the items described in this Note. Some of these claims, controversies, disputes and other contingent matters involve litigation or other contested proceedings. For all such matters, the Company intends to vigorously protect and defend its interests and pursue its rights. However, no assurance can be given as to the ultimate outcome of any particular matter because litigation and other contested proceedings are inherently subject to numerous uncertainties. For matters that affect Avista Corp.'s operations, the Company intends to seek, to the extent appropriate, recovery of incurred costs through the ratemaking process. California Refund Proceeding Recently, APX, a market maker in these proceedings in whose markets Avista Energy participated in the summer of 2000, has asserted that A vista Energy and its other customer/participants may be responsible for a share of the disgorgement penalty APX may be found to owe to the California parties. The penalty arises as a result of the FERC fmding that APX committed violations in the California market in the summer of 2000. APX is making these assertions despite A vista Energy having been dismissed in FERC Opinion No. 536 from the on-going administrative proceeding at the FERC regarding potential wrongdoing in the California markets in the summer of2000. APX has identified Avista Energy's share of APX's exposure to be as much as $16.0 million even though no wrongdoing allegations are specifically attributable to Avista Energy. Avista Energy believes its settlement insulates it from any such liability and that as a dismissed party it cannot be drawn back into the litigation. Avista Energy intends to vigorously dispute APX's assertions of indirect liability, but cannot at this time predict the eventual outcome. I FERG FORM NO. 2/3-Q (REV 12-07) 122.38 PC_DR_009 Attachment B Page 72 of 177 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Avista Corporation (2) A Resubmission 04/15/2016 2015/04 Notes to Financial Statements Pacific Northwest Refund Proceeding In July 2001, the FERC initiated a preliminary evidentiary hearing to develop a factual record as to whether prices for spot market sales of wholesale energy in the Pacific Northwest between December 25, 2000 and June 20, 2001 were just and reasonable. In June 2003, the FERC terminated the Pacific Northwest refund proceedings, after fmding that the equities do not justify the imposition of refunds. In August 2007, the Ninth Circuit found that the FERC had failed to take into account new evidence of market manipulation and that such failure was arbitrary and capricious and, accordingly, remanded the case to the FERC, stating that the FERC's findings must be reevaluated in light of the new evidence. The Ninth Circuit expressly declined to direct the FERC to grant refunds. On October 3, 2011, the FERC issued an Order on Remand. On April 5, 2013, the FERC issued an Order on Rehearing expanding the temporal scope of the proceeding to permit parties to submit evidence on transactions during the period from January 1, 2000 through and including June 20, 2001. The Order on Remand established an evidentiary, trial-type hearing before an ALJ, and reopened the record to permit parties to present evidence of unlawful market activity. The Order on Remand stated that parties seeking refunds must submit evidence demonstrating that specific unlawful market activity occurred, and must demonstrate that such activity directly affected negotiations with respect to the specific contract rate about which they complain. Simply alleging a general link between the dysfunctional spot market in California and the Pacific Northwest spot market would not be sufficient to establish a causal connection between a particular seller's alleged unlawful activities and the specific contract negotiations at issue. The hearing was conducted in August through October 2013. On July 11, 2012 and March 28, 2013, Avista Energy and Avista Corp. filed settlements of all issues in this docket with regard to the claims made by the City of Tacoma and the California AG (on behalf of CERS). The FERC has approved the settlements and they are fmal. The remaining direct claimant against A vista Corp. and A vista Energy in this proceeding is the City of Seattle, Washington (Seattle). With regard to the Seattle claims, on March 28, 2014, the Presiding ALJ issued her Initial Decision fmding that: 1) Seattle failed to demonstrate that either Avista Corp. or A vista Energy engaged in unlawful market activity and also failed to identify any specific contracts at issue; 2) Seattle failed to demonstrate that contracts with either Avista Corp. or A vista Energy imposed an excessive burden on consumers or seriously harmed the public interest; and that 3) Seattle failed to demonstrate that either Avista Corp. or Avista Energy engaged in any specific violations of substantive provisions of the FPA or any filed tariffs or rate schedules. Accordingly, the ALJ denied all of Seattle's claims under both section 206 and section 309 of the FPA. On May 22, 2015, the FERC issued its Order on Initial Decision in which it upheld the ALJ's Initial Decision denying all of Seattle's claims against Avista Corp. and Avista Energy. Seattle filed a Request for Rehearing of the FERC' s Order on Initial Decision which was denied on December 31, 2015. Seattle appealed the FERC's decision to the Ninth Circuit. The Company does not expect that this matter will have a material adverse effect on its financial condition, results of operations or cash flows. Sierra Club and Montana Environmental Information Center Complaint Against the Owners of Colstrip On March 6, 2013, the Sierra Club and Montana Environmental Infonnation Center (MEIC) (collectively "Plaintiffs"), filed a Complaint in the United States District Court for the District of Montana, Billings Division, against the Owners of the Colstrip Generating Project ("Colstrip"). Avista Corp. owns a 15 percent interest in Units 3 & 4 of Colstrip. The other Colstrip co-Owners are Talen (formerly PPL Montana), Puget Sound Energy, Portland General Electric Company, NorthWestern Energy and PacifiCorp. The Complaint alleges certain violations of the Clean Air Act, including the New Source Review, Title V and opacity requirements. On September 27, 2013, the Plaintiffs filed an Amended Complaint. The Amended Complaint withdrew from the original Complaint fifteen claims related to seven pre-January 1, 2001 Colstrip maintenance projects, upgrade projects and work projects and claims alleging violations of Title V and opacity requirements. The Amended Complaint alleges certain violations of the Clean Air Act and the New Source Review and adds claims with respect to post-January 1, 2001 Colstrip projects. On August 27, 2014, the Plaintiffs filed a Second Amended Complaint. The Second Amended Complaint withdraws from the I FERC FORM NO. 2/3-Q (REV 12-07) 122.39 PC_DR_009 Attachment B Page 73 of 177 Name of Respondent This Report is: Date of Report Year/Period of Report (1) ~An Original (Mo, Da, Yr) Avista Corporation (2) _ A Resubmission 04/15/2016 2015/04 Notes to Financial Statements Amended Complaint five claims and adds one new claim. The Second Amended Complaint alleges certain violations of the Clean Air Act and the New Source Review. The Plaintiffs request that the Court grant injunctive and declaratory relief, order remediation of alleged environmental damages, impose civil penalties, require a beneficial environmental project in the areas affected by the alleged air pollution and require payment of Plaintiffs' costs of litigation and attorney fees. The Plaintiffs have since indicated that they do not intend to pursue two of the seven projects, leaving a total of five projects remaining. A number of motions for summary judgment were filed by both the Plaintiffs and the defendants. The Court issued its rulings on these motions and, as a result, only two projects remain for trial. The Plaintiffs have filed objections to the order. The case has been bifurcated into separate liability and remedy trials. The Court has set the liability trial date for May 31, 2016. No date has been set for the remedy trial. Management believes that it is reasonably possible that this matter could result in a loss to the Company. However, due to uncertainties concerning this matter, A vista Corp. cannot predict the outcome or determine whether it would have a material impact on the Company. Cabinet Gorge Total Dissolved Gas Abatement Plan Dissolved atmospheric gas levels (referred to as "TDG") in the Clark Fork River exceed state ofldaho and federal water quality numeric standards downstream of Cabinet Gorge during periods when excess river flows must be diverted over the spillway. Under the terms of the Clark Fork Settlement Agreement as incorporated in Avista Corp.'s FERC license for the Clark Fork Project, Avista Corp. has worked in consultation with agencies, tribes and other stakeholders to address this issue. Under the terms of a gas supersaturation mitigation plan, A vista is reducing TDG by constructing spill crest modifications on spill gates at the dam, and the Company expects to continue spill crest modifications over the next several years, in ongoing consultation with key stakeholders. Avista Corp. cannot at this time predict the outcome or estimate a range of costs associated with this contingency; however, the Company will continue to seek recovery, through the ratemaking process, of all operating and capitalized costs related to this issue. Fish Passage at Cabinet Gorge and Noxon Rapids In 1999, the United States Fish and Wildlife Service (USFWS) listed bull trout as threatened under the Endangered Species Act. In 2010, the USFWS issued a revised designation of critical habitat for bull trout, which includes the lower Clark Fork River. The USFWS issued a final recovery plan in October 2015. The Clark Fork Settlement Agreement describes programs intended to help restore bull trout populations in the project area. Using the concept of adaptive management and working closely with the USFWS, the Company evaluated the feasibility of fish passage at Cabinet Gorge and Noxon Rapids. The results of these studies led, in part, to the decision to move forward with development of permanent facilities, among other bull trout enhancement efforts. Fishway designs for Cabinet Gorge have been completed, and the Company is developing construction cost estimates currently. The Company believes its ongoing efforts through the Clark Fork Settlement Agreement continue to effectively address issues related to bull trout. Avista Corp. cannot at this time predict the outcome or estimate a range of costs associated with this contingency; however, the Company will continue to seek recovery, through the ratemaking process, of all operating and capitalized costs related to fish passage at Cabinet Gorge and Noxon Rapids. Collective Bargaining Agreements The Company's collective bargaining agreements with the IBEW represents approximately 45 percent of all of Avista Corp.'s employees. The agreement with the local union in Washington and Idaho representing the majority (approximately 90 percent) of the Avista Corp. 's bargaining unit employees expires in March 2016. In October 2015, a new collective bargaining agreement concerning wages over the three-year period 2016 through 2018 was approved by the local IBEW in Washington and Idaho. The new collective bargaining agreement will be effective in March 2016. A three-year agreement in Oregon, which covers approximately 50 employees, expires in March 2017. I FERC FORM NO. 2/3-Q (REV 12-07) 122.40 PC_DR_009 Attachment B Page 74 of 177 Name of Respondent This Report is: Date of Report Year/Period of Report ( 1) 6 An Original (Mo, Da, Yr) Avista Corporation (2) A Resubmission 04/15/2016 2015/04 Notes to Financial Statements There is a risk that if collective bargaining agreements expire and new agreements are not reached in each of our jurisdictions, employees could strike. Given the magnitude of employees that are covered by collective bargaining agreements, this could result in disruptions of our operations. However, the Company believes that the possibility of this occurring is remote. Customer Information and Work Management Systems Project Cost Recovery Over the past four years, Avista Corp. has invested significant capital into Project Compass. Project Compass was completed and went into service during the first quarter of2015. As part of the Washington electric and natural gas general rate cases filed in February 2015 and the Oregon natural gas general rate case filed in May 2015, Avista Corp. requested the full recovery of the Washington and Oregon share of the costs associated with this project. On July 27, 2015, the UTC Staff in the Company's electric and natural gas general rate cases filed responsive testimony. Included in their testimony was a recommendation to disallow $12.7 million (Washington's share) of Project Compass costs primarily related to the delay in the completion of the project. In a UTC order received in January 2016, the UTC approved the full recovery of Washington's share of Project Compass costs with no disallowances. In October 2015, the OPUC staff filed testimony in the Company's natural gas general rate case which included a recommendation to disallow $1.2 million (Oregon's share) of Project Compass costs, similar to the initial recommendation in Washington. In an OPUC order received in February 2016, the OPUC approved the full recovery of Oregon's portion of Project Compass costs, with no disallowances. Other Contingencies In the normal course of business, the Company has various other legal claims and contingent matters outstanding. The Company believes that any ultimate liability arising from these actions will not have a material impact on its financial condition, results of operations or cash flows. It is possible that a change could occur in the Company's estimates of the probability or amount of a liability being incurred. Such a change, should it occur, could be significant. The Company routinely assesses, based on studies, expert analyses and. legal reviews, its contingencies, obligations and commitments for remediation of contaminated sites, including assessments of ranges and probabilities of recoveries from other responsible parties who either have or have not agreed to a settlement as well as recoveries from insurance carriers. The Company's policy is to accrue and charge to current expense identified exposures related to environmental remediation sites based on estimates of investigation, cleanup and monitoring costs to be incurred. For matters that affect Avista Corp.'s or AEL&P's operations, the Company seeks, to the extent appropriate, recovery of incurred costs through the ratemaking process. The Company has potential liabilities under the Endangered Species Act for species of fish, plants and wildlife that have either already been added to the endangered species list, listed as "threatened" or petitioned for listing. Thus far, measures adopted and implemented have had minimal impact on the Company. However, the Company will continue to seek recovery, through the ratemaking process, of all operating and capitalized costs related to these issues. Under the federal licenses for its hydroelectric projects, the Company is obligated to protect its property rights, including water rights. In addition, the company holds additional non-hydro water rights. The state of Montana is examining the status of all water right claims within state boundaries through a general adjudication. Claims within the Clark Fork River basin could adversely affect the energy production of the Company's Cabinet Gorge and Noxon Rapids hydroelectric facilities. The state of Idaho has initiated adjudication in northern Idaho, which will ultimately include the lower Clark Fork River, the Spokane River and the Coeur d'Alene basin. The Company is and will continue to be a participant in these and any other relevant adjudication processes. The complexity of such adjudications makes each unlikely to be concluded in the foreseeable future. As such, it is not possible for the Company to estimate the I FERC FORM NO. 213-Q (REV 12-07) 122.41 PC_DR_009 Attachment B Page 75 of 177 Name of Respondent This Report is: Date of Report Year/Period of Report (1) 6 An Original (Mo, Da, Yr) Avista Corporation (2) A Resubmission 04/15/2016 2015/04 Notes to Financial Statements impact of any outcome at this time. The Company will continue to seek recovery, through the ratemaking process, of all operating and capitalized costs related to this issue. NOTE 17. REGULATORY MATTERS Power Cost Deferrals and Recove1y Mechanisms Deferred power supply costs are recorded as a deferred charge on the Balance Sheets for future prudence review and recovery through retail rates. The power supply costs deferred include certain differences between actual net power supply costs incurred by A vista Corp. and the costs included in base retail rates. This difference in net power supply costs primarily results from changes in: • short-term wholesale market prices and sales and purchase volumes, • the level and availability of hydroelectric generation, • the level and availability of thermal generation (including changes in fuel prices), and • retail loads. In Washington, the ERM allows Avista Corp. to periodically increase or decrease electric rates with UTC approval to reflect changes in power supply costs. The ERM is an accounting method used to track certain differences between actual power supply costs, net of wholesale sales and sales of fuel, and the amount included in base retail rates for Washington customers. Total net deferred power costs under the ERM were a liability of$18.0 million as of December 31, 2015 compared to a liability of $14.2 million as of December 31, 2014, and these deferred power cost balances represent amounts due to customers. Avista Corp. has a PCA mechanism in Idaho that allows it to modify electric rates on October 1 of each year with IPUC approval. Under the PCA mechanism, Avista Corp. defers 90 percent of the difference between certain actual net power supply expenses and the amount included in base retail rates for its Idaho customers. These annual October 1 rate adjustments recover or rebate power costs deferred during the preceding July-June twelve-month period. Total net power supply costs deferred under the PCA mechanism were a regulatory asset of $0.2 million as of December 31, 2015 compared to a regulatory asset of $8.3 million as of December 31, 2014. Natural Gas Cost Deferrals and Recovery Mechanisms Avista Corp. files a PGA in all three states it serves to adjust natural gas rates for: 1) estimated commodity and pipeline transportation costs to serve natural gas customers for the coming year, and 2) the difference between actual and estimated commodity and transportation costs for the prior year. Total net deferred natural gas costs to be refunded to customers were a liability of $17.9 million as of December 31, 2015 compared to a liability of $3 .9 million as of December 31, 2014. Decoupling and Earnings Sharing Mechanisms Decoupling is a mechanism designed to sever the link between a utility's revenues and consumers' energy usage. The Company's actual revenue, based on kilowatt hour and therm sales will vary, up or down, from the level included in a general rate case, which could be caused by changes in weather, energy conservation or the economy. Generally, the Company's electric and natural gas revenues will be adjusted each month to be based on the number of customers, rather than kilowatt hour and therm sales. The difference between revenues based on sales and revenues based on the number of customers will be deferred and either surcharged or rebated to customers beginning in the following year. Washington Decoupling and Earnings Sharing In Washington, the UTC approved the Company's decoupling mechanisms for electric and natural gas for a five-year period that commenced January 1, 2015. Electric and natural gas decoupling surcharge rate adjustments to customers are limited to 3 percent on an annual basis, with any remaining surcharge balance carried forward for recovery in a future period. There is no limit on the level of I FERC FORM NO. 2/3-Q (REV 12-07) 122.42 PC_DR_009 Attachment B Page 76 of 177 Name of Respondent This Report is: Date of Report Year/Period of Report (1) ~An Original (Mo, Da, Yr) Avista Corporation (2) _ A Resubmission 04/15/2016 2015/04 Notes to Financial Statements rebate rate adjustments. The decoupling mechanisms each include an after-the-fact earnings test. At the end of each calendar year, separate electric and natural gas earnings calculations will be made for the prior calendar year. These earnings tests will reflect actual decoupled revenues, normalized power supply costs and other normalizing adjustments. As of December 31, 2015, the Company had a total net decoupling surcharge (asset) of $10.9 million for Washington electric and natural gas customers and a liability (rebate to customers) for earnings sharing of $3.4 million for Washington electric customers. Idaho Fixed Cost Adjustment (FCA) and Earnings Sharing Mechanisms In Idaho, the IPUC approved the implementation ofFCAs for electric and natural gas (similar in operation and effect to the Washington decoupling mechanisms) for an initial term of three years, commencing on January 1, 2016. For the period 2013 through 2015, the Company had an after-the-fact earnings test, such that if Avista Corp., on a consolidated basis for electric and natural gas operations in Idaho, earned more than a 9.8 percent ROE, the Company was required to share with customers 50 percent of any earnings above the 9.8 percent. There was no provision for a surcharge to customers ifthe Company's ROE was less than 9.8 percent. This after-the-fact earnings test was discontinued as part of the settlement of the Company's 2015 Idaho electric and natural gas general rates cases. As of December 31, 2015 and December 31, 2014, the Company had total cumulative earnings sharing liabilities (rebates to customers) of $8.8 million and $10.1 million, respectively for electric and natural gas customers. NOTE 18. SUPPLEMENTAL CASH FLOW INFORMATION Cash paid for interest Cash paid (received) for income taxes I FERC FORM NO. 2/3-Q (REV 12-07) 122.43 2015 $72,405 $(10,506) 2014 $69,693 $41,154 PC_DR_009 Attachment B Page 77 of 177 This Page Intentionally Left Blank PC_DR_009 Attachment B Page 78 of 177 Name ot Kespondent lhlS wort Is: uate of Report Year/Period of Report Avista Corporation (1) X An Original (Mo, Da, Yr) (2) DA Resubmission 04/15/2016 End of 2015/04 Summary of Utility Plant and Accumulated Provisions for Depreciation, Amortization and Depletion Line Item Total Company No. (a) For the Current Quarter/Year 1 UTILITY PLANT 2 In Service 3 Plant in Service (Classified) 4,912,498,999 4 Property Under Capital Leases 6,729,064 5 Plant Purchased or Sold 6 Completed Construction not Classified 7 Experimental Plant Unclassified 8 TOTAL Utility Plant (Total of lines 3 thru 7) 4,919,228,063 9 Leased to Others 10 Held for Future Use 3,966,915 11 Construction Work in Progress 190, 108,665 12 Acquisition Adjustments 13 TOTAL Utility Plant (Total of lines 8 thru 12) 5, 113,303,643 14 Accumulated Provisions for Depreciation, Amortization, & Depletion 1,680,907,938 15 Net Utility Plant (Total of lines 13 and 14) 3,432,395,705 16 DETAIL OF ACCUMULATED PROVISIONS FOR DEPRECIATION, AMORTIZATION AND DEPLETION 17 In Service: 18 Depreciation 1,626,086,020 19 Amortization and Depletion of Producing Natural Gas Land and Land Rights 20 Amortization of Underground Storage Land and Land Rights 21 Amortization of Other Utility Plant 54,821,918 22 TOTAL In Service (Total of lines 18 thru 21) 1,680,907,938 23 Leased to Others -24 Depreciation 25 Amortization and Depletion 26 TOTAL Leased to Others (Total of lines 24 and 25) 27 Held for Future Use 28 Depreciation 29 Amortization 30 TOTAL Held for Future Use (Total of lines 28 and 29) 31 Abandonment of Leases (Natural Gas) 32 Amortization of Plant Acquisition Adjustment 33 TOTAL Accum. Provisions (Should agree with line 14 above)(Total of lines 22, 26, 30, 31, and 32) 1,680,907,938 FERC FORM NO. 2 (12-96) Page 200 PC_DR_009 Attachment B Page 79 of 177 Avista Corporation This ~ort Is: Date of Report (1) l2$.JAn Original (Mo, Da, Yr) (2) DA Resubmission 04/15/2016 End of 2015/04 Year/Period of Report Name of Respondent Summary of Utility Plant and Accumulated Provisions for Depreciation, Amortization and Depletion (continued) Line No. 4 5 6 7 8 9 10 11 12 13 14 15 33 Electric (c) 3,525, 164,547 286,715 3,525,451,262 3,776,330 152,073,992 3,681,301,584 1,264,628, 194 2,416,673,390 1,264,628, 193 FERC FORM NO. 2 (12-96) Gas (d) 962,527,501 858,864 963,386,365 190,585 13,516,794 977,093,744 317,998,694 659,095,050 317,998,695 Page 201 Other (specify) (e) Common (f) 424,806,951 5,583,485 430,390,436 24,517,879 454,908,315 98,281,050 356,627,265 98,281,050 PC_DR_009 Attachment B Page 80 of 177 Name of Respondent Avista Corporation This ~ort Is: (1) llUAn Original (2) DA Resubmission Gas Plant in Service (Accounts 101, 102, 103, and 106) 1. Report below the original cost of gas plant in service according to the prescribed accounts. Date of Report (Mo, Da, Yr) 04/15/2016 Year/Period of Report End of 2015/04 2. In addition to Account 101, Gas Plant in Service (Classified), this page and the next include Account 102, Gas Plant Purchased or Sold, Account 103, Experimental Gas Plant Unclassified, and Account 106, Completed Construction Not Classified-Gas. 3. Include in column (c) and (d), as appropriate corrections of additions and retirements for the current or preceding year. 4. Enclose in parenthesis credit adjustments of plant accounts to indicate the negative effect of such accounts. 5. Classify Account 106 according to prescribed accounts, on an estimated basis if necessary, and include the entries in column (c).Also to be included in column (c) are entries for reversals of tentative distributions of prior year reported in column (b). Likewise, if the respondent has a significant amount of plant retirements which have not been classified to primary accounts at the end of the year, include in column (d) a tentative distribution of such retirements, on an estimated basis, with appropriate contra entry to the account for accumulated depreciation provision. Include also in column (d) reversals of tentative distributions of prior year's unclassified retirements. Attach supplemental statement showing the account distributions of these tentative classifications in columns (c) and (d), Line No. INTANGIBLE PLANT 2 301 Organization Account a 3 302 Franchises and Consents 4 303 Miscellaneous Intangible Plant 5 TOTAL Intangible Plant (Enter Total of lines 2 thru 4) 6 PRODUCTION PLANT 7-Natural Gas Production and Gathering Plant 8 325.1 Producing Lands 9 325.2 Producing Leaseholds 10 325.3 Gas Rights 11 325.4 Rights-of-Way 12 325.5 Other Land and Land Rights 13 326 Gas Well Structures 14 327 Field Compressor Station Structures 15 328 Field Measuring and Regulating Station Equipment 16 329 Other Structures 17 330 Producing Gas Wells-Well Construction 18 331 Producing Gas Wells-Well Equipment 19 332 Field Lines 20 333 Field Compressor Station Equipment 21 334 Field Measuring and Regulating Station Equipment 22 335 Drilling and Cleaning Equipment 23 336 Purification Equipment 24 337 Other Equipment 25 338 Unsuccessful Exploration and Development Costs 26 339 Asset Retirement Costs for Natural Gas Production and 27 TOTAL Production and Gathering Plant (Enter Total of lines 8 28 PRODUCTS EXTRACTION PLANT 29 340 Land and Land Rights 30 341 Structures and Improvements 31 342 Extraction and Refining Equipment 32 343 Pipe Lines 33 344 Extracted Products Storage Equipment FERC FORM NO. 2 (12-96) Page 204 Balance at Beginning of Year b 4,070,621 4,070,621 Additions 1,342,257 1,342,257 PC_DR_009 Attachment B Page 81 of 177 Name of Respondent Avista Corporation This ~ort Is: Date of Report (1) ~An Original (Mo, Da, Yr) (2) DA Resubmission 04/15/2016 Gas Plant in Service (Accounts 101, 102, 103, and 106) (continued) Year/Period of Report End of 2015/04 including the reversals of the prior years tentative account distributions of these amounts. Careful observance of the above instructions and the texts of Account 101 and 106 will avoid serious omissions of respondent's reported amount for plant actually in service at end of year. 6. Show in column (f) reclassifications or transfers within utility plant accounts. Include also in column (f) the additions or reductions of primary account classifications arising from distribution of amounts initially recorded in Account 102. In showing the clearance of Account 102, include in column (e) the amounts with respect to accumulated provision for depreciation, acquisition adjustments, etc., and show in column (f) only the offset to the debits or credits to primary account classifications. 7. For Account 399, state the nature and use of plant included in this account and if substantial in amount submit a supplementary statement showing subaccount classification of such plant conforming to the requirements of these pages. 8. For each amount comprising the reported balance and changes in Account 102, state the property purchased or sold, name of vendor or purchaser, and date of transaction. If proposed journal entries have been filed with the Commission as required by the Uniform System of Accounts, give date of such filing. Line No. 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 29 30 31 32 33 Retirements FERC FORM NO. 2 (12-96) Adjustments Transfers Page 205 PC_DR_009 Attachment B Page 82 of 177 Name of Respondent Avista Corporation This ~ort Is: Date of Report (1) ~An Original (Mo, Da, Yr) (2) DA Resubmission 04/15/2016 Gas Plant in Service (Accounts 101, 102, 103, and 106) (continued) Line No. Account a 34 345 Compressor Equipment 35 346 Gas Measuring and Regulating Equipment 36 347 Other Equipment 37 348 Asset Retirement Costs for Products Extraction Plant 38 TOTAL Products Extraction Plant (Enter Total of lines 29 thru 37) 39 TOTAL Natural Gas Production Plant (Enter Total of lines 27 and 40 Manufactured Gas Production Plant (Submit Supplementary 41 TOTAL Production Plant (Enter Total of lines 39 and 40) 42 NATURAL GAS STORAGE AND PROCESSING PLANT 43 Underground Storage Plant 44 350.1 Land 45 350.2 Rights-of-Way 46 351 Structures and Improvements 47 352 Wells 48 352.1 Storage Leaseholds and Rights 49 352.2 Reservoirs 50 352.3 Non-recoverable Natural Gas 51 353 Lines 52 354 Compressor Station Equipment 53 355 Other Equipment 54 356 Purification Equipment 55 357 Other Equipment 56 358 Asset Retirement Costs for Underground Storage Plant 57 TOTAL Underground Storage Plant (Enter Total of lines 44 thru 58 Other Storage Plant 59 360 Land and Land Rights 60 361 Structures and Improvements 61 362 Gas Holders 62 363 Purification Equipment 63 363.1 Liquefaction Equipment 64 363.2 Vaporizing Equipment 65 363.3 Compressor Equipment 66 363.4 Measuring and Regulating Equipment 67 363.5 Other Equipment 68 363.6 Asset Retirement Costs for Other Storage Plant 69 TOTAL Other Storage Plant (Enter Total of lines 58 thru 68) 70 Base Load Liquefied Natural Gas Terminaling and Processing Plant 71 364.1 Land and Land Rights 72 364.2 Structures and Improvements 73 364.3 LNG Processing Terminal Equipment 74 364.4 LNG Transportation Equipment 75 364.5 Measuring and Regulating Equipment 76 364.6 Compressor Station Equipment 77 364.7 Communications Equipment 78 364.8 Other Equipment 79 364.9 Asset Retirement Costs for Base Load Liquefied Natural Gas 80 TOTAL Base Load Liquefied Nat'I Gas, Terminaling and FERC FORM NO. 2 (12-96) Page 206 Balance at Beginning of Year b 7,628 7,628 407,111 59,812 1,682,690 13.681,024 254,354 1,667,492 5,810,311 1.106,781 14,656,647 458,185 403,712 1.774,986 41,963,105 Year/Period of Report End of 2015/04 Additions c 223,772 223,773 223,772 223,773 223,772 1, 118,862 PC_DR_009 Attachment B Page 83 of 177 Name of Respondent Avista Corporation Line No. Retirements (d) 34 35 36 37 38 39 40 41 45 46 47 48 49 50 51 52 53 54 55 56 57 59 60 61 62 63 64 65 66 67 68 69 71 72 73 74 75 76 77 78 79 80 FERC FORM NO. 2 (12-96) This ~ort Is: Date of Report (1) 125.J An Original (Mo, Da, Yr) (2) DA Resubmission 04/15/2016 Gas Plant in Service (Accounts 101, 102, 103, and 106) (continued) Adjustments Transfers (e) (f) 2,268 2,268 3,711) 1,443 2,268 Page 207 Year/Period of Report End of 2015/04 Balance at End of Year (g) 7,628 7,628 59,812 1,906,462 13,904,797 254,354 1,667,492 5,810,311 1,106,781 14,876,708 683,401 403,712 1,998,758 43,079,699 PC_DR_009 Attachment B Page 84 of 177 Name of Respondent This 'IB]ort Is: Date of Report Year/Period of Report Avista Corporation (1) X An Original (Mo, Da, Yr) (2) DA Resubmission 04/15/2016 End of 2015/04 Gas Plant in Service (Accounts 101, 102, 103, and 106) (continued) Line Account Balance at Additions No. Beginning of Year a b c 81 TOTAL Nat'I Gas Storage and Processing Plant (Total of lines 57, 41,963,105 1,118,862 82 TRANSMISSION PLAN 83 365.1 Land and Land Rights 84 365.2 Rights-of-Way 85 366 Structures and Improvements 86 367 Mains 87 368 Compressor Station Equipment 88 369 Measuring and Regulating Station Equipment 89 370 Communication Equipment 90 371 Other Equipment 91 372 Asset Retirement Costs for Transmission Plant 92 TOTAL Transmission Plant (Enter Totals of lines 83 thru 91) 93 DISTRIBUTION PLANT 94 374 Land and Land Rights 855,317 31,457 95 375 Structures and Improvements 1, 135,565 197,827 96 376 Mains 425,897,613 37,847,636 97 377 Compressor Station Equipment 98 378 Measuring and Regulating Station Equipment-General 10,199,118 423,507 99 379 Measuring and Regulating Station Equipment-City Gate 7,880,758 1,651,797 100 380 Services 255,486,916 22,316,711 101 381 Meters 104, 152, 189 7,882,260 102 382 Meter Installations 103 383 House Regulators 104 384 House Regulator Installations 105 385 Industrial Measuring and Regulating Station Equipment 4,688,395 244,495 106 386 Other Property on Customers' Premises 107 387 Other Equipment 539 108 388 Asset Retirement Costs for Distribution Plant 109 TOTAL Distribution Plant (Enter Total of lines 94 thru 108) 810,296,410 70,595,690 110 GENERAL PLANT 111 389 Land and Land Rights 1,327,029 112 390 Structures and Improvements 5,761,699 86,765 113 391 Office Furniture and Equipment 624,640 20,269 114 392 Transportation Equipment 12,253,089 2,652,361 115 393 Stores Equipment 141,498 116 394 Tools, Shop, and Garage Equipment 5,955,544 367,787 117 395 Laboratory Equipment 530,584 8,434 118 396 Power Operated Equipment 4,316,053 384,934 119 397 Communication Equipment 3,478,666 120 398 Miscellaneous Equipment 2,367 121 Subtotal (Enter Total of lines 111 thru 120) 34,391, 169 3,520,550 122 399 Other Tangible Property 123 399.1 Asset Retirement Costs for General Plant 124 TOTAL General Plant (Enter Total of lines 121, 122 and 123) 34,391, 169 3,520,550 125 TOTAL (Accounts 1O1 and 106) 890,728,933 76,577,359 126 Gas Plant Purchased (See Instruction 8) 127 (Less) Gas Plant Sold (See Instruction 8) 128 Experimental Gas Plant Unclassified 129 TOTAL Gas Plant In Service (Enter Total of lines 125 thru 128) 890,728,933 76,577,359 FERC FORM NO. 2 (12-96) Page 208 PC_DR_009 Attachment B Page 85 of 177 Name of Respondent Avista Corporation This ~ort Is: Date of Report (1) 12UAn Original (Mo, Da, Yr) (2) DA Resubmission 04/15/2016 Gas Plant in Service (Accounts 101, 102, 103, and 106) (continued) Line No. 81 83 84 85 86 87 88 89 90 91 94 95 96 97 98 99 100 101 102 103 104 105 106 107 108 109 112 113 114 115 116 117 118 119 120 121 122 123 124 127 128 129 Retirements (d) 2,268 3,710 1 ,390,887 38,780 43,527 456,588 166,372 2,099,864 1,320 10,577 687,878 58,314 107,604 9,552 875,245 875,245 3,919,927 3,919,927 FERC FORM NO. 2 (12-96) Adjustments Transfers (e) (f) 3,087 131,898 131,898) ( 3,087) 2 261) 258 Page 209 Year/Period of Report End of 2015/04 Balance at End of Year (g) 43,079,699 886,774 1 ,329,682 462,357,449 10,715,743 9,354,043 277,347,039 111 ,868,077 4,932,890 539 878, 792,236 1,325,709 5,848,464 634,332 14,217,573 141 ,498 6,265,019 431 ,414 4,700,726 3,469,372 2,367 37,036,474 37,036,474 963,386,365 963,386,365 PC_DR_009 Attachment B Page 86 of 177 Name of Respondent Avista Corporation This ~Ort Is: (1) ~An Original (2) DA Resubmission Gas Plant Held for Future Use (Account 105) Date of Report (Mo, Da, Yr) 04/15/2016 Year/Period of Report End of 2015/04 1. Report separately each property held for future use at end of the year having an original cost of $1,000,000 or more. Group other items of property held for future use. 2. For property having an original cost of $1,000,000 or more previously used in utility operations, now held for future use, give in column (a), in addition to other required information, the date that utility use of such property was discontinued, and the date the original cost was transferred to Account 105. Line No. Description and Location of Property (a) Gas Distribution Mains and Services 2 located in Coeur d'Alene, Idaho 3 Gas Distribution Mains and Services 4 located in Coeur d'Alene, Idaho 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 Total FERC FORM NO. 2 (12-96) Date Originally Included Date Expected to be Used in this Account in Utility Service (b) (c) 03/01/2007 07/01/2011 ~-------1 Page 214 Balance at End of Year (d) 159,823 30,762 190,585 PC_DR_009 Attachment B Page 87 of 177 Name of Respondent This 0ort Is: Date of Report Year/Period of Report Avista Corporation (1) X An Original (Mo, Da, Yr) (2) DA Resubmission 04/15/2016 End of 2015/04 Construction Work in Progress-Gas (Account 107) 1. Report below descriptions and balances at end of year of projects in process of construction (Account 107). 2. Show items relating to "research, development, and demonstration" projects last, under a caption Research, Development, and Demonstration (see Account 107 of the Uniform System of Accounts). 3. Minor projects (less than $1,000,000) may be grouped. Construction Work in Estimated Additional Line Description of Project Progress-Gas Cost of Project No. (Account 107) (a) (b) (c) 1 East Medford Reinforcement 4,797,215 2 Gas Revenue Blanket 1,513,280 3 Dollar Rd Service Center Addition and Remodel 1,210,047 4 Spokane St Bridge Gas Main 1,030, 101 5 Minor Projects under $1,000,000 4,966, 151 97,500,000 6 7 8 Notes: 9 Estimated additional cost amounts represent a five year 10 budget total. 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 Total 13,516,794 97,500,000 FERC FORM NO. 2 (12-96) Page 216 PC_DR_009 Attachment B Page 88 of 177 Name of Respondent This Report is: Date of Report Year/Period of Report (1) 6 An Original (Mo, Da1 Yr) Avista Corporation (2) A Resubmission 04/15/2016 2015/04 General Description of Construction Overhead Procedure 1. For each construction overhead explain: (a) the nature and extent of work, etc., the overhead charges are intended to cover, (b) the general procedure for determining the amount capitalized, (c) the method of distribution to construction jobs, (d) whether different rates are applied to different types of construction, (e) basis of differentiation in rates for different types of construction, and (f) whether the overhead is directly or indirectly assigned. 2. Show below the computation of allowance for funds used during construction rates, in accordance with the provisions of Gas Plant Instructions 3 (17) of the Uniform System of Accounts. 3. Where a net-of-tax rate for borrowed funds is used, show the appropriate tax effect adjustment to the computations below in a manner that clearly indicates the amount of reduction in the gross rate for tax effects. Construction costs with a direct relationship to new construction and capital replacement activities that cannot be clearly identified with specific projects are charged to overhead pools. The established pools are: • Construction Overhead North Gas • Construction Overhead South Gas Pool costs are allocated monthly to gas construction projects on a percent rate applied to direct project costs, excluding AFUDC. Each pool's rate is calculated separately and applied only to the related gas construction projects for allocation. Allowance for funds used during construction is calculated system wide using a rate that is equivalent to the allowed rate of return approved in the latest rate order from the company's primary state commission (Washington State). For 2015! Avista used a rate of 7.32%, which is the allowed Rate of Return contained in the Washington Utilities Transportation Commission Final Order 05 date August 181 2014 for consolidated Dockets UE-140188 and UG-140189. I FERC FORM NO. 2 (REV 12-07) 218.1 PC_DR_009 Attachment B Page 89 of 177 Name of Respondent Avista Corporation This ~ort Is: (1) ~An Original (2) DA Resubmission Date of Report (Mo, Da, Yr) 04/15/2016 General Description of Construction Overhead Procedure (continued) COMPUTATION OF ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION RATES 1. For line (5), column (d) below, enter the rate granted in the last rate proceeding. If not available, use the average rate earned during the preceding 3 years. 2. Identify, in a footnote, the specific entity used as the source for the capital structure figures. Year/Period of Report End of 2015/04 3. Indicate, in a footnote, if the reported rate of return is one that has been approved in a rate case, black-box settlement rate, or an actual three-year average rate. 1. Components of Formula (Derived from actual book balances and actual cost rates): Title Amount Line No. (a) (1) Average Short-Term Debt (2) Short-Term Interest (3) Long-Term Debt ( 4) Preferred Stock (5) Common Equity (6) Total Capitalization (7) Average Construction Work In Progress Balance D p c w 2. Gross Rate for Borrowed Funds s(S/W) + d[(D/(D+P+C)) (1-(S/W))] 3. Rate for Other Funds (1-(S/W)] [p(P/(D+P+C)) + c(C/(D+P+C))] 4. Weighted Average Rate Actually Used for the Year: a. Rate for Borrowed Funds - b. Rate for Other Funds - FERC FORM NO. 2 (REV 12-07) Page 218a (b) Capitalization Ration (percent) (c) d p c Cost Rate Percentage (d) ---~ 2.58 4.74 PC_DR_009 Attachment B Page 90 of 177 Name of Respondent Avista Corporation This ~ort Is: Date of Report (1) ~An Original (Mo, Da, Yr) (2) DA Resubmission 04/15/2016 Accumulated Provision for Depreciation of Gas Utility Plant (Account 108) 1. Explain in a footnote any important adjustments during year. Year/Period of Report End of 2015/04 2. Explain in a footnote any difference between the amount for book cost of plant retired, line 10, column (c), and that reported for gas plant in service, page 204-209, column (d), excluding retirements of nondepreciable property. · 3. The provisions of Account 108 in the Uniform System of Accounts require that retirements of depreciable plant be recorded when such plant is removed from service. If the respondent has a significant amount of plant retired at year end which has not been recorded and/or classified to the various reserve functional classifications, make preliminary closing entries to tentatively functionalize the book cost of the plant retired. In addition, include all costs included in retirement work in progress at year end in the appropriate functional classifications. 4. Show separately interest credits under a sinking fund or similar method of depreciation accounting. 5. At lines 7 and 14, add rows as necessary to report all data. Additional rows should be numbered in sequence, e.g., 7.01, 7.02, etc. Line No. Item (a) Section A. BALANCES AND CHANGES DURING YEAR Balance Beginning of Year 2 Depreciation Provisions for Year, Charged to 3 (403) Depreciation Expense 4 (403.1) Depreciation Expense for Asset Retirement Costs 5 (413) Expense of Gas Plant Leased to Others 6 Transportation Expenses -Clearing 7 Other Clearing Accounts 8 Other Clearing (Specify) (footnote details): 9 10 TOTAL Depree. Prov. for Year (Total of lines 3 thru 8) 11 Net Charges for Plant Retired: 12 Book Cost of Plant Retired 13 Cost ofRemoval 14 Salvage (Credit) 15 TOTAL Net Chrgs for Plant Ret. (Total of lines 12 thru 14) 16 Other Debit or Credit Items (Describe) (footnote details): 17 18 Book Cost of Asset Retirement Costs 19 Balance End of Year (Total of lines 1, 10, 15, 16 and 18) Section B. BALANCES AT END OF YEAR ACCORDING TO FUNCTIONAL CLASSIFICATIONS 21 Productions-Manufactured Gas 22 Production and Gathering-Natural Gas 23 Products Extraction-Natural Gas 24 Underground Gas Storage 25 Other Storage Plant 26 Base Load LNG Terminaling and Processing Plant 27 Transmission 28 Distribution 29 General 30 TOTAL (Total of lines 21thru29) FERC FORM NO. 2 (12-96) Total 808,214) 22,164,836 ( 2,979,208) ( 215,490) 12) ( 3,194,686) ( 122,224) 315,698,414 14,482,360 286,927,353 14,288,701 315,698,414 Page 219 Gas Plant in 808,214) 22,164,836 ( 2,979,208) ( 215,490) ( 12) ( 3,194,686) ( 122,224) 315,698,414 14,482,360 286,927,353 14,288,701 315,698,414 Gas Plant Held for Future Use (d) Gas Plant Leased to Others (e) PC_DR_009 Attachment B Page 91 of 177 Name of Respondent This Report is: Date of Report Year/Period of Report (1) 6An Original (Mo, Da, Yr) Avista Corporation (2) _ A Resubmission 04/15/2016 2015/04 FOOTNOTE DATA !Schedule Page: 219 Line No.: 16 Column: c Chan e in Removal Work in Pro ress $-122,224 Schedule Pa e: 219 Line No.: 8 Column: c Adjustment to beginning balance $-448,214 I FERC FORM NO. 2 (12-96) Page 552.1 PC_DR_009 Attachment B Page 92 of 177 This Page Intentionally Left Blank PC_DR_009 Attachment B Page 93 of 177 Name of Respondent Avista Corporation This ~ort Is: Date of Report (1) ~An Original (Mo, Da, Yr) (2) DA Resubmission 04/15/2016 Gas Stored (Accounts 117 .1, 117 .2, 117 .3, 117.4, 164.1, 164.2, and 164.3) Year/Period of Report End of 2015/04 1. If during the year adjustments were made to the stored gas inventory reported In columns (d), (f), (g), and (h) (such as to correct cumulative inaccuracies of gas measurements), explain in a footnote the reason for the adjustments, the Dth and dollar amount of adjustment, and account charged or credited.· 2. Report in column (e) all encroachments during the year upon the volumes designated as base gas, column (b), and system balancing gas, column (c), and gas property recordable in the plant accounts. 3. State in a footnote the basis of segregation of inventory between current and noncurrent portions. Also, state in a footnote the method used to report storage (i.e., fixed asset method or inventory method). Line No. 1 2 3 4 5 6 7 Description (a) Balance at Beginning of Gas Delivered to Storage Gas Withdrawn from Other Debits and Credits Balance at End of Year Dth Amount Per Dth (Account 117.1) (b) 6,992,076 6,992,076 1,253,060 5.5800 FERC FORM NO. 2 (REV 04-04) (Account 117.2) (c) Noncurrent (Account 117.3) (d) (Account 117.4) (e) Page 220 Current (Account 164.1) (f) 28,731,49t 29,241,18~ 45,198,194 12,774,481 5,413,71( 2.3591 LNG (Account 164.2) (g) LNG (Account 164.3) (h) Total (i) 35,723,574 29,241,183 45,198,194 19,766,563 6,666,770 2.9649 PC_DR_009 Attachment B Page 94 of 177 Name of Respondent This wort Is: Date of Report Year/Period of Report Avista Corporation (1) X An Original (Mo, Da, Yr) (2) DA Resubmission 04/15/2016 End of 2015/04 Investments (Account 123, 124, and 136) 1. Report below investments in Accounts 123, Investments in Associated Companies, 124, Other Investments, and 136, Temporary Cash Investments. 2. Provide a subheading for each account and list thereunder the information called for: (a) Investment in Securities-List and describe each security owned, giving name of issuer, date acquired and date of maturity. For bonds, also give principal amount, date of issue; maturity, and interest rate. For capital stock (including capital stock of respondent reacquired under a definite plan for resale pursuant to authorization by the Board of Directors, and included in Account 124, Other Investments) state number of shares, class, and series of stock. Minor investments may be grouped by classes. Investments included in Account 136, Temporary Cash Investments, also may be grouped by classes. (b) Investment Advances-Report separately for each person or company the amounts of loans or investment advances that are properly includable in Account 123. Include advances subject to current repayment in Account 145 and 146. With respect to each advance, show whether the advance is a note or open account. Description of Investment Book Cost at Beginning of Year Purchases or (If book cost is different from Additions Line * cost to respondent, give cost to During the Year No. respondent in a footnote and explain difference) (a) {b) (c) (d) 1 Investment in Spokane Energy (123000) 500,000 2 Investment in Avista Capital II (123010) 11,547,000 3 Other Investment-WZN Loans Sandpoint (124350) 61, 177 4 Other Investment-Coli Cash Value (124600) 17,877,754 5 Other Investment -Coli Borrowings ( 124610) ( 17,877,754) 6 Other Investment -WZN Loans Oregon ( 124680) 31, 125 7 Other Investment-WNP3 Exchange Power (124900) 79,626,000 8 Other Investment-AMT WNP3 Exchange (124930) ( 68, 192,916) 9 Temp Cash Investments (136000) 15,508,864 10 Energy Commodity Contract (124020) 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 FERC FORM NO. 2 (12-96) Page 222 PC_DR_009 Attachment B Page 95 of 177 Name of Respondent This IBJort Is: Date of Report Year/Period of Report Avista Corporation (1) X An Original (Mo, Da, Yr) (2) DA Resubmission 04/15/2016 End of 2015/04 Investments (Account 123, 124, and 136) (continued) List each note, giving date of issuance, maturity date, and specifying whether note is a renewal. Designate any advances due from officers, directors, stockholders, or employees. 3. Designate with an asterisk in column (b) any securities, notes or accounts that were pledged, and in a footnote state the name of pledges and purpose of the pledge. 4. If Commission approval was required for any advance made or security acquired, designate such fact in a footnote and cite Commission, date of authorization, and case or docket number. 5. Report in column (h) interest and dividend revenues from investments including such revenues from securities disposed of during the year. 6. In column (i) report for each investment disposed of during the year the gain or loss represented by the difference between cost of the investment (or the other amount at which carried in the books of account if different from cost) and the selling price thereof, not including any dividend or interest adjustment includible in column (h). Sales or Other Principal Amount or Book Cost at End of Year Revenues for Gain or Loss from Dispositions No. of Shares at (If book cost is different from cost Year Investment Line During Year End of Year to respondent, give cost to Disposed of No. respondent in a footnote and explain difference) (e) (0 (g) (h) (i) 1 500,000 2 11,547,000 3 1,822 59,355 4 ( 1,839,750) 19,717,504 5 1,839,750 ( 19,717,504) 6 7,584 23,541 7 79,626,000 8 2,450,031 ( 70,642,947) 9 15,304,632 204,232 10 ( 14,694,374) 14,694,374 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 FERC FORM NO. 2 (12-96) Page 223 PC_DR_009 Attachment B Page 96 of 177 Name of Respondent This IBJort Is: Date of Report Year/Period of Report Avista Corporation (1) X An Original (Mo, Da, Yr) (2) DA Resubmission 04/15/2016 End of 2015/04 Investments in Subsidiary Companies (Account 123.1) 1. Report below investments in Account 123.1, Investments in Subsidiary Companies. 2. Provide a subheading for each company and list thereunder the information called for below. Sub-total by company and give a total in columns (e), (D, (g) and (h). (a) Investment in Securities-List and describe each security owned. For bonds give also principal amount, date of issue, maturity, and interest rate. ·- (b) Investment Advances -Report separately the amounts of loans or investment advances which are subject to repayment, but which are not subject to current settlement. With respect to each advance show whether the advance is a note or open account. List each note giving date of issuance, maturity date, and specifying whether note is a renewal. 3. Report separately the equity in undistributed subsidiary earnings since acquisition. The total in column (e) should equal the amount entered for Account 418. 1. Description of Investment Date Date of Amount of Acquired Maturity Investment at Line Beginning of Year No. (a) (b) (c) (d) 1 Investment in Avista Capital 01/01/1997 206, 138,971 2 Avista Capital -Equity in Earnings ( 148,878, 702) 3 Investment in AERC 07/01/2014 89,816,380 4 AERC-Equity in Earnings 1, 179,202 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 TOTAL Cost of Account 123.1 $ TOTAL 148,255,851 FERC FORM NO. 2 (12~96) Page 224 PC_DR_009 Attachment B Page 97 of 177 Name of Respondent This wort Is: Date of Report Year/Period of Report Avista Corporation (1) X An Original (Mo, Da, Yr) (2) DA Resubmission 04/15/2016 End of 2015/04 Investments in Subsidiary Companies (Account 123.1) (continued) 4. Designate in a footnote, any securities, notes, or accounts that were pledged, and state the name of pledgee and purpose of the pledge. 5. If Commission approval was required for any advance made or security acquired, designate such fact in a footnote and give name of Commission, date of authorization, and case or docket number. 6. Report in column (D interest and dividend revenues from investments, including such revenues from securities disposed of during the year. 7. In column (h) report for each investment disposed of during the year, the gain or loss represented by the difference between cost of the investment (or the other amount at which carried in the books of account if different from cost), and the selling price thereof, not including interest adjustments includible in column (D. 8. Report on Line 40, column (a) the total cost of Account 123. 1. Equity in Subsidiary Revenues for Year Amount of Investment Gain or Loss from Earnings for Year at End of Year Investment Line Disposed of No. (e) (0 (g) (h) 1 206, 138,971 2 4,856,990 ( 144,021,712) 3 89,816,380 4 6,307,795 1,905,356 5,581,641 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 11, 164,785 1,905,356 157,515,280 FERC FORM NO. 2 (12-96) Page 225 PC_DR_009 Attachment B Page 98 of 177 This Page Intentionally Left Blank PC_DR_009 Attachment B Page 99 of 177 Avista Corporation This ~ort Is: Date of Report (1) l.2U An Original (Mo, Da, Yr) (2) DA Resubmission 04/15/2016 End of 2015/04 Year/Period of Report Name of Respondent Prepayments (Acct 165), Extraordinary Property Losses (Acct 182.1), Unrecovered Plant and Regulatory Study Costs (Acct 182.2) PREPAYMENTS (ACCOUNT 165) 1. Report below the particulars (details) on each prepayment. Line No. 1 2 3 4 5 6 Prepaid Insurance Prepaid Rents Prepaid Taxes Prepaid Interest Miscellaneous Prepayments TOTAL FERC FORM NO. 2 (12-96) Nature of Payment (a) Page 230a Balance at End of Year (in dollars) (b) 1,728,569 10,740 8,841,625 10,580,934 PC_DR_009 Attachment B Page 100 of 177 Name of Respondent This [8Jort Is: Date of Report Year/Period of Report Avista Corporation (1) X An Original (Mo, Da, Yr) (2) DA Resubmission 04/15/2016 End of 2015/04 Other Regulatory Assets (Account 182.3) 1. Report below the details called for concerning other regulatory assets which are created through the ratemaking actions of regulatory agencies (and not includable in other accounts). ·~ 2. For regulatory assets being amortized, show period of amortization in column (a). 3. Minor items (5% of the Balance at End of Year for Account 182.3 or amounts less than $250,000, whichever is less) may be grouped by classes. 4. Report separately any "Deferred Regulatory Commission Expenses" that are also reported on pages 350-351, Regulatory Commission Expenses. 5. Provide in a footnote, for each line item, the regulatory citation where authorization for the regulatory asset has been granted (e.g. Commission Order, state commission order, court decision). Line Description and Purpose of Balance at Debits Written off During Written off Written off Balance at End of No. Other Regulatory Assets Beginning Quarter/Year During Period During Period Current Current Account Amount Recovered Amount Deemed Quarter/Year Quarter/Year Charged Unrecoverable (a) (b) (c) (d) (e) (D (g) 1 Reg Asset Post Ret Liab 235,758,103 283 749,255 235,008,848 2 Regulatory Asset FAS109 Utility Plant 44,773,122 283 2,668,880 42,104,242 3 Regulatory Asset Lancaster Generation 1,246,667 407 1,246,667 4 Regulatory Asset FAS109 DSIT Non Plant 48,022,781 3,804,812 51,827,593 5 Regulatory Asset FAS109 DFIT State Tax Cr 4,238,612 413,509 4,652,121 6 Regulatory Asset FAS109 WNP3 3,441,373 283 737,482 2,703,891 7 Regulatory Asset-Spokane River Relicense 464,890 407 78,736 386,154 8 Regulatory Asset-Spokane River PM&E 429,262 557 73,312 355,950 9 Regulatory Asset-Lake CDA Fund 9,015,469 407 211,065 8,804,404 10 Regulatory Asset-Lake CDA IPA Fund 2,000,000 2,000,000 11 Reg Asset-Decoupling Surcharge 468,893 468,893 12 Regulatory Asset-Decoupling Surcharge 5,460 180 5,640 13 Regulatory Asset-Lake CDA Def Costs 1,277,422 407 32,719 1,244,703 14 Def CS2 & Colstrip 5,804,313 407 981,015 4,823,298 15 Reardan Wind Generation 170,529 407 170,529 16 ID Wind Gen AFUDC 46,171 407 46,171 17 Regulatory Asset Wartsila Units 153,156 407 153,156 18 MTM ST Regulatory Asset 29,640,374 244 12,380,197 17,260,177 19 MTM LT Regulatory Asset 24,483, 175 7,936,548 32,419,723 20 Regulatory Asset FAS 143 Asset Retirement Obligation 2,301,253 574,645 2,875,898 21 Reg Asset AN-CDA Lake Settlement 34,516,176 407 . 884,086 33,632,090 22 Reg Asset WA-CDA Lake Settlement 900,034 407 152,118 747,916 23 Regulatory Asset Workers Comp 2,194,343 407 146,511 2,047,832 24 Regulatory Asset ID PCA Deferral 1 932,887 932,887 25 Regulatory Asset ID PCA Deferral 2 6,211,802 557 6,211,802 26 Regulatory Asset ID PCA Deferral 3 2,078,991 557 2,078,991 27 Spokane River TOG 871,184 407 290,395 580,789 28 Settled Interest Rate Swap Asset 33,964,535 6,821,977 40,786,512 29 DSM Asset 4,603,415 3,167,519 407 4,603,415 3,167,519 30 Unsettled Interest Rate Swap Asset 77,062,517 6,910,260 83,972,777 31 Other Reg Assets 103,536 117,677 221,213 32 33 34 35 36 37 38 39 40 Total 576,247,558 30,680,014 33,896,502 0 573,031,070 FERC FORM NO. 2/3Q (REV 12-07) Page 232 PC_DR_009 Attachment B Page 101 of 177 Name of Respondent This 0ort Is: Date of Report Year/Period of Report Avista Corporation (1) X An Original (Mo, Da, Yr) (2) DA Resubmission 04/15/2016 End of 2015/04 Miscellaneous Deferred Debits (Account 186) 1. Report below the details called for concerning miscellaneous deferred debits. 2. For any deferred debit being amortized, show period of amortization in column (a). 3. Minor items (less than $250,000) may be grouped by classes. Line Description of Miscellaneous Balance at Debits Credits Credits Balance at No. Deferred Debits Beginning End of Year of Year Account Amount Charged (a) (b) (c) (d) (e) (0 1 2 Colstrip Common Fae. 1, 110,999 406 1,110,999 3 Regulatory Asset-Mt Lease Pymt 631,197 540 360,684 270,513 4 Regulatory Asset-Mt Lease Pymt 1,353,216 540 676,632 676,584 5 Colstrip Common Fae. 2,355,642 2,355,642 6 Prepaid Airplane Lease LT 24,528 417,438 931 441,966 7 Misc DD-Airplane Lease 21,692 493,708 515,400 8 Plant Alloc of Clearing Jrl 3,530,342 1,642,293 1,888,049 9 Misc Posting Suspense 43,137 72,158 VAR 115,295 10 Renewable Energy-Cert Fees 67,688 557 45,938 21,750 11 Nez Perce Settlement 150,325 557 5,212 145,113 12 Reg Asset ID-Lake CDA 178,106 506 30,975 147,131 13 Credit Union Labor & Expense 36,474 26,504 62,978 14 Misc Work Orders <$50,000 ( 109,222) 23,130 VAR ( 86,092) 15 Subsidiary Billings 433,608 38,043 VAR 471,651 16 Misc Deferred Debits (WA) 16,568 16,568 17 Regulatory Assets Consv 1,878,235 276,346 2,154,581 18 Reg Asset-Decoupling deferred 13,305,979 13,305,979 19 Optional Wind Power ( 215,056) 8,821 909 ( 206,235) 20 Gas Telemetry equip 6,503 1,680 4,823 21 Misc deferred debits/Res Acct 225,361 225,361 22 Mutual Aid Response PGE 81,208 81,208 23 Deferred Project Compass (ID) 3,346,902 3,346,902 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 Miscellaneous Work in Progress 11,803,983~ 40 Total 26,759,597 FERC FORM NO. 2 (12-96) Page 233 PC_DR_009 Attachment B Page 102 of 177 Name of Respondent Avista Corporation This ~Ort Is: (1) l.2SjAn Original (2) DA Resubmission· Accumulated Deferred Income Taxes (Account 190) 1. Report the information called for below concerning the respondent's accounting for deferred income taxes. 2. At Other (Specify), include deferrals relating to other income and deductions. Date of Report (Mo, Da, Yr) 04/15/2016 Year/Period of Report End of 2015/04 3. Provide in a footnote a summary of the type and amount of deferred income taxes reported in the beginning-of-year and end-of-year balances for deferred income taxes that the respondent estimates could be included in the development of jurisdictional recourse rates. Account Subdivisions Line No. (a) Account 190 2 Electric 3 Gas 4 Other (Define) (footnote details) 5 Total (Total of lines 2 thru 4) 6 Other (Specify) (footnote details) 7 TOTAL Account 190 (Total of lines 5 thru 6) 8 Classification of TOTAL 9 Federal Income Tax 10 State Income Tax 11 Local Income Tax FERC FORM NO. 2 (REV 12-07) Balance at Beginning of Year 8,884,982 1, 147,644 113,228,848 123,261,474 123,261,474 123,261,474 Page 234 Changes During Year Amounts Debited to Account 410.1 (c) 1,688,218) 397,117 11,483,544) 12,774,645) 12,774,645) 12,77 4,645) Changes During Year Amounts Credited to Account 411.1 (d) PC_DR_009 Attachment B Page 103 of 177 Name of Respondent Avista Corporation This ~Ort Is: (1) ~An Original (2) DA Resubmission Date of Report (Mo, Da, Yr) 04/15/2016 Accumulated Deferred Income Taxes (Account 190) (continued) Line No. 2 3 4 5 6 9 10 11 Changes During Year Amounts Debited to Account 410.2 (e) Changes During Year Amounts Credited to Account 411.2 (D FERC FORM NO. 2 (REV 12-07) Adjustments Debits Account No. (g) Adjustments Adjustments Adjustments Debits Credits Credits Amount Account No. Amount (h) (i) U) Page 235 Year/Period of Report End of 2015/04 Balance at End of Year (k) 10,573,200 750,527 124,712,392 136,036,119 136,036,119 136,036,119 PC_DR_009 Attachment B Page 104 of 177 Name of Respondent This IBJort Is: Date of Report Year/Period of Report Avista Corporation (1) X An Original (Mo, Da, Yr) (2) DA Resubmission 04/15/2016 End of 2015/Q4 Capital Stock (Accounts 201 and 204) 1. Report below the details called for concerning common and preferred stock at end of year, distinguishing separate series of any general class. Show separate totals for common and preferred stock. 2. Entries in column (b) should represent the number of shares authorized by the articles of incorporation as amended to end of year. 3. Give details concerning shares of any class and series of stock authorized to be issued by a regulatory commission which have not yet been issued. Class and Series of Stock and Number of Shares Par or Stated Value Call Price at Name of Stock Exchange Authorized by Charter per Share End of Year Line No. (a) (b) (c) (d) 1 Acct 201 -Common Stock Issued: 2 No Par Value 200,000,000 3 Restriced shares 4 TOTAL Common 200,000,000 5 6 7 Account 204 -Preferred Stock Issued 10,000,000 8 9 Total Preferred 10,000,000 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 FERC FORM NO. 2 (12-96) Page 250 PC_DR_009 Attachment B Page 105 of 177 Name of Respondent This wort Is: Date of Report Year/Period of Report Avista Corporation (1) X An Original (Mo, Da, Yr) (2) DA Resubmission 04/15/2016 End of 2015/04 Capital Stock (Accounts 201 and 204) 4. The identification of each class of preferred stock should show the dividend rate and whether the dividends are cumulative or noncumulative. 5. State in a footnote if any capital stock that has been nominally issued is nominally outstanding at end of year. 6. Give particulars (details) in column (a) of any nominally issued capital stock, reacquired stock, or stock in sinking and other funds which is pledged, stating name of pledgee and · purpose of pledge. Outstanding per Bal. Sheet Outstanding per Bal. Held by Held by Held by Held by (total amt outstanding Sheet Respondent Respondent Respondent Respondent Line without reduction for amts As Reacquired As Reacquired In Sinking and In Sinking and No. held by respondent) Stock (Acct 217) Stock (Acct 217) Other Funds Other Funds Shares (e) Amount Shares Cost Shares Amount (D (g) (h) (i) U) 1 2 62,312,651 984,603,843 3 4 62,312,651 984,603,843 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 FERC FORM NO. 2 (12-96) Page 251 PC_DR_009 Attachment B Page 106 of 177 This Page Intentionally Left Blank PC_DR_009 Attachment B Page 107 of 177 Name of Respondent This IBJort Is: Date of Report Year/Period of Report Avista Corporation (1) X An Original (Mo, Da, Yr) (2) DA Resubmission 04/15/2016 End of 2015/04 Other Paid-In Capital (Accounts 208-211) 1. Report below the balance at the end of the year and the information specified below for the respective other paid-in capital accounts. Provide a subheading for each account and show a total for the account, as well as a total of all accounts for reconciliation with the balance sheet, page 112. Explain changes made in any account during the year and give the accounting entries effecting such change. (a) Donations Received from Stockholders (Account 208) -State amount and briefly explain the origin and purpose of each donation. (b) Reduction in Par or Stated Value of Capital Stock (Account 209) -State amount and briefly explain the capital changes that gave rise to amounts reported under this caption including identification with the class and series of stock to which related. (c) Gain or Resale or Cancellation of Reacquired Capital Stock (Account 210) -Report balance at beginning of year, credits, debits, and balance at end of year with a designation of the nature of each credit and debit identified by the class and series of stock to which related. (d) Miscellaneous Paid-In Capital (Account 211) -Classify amounts included in this account according to captions that, together with brief explanations, disclose the general nature of the transactions that gave rise to the reported amounts. Line Item Amount No. (a) (b) 1 Equity Transactions of Subsidiaries ( 9,506,476) 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 Total ( 9,506,476) FERC FORM NO. 2 (12-96) Page 253 PC_DR_009 Attachment B Page 108 of 177 Name of Respondent This wort Is: Date of Report Year/Period of Report Avista Corporation (1) X An Original (Mo, Da, Yr) (2) DA Resubmission 04/15/2016 End of 2015/04 DISCOUNT ON CAPITAL STOCK (ACCOUNT 213) 1. Report the balance at end of year of discount on capital stock for each class and series of capital stock. Use as many rows as necessary to report all data. 2. If any change occurred during the year in the balance with respect to any class or series of stock, attach a statement giving details of the change. State the reason for any charge-off during the year and specify the account charged. Class and Series of Stock Balance at Line End of Year No. (a) (b) 1 2 3 4 5 6 7 8 9 10 11 12 13 14 TOTAL CAPITAL STOCK EXPENSE (ACCOUNT 214) 1. Report the balance at end of year of capital stock expenses for each class and series of capital stock. Use as many rows as necessary to report all data. Number the rows in sequence starting from the last row number used for Discount on Capital Stock above. 2. If any change occurred during the year in the balance with respect to any class or series of stock, attach a statement giving details of the change. State the reason for any charge-off of capital stock expense and specify the account charged. Class and Series of Stock Balance at Line End of Year No. (a) (b) 16 Common Stock-no par ' ( 29,238,213) 17 18 19 20 21 22 23 24 25 26 27 28 TOTAL ( 29,238,213) FERC FORM NO. 2 (12-96) Page 254 PC_DR_009 Attachment B Page 109 of 177 Name of Respondent This Report is: Date of Report Year/Period of Report (1) ~An Original (Mo, Da, Yr) Avista Corporation (2) A Resubmission 04/15/2016 2015/Q4 FOOTNOTE DATA !Schedule Page: 254 Line No.: 16 Column: b Beginning Balance $ (25,079,123} Issuance of Common Stock $ 55,902 Repurchase and Retirement of Common Stock $ 31,833 Tax Benefit-Options Excercised $ (51,358} Excess Tax Benefits on stock compensation $ 1,831,678 Stock Compensation Accrual $ (6,027,145) Ending Balance $ (29,238,213) During 2015, the Company executed a stock repurchase program. Through 12/31/15, the Company repurchased 89,400 shares. All repurchased shares under the program were retired and reverted to the status of authorized, but unissued shares. The amounts in account 214 applicable to the retired shares were written off due to the stock repurchase. I FERC FORM NO. 2 (12-96) Page 552.1 PC_DR_009 Attachment B Page 110 of 177 This Page Intentionally Left Blank PC_DR_009 Attachment B Page 111 of 177 Name of Respondent This Report is: Date of Report Year/Period of Report (1) 6 An Original (Mo, Da, Yr) Avista Corporation (2) A Resubmission 04/15/2016 2015/04 Securities Issued or Assumed and Securities Refunded or Retired During the Year 1. Furnish a supplemental statement briefly describing security financing and refinancing transactions during the year and the accounting for the securities, discounts, premiums, expenses, and related gains or losses. Identify as to Commission authorization numbers and dates. 2. Provide details showing the full accounting for the total principal amount, par value, or stated value of each class and series of security issued, assumed, retired, or refunded and the accounting for premiums, discounts, expenses, and gains or losses relating to the securities. Set forth the facts of the accounting clearly with regard to redemption premiums, unamortized discounts, expenses, and gain or losses relating to securities retired or refunded, including the accounting for such amounts carried in the respondent's accounts at the date of the refunding or refinancing transactions with respect to securities previously refunded or retired. 3. Include in the identification of each class and series of security, as appropriate, the interest or dividend rate, nominal date of issuance, maturity date, aggregate principal amount, par value or stated value, and number of shares. Give also the issuance of redemption price and name of the principal underwriting firm through which the security transactions were consummated. 4. Where the accounting for amounts relating to securities refunded or retired is other than that specified in General Instruction 17 of the Uniform System of Accounts, cite the Commission authorization for the different accounting and state the accounting method. 5. For securities assumed, give the name of the company for which the liability on the securities was assumed as well as details of the transactions whereby the respondent undertook to pay obligations of another company. If any unamortized discount, premiums, expenses, and gains or losses were taken over onto the respondent's books, furnish details of these amounts with amounts relating to refunded securities clearly earmarked. In December 2015, Avista Corp. issued $100.0 million of first mortgage bonds to three institutional investors in a private placement transaction. The first mortgage bonds bear an interest rate of 4.37 percent and mature in 2045. The total net proceeds from the sale of the new bonds were used to repay a portion of the borrowings outstanding under the Company's $400.0 million committed line of credit and for general corporate purposes. The new issuance is based on the following state commission orders: 1. Order of the Washington Utilities and Transportation Commission entered July 13, 2011, as amended on August 24, 2011 in Docket No. U-111176; 2. Order of the Idaho Public Utilities Commission, Order No. 32338, entered August 25, 2011; 3. Order of the Public Utility Commission of Oregon, Order No. 15305, entered October 6, 2015; Order of the Public Service Commission of the State of Montana, Default Order No. 4535 In 2015, we issued $1.6 million of common stock under the employee stock ownership and long term incentive plans. During 2015, the Company executed a stock repurchase program. Through 12/31/15, the Company repurchased 89,400 shares. All repurchased shares under the program were retired and reverted to the status of authorized, but unissued shares. The amounts in account 214 applicable to the retired shares were written off due to the stock repurchase. I FERC FORM NO. 2 (12-96) 255.1 PC_DR_009 Attachment B Page 112 of 177 Name of Respondent This IBJort Is: Date of Report Year/Period of Report Avista Corporation (1) X An Original (Mo, Da, Yr) (2) DA Resubmission 04/15/2016 End of 2015/04 Long-Term Debt (Accounts 221, 222, 223, and 224) 1. Report by Balance Sheet Account the details concerning long-term debt included in Account 221, Bonds, 222, Reacquired Bonds, 223, Advances from Associated Companies, and 224, Other Long-Term Debt. 2. For bonds assumed by the respondent, include in column (a) the name of the issuing company as well as a description of the bonds. 3. For Advances from Associated Companies, report separately advances on notes and advances on open accounts. Designate demand notes as such. Include in column (a) names of associated companies from which advances were received. 4. For receivers' certificates, show in column (a) the name of the court and date of court order under which such certificates were issued. Class and Series of Obligation and Nominal Date Date of Outstanding Name of Stock Exchange of Issue Maturity (Total amount Line outstanding without No. reduction for amts held by respondent) (a) (b) (c) (d) 1 FMBS -SERIES A -7.53% DUE 05/05/2023 05/06/1993 05/05/2023 5,500,000 2 FMBS -SERIES A-7.54% DUE 5/05/2023 05/07/1993 05/05/2023 1,000,000 3 FMBS -SERIES A-7.39% DUE 5/11/2018 05/11/1993 05/11/2018 7,000,000 4 FMBS -SERIES A-7.45% DUE 6/11/2018 06/09/1993 06/11/2018 15,500,000 5 FMBS -SERIES A -7. 18% DUE 8/11/2023 08/12/1993 08/11/2023 7,000,000 6 ADVANCE ASSOCIATED-AVISTA CAPITAL II (ToPRS) : 06/03/1997 06/01/2037 51,547,000 7 FMBS -6.37% SERIES C 06/19/1998 06/19/2028 25,000,000 8 FMBS -5.45% SERIES 11/18/2004 12/01/2019 90,000,000 9 10 FMBS -6.25% SERIES 11/17/2005 12/01/2035 150,000,000 11 FMBS -5.70% SERIES 12/15/2006 07/01/2037 150,000,000 12 FMBS -5.95% SERIES 04/02/2008 06/01/2018 250,000,000 13 FMBS -5.125% SERIES 09/22/2009 04/01/2022 250,000,000 14 COLSTRIP 2010A PCRBs DUE 2032 : 12/15/2010 10/01/2032 66,700,000 15 COLSTRIP 2010B PCRBs DUE 2034 12/15/2010 03/01/2034 17,000,000 16 FMBS -3.89% SERIES 12/20/2010 12/20/2020 52,000,000 17 FMBS -5.55% SERIES 12/20/2010 12/20/2040 35,000,000 18 4.45% SERIES DUE 12-14-2041 12/14/2011 12/14/2041 85,000,000 19 4.23% SERIES DUE 11-29-2047 11 /30/2012 11/29/2047 80,000,000 20 FMBS-0.84% SERIES 08/14/2013 08/14/2016 90,000,000 21 FMBS-4. 11 % SERIES 12/18/2014 12/01/2044 60,000,000 22 FMBS-4.37% SERIES 12/16/2015 12/01/2045 100,000,000 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 TOTAL 1 ,588,247,000 FERC FORM NO. 2 (12-96) Page 256 PC_DR_009 Attachment B Page 113 of 177 Name of Respondent This IBJort Is: Date of Report Year/Period of Report Avista Corporation (1) X An Original (Mo, Da, Yr) (2) DA Resubmission 04/15/2016 End of 2015/04 Long-Term Debt (Accounts 221, 222, 223, and 224) 5. In a supplemental statement, give explanatory details for Accounts 223 and 224 of net changes during the year. With respect to long-term advances, show for each company: (a) principal advanced during year (b) interest added to principal amount, and (c) principal repaid during year. Give Commission authorization numbers and dates. 6. If the respondent has pledged any of its long-term debt securities, give particulars (details) in a footnote, including name of the pledgee and purpose of the pledge. 7. If the respondent has any long-term securities that have been nominally issued and are nominally outstanding at end of year, describe such securities in a footnote. 8. If interest expense was incurred during the year on any obligations retired or reacquired before end of year, include such interest expense in column (0. Explain in a footnote any difference between the total of column (D and the total Account 427, Interest on Long-Term Debt and Account 430, Interest on Debt to Associated Companies. 9. Give details concerning any long-term debt authorized by a regulatory commission but not yet issued. Interest for Interest for Held by Held by Redemption Price Year Year Respondent Respondent per $100 at Line End of Year No. Rate Amount Reacquired Bonds Sinking and (in%) (Acct 222) Other Funds (e) (0 (g) (h) (i) 1 7.530 414,150 2 7.540 75,400 3 7.390 517,300 4 7.450 1, 154,750 5 7.180 502,600 6 1.289 473,352 7 6.370 1,592,500 8 5.450 4,905,000 9 10 6.250 9,375,000 11 5.700 8,550,000 12 5.950 14,875,000 13 5.125 12,812,500 14 0.300 162,236 66,700,000 15 0.300 41,349 17,000,000 16 3.890 2,022,800 17 5.550 1,942,500 18 4.450 3,782,500 19 4.230 3,384,000 20 0.840 756,000 21 4.110 2,466,000 22 4.370 194,222 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 69,999,159 83,700,000 FERC FORM NO. 2 (12-96) Page 257 PC_DR_009 Attachment B Page 114 of 177 Name of Respondent Avista Corporation !Schedule Page: 256 Line No.: 14 Column: e interest rate at 12/31 !Schedule Page: 256 Line No.: 15 Column: e interest rate at 12/31 !Schedule Page: 256 Line No.: 6 Column: e interest rate at 12/31 !Schedule Page: 256 Line No.: 6 Column: f This Report is: Date of Report Year/Period of Report (1) 6 An Original (Mo, Da, Yr) (2) A Resubmission 04/15/2016 2015/04 FOOTNOTE DATA Upon issuance Avista Capital II issued $1.5 million of Common Trust Securities to the Company. In December 2000, the Company purchased $10.0 million of these Preferred Trust Securities. The interest for the year disclosed in column (i) reflects the net amount owed to third parties. !Schedule Page: 256 Line No.: 6 Column: a Upon issuance Avista Capital II issued $1.5 million of Common Trust Securities to the Company. In December 2000, the Company purchased $10.0 million of these Preferred Trust Securities. The interest for the year disclosed in column (i) reflects the net amount owed to third parties. !Schedule Page: 256 Line No.: 14 Column: a I The Company reacquired this debt in 2010. These bonds have not been retired or canceled; the Company plans, based on liquidity needs and market conditions, to remarket these bonds at a future date. !Schedule Page: 256 Line No.: 15 Column: a The Company reacquired this debt in 2010. These bonds have not been retired or canceled; the Company plans, based on liquidity needs and market conditions, to remarket these bonds at a future date. !Schedule Page: 256 Line No.: 22 Column: a The new issuance is based on the following state commission orders: 1. Order of the Washington Utilities and Transportation Commission entered July 13, 2011, as amended on August 24, 2011 in Docket No. U-111176; 2. Order of the Idaho Public Utilities Commission, Order No. 32338, entered August 25, 2011; 3. Order of the Public Utility Commission of Oregon, Order No. 15305, entered October 6, 2015; Order of the Public Service Commission of the State of Montana, Default Order No. 4535 I FERC FORM NO. 2 (12-96) Page 552.1 PC_DR_009 Attachment B Page 115 of 177 This Page Intentionally Left Blank PC_DR_009 Attachment B Page 116 of 177 Name of Respondent This ~Ort Is: Date of Report Year/Period of Report Avista Corporation (1) X An Original (Mo, Da, Yr) (2) DA Resubmission 04/15/2016 End of 2015/04 Unamortized Debt Expense, Premium and Discount on Long-Term Debt (Accounts 181, 225, 226) 1. Report under separate subheadings for Unamortized Debt Expense, Unamortized Premium on Long-Term Debt and Unamortized Discount on Long-Term Debt, details of expense, premium or discount applicable to each class and series of long-term debt. 2. Show premium amounts by enclosing the figures in parentheses. 3. In column (b) show the principal amount of bonds or other long-term debt originally issued. 4. In column (c) show the expense, premium or discount with respect to the amount of bonds or other long-term debt originally issued. Designation of Principal Amount Total Expense Amortization Amortization Long-Term Debt of Debt Issued Premium or Period Period Line Discount No. Date From Date To (a) (b) (c) (d) (e) 1 FMBS -SERIES A -7.53% DUE 05/05/2023 5,500,000 42,712 05/06/1993 05/05/2023 2 FMBS -SERIES A -7.54% DUE 5/05/2023 1,000,000 7,766 05/07/1993 05/05/2023 3 FMBS -SERIES A -7.39% DUE 5/11/2018 7,000,000 54,364 05/11/1993 05/11/2018 4 FMBS -SERIES A-7.45% DUE 6/11/2018 15,500,000 170,597 06/09/1993 06/11/2018 5 FMBS -SERIES A -7.18% DUE 8/11/2023 7,000,000 54,364 08/12/1993 08/11/2023 6 ADVANCE ASSOCIATED-AVISTA CAPITAL II (ToPRS) 51,547,000 1,296,086 06/03/1197 06/01/2037 7 FMBS -6.37% SERIES C 25,000,000 158,304 06/19/1998 06/19/2028 8 FMBS -5.45% SERIES 90,000,000 1,432,081 11/18/2004 12/01/2019 9 FMBS -6.25% SERIES 150,000,000 2, 180,435 11/17/2005 12/01/2035 10 FMBS -5.70% SERIES 150,000,000 4,924,304 12/15/2006 07/01/2037 11 FMBS -5.95% SERIES 250,000,000 3,081,419 04/02/2008 06/01/2018 12 FMBS -5.125% SERIES 250,000,000 2,859,788 09/22/2009 04/01/2022 13 FMBS -3.89% SERIES 52,000,000 385,129 12/20/2010 12/20/2020 14 FMBS -5.55% SERIES 35,000,000 258,834 12/20/2010 12/20/2040 15 Short-Term Credit Facility 3,959,449 12/14/2011 02/10/2017 16 4.45% SERIES DUE 12-14-2041 85,000,000 692,833 12/14/2011 12/14/2041 17 4.23% SERIES DUE 11-29-2047 80,000,000 730,833 11/30/2012 11/29/2047 18 0.84% Series Due 08-14-2016 90,000,000 515,369 08/14/2013 08/14/2016 19 4.11% Seires Due 12-1-2044 60,000,000 428,782 12/18/2014 12/01/2044 20 4.37% Series Due 12-1-2045 100,000,000 564,165 12/16/2015 12/01/2045 21 Rathrum 2005 71,646 09/30/2005 12/01/2035 22 Debt Strategies 56,760 08/01/2035 08/01/2005 23 WKSI Shelf Registration Statement 16,064 03/01/2013 03/01/2018 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 FERC FORM NO. 2 (12-96) Page 258 PC_DR_009 Attachment B Page 117 of 177 Name of Respondent This ~ort Is: Date of Report Year/Period of Report Avista Corporation (1) X An Original (Mo, Da, Yr) (2) DA Resubmission 04/15/2016 End of 2015/04 Unamortized Debt Expense, Premium and Discount on Long-Term Debt (Accounts 181, 225, 226) 5. Furnish in a footnote details regarding the treatment of unamortized debt expense, premium or discount associated with issues redeemed during the year. Also, give in a footnote the date of the Commission's authorization of treatment other than as specified by the Uniform System of Accounts. 6. Identify separately undisposed amounts applicable to issues which were redeemed in prior years. 7. Explain any debits and credits other than amortization debited to Account 428, Amortization of Debt Discount and Expense, or credited to Account 429, Amortization of Premium on Debt-Credit. Balance at Debits During Credits During Balance at Beginning Year Year End of Year Line of Year No. (0 (g) (h) (i) 1 11,983 1,424 10,559 2 2,179 259 1,920 3 7,429 2,175 5,254 4 23,884 6,824 17,060 5 15,705 1,812 13,893 6 315,333 14,015 301,318 7 71,236 5,277 65,959 8 437,377 93,536 343,841 9 1,523,947 72,569 1,451,378 10 3,636,631 161,032 3,475,599 11 1,035,559 303,090 732,469 12 1,668,777 227,561 1,441,216 13 231,715 38,619 193,096 14 224,330 8,628 215,702 15 2,309,836 533,039 1,776,797 16 623,806 23,104 600,702 17 687,501 20,886 666,615 18 290,594 174,357 116,237 19 381,512 47,270 14,003 414,779 20 564, 165 564,165 21 49,739 2,368 47,371 22 592 29 563 23 9,876 3,671 6,205 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 FERC FORM NO. 2 (12-96) Page 259 PC_DR_009 Attachment B Page 118 of 177 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Avista Corporation (2) A Resubmission 04/15/2016 2015/04 FOOTNOTE DATA !Schedule Page: 258 Line No.: 20 Column: c Expenses may change as more invoices related to this issuance become known I FERC FORM NO. 2 (12-96) Page 552.1 PC_DR_009 Attachment B Page 119 of 177 This Page Intentionally Left Blank PC_DR_009 Attachment B Page 120 of 177 Name of Respondent This IBJort Is: Date of Report Year/Period of Report Avista Corporation (1) X An Original (Mo, Da, Yr) (2) DA Resubmission 04/15/2016 End of 2015/04 Unamortized Loss and Gain on Reacquired Debt (Accounts 189, 257) 1. Report under separate subheadings for Unamortized Loss and Unamortized Gain on Reacquired Debt, details of gain and loss, including maturity date, on reacquisition applicable to each class and series of long-term debt. If gain or loss resulted from a refunding transaction, include also the maturity date of the new issue. 2. In column (c) show the principal amount of bonds ot other long-term debt reacquired. 3. In column (d) show the net gain or net loss realized on each debt reacquisition as computed in accordance with General Instruction 17 of the Uniform Systems of Accounts. 4. Show loss amounts by enclosing the figures in parentheses. 5. Explain in a footnote any debits and credits other than amortization debited to Account 428.1, Amortization of Loss on Reacquired Debt, or credited to Account 429.1, Amortization of Gain on Reacquired Debt-Credit. Line Designation of Date Principal Net Gain or Balance at Balance at No. Long-Term Debt Reacquired of Debt Loss Beginning End of Year Reacquired of Year (a) (b) (c) (d) (e) (f) 1 Misc Debt Repurchases I 05/10/1993 ( 4,695,395) ( 871 ,755) ( 692,787) 2 ADVANCE ASSOCIATED-AVISTA CAPITAL II (ToPRS) 12/18/2000 10,000,000 1,769, 125 1,094,011 1,045,207 3 Misc 2002 Repurchase 12/31/2002 10,000,000 2,228,153 672,851 620,760 4 Misc 2003 Repurchase 12/31/2003 25,330,000 315,274 106,861 99,861 5 Misc 2004 Repurchase 12/31/2004 36,590,000 ( 7,244,895) ( 1,083,632) ( 785,339) 6 Misc 2005 Repurchase 12/31/2005 26,000,000 ( 1,700,371) ( 687,945) ( 637,031) 7 Misc 2006 Repurchase 12/31/2006 6,875,000 ( 483,582) ( 48,698) ( 32,733) 8 Misc 2008 Repurchase Costs 12/31/2008 43,132 24,400 21,705 9 AVA Capital Trust Ill (2022) 04/01/2009 60,000,000 ( 2,875,817) ( 1,681,347) ( 1,452,072) 10 COLSTRIP 2010A PCRBs DUE 2032 12/14/2010 66,700,000 ( 3,709,174) ( 2,776,075) ( 2,620,408) 11 COLSTRIP 20108 PCRBs DUE 2034 12/14/2010 17,000,000 ( 1,916,297) ( 1,584,463) ( 1,501,969) 12 FMBS -7.25% SERIES (2040) 12/20/2010 30,000,000 ( 5,263,822) ( 4,561,979) ( 4,386,518) 13 FMBS -6.125% SERIES (2020) 12/20/2010 45,000,000 ( 6,273,664) ( 3,764,199) ( 3,136,832) 14 KETTLE FALLS PC REV BONDS DUE 14 (2047) 06/28/2012 4,100,000 ( 105,020) ( 98,769) ( 95,769) 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 FERC FORM NO. 2 (12-96) Page 260 PC_DR_009 Attachment B Page 121 of 177 Name of Respondent Avista Corporation This ~ort Is: Date of Report (1) l25_J An Original (Mo, Da, Yr) (2) DA Resubmission 04/15/2016 Reconciliation of Reported Net Income with Taxable Income for Feder Income Taxes Year/Period of Report End of 2015/04 1. Report the reconciliation of reported net income for the year with taxable income used in computing Federal Income Tax accruals and show computation of such tax accruals. Include in the reconciliation, as far as practicable, the same detail as furnished on Schedule M-1 of the tax return for the year. Submit a reconciliation even though there is no taxable income for the year. Indicate clearly the nature of each reconciling amount. 2. If the utility is a member of a group that files consolidated Federal tax return, reconcile reported net income with taxable net income as if a separate return were to be filed, indicating, however, intercompany amounts to be eliminated in such a consolidated return. State names of group members, tax assigned to each group member, and basis of allocation, assignments, or sharing of the consolidated tax among the group members. Line No. Net Income for the Year (Page 116) 2 Reconciling Items for the Year 3 4 Taxable Income Not Reported on Books 5 6 7 8 TOTAL 9 Deductions Recorded on Books Not Deducted for Return 10 11 12 13 TOTAL 14 Income Recorded on Books Not Included in Return 15 16 17 18 TOTAL 19 Deductions on Return Not Charged Against Book Income Details (a) Amount (b) 123,227,041 ( 293,458,641) 293,458,641) 20 50, 133,967) 21 22 23 24 25 26 TOTAL 50, 133,967) 27 Federal Tax Net Income 34, 172,612 28 Show Computation of Tax: 29 State Tax@ 2% 919,149 30 Federal Tax net income less state tax 35,091,761 31 32 prior year true ups ( 7,241,736) 33 cabinet gorge ( 154,305) 34 Total Federal Expense 4,886,075 35 FERC FORM NO. 2 (12-96) Page 261 PC_DR_009 Attachment B Page 122 of 177 Name of Respondent This ~ort Is: Date of Report Year/Period of Report Avista Corporation (1) X An Original (Mo, Da, Yr) (2) DA Resubmission 04/15/2016 End of 2015/04 Taxes Accrued, Prepaid and Charged During Year, Distribution of Taxes Charged (Show utility dept where applicable and acct charged) 1. Give details of the combined prepaid and accrued tax accounts and show the total taxes charged to operations and other accounts during the year. Do not include gasoline and other sales taxes which have been charged to the accounts to which the taxed material was charged. If the actual or estimated amounts of such taxes are known, show the amounts in a footnote and designate whether estimated or actual amounts. 2. Include on this page, taxes paid during the year and charged direct to final accounts, (not charged to prepaid or accrued taxes). Enter the amounts in both columns (d) and (e). The balancing of this page is not affected by the inclusion of these taxes. 3. Include in column (d) taxes charged during the year, taxes charged to operations and other accounts through (a) accruals credited to taxes accrued, (b) amounts credited to the portion of prepaid taxes charged to current year, and ( c) taxes paid and charged direct to operations or accounts other than accrued and prepaid tax accounts. 4. List the aggregate of each kind of tax in such manner that the total tax for each State and subdivisi.on can readily be ascertained. Balance at Balance at Line Kind ofTax Beg. of Year Beg. of Year No. (See Instruction 5) Taxes Accrued Prepaid Taxes (a) (b) (c) 1 FEDERAL: 2 Income Tax 2010 1'°78,764 3 Income Tax 2011 ( 34,876) 4 Income Tax 2012 2,014,544 5 Income Tax 2013 ( 3,666,967) 6 Income Tax 2014 ( 34,331,525) 7 Income Tax (Current) 8 Prior Retained Earnings (2012) ( 2,124,050) 9 Prior Retained Earnings (2013) ( 483,257) 10 Prior Retained Earnings (2014) ( 470,244) 11 Current Retained EArnings 12 Total Federal ( 38,017,611) 13 14 STATE OF WASHINGTON 15 Property Tax (2014) 14,264,301 16 Property Tax (2015) 17 Excise Tax (2010) ( 22,495) 18 Excise Tax (2014) 2,768,507 19 Excise Tax (2015) 20 Natural Gas Use Tax 1,409 21 Municipal Occupation Tax 2,953,568 22 Community Solar 23 Sales & Use Tax (2013) 1 24 Sales & Use Tax (2014) 72,250 25 Sales & Use Tax (2015) 26 Total Washington 20,037,541 27 28 STA TE OF IDAHO: 29 Income Tax (2013) 41,220 30 Income Tax (2014) 113,280 31 Income Tax (2015) 32 Property Tax (2013) ( 719) 33 Property Tax (2014) 3,397,575 34 Property Tax (2015) 35 Sales & Use Tax (2014) 5,617 36 Sales & Use Tax (2015) 37 KWH Tax (2012) 1 38 KWH Tax (2014) 27,143 39 KWH Tax (2015) FERC FORM NO. 2 (REV 12-07) Page 262a PC_DR_009 Attachment B Page 123 of 177 Name of Respondent This wort Is: Date of Report Year/Period of Report Avista Corporation (1) X An Original (Mo, Da, Yr) (2) DA Resubmission 04/15/2016 End of 2015/04 Taxes Accrued, Prepaid and Charged During Year, Distribution of Taxes Charged (Show utility dept where applicable and acct charged) (continued) 5. If any tax (exclude Federal and State income taxes) covers more than one year, show the required information separately for each tax year, identifying the year in column (a). 6. Enter all adjustments of the accrued and prepaid tax accounts in column (f) and explain each adjustment in a footnote. Designate debit adjustments by parentheses. 7. Do not include on this page entries with respect to deferred income taxes or taxes collected through payroll deductions or otherwise pending transmittal of such taxes to the taxing authority. 8. Show in columns (i) thru (p) how the taxes accounts were distributed. Show both the utility department and number of account charged. For taxes charged to utility plant, show the number of the appropriate balance sheet plant account or subaccount. 9. For any tax apportioned to more than one utility department or account, state in a footnote the basis (necessity) of apportioning such tax. 10. Items under $250,000 may be grouped. 11. Report in column ( q) the applicable effective state income tax rate. Balance at Balance at Line Taxes Charged Taxes Paid End of Year End of Year No. During Year During Year Adjustments Taxes Accrued Prepaid Taxes (Account 236) (Included in Acct 165) (d) (e) (D (g) (h) 1 2 ( 1,078,764) 3 34,876 4 264,697 ( 2,279,241) 5 123,858 4,349,313 806,204 6 ( 4,319,636) ( 37,000,000) 2,166,027 514,866 7 11,039,712 24,130,403 ( 5,786,505). ( 18,877,196) 8 2,124,050 9 ( 483,257) 10 470,244 11 ( 1,920,588) ( 1;920,588) 12 5,188,043 ( 12,869,597) ( 19,959,971) 13 14 15 ( 150,566) 14,117,079 ( 3,344) 16 15,566,000 6,438 15,559,562 17 22,495 18 81,261 2,849,769 ( 1) 19 26,045,762 23,339,258 2,706,504 20 3,710 3,823 ( 759) 537 21 23,837,695 23,888,611 2,902,651 22 ( 105,669) ( 105,669) 23 ( 1) 24 71,906 344 25 1,085,002 957,174 127,828 26 66,385,689 65,234,058 ( 759) 21,188,412 27 28 29 41,220 30 ( 255,482) ( 142,202) 31 497,695 555,000 ( 57,305) 32 719 33 3,345,172 52,403 34 7,127,878 3,569,906 3,557,972 35 1 5,617 36 150,773 137,990 12,784 37 ( 1) 38 ( 5,049) 22,094 39 393,696 369,501 24,195 FERC FORM NO. 2 (REV 12-07) Page 263a PC_DR_009 Attachment B Page 124 of 177 Name of Respondent This 'IB:Jort Is: Date of Report Year/Period of Report Avista Corporation (1) X An Original (Mo, Da, Yr) (2) DA Resubmission 04/15/2016 End of 2015/04 Taxes Accrued, Prepaid and Charged During Year, Distribution of Taxes Charged (Show utility dept where applicable and acct charged) 1. Give details of the combined prepaid and accrued tax accounts and show the total taxes charged to operations and other accounts during the year. Do not include gasoline and other sales taxes which have been charged to the accounts to which the taxed material was charged. If the actual or estimated amounts of such taxes are known, show the amounts in a footnote and designate whether estimated or actual amounts. 2. Include on this page, taxes paid during the year and charged direct to final accounts, (not charged to prepaid or accrued taxes). Enter the amounts in both columns (d) and (e). The balancing of this page is not affected by the inclusion of these taxes. 3. Include in column (d) taxes charged during the year, taxes charged to operations and other accounts through (a) accruals credited to taxes accrued, (b) amounts credited to the portion of prepaid taxes charged to current year, and ( c) taxes paid and charged direct to operations or accounts other than accrued and prepaid tax accounts. 4. List the aggregate of each kind of tax in such manner that the total tax for each State and subdivision can readily be ascertained. DISTRIBUTION OF TAXES CHARGED (Show utility department where applicable and account charged.) Electric Gas Other Utility Dept. Other Income and Line (Account 408.1, (Account 408.1, (Account 408.1, Deductions No. 409.1) 409.1) 409.1) (Account 408.2, 409.2) (i) U) (k) (I) 1 2 3 4 264,697 5 123,858 6 32 ( 4,121,044) 7 13,555,299 ( 4;221,438) 318,627 8 9 10 11 ( 1,920,588) 12 13,555,331 ( 4,221,438) ( 5,334,450) 13 14 15 ( 136,375) ( 45,872) 31,682 16 12,373,000 3,157,000 36,000 17 22,495 18 ( 49,041) ( 1,745) 14,727 19 20,166,813 5,795,040. 83,909 20 3,710 21 18, 114,786 5,556,559 22 23 ( 1) 24 25 26 50,472,892 14,460,982 188,813 27 28 29 30 ( 204,386) ( 51,096) 31 1,013,154 96,506 32 1 718 33 34 5,717,716 1,396,809 13,353 35 36 ( 8) 37 38 ( 5,049) 39 413,181 FERC FORM NO. 2 (REV 12-07) Page 262b PC_DR_009 Attachment B Page 125 of 177 Name of Respondent This IB:Jort Is: Date of Report Year/Period of Report Avista Corporation (1) X An Original (Mo, Da, Yr) (2) DA Resubmission 04/15/2016 End of 2015/Q4 Taxes Accrued, Prepaid and Charged During Year, Distribution of Taxes Charged (Show utility dept where applicable and acct charged) (continued) 5. If any tax (exclude Federal and State income taxes) covers more than one year, show the required information separately for each tax year, identifying the year in column (a). 6. Enter all adjustments of the accrued and prepaid tax accounts in column (D and explain each adjustment in a footnote. Designate debit adjustments by parentheses. "- 7. Do not include on this page entries with respect to deferred income taxes or taxes collected through payroll deductions or otherwise pending transmittal of such taxes to the taxing authority. 8. Show in columns (i) thru (p) how the taxes accounts were distributed. Show both the utility department and number of account charged. For taxes charged to utility plant, show the number of the appropriate balance sheet plant account or subaccount. 9. For any tax apportioned to more than one utility department or account, state in a footnote the basis (necessity) of apportioning such tax. 10. Items under $250,000 may be grouped. 11. Report in column ( q) the applicable effective state income tax rate. DISTRIBUTION OF TAXES CHARGED (Show utility department where applicable and account charged.) Extraordinary Items Other Utility Opn. Adjustment to Ret. State/Local Line (Account 409.3) Income Earnings Other Income Tax No. (Account 408.1, (Account 439) Rate 409.1) (m) (n) (o) (p) (q) 1 2 3 4 5 6 ( 198,624) 7 1,387,224 8 9 10 11 12 1,188,600 13 14 15 16 17 18 117,320 19 20 21 166,349 22 ( 105,669) 23 24 25 1,085,002 26 1,263,002 27 28 29 30 31 ( 611,965) 32 33 34 35 1 36 150,781 37 38 39 ( 19,485) FERC FORM NO. 2 (REV 12-07) Page 263b PC_DR_009 Attachment B Page 126 of 177 Name of Respondent This wort Is: Date of Report Year/Period of Report Avista Corporation (1) X An Original (Mo, Da, Yr) (2) DA Resubmission 04/15/2016 End of 2015/04 Taxes Accrued, Prepaid and Charged During Year, Distribution of Taxes Charged (Show utility dept where applicable and acct charged) (continued) Balance at Balance at Line Kind ofTax Beg. of Year Beg. of Year No. (See Instruction 5) Taxes Accrued Prepaid Taxes (a) (b) (c) 1 Franchise Tax (2013) ( 3,128) 2 Franchise Tax (2014) 1,650,689 3 Franchise Tax (2015) 4 Total Idaho 5,231,678 5 6 STA TE OF MONTANA 7 Income Tax (2011 & Prior) 22,865 8 Income Tax (2014) ( ,423,731) 9 Income Tax (2015) 10 Property Tax (2014) 4,226,439 11 Property Tax (2015) 12 Colstrip Generatin Tax 13 KWH Tax (2014) 263,479 14 KWH Tax (2015) 15 Consumer Council Tax 9 16 Public Commission Tax 19 17 Total Montana 4,089,080 18 19 STATE OF OREGON 20 Income Tax (2012) 99,999 21 Income Tax (2014) ( 655,185) 22 Income Tax (2015) 23 Property Tax (2013) ( 2,086,108) 24 Property Tax (2014) ( 86,548) 25 Property Tax (2015) 26 BETC Credit (2010) ( 17,483) 27 BETC Credit (2011) ( 29,962) 28 BETC Credit (2012) ( 57,789) 29 Glendate Regulatory Cr. 2009 ( 34,911) 30 Franchise Tax (2014) 776,328 31 Franchise Fee (2015) 32 Total Oregon ( 2,091,659) 33 34 STATE OF CALIFORNIA 35 Income Tax (2011) ( 800) 36 Income Tax (2014) ( 1,600) 37 Total California ( 2,400) 38 39 MISCELLANEOUS STATES: FERC FORM NO. 2 (REV 12-07) Page 262a.1 PC_DR_009 Attachment B Page 127 of 177 Name of Respondent This wort Is: Date of Report Year/Period of Report Avista Corporation (1) X An Original (Mo, Da, Yr) (2) DA Resubmission 04/15/2016 End of 2015/04 Taxes Accrued, Prepaid and Charged During Year, Distribution of Taxes Charged (Show utility dept where applicable and acct charged) (continued) Balance at Balance at Line Taxes Charged Taxes Paid End of Year End of Year No. During Year During Year Adjustments Taxes Accrued Prepaid Taxes (Account 236) (Included in Acct 165) (d) (e) (D (g) (h) 1 ( 3,128) 2 1,650,689 3 4,611,505 3,084,524 1,526,981 4 12,521,736 12,737,365 ( 1) 5,016,048 5 6 7 ( 22,865) 8 348,781 ( 74,950) 9 ( 108,607) 305,000 ( 413,607) 10 4,217,182 9,257 11 8,484,422 4,250,729 4,233,693 12 3,965 3,965 13 263,479 14 1, 138,846 898,734 240,112 15 75 61 23 16 95 54 60 17 9,844,712 9,939,204 3,994,588 18 19 20 ( 300,000) ( 200,000) 1 21 555,185 ( 100,000) 22 ( 378,037) ( 378,037) 23 2,086, 108 24 86,548 25 2,722,850 5,445,699 ( 2,722,849) 26 ( 17,483) 27 ( 29,962) 28 ( 57,789) 29 (. 34,911) 30 776,332 4 31 3,552,644 2,632,302 ( 2) 920,340 32 8,325,298 8,654,333 3 ( 2,420,691) 33 34 35 800 36 1,600 37 2,400 38 39 FERC FORM NO. 2 (REV 12-07) Page 263a.1 PC_DR_009 Attachment B Page 128 of 177 Name of Respondent This wort ls: Date of Report Year/Period of Report Avista Corporation (1) X An Original (Mo, Da, Yr) (2) DA Resubmission 04/15/2016 End of 2015/04 Taxes Accrued, Prepaid and Charged During Year, Distribution of Taxes Charged (Show utility dept where applicable and acct charged) (continued) DISTRIBUTION OF TAXES CHARGED (Show utility department where applicable and account charged.) Electric Gas Other Utility Dept. Other Income and Line (Account 408.1, (Account 408.1, (Account 408.1, Deductions No. 409.1) 409.1) 409.1) (Account 408.2, 409.2) (i) 0) (k) (I) 1 2 ( 720) ( 402) 3 3.476.436 1,118,268 4 10.410,333 2,560,085 14,063 5 6 7 ( 22,865) 8 348,781 9 125,077 10 11 8.484.422 12 3,965 13 14 1,138,846 15 89 16 81 17 10,078,396 18 19 20 ( 300,000) 21 138,796 416,389 22 780 2,342 23 910,347 1,175,761 24 162,053 ( 75,505) 25 1,358,914 1,363,936 26 27 28 29 30 997 31 3,535,778 32 2,570,890 6,119,698 33 34 35 800 36 1,600 37 2.400 38 39 FERC FORM NO. 2 (REV 12-07) Page 262b.1 PC_DR_009 Attachment B Page 129 of 177 Name of Respondent This 'IB]ort Is: Date of Report Year/Period of Report Avista Corporation (1) X An Original (Mo, Da, Yr) (2) DA Resubmission 04/15/2016 End of 2015/04 Taxes Accrued, Prepaid and Charged During Year, Distribution of Taxes Charged (Show utility dept where applicable and acct charged) (continued) DISTRIBUTION OF TAXES CHARGED (Show utility department where applicable and account charged.) Extraordinary Items Other Utility Opn. Adjustment to Ret. State/Local Line (Account 409.3) Income Earnings Other Income Tax No. (Account 408.1, (Account 439) Rate 409.1) (m) (n) (o) (p) (q) 1 2 1,122 3 16,802 4 ( 462,744) 5 6 7 8 9 ( 233,684) 10 11 12 13 14 15 ( 14) 16 14 17 ( 233,684) 18 19 20 21 22 ( 381,159) 23 24 25 26 27 28 29 30 ( 997) 31 16,866 32 ( 365,290) 33 34 35 36 37 38 39 FERG FORM NO. 2 (REV 12-07) Page 263b.1 PC_DR_009 Attachment B Page 130 of 177 Name of Respondent This IB]ort Is: Date of Report Year/Period of Report Avista Corporation (1) X An Original (Mo, Da, Yr) (2) DA Resubmission 04/15/2016 End of 2015/04 Taxes Accrued, Prepaid and Charged During Year, Distribution of Taxes Charged (Show utility dept where applicable and acct charged) (continued) Balance at Balance at Line Kind of Tax Beg. of Year Beg. of Year No. (See Instruction 5) Taxes Accrued Prepaid Taxes (a) (b) (c) 1 Income Tax (2013) 1 2 Income Tax (2014) 28,632 3 Income Tax (2015) 4 Total Misc States 28,633 5 6 COUNTY & MUNICIPAL 7 WA Renewable Energy ( 561) 8 Vehicle Excise Tax 2015 9 Misc. 2 10 Total County ( 559) 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 ;:,\ c''" 38 39 TOTAL ( 10,725,297) FERC FORM NO. 2 (REV 12-07) Page 262a.2 PC_DR_009 Attachment B Page 131 of 177 Name of Respondent This IB]ort Is: Date of Report Year/Period of Report Avista Corporation (1) X An Original (Mo, Da, Yr) (2) DA Resubmission 04/15/2016 End of 2015/04 Taxes Accrued, Prepaid and Charged During Year, Distribution of Taxes Charged (Show utility dept where applicable and acct charged) (continued) Balance at Balance at Line Taxes Charged Taxes Paid End of Year End of Year No. During Year During Year Adjustments Taxes Accrued Prepaid Taxes (Account 236) (Included in Acct 165) (d) (e) (D (g) (h) 1 1 2 28,632 3 ( 646,729) ( 646,729) 4 ( 646,729) ( 618,096) 5 6 7 ( 294,364) . ( 294,364) ( 561) 8 13,850 ( 13,850) 9 65,975 65,800 759 939 10 ( 228,389) ( 214,714) 759 ( 13,472) 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 TOTAL 101,392,760 83,480,649 2 7,186,818 FERC FORM NO. 2 (REV 12-07) Page 263a.2 PC_DR_009 Attachment B Page 132 of 177 Name of Respondent This wort Is: Date of Report Year/Period of Report Avista Corporation (1) X An Original (Mo, Da, Yr) (2) DA Resubmission 04/15/2016 End of 2015/04 Taxes Accrued, Prepaid and Charged During Year, Distribution of Taxes Charged (Show utility dept where applicable and acct charged) (continued). DISTRIBUTION OF TAXES CHARGED (Show utility department where applicable and account charged.) Electric Gas Other Utility Dept. Other Income and Line (Account 408.1, (Account 408.1, (Account 408.1, Deductions No. 409.1) 409.1) 409.1) (Account 408.2, 409.2) (i) U) (k) (I) 1 2 3 176 4 176 5 6 7 8 9 ( 541) 10 ( 541) 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 TOTAL 87,087,842 18,921,727 ( 5,131,939) FERC FORM NO. 2 (REV 12-07) Page 262b.2 PC_DR_009 Attachment B Page 133 of 177 Name of Respondent This 0ort Is: Date of Report Year/Period of Report Avista Corporation (1) X An Original (Mo, Da, Yr) (2) DA Resubmission 04/15/2016 End of 2015/04 Taxes Accrued, Prepaid and Charged During Year, Distribution of Taxes Charged (Show utility dept where applicable and acct charged) (continued) DISTRIBUTION OF TAXES CHARGED (Show utility department where applicable and account charged.) Extraordinary Items Other Utility Opn. Adjustment to Ret. State/Local Line (Account 409.3) Income Earnings Other Income Tax No. (Account 408.1, (Account 439) Rate 409.1) (m) (n) (o) (p) (q) 1 2 3 ( 646,905) 4 ( 646,905) 5 6 7 ( 294,364) 8 9 66,516 10 ( 227,848) 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 TOTAL 515,131 FERC FORM NO. 2 (REV 12-07) Page 263b.2 PC_DR_009 Attachment B Page 134 of 177 Name of Respondent This [filort Is: Date of Report Year/Period of Report Avista Corporation (1) X An Original (Mo, Da, Yr) (2) DA Resubmission 04/15/2016 End of 2015/04 Miscellaneous Current and Accrued Liabilities (Account 242) 1. Describe and report the amount of other current and accrued liabilities at the end of year. 2. Minor items (less than $250,000) may be grouped under appropriate title. Line Item Balance at No. End of Year (a) (b) 1 MARGIN CALL DEPOSITS 470,000 2 FOREST USE PERMITS 3,196,122 3 MIRABEAU ACCRUED RENT 643 4 5 FERG ADMIN FEE ACC 666,664 6 FERG ELEC ADMIN CHG 135,000 7 MT LEASE PAYMENTS 4,697,415 8 PAYROLL EQLZTN 18,822,859 9 LOW INCOME ENERGY ASSIST 2,560,045 10 AVISTA GRANTS ENG SUSTAIN WSU 116,612 11 MOBIUS 100,000 12 WORKERS COMP LIABILITY 2,047,832 13 ACCOUNTS PAYABLE EXPENSE ACCRUAL SC 4,190,040 14 CURRENT PORTION-BENEFIT LIAS 7,463,567 15 CLEARING ACCOUNT 512,042 16 PREPAYMENTS 158,208 17 CUSTOMER ACCOUNTS 9,670,215 18 CURRENT PORTION OF PENSION 2,769,853 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 Total 57,577,117 FERC FORM NO. 2 (12-96) Page 268 PC_DR_009 Attachment B Page 135 of 177 Name of Respondent This Report Is: Date of Report Year/Period of Report Avista Corporation (1) [K]An Original (Mo, Da, Yr) (2) DA Resubmission 04/15/2016 End of 2015/04 Other Deferred Credits (Account 253) 1. Report below the details called for concerning other deferred credits. 2. For any deferred credit being amortized, show the period of amortization. 3. Minor items (less than $250,000) may be grouped by classes. Line Balance at Debit Debit No. Description of Other Beginning Contra Credits Balance at Deferred Credits of Year Account Amount End of Year (a) (b) (c) (d) (e) (D 1 Defer Gas Exchange (253028) 1,124,990 10 1,125,000 2 Rathdrum Refund (253120) 171,932 33,822 138,110 3 NE Tank Spill (253130) 26,528 23,298 3,230 4 Bills Pole Rentals (253140) 311,640 127,239 184,401 5 CR-CS2 GE L TSA (253150) 1,164,668 1,164,668 6 Credit Resource Actg 225,361 225,361 7 DOC EECE Grant 177,282 159,364 17,918 8 Defer Comp Retired Execs (253900) 10,329 10,329 9 Defer Comp Active Execs (253910) 8,676,886 583, 106 8,093,780 10 Executive lncent Plan (253920) 140,000 140,000 11 Unbilled Revenue (253990) 674,258 174,476 848,734 12 WA Energy Recovery Mechanism 4,224,011 7,311,172 11,535,183 13 Misc Deferred Credits 3,677,156 903,718 2,773,438 14 REC Deferral 15 Kettle Falls Diesel Leak 664,699 428,564 236,135 16 Energy Commodity (253020) 14,694,374 14,694,374 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 Total 21,269,740 3,659,469 22,180,032 39,790,303 FERC FORM NO. 2 (12-96) Page 269 PC_DR_009 Attachment B Page 136 of 177 Name of Respondent Avista Corporation This ~ort Is: (1) ~An Original (2) DA Resubmission Date of Report (Mo, Da, Yr) 04/15/2016 Accumulated Deferred Income Taxes-Other Property (Account 282) Year/Period of Report End of 2015/04 1. Report the information called for below concerning the respondent's accounting for deferred income taxes relating to property not subject to accelerated amortization. 2. At Other (Specify), include deferrals relating to other income and deductions. Balance at Amounts Amounts Line Account Subdivisions Beginning Debited to Credited to No. of Year Account410.1 Account 411. 1 (a) (b) (c) (d) Account282 2 Electric 389,834, 132 53,938,541 3 Gas 141,409,318 5,797,368) 4 Other (Define) (footnote details) 51,477,902 16,007,841 5 Total (Enter Total of lines 2 thru 4) 582,721,352 64, 149,014 6 Other (Specify) (footnote details) 7 TOTAL Account 282 (Enter Total of lines 5 thr 582,721,352 64, 149,014 8 Classification of TOTAL 9 Federal Income Tax 568,018,213 62,428,794 10 State Income Tax 14,703,139 .1,720,220 11 Local Income Tax FERC FORM NO. 2 (REV 12-07) Page 274 PC_DR_009 Attachment B Page 137 of 177 Name of Respondent Avista Corporation This ~ort Is: Date of Report (1) 1.2UAn Original (Mo, Da, Yr) (2) DA Resubmission 04/15/2016 Accumulated Deferred Income Taxes-Other Property (Account 282) (continued) Year/Period of Report End of 2015/04 3. Provide in a footnote a summary of the type and amount of deferred income taxes reported in the beginning-of-year and end-of-year balances for deferred income taxes that the respondent estimates could be included in the development of jurisdictional recourse rates. Line No. 2 3 4 5 6 9 10 11 Changes during Year Amounts Debited to Account 410 .2 (e) Changes during Year Amounts Credited to Account 411.2 (D FERC FORM NO. 2 (REV 12-07) Adjustments Debits Acct. No. (g) Adjustments Adjustments Debits Credits Amount Account No. (h) (i) Page 275 Adjustments Credits Amount U) Balance at End of Year (k) 443,772,673 135.611 ,950 67.485.743 646,870,366 646,870,366 630.447,007 16.423,359 PC_DR_009 Attachment B Page 138 of 177 Name of Respondent Avista Corporation This ~Ort Is: (1) l2UAn Original (2) DA Resubmission Date of Report (Mo, Da, Yr) 04/15/2016 Accumulated Deferred Income Taxes-Other (Account 283) 1. Report the information called for below concerning the respondent's accounting for deferred income taxes relating to amounts recorded in Account 283. 2. At Other (Specify), include deferrals relating to other income and deductions. Changes During Year Balance at Amounts Line Account Subdivisions Beginning Debited to No. of Year Account 410. 1 (a) (b) (c) Account283 2 Electric 17,343,593 ( 869,714) 3 Gas 708,828) ( 2,628,563) 4 Other (Define) (footnote details) 208,219,022 7,992,949 5 Total (Total of lines 2 thru 4) 224,853,787 4,494,672 6 Other (Specify) (footnote details) 7 TOTAL Account 283 (Total of lines 5 thru 224,853,787 4,494,672 8 Classification of TOTAL 9 Federal Income Tax 224,853,787 4,494,672 10 State Income Tax 11 Local Income Tax FERC FORM NO. 2/3Q (REV 12-07) Page 276 Year/Period of Report End of 2015/04 Changes During Year Amounts Credited to Account 411. 1 (d) PC_DR_009 Attachment B Page 139 of 177 Name of Respondent Avista Corporation This ~ort Is: Date of Report (1) ~An Original (Mo, Da, Yr) (2) DA Resubmission 04/15/2016 Accumulated Deferred Income Taxes-Other (Account 283) (continued) Year/Period of Report End of 2015/04 3. Provide in a footnote a summary of the type and amount of deferred income taxes reported in the beginning-of-year and end-of-year balances for deferred income taxes that the respondent estimates could be included in the development of jurisdictional recourse rates. Changes during Changes during Adjustments Adjustments Adjustments Adjustments Year Year Balance at Line Amounts Debited Amounts Credited Debits Debits Credits Credits End of Year No. to Account 410.2 to Account 411.2 Acct. No. Amount Account No. Amount (e) (D (g) (h) (i) U) (k) 2 106,469) 16,367,410 3 50,645 3,286,746) 4 5,173,655) 3,691,659 214,729,975 5 5,173,655) 3,635,835 227,810,639 6 5,173,655) 3,635,835 227,810,639 9 5,173,655) 3,635,835 227,810,639 10 11 FERC FORM NO. 2/3Q (REV 12-07) Page 277 PC_DR_009 Attachment B Page 140 of 177 This Page Intentionally Left Blank PC_DR_009 Attachment B Page 141 of 177 Name of Respondent I nlS '"IB:Jort Is: Date of Keport Year!l-'enod ot Keport Avista Corporation (1) X An Original (Mo, Da, Yr) (2) DA Resubmission 04/15/2016 End of 2015/04 Other Regulatory Liabilities (Account 254) 1. Report below the details called for concerning other regulatory liabilities which are created through the ratemaking actions of regulatory agencies (and not includable in other amounts). 2. For regulatory liabilities being amortized, show period of amortization in column (a). 3. Minor items (5% of the Balance at End of Year for Account 254 or amounts less than $250,000, whichever is less) may be grouped by classes. 4. Provide in a footnote, for each line item, the regulatory citation where the respondent was directed to refund the regulatory liability (e.g. Commission Order, state commission order, court decision). Line Balance at Written off during Written off Written off Balance at No. Description and Purpose of Beginning of Quarter/Period During Period During Period Credits End of Current Other Regulatory Liabilities Current Account Amount Amount Deemed Quarter/Year (a) Quarter/Year Credited Refunded Non-Refundable (0 (g) (b) (c) (d) (e) 1 Idaho Investment Tax Credit (254005) 10,462,03S 825,970 11,288,009 2 Oregon BETC Credit (254010) 831,13E 268,734 1,099,872 3 Noxon ITC (254025) 3,241,231 190 52,632 3, 188,599 4 Community Solar ITC (254035) 190,418 190,418 5 Settled Int Rate Swaps (254090) 16,423,55i 428 2,152,005 14,271,547 6 Unsettled Int Rate Swaps (254100) 460,31E 176 437,629 22,687 7 FAS 109 Invest Credit (254180) 63,90( 190 16,188 47,712 8 Nez Perce (254220) 638,34E 557 22,008 616,340 9 Idaho Earnings Test (254229) 4,275,41E 407 3,515,350 760,068 10 BPA Parallel Capacity (254331) 808, 13E 407 808,136 11 BPA Res Exchange (254345) 1,659,457 407 1,230,833 428,624 12 Other Regulatory Liabilities 1,841,650 1,841,650 13 WA ERM 9,962,091 9,962,091 6,457,271 6,457,271 14 ID PCA 754,958 754,958 15 Roseburg /Medford 8,72S 8,729 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 Total 48,834,355-18,196,872 0 10,339,001 40,976,484 FERC FORM NO. 2/3Q (REV 12-07) Page 278 PC_DR_009 Attachment B Page 142 of 177 Name of Respondent This wort Is: Date of Report Year/Period of Report Avista Corporation (1) X An Original (Mo, Da, Yr) (2) DA Resubmission 04/15/2016 End of 2015/04 Gas Operating Revenues 1. Report below natural gas operating revenues for each prescribed account total. The amounts must be consistent with the detailed data on succeeding pages. 2. Revenues in columns (b) and (c) include transition costs from upstream pipelines. 3. Other Revenues in columns (0 and (g) include reservation charges received by the pipeline plus usage charges, less revenues reflected in columns (b) through (e). Include in columns (0 and (g) revenues for Accounts 480-495. Revenues for Revenues for Revenues for Revenues for Transition Transition GRI andACA GRI andACA Costs and Costs and Line Take-or-Pay Take-or-Pay No. Title of Account Amount for Amount for Amount for Amount for Current Year Previous Year Current Year Previous Year (a) (b) (c) (d) (e) 1 480 Residential Sales 2 481 Commercial and Industrial Sales 3 482 Other Sales to Public Authorities 4 483 Sales for Resale 5 484 Interdepartmental Sales 6 485 lntracompany Transfers 7 487 Forfeited Discounts 8 488 Miscellaneous Service Revenues 9 489.1 Revenues from Transportation of Gas of Others Through Gathering Facilities 10 489.2 Revenues from Transportation of Gas of Others Through Transmission Facilities 11 489.3 Revenues from Transportation of Gas of Others Through Distribution Facilities 12 489.4 Revenues from Storing Gas of Others 13 490 Sales of Prod. Ext. from Natural Gas 14 491 Revenues from Natural Gas Proc. by Others 15 492 Incidental Gasoline and Oil Sales 16 493 Rent from Gas Property 17 494 Interdepartmental Rents 18 495 Other Gas Revenues 19 Subtotal: 20 496 (Less) Provision for Rate Refunds 21 TOTAL: FERC FORM NO. 2 (REV 12-07) Page 300 PC_DR_009 Attachment B Page 143 of 177 Name of Respondent Avista Corporation This ~ort Is: (1) ~An Original (2) DA Resubmission Gas Operating Revenues Date of Report (Mo, Da, Yr) 04/15/2016 Year/Period of Report End of 2015/04 4. If increases or decreases from previous year are not derived from previously reported figures, explain any inconsistencies in a footnote. 5. On Page 108, include information on major changes during the year, new service, and important rate increases or decreases. 6. Report the revenue from transportation services that are bundled with storage services as transportation service revenue. Line No. 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 Other Revenues Amount for Current Year (f) 193,825, 126 103,325,365 208, 128,979 281,994 80,331 7,988,080 3,211 10,770,592 524,403,678 524,403,678 FERC FORM NO. 2 (REV 12-07) Other Revenues Amount for Previous Year (g) 203,373,340 110, 129, 154 230,997,169 337,273 188,455 7,735,097 3,132 5,329,746 558,093,366 221,098 557,872,268 Total Operating Revenues Amount for Current Year (h) 193,825,126 103,325,365 208, 128,978 281,994 80,331 7,988,080 3,211 10,770,593. 524,403,678 524,403,678 Page 301 Total Operating Revenues Amount for Previous Year (i) 203,373,340 110,129,154 230,997,169 337,273 188,455 7,735,097 3,132 5,329,746 558,093,366 221,098 557,872,268 Dekatherm of Natural Gas Amount for Current Year U) 17,661,330 11,767,225 83,131,135 33,451 Dekatherm of Natural Gas Amount for Previous Year (k) 19,017,094 12,742,856 56,068,962 41,051 ~~ I I I I I I 16,723,353 16,231,147 PC_DR_009 Attachment B Page 144 of 177 Name of Respondent This [fil'ort Is: Date of Report Year/Period of Report Avista Corporation (1) X An Original (Mo, Da, Yr) (2) DA Resubmission 04/15/2016 End of 2015/04 Other Gas Revenues (Account 495) Report below transactions of $250,000 or more included in Account 495, Other Gas Revenues. Group all transactions below $250,000 in one amount and provide the number of items. Line Description of Transaction Amount No. (in dollars) (a) (b) 1 Commissions on Sale or Distribution of Gas of Others 2 Compensation for Minor or Incidental Services Provided for Others 3 Profit or Loss on Sale of Material and Supplies not Ordinarily Purchased for Resale 4 Sales of Stream, Water, or Electricity, including Sales or Transfers to Other Departments 5 Miscellaneous Royalties 6 Revenues from Dehydration and Other Processing of Gas of Others except as provided for in the Instructions to Account 495 7 Revenues for Right and/or Benefits Received from Others which are Realized Through Research, Development, and Demonstration Ventures 8 Gains on Settlements of Imbalance Receivables and Payables 9 Revenues from Penalties earned Pursuant to Tariff Provisions, including Penalties Associated with Cash-out Settlements 10 Revenues from Shipper Supplied Gas 11 Other revenues (Specify): 12 Misc Bills 264,257 13 Deferred Exchange Revenue 4,500,000 14 Decoupling Deferred Revenue 6,004,224 15 DSM Lost Margin (Oregon) 2, 111 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 Total I 10,770,592 FERC FORM NO. 2 (12-96) Page 308 PC_DR_009 Attachment B Page 145 of 177 Name of Respondent This ~Ort Is: Date of Report Year/Period of Report Avista Corporation (1) X An Original (Mo, Da, Yr) (2) DA Resubmission 04/15/2016 End of 2015/04 Gas Operation and Maintenance Expenses Line Account Amount for Amount for No. Current Year Previous Year (a) (b) (c) 1. PRODUCTION EXPENSES 2 A. Manufactured Gas Production 3 Manufactured Gas Production (Submit Supplemental Statement) 4 B. Natural Gas Production 5 81. Natural Gas Production and Gathering 6 Operation 7 750 Operation Supervision and Engineering 0 0 8 751 Production Maps and Records 0 0 9 752 Gas Well Expenses 0 0 10 753 Field Lines Expenses 0 0 11 754 Field Compressor Station Expenses 0 0 12 755 Field Compressor Station Fuel and Power 0 0 13 756 Field Measuring and Regulating Station Expenses 0 0 14 757 Purification Expenses 0 0 15 758 Gas Well Royalties 0 0 16 759 Other Expenses 0 0 17 760 Rents 0 0 18 TOTAL Operation (Total of lines 7 thru 17) 0 0 19 Maintenance 20 761 Maintenance Supervision and Engineering 0 0 21 762 Maintenance of Structures and Improvements 0 0 22 763 Maintenance of Producing Gas Wells 0 0 23 764 Maintenance of Field Lines 0 0 24 765 Maintenance of Field Compressor Station Equipment 0 0 25 766 Maintenance of Field Measuring and Regulating Station Equipment 0 0 26 767 Maintenance of Purification Equipment 0 0 27 768 Maintenance of Drilling and Cleaning Equipment 0 0 28 769 Maintenance of Other Equipment 0 0 29 TOTAL Maintenance (Total of lines 20 thru 28) 0 0 30 TOTAL Natural Gas Production and Gathering (Total of lines 18 and 29) 0 0 FERC FORM NO. 2 (12-96) Page 317 PC_DR_009 Attachment B Page 146 of 177 Name of Respondent This ~ort Is: Date of Report Year/Period of Report Avista Corporation (1) X An Original (Mo, Da, Yr) (2) DA Resubmission 04/15/2016 End of 2015/04 Gas Operation and Maintenance Expenses(continued) Line Account Amount for Amount for No. Current Year Previous Year (a) (b) (c) 31 82. Products Extraction 32 Operation 33 770 Operation Supervision and Engineering 0 0 34 771 Operation Labor 0 0 35 772 Gas Shrinkage 0 0 36 773 Fuel 0 0 37 774 Power 0 0 38 775 Materials 0 0 39 776 Operation Supplies and Expenses 0 0 40 777 Gas Processed by Others 0 0 41 778 Royalties on Products Extracted 0 0 42 779 Marketing Expenses 0 0 43 780 Products Purchased for Resale 0 0 44 781 Variation in Products Inventory 0 0 45 (Less) 782 Extracted Products Used by the Utility-Credit 0 0 46 783 Rents 0 0 47 TOTAL Operation (Total of lines 33 thru 46) 0 0 48 Maintenance · 49 784 Maintenance Supervision and Engineering 0 0 50 785 Maintenance of Structures and Improvements 0 0 51 786 Maintenance of Extraction and Refining Equipment 0 0 52 787 Maintenance of Pipe Lines 0 0 53 788 Maintenance of Extracted Products Storage Equipment 0 0 54 789 Maintenance of Compressor Equipment 0 0 55 790 Maintenance of Gas Measuring and Regulating Equipment 0 0 56 791 Maintenance of Other Equipment 0 0 57 TOTAL Maintenance (Total of lines 49 thru 56) 0 0 58 TOTAL Products Extraction (Total of lines 47 and 57) 0 0 FERC FORM NO. 2 (12-96) Page 318 PC_DR_009 Attachment B Page 147 of 177 Name of Respondent This ~Ort Is: Date of Report Year/Period of Report Avista Corporation (1) X An Original (Mo, Da, Yr) (2) DA Resubmission 04/15/2016 End of 2015/04 Gas Operation and Maintenance Expenses(continued) Line Account Amount for Amount for No. Current Year Previous Year (a) (b) (c) 59 C. Exploration and Development 60 Operation 61 795 Delay Rentals 0 0 62 796 Nonproductive Well Drilling 0 0 63 797 Abandoned Leases 0 0 64 798 Other Exploration 0 0 65 TOTAL Exploration and Development (Total of lines 61 thru 64) 0 0 66 D. Other Gas Supply Expenses 67 Operation 68 800 Natural Gas Well Head Purchases 0 0 69 800.1 Natural Gas Well Head Purchases, lntracompany Transfers 0 0 70 801 Natural Gas Field Line Purchases 0 0 71 802 Natural Gas Gasoline Plant Outlet Purchases 0 0 72 803 Natural Gas Transmission Line Purchases 0 0 73 804 Natural Gas City Gate Purchases 319,282,550 416,037,120 74 804.1 Liquefied Natural Gas Purchases 0 0 75 805 Other Gas Purchases 0 0 76 (Less) 805.1 Purchases Gas Cost Adjustments ( ' 13;720,762) 8,065,460 77 TOTAL Purchased Gas (Total of lines 68 thru 76) 333,003,312 407,971,660 78 806 Exchange Gas 0 0 79 Purchased Gas Expenses 80 807. 1 Well Expense-Purchased Gas 0 0 81 807.2 Operation of Purchased Gas Measuring Stations 0 0 82 807.3 Maintenance of Purchased Gas Measuring Stations 0 0 83 807.4 Purchased Gas Calculations Expenses 0 0 84 807.5 Other Purchased Gas Expenses 0 0 85 TOTAL Purchased Gas Expenses (Total of lines 80 thru 84) 0 0 FERC FORM NO. 2 (12-96) Page 319 PC_DR_009 Attachment B Page 148 of 177 Name of Respondent Avista Corporation This ~ort Is: (1) ~An Original (2) DA Resubmission Gas Operation and Maintenance Expenses(continued) Line Account No. (a) 86 808.1 Gas Withdrawn from Storage-Debit 87 (Less) 808.2 Gas Delivered to Storage-Credit 88 809.1 Withdrawals of Liquefied Natural Gas for Processing-Debit 89 (Less) 809.2 Deliveries of Natural Gas for Processing-Credit 90 Gas used in Utility Operation-Credit 91 810 Gas Used for Compressor Station Fuel-Credit 92 811 Gas Used for Products Extraction-Credit 93 812 Gas Used for Other Utility Operations-Credit 94 TOTAL Gas Used in Utility Operations-Credit (Total of lines 91 thru 93) 95 813 Other Gas Supply Expenses 96 TOTAL Other Gas Supply Exp. (Total of lines 77,78,85,86 thru 89,94,95) 97 TOTAL Production Expenses (Total of lines 3, 30, 58, 65, and 96) 98 2. NATURAL GAS STORAGE, TERMINALING AND PROCESSING EXPENSES 99 A. Underground Storage Expenses 100 Operation 101 814 Operation Supervision and Engineering 102 815 Maps and Records 103 816 Wells Expenses 104 817 Lines Expense 105 818 Compressor Station Expenses 106 819 Compressor Station Fuel and Power 107 820 Measuring and Regulating Station Expenses 108 821 Purification Expenses 109 822 Exploration and Development 110 823 Gas Losses 111 824 Other Expenses 112 825 Storage Well Royalties 113 826 Rents 114 TOTAL Operation (Total of lines of 101 thru 113) FERC FORM NO. 2 (12-96) Page 320 Date of Report (Mo, Da, Yr) 04/15/2016 Amount for Current Year (b) 45, 198, 194 29,241,184 0 0 0 446,368 0 446,368 1,750,521 350,264,475 350,264,475 13,588 0 0 0 0 0 0 0 0 0 677,721 0 0 691,309 Year/Period of Report End of 2015/04 Amount for Previous Year (c) 23,222,085 38,924,873 0 0 0 1,602,046 0 1,602,046 1,634,458 392,301,284 392,301,284 9,776 0 0 0 0 0 0 0 0 0 723,454 0 0 733,230 PC_DR_009 Attachment B Page 149 of 177 Name of Respondent Avista Corporation This ~ort Is: (1) ~An Original (2) DA Resubmission Gas Operation and Maintenance Expenses(continued) Line No. Account (a) 115 Maintenance 116 830 Maintenance Supervision and Engineering 117 831 Maintenance of Structures and Improvements 118 832 Maintenance of Reservoirs and Wells 119 833 Maintenance of Lines 120 834 Maintenance of Compressor Station Equipment 121 835 Maintenance of Measuring and Regulating Station Equipment 122 836 Maintenance of Purification Equipment 123 837 Maintenance of Other Equipment 124 TOTAL Maintenance (Total of lines 116 thru 123) 125 TOTAL Underground Storage Expenses (Total of lines 114 and 124) 126 B. Other Storage Expenses 127 Operation 128 840 Operation Supervision and Engineering 129 841 Operation Labor and Expenses 130 842 Rents 131 842.1 Fuel 132 842.2 Power 133 842.3 Gas Losses 134 TOTAL Operation (Total of lines 128 thru 133) 135 Maintenance 136 843.1 Maintenance Supervision and Engineering 137 843.2 Maintenance of Structures 138 843.3 Maintenance of Gas Holders 139 843.4 Maintenance of Purification Equipment 140 843.5 Maintenance of Liquefaction Equipment 141 843.6 Maintenance of Vaporizing Equipment 142 843. 7 Maintenance of Compressor Equipment 143 843.8 Maintenance of Measuring and Regulating Equipment 144 843.9 Maintenance of Other Equipment 145 TOTAL Maintenance (Total of lines 136 thru 144) 146 TOTAL Other Storage Expenses (Total of lines 134 and 145) FERC FORM NO. 2 (12-96) Page 321 Date of Report (Mo, Da, Yr) 04/15/2016 Amount for Current Year (b) 0 0 0 0 0 0 0 648,898 648,898 1,340,207 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Year/Period of Report End of 2015/04 Amount for Previous Year (c) 0 0 0 0 0 0 0 661,095 661,095 1,394,325 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 PC_DR_009 Attachment B Page 150 of 177 Name of Respondent Avista Corporation This ~Ort Is: (1) ~An Original (2) DA Resubmission Gas Operation and Maintenance Expenses(continued) Line No. Account (a) 147 C. Liquefied Natural Gas Terminaling and Processing Expenses 148 Operation 149 844.1 Operation Supervision and Engineering 150 844.2 LNG Processing Terminal Labor and Expenses 151 844.3 Liquefaction Processing Labor and Expenses 152 844.4 Liquefaction Transportation Labor and Expenses 153 844.5 Measuring and Regulating Labor and Expenses 154 844.6 Compressor Station Labor and Expenses 155 844.7 Communication System Expenses 156 844.8 System Control and Load Dispatching 157 845.1 Fuel 158 845.2 Power 159 845.3 Rents 160 845.4 Demurrage Charges 161 (less) 845.5 Wharfage Receipts-Credit 162 845.6 Processing Liquefied or Vaporized Gas by Others 163 846.1 Gas Losses 164 846.2 Other Expenses 165 TOTAL Operation (Total of lines 149 thru 164) 166 Maintenance 167 84 7 .1 Maintenance Supervision and Engineering 168 847.2 Maintenance of Structures and Improvements 169 847.3 Maintenance of LNG Processing Terminal Equipment 170 847.4 Maintenance of LNG Transportation Equipment 171 847.5 Maintenance of Measuring and Regulating Equipment 172 847.6 Maintenance of Compressor Station Equipment 173 847.7 Maintenance of Communication Equipment 174 847.8 Maintenance of Other Equipment 175 TOTAL Maintenance (Total of lines 167 thru 174) 176 TOTAL Liquefied Nat Gas Terminaling and Proc Exp (Total of lines 165 and 175) 177 TOTAL Natural Gas Storage (Total of lines 125, 146, and 176) FERC FORM NO. 2 (12-96) Page 322 Date of Report (Mo, Da, Yr) 04/15/2016 Amount for Current Year (b) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 1,340,207 Year/Period of Report End of 2015/04 Amount for Previous Year (c) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 1,394,325 PC_DR_009 Attachment B Page 151 of 177 Name of Respondent Avista Corporation This ~Ort Is: (1) ~An Original (2) DA Resubmission Gas Operation and Maintenance Expenses(continued) Line No. 178 3. TRANSMISSION EXPENSES 179 Operation Account (a) 180 850 Operation Supervision and Engineering 181 851 System Control and Load Dispatching 182 852 Communication System Expenses 183 853 Compressor Station Labor and Expenses 184 854 Gas for Compressor Station Fuel 185 855 Other Fuel and Power for Compressor Stations 186 856 Mains Expenses 187 857 Measuring and Regulating Station Expenses 188 858 Transmission and Compression of Gas by Others 189 859 Other Expenses 190 860 Rents 191 TOTAL Operation (Total of lines 180 thru 190) 192 Maintenance 193 861 Maintenance Supervision and Engineering 194 862 Maintenance of Structures and Improvements 195 863 Maintenance of Mains 196 864 Maintenance of Compressor Station Equipment 197 865 Maintenance of Measuring and Regulating Station Equipment 198 866 Maintenance of Communication Equipment 199 867 Maintenance of Other Equipment 200 TOTAL Maintenance (Total of lines 193 thru 199) 201 TOTAL Transmission Expenses (Total of lines 191 and 200) 202 4. DISTRIBUTION EXPENSES 203 Operation 204 870 Operation Supervision and Engineering 205 871 Distribution Load Dispatching 206 872 Compressor Station Labor and Expenses 207 873 Compressor Station Fuel and Power FERC FORM NO. 2 (12-96) Page 323 Date of Report (Mo, Da, Yr) 04/15/2016 Amount for Current Year (b) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 2,335,426 0 0 0 Year/Period of Report End of 2015/04 Amount for Previous Year (c) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 2,231,329 0 0 0 PC_DR_009 Attachment B Page 152 of 177 Name of Respondent Avista Corporation This ~ort Is: (1) ~An Original (2) DA Resubmission Gas Operation and Maintenance Expenses(continued) Line No. 208 209 210 Account (a) 87 4 Mains and Services Expenses 875 Measuring and Regulating Station Expenses-General 876 Measuring and Regulating Station Expenses-Industrial 211 877 Measuring and Regulating Station Expenses-City Gas Check Station 212 878 Meter and House Regulator Expenses 213 879 Customer Installations Expenses 214 880 Other Expenses 215 881 Rents 216 TOTAL Operation (Total of lines 204 thru 215) 217 Maintenance 218 885 Maintenance Supervision and Engineering 219 886 Maintenance of Structures and Improvements 220 887 Maintenance of Mains 221 888 Maintenance of Compressor Station Equipment 222 889 Maintenance of Measuring and Regulating Station Equipment-General 223 890 Maintenance of Meas. and Reg. Station Equipment-Industrial 224 891 Maintenance of Meas. and Reg. Station Equip-City Gate Check Station 225 892 Maintenance of Services 226 893 Maintenance of Meters and House Regulators 227 894 Maintenance of Other Equipment 228 TOTAL Maintenance (Total of lines 218 thru 227) 229 TOTAL Distribution Expenses (Total of lines 216 and 228) 230 5. CUSTOMER ACCOUNTS EXPENSES 231 Operation 232 901 Supervision 233 902 Meter Reading Expenses 234 903 Customer Records and Collection Expenses FERC FORM NO. 2 (12-96) Page 324 Date of Report (Mo, Da, Yr) 04/15/2016 Amount for Current Year (b) 5,809,786 192,859 8,087 131,087 1,069,806 3,226,050 3,026,742 57,176 15,857,019 179,467 0 2,552, 162 0 531,220 240,023 118,017 2,688,703 2,739,937 349,692 9,399,221 25,256,240 310,965 2,232,796 7,748,363 Year/Period of Report End of 2015/04 Amount for Previous Year (c) 5,050,253 227,487 6,093 168,066 821,734 2,770,677 2,956,344 50,086 14,282,069 202,495 0 3,689,559 0 408,967 306,081 86,733 2,624,504 2,473, 195 359,692 10,151,226 24,433,295 288,098 2,032,328 7,431,401 PC_DR_009 Attachment B Page 153 of 177 Name of Respondent Avista Corporation This ~Ort Is: (1) ~An Original (2) DA Resubmission Gas Operation and Maintenance Expenses(continued) Line Account No. (a) 235 904 Uncollectible Accounts 236 905 Miscellaneous Customer Accounts Expenses 237 TOTAL Customer Accounts Expenses (Total of lines 232 thru 236) 238 6. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES 239 Operation 240 907 Supervision 241 908 Customer Assistance Expenses 242 909 Informational and Instructional Expenses 243 91 O Miscellaneous Customer Service and Informational Expenses 244 TOTAL Customer Service and Information Expenses (Total of lines 240 thru 243) 245 7. SALES EXPENSES 246 Operation 247 911 Supervision 248 912 Demonstrating and Selling Expenses 249 913 Advertising Expenses 250 916 Miscellaneous Sales Expenses 251 TOTAL Sales Expenses (Total of lines 247 thru 250) 252 8. ADMINISTRATIVE AND GENERAL EXPENSES 253 Operation 254 920 Administrative and General Salaries 255 921 Office Supplies and Expenses 256 (Less) 922 Administrative Expenses Transferred-Credit 257 923 Outside Services Employed 258 924 Property Insurance 259 925 Injuries and Damages 260 926 Employee Pensions and Benefits 261 927 Franchise Requirements 262 928 Regulatory Commission Expenses 263 (Less) 929 Duplicate Charges-Credit 264 930.1 General Advertising Expenses 265 930.2Miscellaneous General Expenses 266 931 Rents 267 TOTAL Operation (Total of lines 254 thru 266) 268 Maintenance 269 932 Maintenance of General Plant 270 TOTAL Administrative and General Expenses (Total of lines 267 and 269) 271 TOTAL Gas O&M Expenses (Total of lines 97, 177,201,229,237,244,251, and 270) FERC FORM NO. 2 (12-96) Page 325 Date of Report (Mo, Da, Yr) 04/15/2016 Amount for Current Year (b) 2,708,708 234,815 13,235,647 0 7,622, 111 886,365 95,402 8,603,878 0 0 0 0 0 12,117,128 1,634,570 18,378 3,629,636 467,995 1,353,757 671,836 0 2,481,480 0 878 1,662,443 353,710 24,355,055 3,826,155 28,181,210 426,881,657 Year/Period of Report End of 2015/04 Amount for Previous Year (c) 2,448,316 175,445 12,375,588 0 7, 161,608 920,194 158,451 8,240,253 0 0 0 0 0 9,505,163 1,766,312 20,731 4,655,459 485,783 1,641,068 719,807 0 2,081,530 0 73 1,485,418 302,200 22,622,082 3,600,782 26,222,864 464,967,609 PC_DR_009 Attachment B Page 154 of 177 Name of Respondent This 0ort Is: Date of Report Year/Period of Report Avista Corporation (1) X An Original (Mo, Da, Yr) (2) DA Resubmission 04/15/2016 End of 2015/04 Gas Used in Utility Operations 1. Report below details of credits during the year to Accounts 810, 811, and 812. 2. If any natural gas was used by the respondent for which a charge was not made to the appropriate operating expense or other account, list separately in column (c) the Dth of gas used, omitting entries in column (d). Natural Gas Natural Gas Natural Gas Natural Gas Line Purpose for Which Gas Was Used Account Amount of Amount of Amount of No. Charged Gas Used Credit Credit Credit Dth (in dollars) (in dollars) (in dollars) (a) (b) (c) (d) (d) (d) 1 810 Gas Used for Compressor Station Fuel -Credit 804 2,175,486 • 0 2 811 Gas Used for Products Extraction -Credit 811 2,894,933 446,368 3 Gas Shrinkage and Other Usage in Respondent's Own Processing 4 Gas Shrinkage, etc. for Respondent's Gas Processed by Others 5 812 Gas Used for Other Utility Operations -Credit (Report separately for each principal use. Group minor uses.) 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 Total 5,070,419 446,368 FERC FORM NO. 2 (12-96) Page 331 PC_DR_009 Attachment B Page 155 of 177 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Avista Corporation (2) _A Resubmission 04/15/2016 2015/04 FOOTNOTE DATA [Schedule Page: 331 Line No.: 1 Column: d Dollar value related to compressor fuel are not seperately recorded. These dollars are included in total gas purchase costs. I FERC FORM NO. 2 (12-96) Page 552.1 PC_DR_009 Attachment B Page 156 of 177 Name of Respondent This ~ort Is: Date of Report Year/Period of Report Avista Corporation (1) X An Original (Mo, Da, Yr) (2) DA Resubmission 04/15/2016 End of 2015/04 Other Gas Supply Expenses (Account 813) 1. Report other gas supply expenses by descriptive titles that clearly indicate the nature of such expenses. Show maintenance expenses, revaluation of monthly encroachments recorded in Account 117.4, and losses on settlements of imbalances and gas losses not associated with storage separately. Indicate the functional classification and purpose of property to which any expenses relate. List separately items of $250,000 or more. Description Amount Line (In dollars) No. (a) (b) 1 Gas Resource Management 2 Labor 791,056 3 Labor Loading 667,312 4 Other Expenses (Professional Services, Travel, Transportation, Office Supplies, Training) 143,124 5 6 Regulatory Affairs 7 Labor 7,939 8 Labor Loading 6,781 9 Other Expenses (Travel, Transportation, Gas Technology Institute Payments) 134,309 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 Total 1,750,521 FERC FORM NO. 2 (12-96) Page 334 PC_DR_009 Attachment B Page 157 of 177 Name of Respondent This ~Ort Is: Date of Report Year/Period of Report Avista Corporation (1) X An Original (Mo, Da, Yr) (2) DA Resubmission 04/15/2016 End of 2015/04 Miscellaneous General Expenses (Account 930.2) 1. Provide the information requested below on miscellaneous general expenses. 2. For Other Expenses, show the (a) purpose, (b) recipient and (c) amount of such items. List separately amounts of $250,000 or more however, amounts less than $250,000 may be grouped if the number of items of so grouped is shown. Description Amount Line (in dollars) No. (a) (b) 1 Industry association dues. 341,750 2 Experimental and general research expenses. ~ a. Gas Research Institute (GRI) b. Other ~ 3 Publishing and distributing information and reports to stockholders, trustee, registrar, and transfer agent fees and expenses, and other expenses of servicing outstanding securities of the respondent 142,773 4 Community Relations 36,686 5 Director Expenses 399,068 6 Education and information 9,602 7 Rating agency fees 68,856 8 Aircraft Operation Fees 77,157 9 Misc general expenses > 5k 296,932 10 Misc general expenses < 5k 289,619 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 Total 1,662,443 FERC FORM NO. 2 (12-96) Page 335 PC_DR_009 Attachment B Page 158 of 177 Name of Respondent This ~Ort Is: Date of Report Year/Period of Report Avista Corporation (1) X An Original (Mo, Da, Yr) (2) DA Resubmission 04/15/2016 End of 2015/04 Depreciation, Depletion and Amortization of Gas Plant (Accts 403, 404.1, 404.2, 404.3, 405} (Except Amortization of Acquisition Adjustments) 1. Report in Section A the amounts of depreciation expense, depletion and amortization for the accounts indicated and classified according to the plant functional groups shown. 2. Report in Section B, column (b) all depreciable or amortizable plant balances to which rates are applied and show a composite total. (If more desirable, report by plant account, ·- subaccount or functional classifications other than those pre-printed in column (a). Indicate in a footnote the manner in which column (b) balances are Section A. Summary of Depreciation, Depletion, and Amortization Charges Amortization Amortization and Amortization of Expense for Depletion of Underground Storage Line Depreciation Asset Producing Natural Land and Land No. Functional Classification Expense Retirement Gas Land and Land Rights (Account 403) Costs Rights (Account 404.2) (Account (Account 404.1) (a) (b) 403.1) (c) (d) (e) 1 Intangible plant 227 2 Production plant, manufactured gas 3 Production and gathering plant, natural gas 4 Products extraction plant 5 Underground gas storage plant 740,549 6 Other storage plant 7 Base load LNG terminaling and processing plant 8 Transmission plant 9 Distribution plant 19,667,183 10 General plant 731,608 11 Common plant-gas 5,454,239 7,737 12 TOTAL 26,593,579 7,964 FERC FORM NO. 2 (12-96) Page 336 PC_DR_009 Attachment B Page 159 of 177 Name of Respondent This wort Is: Date of Report Year/Period of Report Avista Corporation (1) X An Original (Mo, Da, Yr) (2) DA Resubmission 04/15/2016 End of 2015/04 Depreciation, Depletion and Amortization of Gas Plant (Accts 403, 404.1, 404.2, 404.3, 405) (Except Amortization of Acquisition Adjustments) (continued) obtained. If average balances are used, state the method of averaging used. For column (c) report available information for each plant functional classification listed in column (a). If composite depreciation accounting is used, report available information called for in columns (b) and (c) on this basis. Where the unit-of-production method is used to determine depreciation charges, show in a footnote any revisions made to estimated gas reserves. 3. If provisions for depreciation were made during the year in addition to depreciation provided by application of reported rates, state in a footnote the amounts and nature of the provisions and the plant items to which related. Section A. Summary of Depreciation, Depletion, and Amortization Charges Amortization of Amortization of Other Limited-term Other Gas Plant Total Line Gas Plant (Account 405) (b tog) No. (Account 404.3) Functional Classification (D (g) (h) (a) 1 447,074 447,301 Intangible plant 2 Production plant, manufactured gas 3 Production and gathering plant, natural gas 4 Products extraction plant 5 740,549 Underground gas storage plant 6 Other storage plant 7 Base load LNG terminaling and processing plant 8 Transmission plant 9 19,667,183 Distribution plant 10 42,986 774,594 General plant 11 4,525,983 9,987,959 Common plant-gas 12 5,016,043 31,617,586 TOTAL FERC FORM NO. 2 (12-96) Page 337 PC_DR_009 Attachment B Page 160 of 177 Name of Respondent Year/Period of Report This Rooort Is: Date of Report (1) X An Original (Mo, Da, Yr) Avista Corporation E d f 2015/04 (2) DA Resubmission 04/15/2016 n o __ _ Depreciation, Depletion and Amortization of Gas Plant (Accts 403, 404.1, 404.2, 404.3, 405) (Except Amortization of Acquisition Adjustments) (continued) 4. Add rows as necessary to completely report all data. Number the additional rows in sequence as 2.01, 2.02, 3.01, 3.02, etc. Line No. Production and Gathering Plant 2 Offshore (footnote details) 3 Onshore (footnote details) Section B. Factors Used in Estimating Depreciation Charges Functional Classification (a) 4 Underground Gas Storage Plant (footnote details) 5 Transmission Plant 6 Offshore (footnote details) 7 Onshore (footnote details) 8 General Plant (footnote details) 9 10 11 12 13 14 15 FERG FORM NO. 2 (12-96) Page 338 Plant Bases (in thousands) Applied Depreciation or Amortization Rates (percent) PC_DR_009 Attachment B Page 161 of 177 Name of Respondent This 0ort Is: Date of Report Year/Period of Report Avista Corporation (1) X An Original (Mo, Da, Yr) (2) DA Resubmission 04/15/2016 End of 2015/04 Particulars Concerning Certain Income Deductions and Interest Charges Accounts Report the information specified below, in the order given, for the respective income deduction and interest charges accounts. (a) Miscellaneous Amortization (Account 425)-Describe the nature of items included in this account, the contra account charged, the total of amortization charges for the year, and the period of amortization. (b) Miscellaneous Income Deductions-Report the nature, payee, and amount of other income deductions for the year as required by Accounts 426.1, Donations; 426.2, Life Insurance; 426.3, Penalties; 426.4, Expenditures for Certain Civic, Political and Related Activities; and 426.5, Other Deductions, of the Uniform System of Accounts. Amounts of less than $250,000 may be grouped by classes within the above accounts. (c) Interest on Debt to Associated Companies (Account 430)-For each associated company that incurred interest on debt during the year, indicate the amount and interest rate respectively for (a) advances on notes, (b) advances on open account, (c) notes payable, (d) accounts payable, and (e) other debt, and total interest. Explain the nature of other debt on which interest was incurred during the year. (d) Other Interest Expense (Account 431)-Report details including the amount and interest rate for other interest charges incurred during the year. Line Item Amount No. (a) (b) 1 Acct. 425.00 -MISCELLANEOUS AMORTIZATIONS 2 Items Under $250,000 3 Total -425.00 4 Acct. 426.10 -DONATIONS 5 Rosaurers Supermarket Inc-Storm Gift Cards to customers 460,950 6 Items Under $250,000 2,747,071 7 Total 426.10 3,208,021 8 Acct. 426.20 -LIFE INSURANCE 9 Officers Life 162,742 10 SERP 2,796,424 11 Items Under $250,000 120,828 12 Total 426.20 3,079,994 13 Acct. 426.30 -PENAL TIES 14 Items Under $250,000 70,316 15 Total 426.30 70,316 16 Acct. 426.40-EXPENDITURES FOR CERTAIN CIVIC, POLITICAL, AND RELATED ACTIVITIES 17 Items Under $250,000 1,625,650 18 Total 426.40 1,625,650 19 Acct. 426.50 -OTHER DEDUCTIONS 20 Executive Deferred Compensation 146,861 21 Hanna & Associates Inc 285,872 22 Items Under $250,000 953,767 23 Total 426.50 1,386,500 24 Acct. 430.00 -INTEREST ON DEBT TO ASSOC. COMPANIES 25 Avista Capital II (long-term debt) (variable rate ranged from 1.11 to 1.29 perc) 473,352 26 Avista Capital, Inc. 131,922 27 Total 430.00 605,274 28 Acct. 43t00 -OTHER INTEREST EXPENSE 29 Interest on electric deferrals 562,497 30 Interest on natural gas deferrals 339,979 31 Interest on committed line of credit 1,297,048 32 Other 436,703 33 Total 431.00 2,636,227 34 35 FERC FORM NO. 2 (12-96) Page 340 PC_DR_009 Attachment B Page 162 of 177 Name of Respondent This 0ort Is: Date of Report Year/Period of Report Avista Corporation (1) X An Original (Mo, Da, Yr) (2) DA Resubmission 04/15/2016 End of 2015/04 Regulatory Commission Expenses (Account 928) 1. Report below details of regulatory commission expenses incurred during the current year (or in previous years, if being amortized) relating to formal cases before a regulatory body, or cases in which such a body was a party. 2. In column (b) and ( c), indicate whether the expenses were assessed by a regulatory body or were otherwise incurred by the utility. ·- Description Deferred in Line (Furnish name of regulatory commission Assessed by Expenses Total Account 182.3 No. or body, the docket number, and a Regulatory of Expenses at Beginning description of the case.) Commission Utility to Date of Year (a) (b) (c) (d) (e) 1 Federal Energy Regulatory Commission 2 Charges include annual fee and license fee 3 for the Spokane River Project, the Cabinet 4 Gorge Project and Noxon Rapids Project 2,210,963 86,315 5 6 Washington Utilities and Transportation Commission 7 Includes annual fee and various other electric dockets 1,025,044 1,182,202 8 9 Includes annual fee and various other natural gas dockets 328,989 302,117 10 11 Idaho Public Utilities Commission 12 Includes annual fee and various other electric dockets 619,966 259,840 13 14 Includes annual fee and various other natural gas dockets 177,604 88,152 15 16 Public Utility Commission of Oregon 17 Includes annual fee and various other dockets 598,978 684,324 18 19 Not directly assigned electric 754,166 20 Not directly assigned natural gas 301,317 21 22 23 24 25 Total 4,961,544 3,658,433 FERC FORM NO. 2 (12-96) Page 350 PC_DR_009 Attachment B Page 163 of 177 Name of Respondent This IB:Jort Is: Date of Report Year/Period of Report Avista Corporation (1) X An Original (Mo, Da, Yr) (2) DA Resubmission 04/15/2016 End of 2015/04 Regulatory Commission Expenses (Account 928) 3. Show in column (k) any expenses incurred in prior years that are being amortized. List in column (a) the period of amortization. 4. Identify separately all annual charge adjustments (ACA). 5. List in column (0, (g), and (h) expenses incurred during year which were charges currently to income, plant, or other accounts. 6. Minor items (less than $250,000) may be grouped. Expenses Expenses Expenses Expenses Amortized Amortized Incurred Incurred Incurred Incurred During Year During Year Line During Year During Year During Year During Year Deferred in No. Charged Charged Charged Account 182.3 Currently To Currently To Currently To Deferred to Contra Amount End of Year Account Account Department Account No. Amount 182.3 (D (g) (h) (i) U) (k) (I) 1 2 3 4 Electric 928 2,297,278 5 6 7 Electric 928 2,207,246 8 9 Gas 928 631,106 10 11 12 Electric 928 879,806 13 14 Gas 928 265,756 15 16 17 Gas 928 1,283,302 18 19 Electric 928 754,166 20 Gas 928 301,317 21 22 23 24 25 8,619,977 FERC FORM NO. 2 (12-96) Page 351 PC_DR_009 Attachment B Page 164 of 177 Name of Respondent This IBJort Is: Date of Report Year/Period of Report Avista Corporation (1) X An Original (Mo, Da, Yr) (2) DA Resubmission 04/15/2016 End of 2015/04 Employee Pensions and Benefits (Account 926) 1. Report below the items contained in Account 926, Employee Pensions and Benefits. Line Expense Amount No. (a) (b) 1 Pensions -defined benefit plans 671,836 2 Pensions -other 3 Post-retirement benefits other than pensions (PBOP) 4 Post-employment benefit plans 5 Other (Specify) 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 Total I 671,836 FERC FORM NO. 2 (NEW 12-07) Page 352 PC_DR_009 Attachment B Page 165 of 177 This Page Intentionally Left Blank PC_DR_009 Attachment B Page 166 of 177 Name of Respondent Avista Corporation This ~Ort Is: (1) ~An Original (2) DA Resubmission Distribution of Salaries and Wages Date of Report (Mo, Da, Yr) 04/15/2016 Year/Period of Report End of 2015/04 Report below the distribution of total salaries and wages for the year. Segregate amounts originally charged to clearing accounts to Utility Depart.ments, Construction, Plant Removals and Other Accounts, and enter such amounts in the appropriate lines and columns provided. Salaries and wages billed to the Respondent by an affiliated company must be assigned to the particular operating function(s) relating to the expenses. In determining this segregation of salaries and wages originally charged to clearing accounts, a method of approximation giving substantially correct results may be used. When reporting detail of other accounts, enter as many rows as necessary numbered sequentially starting with 75.01, 75.02, etc. Line No. Classification (a) Electric 2 Operation 3 Production 4 Transmission 5 Distribution 6 Customer Accounts 7 Customer Service and Informational 8 Sales 9 Administrative and General 10 TOTAL Operation (Total of lines 3 thru 9) 11 Maintenance 12 Production 13 Transmission 14 Distribution 15 Administrative and General 16 TOTAL Maintenance (Total of lines 12 thru 15) 17 Total Operation and Maintenance 18 Production (Total of lines 3 and 12) 19 Transmission (Total of lines 4 and 13) 20 Distribution (Total of lines 5 and 14) 21 Customer Accounts (line 6) 22 Customer Service and Informational (line 7) 23 Sales (line 8) 24 Administrative and General (Total of lines 9 and 15) 25 TOTAL Operation and Maintenance (Total oflines 18 thru 24) 26 Gas 27 Operation 28 Production -Manufactured Gas 29 Production -Natural Gas(lncluding Exploration and Development) 30 Other Gas Supply 31 Storage, LNG Terminaling and Processing 32 Transmission 33 Distribution 34 Customer Accounts 35 Customer Service and Informational 36 Sales 37 Administrative and General 38 TOTAL Operation (Total of lines 28 thru 37) 39 Maintenance 40 Production -Manufactured Gas 41 Production -Natural Gas(lncluding Exploration and Development) 42 Other Gas Supply 43 Storage, LNG Terminaling and Processing 44 Transmission 45 Distribution FERC FORM NO. 2 (REVISED) Payroll Billed Allocation of Direct Payroll by Affiliated Payroll Charged Total Distribution Companies for Clearing Accounts (b) (c) (d) (e) 10,679,266 10,679,266 2,940,353 2,940,353 8,288,339 8,288,339 7,465,204 7,465,204 739,691 739,691 17,886,460 17,886,460 47,999,313 47,999,313 3,327,489 3,327,489 1,267,086 1,267,086 5,715,670 5,715,670 15,660, 180 15,660, 180 10,310,245 15,660,180 25,970,425 14,006,755 14,006,755 4,207,439 4,207,439 14,004,009 14,004,009 7,465,204 7,465,204 739,691 739,691 .17,886,460 15,660, 180 33,546,640 58,309,558 15,660,180 73,969,738 798,995 798,995 6,496 6,496 5,089, 107 5,089, 107 2,912,246 2,912,246 334,840 334,840 6,856,322 6,856,322 15,998,006 15,998,006 1,142,631 1,142,631 3,333,267 3,333,267 Page 354 PC_DR_009 Attachment B Page 167 of 177 Name of Respondent Avista Corporation This ~Ort Is: (1) ~An Original (2) DA Resubmission Distribution of Salaries and Wages (continued) Line No. Classification (a) 46 Administrative and General 47 TOTAL Maintenance (Total of lines 40 thru 46) 48 Gas (Continued) 49 Total Operation and Maintenance 50 Production -Manufactured Gas (Total of lines 28 and 40) 51 Production -Natural Gas (Including Expl. and Dev.)(11. 29 and 41) 52 Other Gas Supply (Total of lines 30 and 42) 53 Storage, LNG Terminaling and Processing (Total of II. 31 and 43) 54 Transmission (Total of lines 32 and 44) 55 Distribution (Total of lines 33 and 45) 56 Customer Accounts (Total of line 34) 57 Customer Service and Informational (Total of line 35) 58 Sales (Total of line 36) 59 Administrative and General (Total of lines 37 and 46) 60 Total Operation and Maintenance (Total of lines 50 thru 59) 61 Other Utility Departments 62 Operation and Maintenance 63 TOTAL ALL Utility Dept. (Total of lines 25, 60, and 62) 64 Utility Plant 65 Construction (By Utility Departments) 66 Electric Plant 67 Gas Plant 68 Other 69 TOTAL Construction (Total of lines 66 thru 68) 70 Plant Removal (By Utility Departments) 71 Electric Plant 72 Gas Plant 73 Other 74 TOTAL Plant Removal (Total of lines 71thru73) 75 Other Accounts (Specify) (footnote details) 76 TOTAL Other Accounts 77 TOTAL SALARIES AND WAGES FERC FORM NO. 2 (REVISED) Direct Payroll Distribution (b) 4,475,898 798,995 6,496 1,142,631 8,422,374 2,912,246 334,840 6,856,322 20,473,904 41,185,936 8,341,583 49,527,519 1,974,884 117,086 2,091,970 45,518,991 45,518,991 175,921,942 Page 355 Payroll Billed by Affiliated Companies (c) Date of Report (Mo, Da, Yr) 04/15/2016 Year/Period of Report End of 2015/04 Allocation of Payroll Charged for Clearing Accounts (d) 5,526,662 5,526,662 5,526,662 5,526,662 15,544,342 4,768,956 20,313,298 520,972 30,887 551,859 42,052,019) 42,052,019) ( 20) Total (e) 5,526,662 10,002,560 798,995 6,496 1,142,631 8,422,374 2,912,246 334,840 12,382,984 26,000,566 56,730,278 13,110,539 69,840,817 2,495,856 147,973 2,643,829 3,466,972 3,466,972 175,921 ,922 PC_DR_009 Attachment B Page 168 of 177 Name of Respondent This wort Is: Date of Report Year/Period of Report Avista Corporation (1) X An Original (Mo, Da, Yr) (2) DA Resubmission 04/15/2016 End of 2015/04 Charges for Outside Professional and Other Consultative Services 1. Report the information specified below for all charges made during the year included in any account (including plant accounts) for outside consultative and other professional services. These services include rate, management, construction, engineering, research, financial, valuation, legal, accounting, purchasing, advertising,labor relations, and public relations, rendered for the respondent under written or oral arrangement, for which aggregate payments were made during the year to any corporation partnership, organization of any kind, or·- individual (other than for services as an employee or for payments made for medical and related services) amounting to more than $250,000, including payments for legislative services, except those which should be reported in Account 426.4 Expenditures for Certain Civic, Political and Related Activities. (a) Name of person or organization rendering services. (b) Total charges for the year. 2. Sum under a description "Other", all of the aforementioned services amounting to $250,000 or less. 3. Total under a description "Total", the total of all of the aforementioned services. 4. Charges for outside professional and other consultative services provided by associated (affiliated) companies should be excluded from this schedule and be reported on Page 358, according to the instructions for that schedule. Description Amount Line (in dollars) No. (a) (b) 1 ABB ENT SOFTWARE INC 293,054 2 AVTEC SYSTEMS INTEGRATOR 432,852 3 BAKER CONSTRUCTION & DEVELOPMENT 3,217,838 4 BLAKC & VEATCH CORP 647,901 5 CIRRUS DESIGN 405, 115 6 COEUR DALENE TRIBE 825,508 7 DAVIS WRIGHT TREMAINE LLP 393,607 8 ERNST & YOUNG 6,644,948 9 H2E INC 319,876 10 HANNA & ASSOCIATES 312,920 11 HAWORTH 571,467 12 HDR ENGINEERING 683,579 13 HELVETICKA 253,574 14 HICKY BROTHERS RESEARCH 331,483 15 HP ENTERPRISE SERVICES 1,039,597 16 IBM CORPORATION 4,735,761 17 If ACTOR CONSULTING 327,790 18 INTERVOICE 442,815 19 LANDAU ASSOC IA TES 488,076 20 MAX J KUNEY COMPANY 427,883 21 MCKINSTRY ESSENTION LLC 4,770,671 22 NEAL STRUCTURAL REPAIR 350,285 23 NORTHWEST POWER POOL 354,703 24 OPOWER INC 257,662 25 PAINE HAMBLEN LLP 449,985 26 POWER CITY ELECTRIC 434,032 27 PRO BUILDING SYSTEM 481,901 28 SAPERE CONSUL TING 912,616 29 SENTURUSINC 322,861 30 STEELHEAD MECHANICAL 324,074 31 STRATA 429,899 32 URS ENERGY CONSTRUCTION 2,450,856 33 UTILITIES INTERNATIONAL 270,128 34 WESTERN ELECTRICITY 944,249 35 OTHER 19,257,681 FERC FORM NO. 2 (REVISED) Page 357 PC_DR_009 Attachment B Page 169 of 177 Name of Respondent Avista Corporation This ~ort Is: (1) ~An Original (2) DA Resubmission Transactions with Associated (Affiliated) Companies Date of Report (Mo, Da, Yr) 04/15/2016 Year/Period of Report End of 2015/04 1. Report below the information called for concerning all goods or services received from or provided to associated (affiliated) companies amounting to more than $250,000. 2. Sum under a description "Other", all of the aforementioned goods and services amounting to $250,000 or less. 3. Total under a description "Total", the total of all of the aforementioned goods and services. 4. Where amounts billed to or received from the associated (affiliated) company are based on an allocation process, explain in a footnote the basis of the allocation. Line Description of the Good or Service No. (a) Goods or Services Provided by Affiliated Company 2 Other 3 Other 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 Goods or Services Provided for Affiliated Company 21 Corporate Support 22 Corporate Support 23 Other 24 Other 25 Other 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 FERC FORM NO. 2 (NEW 12-07) Name of Associated/Affiliated Company (b) Account(s) Charged or Credited (c) Amount Charged or Credited (d) ------1 Steam Plant Square 931000 149,304 Spokane Energy 456000 14,230 -.---1 Salix 146000 737,375 Avista Development 146000 292,333 Avista Capital 146000 75,115 AELP, Inc 146000 137,732 Avista Energy 149000 879 Page 358 PC_DR_009 Attachment B Page 170 of 177 Name of Respondent Avista Corporation This ~ort Is: (1) ~An Original (2) DA Resubmission Gas Storage Projects 1. Report injections and withdrawals of gas for all storage projects used by respondent. Gas Line Item Belonging to No. Respondent (Dth) (a) (b) STORAGE OPERATIONS (in Dth) Gas Delivered to Storage 2 January 106,680 3 February 115,972 4 March 643,498 5 April 1,054, 123 6 May 3,026,992 7 June 1,235, 126 8 July 1,467,109 9 August 2,259,399 10 September 1,507,656 11 October 253,308 12 November 15,614 13 December 357,764 14 TOTAL (Total of lines 2 thru 13) 12,043,241 15 Gas Withdrawn from Storage 16 January 3,083,016 17 February 2,208,427 18 March 1,459,725 19 April 667,428 20 May 72,619 21 June 1,950,700 22 July 803,153 23 August 7,301 24 September 164,506 25 October 107,138 26 November 1,569,433 27 December 1,928,213 28 TOTAL (Total of lines 16 thru 27) 14,021,659 FERC FORM NO. 2 (12-96) Page 512_ Date of Report (Mo, Da, Yr) 04/15/2016 Gas Belonging to Others (Dth) (c) Year/Period of Report End of 2015/04 Total Amount (Dth) (d) 106,680 115,972 643,498 1,054, 123 3,026,992 1,235, 126 1,467, 109 2,259,399 1,507,656 253,308 15,614 357,764 12,043,241 3,083,016 2,208,427 1,459,725 667,428 72,619 1,950,700 803,153 7,301 164,506 107,138 1,569,433 1,928,213 14,021,659 PC_DR_009 Attachment B Page 171 of 177 Name of Respondent Avista Corporation 1. On line 4, enter the total storage capacity certificated by FERC. This ~Ort Is: (1) ~An Original (2) DA Resubmission Gas Storage Projects Date of Report (Mo, Da, Yr) 04/15/2016 Year/Period of Report End of 2015/04 2. Report total amount in Dth or other unit, as applicable on lines 2, 3, 4, 7. If quantity is converted from Met to Dth, provide conversion factor in a footnote. Line Item Total Amount No. (a) (b) STORAGE OPERATIONS Top or Working Gas End of Year 8,528,000 2 Cushion Gas (Including Native Gas) 7,730,668 3 Total Gas in Reservoir (Total of line 1 and 2) 16,258,668 4 Certificated Storage Capacity 16,258,668 5 Number of Injection -Withdrawal Wells 54 6 Number of Observation Wells 48 7 Maximum Days' Withdrawal from Storage 8 Date of Maximum Days' Withdrawal 9 LNG Terminal Companies (in Dth) 10 Number of Tanks 11 Capacity ofTanks 12 LNG Volume 13 Received at "Ship Rail" 14 Transferred to Tanks 15 Withdrawn from Tanks 16 "Boil Off' Vaporization Loss FERC FORM NO. 2 (12-96) Page 513_ PC_DR_009 Attachment B Page 172 of 177 Name of Respondent This Report is: Date of Report Year/Period of Report (1) ~An Original (Mo, Da, Yr) Avista Corporation (2) A Resubmission 04/15/2016 2015/04 FOOTNOTE DATA . ~ [Schedule Page: 513 Line No.: 7 Column: b Mcf converted to Dth using a factor of 1.04 I FERC FORM NO. 2 (12-96) Page 552.1 PC_DR_009 Attachment B Page 173 of 177 This Page Intentionally Left Blank PC_DR_009 Attachment B Page 174 of 177 Name of Respondent This 'IB:Jort Is: Date of Report Year/Period of Report Avista Corporation (1) X An Original (Mo, Da, Yr) (2) DA Resubmission 04/15/2016 End of 2015/04 Auxiliary Peaking Facilities 1. Report below auxiliary facilities of the respondent for meeting seasonal peak demands on the respondent's system, such as underground storage projects, liquefied petroleum gas installations, gas liquefaction plants, oil gas sets, etc. 2. For column ( c), for underground storage projects, report the delivery capacity on February 1 of the heating season overlapping the year-end for which this report is submitted. For other facilities, report the rated maximum daily delivery capacities. 3. For column (d), include or exclude (as appropriate) the cost of any plant used jointly with another facility on the basis of predominant use, unless the auxiliary peaking facility is a separate plant as contemplated by general instruction 12 of the Uniform System of Accounts. Maximum Daily Cost of Was Facility Location of Type of Delivery Capacity Facility Operated on Day Line Facility Facility of Facility (in dollars) of Highest No. Dth Transmission Peak (a) (b) (c) (d) Delivery? 1 2 Chehalis, Washington Underground Natural Gas 346,667 37,061,388 Yes 3 Storage Field 4 Washington & Idaho Supply 5 6 Chehalis, Washington Underground Natural Gas 52,000 6,018,313 Yes 7 Storage Field 8 Oregon Supply 9 10 Chehalis, Washington Underground Natural Gas 2,623 . ( 1) No 11 Storage Field 12 Oregon Supply 13 14 Rock Springs, Wyoming Underground Natural Gas 186,125 ( 1) Yes 15 Storage Field 16 Washington & Idaho Supply 17 18 Rock Springs, Wyoming Underground Natural Gas 63,875 . ( 1) Yes 19 Storage Field 20 Oregon Supply 21 22 23 24 25 26 27 28 29 30 FERC FORM NO. 2 (12-96) Page 519 PC_DR_009 Attachment B Page 175 of 177 Name of Respondent This Report is: Date of Report Yea~PeriodofReport (1) 6 An Original (Mo, Da, Yr) Avista Corporation (2) A Resubmission 04/15/2016 2015/04 FOOTNOTE DATA Line No.: 10 Column: d ant in the facilities, not an owner and is char ed a fee for demand deliverabilit Line No.: 14 Column: d ant in the facilities, not an owner and is char ed a fee for demand deliverabilit I FERC FORM NO. 2 (12-96) Page 552.1 PC_DR_009 Attachment B Page 176 of 177 This ~Ort Is: (1) ~An Original Date of Report (Mo, Da, Yr) Year/Period of Report Name of Respondent Avista Corporation (2) DA Resubmission 04/15/2016 End of 2015/04 Gas Account -Natural Gas 1. The purpose of this schedule is to account for the quantity of natural gas received and delivered by the respondent. 2. Natural gas means either natural gas unmixed or any mixture of natural and manufactured gas. 3. Enter in column (c) the year to date Dth as reported in the schedules indicated for the items of receipts and deliveries. 4. Enter in column (d) the respective quarter's Dth as reported in the schedules indicated for the items of receipts and deliveries. 5. Indicate in a footnote the quantities of bundled sales and transportation gas and specify the line on which such quantities are listed. 6. If the respondent operates two or more systems which are not interconnected, submit separate pages for this purpose. 7. Indicate by footnote the quantities of gas not subject to Commission regulation which did not incur FERC regulatory costs by showing (1) the local distribution volumes another jurisdictional pipeline delivered to the local distribution company portion of the reporting pipeline (2) the quantities that the reporting pipeline transported or sold through its local distribution facilities or intrastate facilities and which the reporting pipeline received through gathering facilities or intrastate facilities, but not through any of the interstate portion of the reporting pipeline, and (3) the gathering line quantities that were not destined for interstate market or that were not transported through any interstate portion of the reporting pipeline. 8. Indicate in a footnote the specific gas purchase expense account(s) and related to which the aggregate volumes reported on line No. 3 relate. 9. Indicate in a footnote (1) the system supply quantities of gas that are stored by the reporting pipeline, during the reporting year and also reported as sales, transportation and compression volumes by the reporting pipeline during the same reporting year, (2) the system supply quantities of gas that are stored by the reporting pipeline during the reporting year which the reporting pipeline intends to sell or transport in a future reporting year, and (3) contract storage quantities. 10. Also indicate the volumes of pipeline production field sales that are included in both the company's total sales figure and the company's total transportation figure. Add additional information as necessary to the footnotes. Ref. Page No. of Total Amount Current Three Line Item (FERC Form Nos. of Dth Months No. 2/2-A) Year to Date Ended Amount of Dth (a) (b) (c) Quarterly Only 01 Name of System: 2 GAS RECEIVED 3 Gas Purchases (Accounts 800-805) 112,733,321 26,490,639 4 Gas of Others Received for Gathering (Account 489.1) 303 5 Gas of Others Received for Transmission (Account 489.2) 305 6 Gas of Others Received for Distribution (Account 489.3) 301 16,467,897 4,535,635 7 Gas of Others Received for Contract Storage (Account 489.4) 307 8 Gas of Others Received for Production/Extraction/Processing (Account 490 and 491) 9 Exchanged Gas Received from Others (Account 806) 328 10 Gas Received as Imbalances (Account 806) 328 69,423 11,572) 11 Receipts of Respondent's Gas Transported by Others (Account 858) 332 12 Other Gas Withdrawn from Storage (Explain) 1,965,882 2,956,092 13 Gas Received from Shippers as Compressor Station Fuel 14 Gas Received from Shippers as Lost and Unaccounted for 15 Other Receipts (Specify) (footnote details) 16 Total Receipts {Total of lines 3 thru 15) 17 GAS DELIVERED 18 Gas Sales (Accounts 480-484) 112,593,140 28,945,296 19 Deliveries of Gas Gathered for Others (Account 489.1) 303 20 Deliveries of Gas Transported for Others (Account 489.2) 305 21 Deliveries of Gas Distributed for Others (Account 489.3) 301 16,467,897 4,535,635 22 Deliveries of Contract Storage Gas (Account 489.4) 307 23 Gas of Others Delivered for Production/Extraction/Processing (Account 490 and 491) 24 Exchange Gas Delivered to Others (Account 806) 328 25 Gas Delivered as Imbalances (Account 806) 328 26 Deliveries of Gas to Others for Transportation (Account 858) 332 27 Other Gas Delivered to Storage (Explain) 28 Gas Used for Compressor Station Fuel 509 2, 175,486 489,863 29 Other Deliveries and Gas Used for Other Operations 30 Total Deliveries (Total of lines 18 thru 29) 131,236,523 33,970,794 31 GAS LOSSES AND GAS UNACCOUNTED FOR 32 Gas Losses and Gas Unaccounted For 33 TOTALS 34 Total Deliveries, Gas Losses & Unaccounted For (Total of lines 30 and 32) FERC FORM NO. 2 (REV 01-11) Page 520 PC_DR_009 Attachment B Page 177 of 177 Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/07/2016 CASE NO: UE-160228 & UG-160229 WITNESS: Mark Thies REQUESTER: Public Counsel RESPONDER: Wendy Manskey TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: PC – 009 TELEPHONE: (509) 495-4565 EMAIL: wendy.manskey@avistacorp.com REQUEST: Please provide a copy of Avista’s Federal Energy Regulatory Commission, Form 2 for 2014 and 2015. RESPONSE: Please see PC_DR_009 Attachment A and B for the Company’s FERC Form 2 for calendar year 2014, which was provided in the original case, and 2015, respectively, in electronic form. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/07/2016 CASE NO: UE-160228 & UG-160229 WITNESS: Mark Thies REQUESTER: Public Counsel RESPONDER: Wendy Manskey TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: PC – 009 TELEPHONE: (509) 495-4565 EMAIL: wendy.manskey@avistacorp.com REQUEST: Please provide a copy of Avista’s Federal Energy Regulatory Commission, Form 2 for 2014 and 2015. RESPONSE: Please see PC_DR_009 Attachment A and B for the Company’s FERC Form 2 for calendar year 2014, which was provided in the original case, and 2015, respectively, in electronic form. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/14/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: Public Counsel RESPONDER: Annette Brandon TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: PC – 010 TELEPHONE: (509) 495-4324 EMAIL: annette.brandon@avistacorp.com REQUEST: Please provide total (all jurisdictions) electric salaries and wages (expense plus capitalized) separated between direct and allocated amounts for each year 2007 through 2015. RESPONSE: Please see PC_DR_010 Attachment A for total salaries and wages for 2007 – 2015 (includes expense and capital amounts). Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/14/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: Public Counsel RESPONDER: Annette Brandon TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: PC – 010 TELEPHONE: (509) 495-4324 EMAIL: annette.brandon@avistacorp.com REQUEST: Please provide total (all jurisdictions) electric salaries and wages (expense plus capitalized) separated between direct and allocated amounts for each year 2007 through 2015. RESPONSE: Please see PC_DR_010 Attachment A for total salaries and wages for 2007 – 2015 (includes expense and capital amounts). Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/14/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: Public Counsel RESPONDER: Annette Brandon TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: PC – 011 TELEPHONE: (509) 495-4324 EMAIL: annette.brandon@avistacorp.com REQUEST: Please provide Washington jurisdictional electric salaries and wages (expense plus capitalized) separated between direct and allocated amounts for each year 2007 through 2015. RESPONSE: Please see the Company’s response to PC_DR_010. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/14/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: Public Counsel RESPONDER: Annette Brandon TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: PC – 011 TELEPHONE: (509) 495-4324 EMAIL: annette.brandon@avistacorp.com REQUEST: Please provide Washington jurisdictional electric salaries and wages (expense plus capitalized) separated between direct and allocated amounts for each year 2007 through 2015. RESPONSE: Please see the Company’s response to PC_DR_010. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/14/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: Public Counsel RESPONDER: Annette Brandon TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: PC – 012 TELEPHONE: (509) 495-4324 EMAIL: annette.brandon@avistacorp.com REQUEST: Please provide total (all jurisdictions) gas salaries and wages (expense plus capitalized) separated between direct and allocated amounts for each year 2007 through 2015. RESPONSE: Please see the Company’s response to PC_DR_010. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/14/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: Public Counsel RESPONDER: Annette Brandon TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: PC – 012 TELEPHONE: (509) 495-4324 EMAIL: annette.brandon@avistacorp.com REQUEST: Please provide total (all jurisdictions) gas salaries and wages (expense plus capitalized) separated between direct and allocated amounts for each year 2007 through 2015. RESPONSE: Please see the Company’s response to PC_DR_010. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/14/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: Public Counsel RESPONDER: Annette Brandon TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: PC – 013 TELEPHONE: (509) 495-4324 EMAIL: annette.brandon@avistacorp.com REQUEST: Please provide Washington jurisdictional gas salaries and wages (expense plus capitalized) separated between direct and allocated amounts for each year 2007 through 2015. RESPONSE: Please see the Company’s response to PC_DR_010. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/14/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: Public Counsel RESPONDER: Annette Brandon TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: PC – 013 TELEPHONE: (509) 495-4324 EMAIL: annette.brandon@avistacorp.com REQUEST: Please provide Washington jurisdictional gas salaries and wages (expense plus capitalized) separated between direct and allocated amounts for each year 2007 through 2015. RESPONSE: Please see the Company’s response to PC_DR_010. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/14/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: Public Counsel RESPONDER: Annette Brandon TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: PC – 014 TELEPHONE: (509) 495-4324 EMAIL: annette.brandon@avistacorp.com REQUEST: Please provide the number of direct Washington electric employees each year 2007 through 2015. RESPONSE: The table below represents Washington electric directly assigned employees for 2007 – 2015. The number of employees represents FTE equivalent (calculated as Washington directly assigned hours divided by 2080 hours) including overtime and actual paid time off. Electric Employees - WA Direct 2007 230 2008 238 2009 237 2010 266 2011 281 2012 274 2013 251 2014 253 2015 275 Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/14/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: Public Counsel RESPONDER: Annette Brandon TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: PC – 014 TELEPHONE: (509) 495-4324 EMAIL: annette.brandon@avistacorp.com REQUEST: Please provide the number of direct Washington electric employees each year 2007 through 2015. RESPONSE: The table below represents Washington electric directly assigned employees for 2007 – 2015. The number of employees represents FTE equivalent (calculated as Washington directly assigned hours divided by 2080 hours) including overtime and actual paid time off. Electric Employees - WA Direct 2007 230 2008 238 2009 237 2010 266 2011 281 2012 274 2013 251 2014 253 2015 275 Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/14/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: Public Counsel RESPONDER: Annette Brandon TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: PC – 015 TELEPHONE: (509) 495-4324 EMAIL: annette.brandon@avistacorp.com REQUEST: Please provide the number of direct Washington gas employees each year 2007 through 2015. RESPONSE: The table below represents Washington natural gas directly assigned employees for 2007 – 2015. The number of employees represents FTE equivalent (calculated as Washington directly assigned hours divided by 2080 hours) including overtime and actual paid time off. Gas Employees - WA Direct 2007 127$ 2008 130 2009 135 2010 118 2011 123 2012 135 2013 132 2014 139 2015 140 Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/14/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: Public Counsel RESPONDER: Annette Brandon TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: PC – 015 TELEPHONE: (509) 495-4324 EMAIL: annette.brandon@avistacorp.com REQUEST: Please provide the number of direct Washington gas employees each year 2007 through 2015. RESPONSE: The table below represents Washington natural gas directly assigned employees for 2007 – 2015. The number of employees represents FTE equivalent (calculated as Washington directly assigned hours divided by 2080 hours) including overtime and actual paid time off. Gas Employees - WA Direct 2007 127$ 2008 130 2009 135 2010 118 2011 123 2012 135 2013 132 2014 139 2015 140 Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/14/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: Public Counsel RESPONDER: Annette Brandon TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: PC – 016 TELEPHONE: (509) 495-4324 EMAIL: annette.brandon@avistacorp.com REQUEST: Please provide total (all jurisdictions) electric employee benefits expenses separated by type for each year 2007 through 2015. RESPONSE: Please see PC_DR_016 Attachment A for the system total benefit expenses by type (pension, medical, etc) for 2007 through 2015. Benefits are part of an overall labor loader which is applied to the account in which the direct labor charges are incurred. Benefit charges by jurisdiction are calculated using the total labor dollars as provided in the Company’s response to PC_DR_010 Attachment A, applied to the total benefit amount for the respective year. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/14/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: Public Counsel RESPONDER: Annette Brandon TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: PC – 016 TELEPHONE: (509) 495-4324 EMAIL: annette.brandon@avistacorp.com REQUEST: Please provide total (all jurisdictions) electric employee benefits expenses separated by type for each year 2007 through 2015. RESPONSE: Please see PC_DR_016 Attachment A for the system total benefit expenses by type (pension, medical, etc) for 2007 through 2015. Benefits are part of an overall labor loader which is applied to the account in which the direct labor charges are incurred. Benefit charges by jurisdiction are calculated using the total labor dollars as provided in the Company’s response to PC_DR_010 Attachment A, applied to the total benefit amount for the respective year. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/14/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: Public Counsel RESPONDER: Annette Brandon TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: PC – 017 TELEPHONE: (509) 495-4324 EMAIL: annette.brandon@avistacorp.com REQUEST: Please provide Washington jurisdictional electric employee benefits expenses separated by type for each year 2007 through 2015. RESPONSE: Please see the Company’s response to PC_DR_016. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/14/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: Public Counsel RESPONDER: Annette Brandon TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: PC – 017 TELEPHONE: (509) 495-4324 EMAIL: annette.brandon@avistacorp.com REQUEST: Please provide Washington jurisdictional electric employee benefits expenses separated by type for each year 2007 through 2015. RESPONSE: Please see the Company’s response to PC_DR_016. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/14/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: Public Counsel RESPONDER: Annette Brandon TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: PC – 018 TELEPHONE: (509) 495-4324 EMAIL: annette.brandon@avistacorp.com REQUEST: Please provide total (all jurisdictions) gas employee benefits expenses separated by type for each year 2007 through 2015. RESPONSE: Please see the Company’s response to PC_DR_016. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/14/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: Public Counsel RESPONDER: Annette Brandon TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: PC – 018 TELEPHONE: (509) 495-4324 EMAIL: annette.brandon@avistacorp.com REQUEST: Please provide total (all jurisdictions) gas employee benefits expenses separated by type for each year 2007 through 2015. RESPONSE: Please see the Company’s response to PC_DR_016. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/14/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: Public Counsel RESPONDER: Annette Brandon TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: PC – 019 TELEPHONE: (509) 495-4324 EMAIL: annette.brandon@avistacorp.com REQUEST: Please provide Washington jurisdictional gas employee benefits expenses separated by type for each year 2007 through 2015. RESPONSE: Please see the Company’s response to PC_DR_016. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/14/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: Public Counsel RESPONDER: Annette Brandon TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: PC – 019 TELEPHONE: (509) 495-4324 EMAIL: annette.brandon@avistacorp.com REQUEST: Please provide Washington jurisdictional gas employee benefits expenses separated by type for each year 2007 through 2015. RESPONSE: Please see the Company’s response to PC_DR_016. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/14/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: Public Counsel RESPONDER: Annette Brandon TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: PC – 020 TELEPHONE: (509) 495-4324 EMAIL: annette.brandon@avistacorp.com REQUEST: Please provide Washington jurisdictional non-executive electric incentive compensation expenses for each year 2007 through 2015. RESPONSE: Please see PC_DR_020 attachment A for total incentive compensation expenses for 2007-2015 categorized by system total, electric executive and non-executive, and natural gas executive and non- executive. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/14/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: Public Counsel RESPONDER: Annette Brandon TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: PC – 020 TELEPHONE: (509) 495-4324 EMAIL: annette.brandon@avistacorp.com REQUEST: Please provide Washington jurisdictional non-executive electric incentive compensation expenses for each year 2007 through 2015. RESPONSE: Please see PC_DR_020 attachment A for total incentive compensation expenses for 2007-2015 categorized by system total, electric executive and non-executive, and natural gas executive and non- executive. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/14/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: Public Counsel RESPONDER: Annette Brandon TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: PC – 021 TELEPHONE: (509) 495-4324 EMAIL: annette.brandon@avistacorp.com REQUEST: Please provide Washington jurisdictional non-executive gas incentive compensation expenses for each year 2007 through 2015. RESPONSE: Please see the Company’s response to PC_DR_020. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/14/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: Public Counsel RESPONDER: Annette Brandon TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: PC – 021 TELEPHONE: (509) 495-4324 EMAIL: annette.brandon@avistacorp.com REQUEST: Please provide Washington jurisdictional non-executive gas incentive compensation expenses for each year 2007 through 2015. RESPONSE: Please see the Company’s response to PC_DR_020. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/14/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: Public Counsel RESPONDER: Annette Brandon TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: PC – 022 TELEPHONE: (509) 495-4324 EMAIL: annette.brandon@avistacorp.com REQUEST: Please provide total Washington jurisdictional executive incentive compensation expenses for each year 2007 through 2015. RESPONSE: Please see the Company’s response to PC_DR_020. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/14/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: Public Counsel RESPONDER: Annette Brandon TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: PC – 022 TELEPHONE: (509) 495-4324 EMAIL: annette.brandon@avistacorp.com REQUEST: Please provide total Washington jurisdictional executive incentive compensation expenses for each year 2007 through 2015. RESPONSE: Please see the Company’s response to PC_DR_020. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/14/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: Public Counsel RESPONDER: Annette Brandon TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: PC – 023 TELEPHONE: (509) 495-4324 EMAIL: annette.brandon@avistacorp.com REQUEST: Please provide total Avista (all jurisdictions) executive incentive compensation expenses for each year 2007 through 2015. RESPONSE: Please see the Company’s response to PC_DR_020. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/14/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: Public Counsel RESPONDER: Annette Brandon TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: PC – 023 TELEPHONE: (509) 495-4324 EMAIL: annette.brandon@avistacorp.com REQUEST: Please provide total Avista (all jurisdictions) executive incentive compensation expenses for each year 2007 through 2015. RESPONSE: Please see the Company’s response to PC_DR_020. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/13/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Patrick Ehrbar REQUESTER: Public Counsel/Energy Project RESPONDER: Joe Miller TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: PC – 024 TELEPHONE: (509) 495-4546 EMAIL: joe.miller@avistacorp.com REQUEST: Please provide the following for each year 2007 through 2015: a) average number of Washington jurisdictional electric customers; b) average number of total (all jurisdictions) electric customers; c) average number of Washington jurisdictional gas customers; d) average number of total (all jurisdictions) gas customers; e) annual Washington jurisdictional KWH sales (retail only); f) annual total (all jurisdictions) KWH sales (retail only); g) Washington distribution circuit miles; h) total Avista (all jurisdictions) distribution circuit miles; i) Washington distribution miles of mains; and j) total Avista (all jurisdictions) distribution miles of mains. RESPONSE: See the attachment labeled “PC_DR_024 Attachment A”. Please note, the Company was unable to provide historical data for all of the requested years in part (g). The query of our GIS system takes a snapshot in time and this level of detail had not been queried in every year unless there was a corresponding rate case filing. For the years where there was not a corresponding general rate case filing in part (h), the Company used the total approximate distribution circuit miles reported in the Company’s 10k filings. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/13/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Patrick Ehrbar REQUESTER: Public Counsel/Energy Project RESPONDER: Joe Miller TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: PC – 024 TELEPHONE: (509) 495-4546 EMAIL: joe.miller@avistacorp.com REQUEST: Please provide the following for each year 2007 through 2015: a) average number of Washington jurisdictional electric customers; b) average number of total (all jurisdictions) electric customers; c) average number of Washington jurisdictional gas customers; d) average number of total (all jurisdictions) gas customers; e) annual Washington jurisdictional KWH sales (retail only); f) annual total (all jurisdictions) KWH sales (retail only); g) Washington distribution circuit miles; h) total Avista (all jurisdictions) distribution circuit miles; i) Washington distribution miles of mains; and j) total Avista (all jurisdictions) distribution miles of mains. RESPONSE: See the attachment labeled “PC_DR_024 Attachment A”. Please note, the Company was unable to provide historical data for all of the requested years in part (g). The query of our GIS system takes a snapshot in time and this level of detail had not been queried in every year unless there was a corresponding rate case filing. For the years where there was not a corresponding general rate case filing in part (h), the Company used the total approximate distribution circuit miles reported in the Company’s 10k filings. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/07/2016 CASE NO: UE-160228 & UG-160229 WITNESS: Mark Thies REQUESTER: Public Counsel RESPONDER: Margie Stevens TYPE: Data Request DEPT: Finance REQUEST NO.: PC – 025 TELEPHONE: (509) 495-8978 EMAIL: margie.stevens@avistacorp.com REQUEST: Please provide a copy of Avista’s Washington and total Company capital expenditure budgets for each year 2007 through 2015. If gas and electric are provided in separate documents, please provide each document separately. RESPONSE: PC_DR_025 Attachment A is the capital expenditure budgets for the total Company as well as broken out by our jurisdictions. Please note that “allocated” jurisdictions indicate that those amounts are broken out amongst the various state jurisdictions. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/07/2016 CASE NO: UE-160228 & UG-160229 WITNESS: Mark Thies REQUESTER: Public Counsel RESPONDER: Margie Stevens TYPE: Data Request DEPT: Finance REQUEST NO.: PC – 025 TELEPHONE: (509) 495-8978 EMAIL: margie.stevens@avistacorp.com REQUEST: Please provide a copy of Avista’s Washington and total Company capital expenditure budgets for each year 2007 through 2015. If gas and electric are provided in separate documents, please provide each document separately. RESPONSE: PC_DR_025 Attachment A is the capital expenditure budgets for the total Company as well as broken out by our jurisdictions. Please note that “allocated” jurisdictions indicate that those amounts are broken out amongst the various state jurisdictions. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/07/2016 CASE NO: UE-160228 & UG-160229 WITNESS: Mark Thies REQUESTER: Public Counsel RESPONDER: Margie Stevens TYPE: Data Request DEPT: Finance REQUEST NO.: PC – 026 TELEPHONE: (509) 495-8978 EMAIL: margie.stevens@avistacorp.com REQUEST: Please provide a copy of Avista’s Washington and total Company operating budgets for each year 2007 through 2015. If gas and electric are provided in separate documents, please provide each document separately. RESPONSE: PC_DR_026 Attachment A is the operating budgets for the total Company as well as broken out by our jurisdictions. Please note that “allocated” jurisdictions indicate that those amounts are broken out amongst the various state jurisdictions. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/07/2016 CASE NO: UE-160228 & UG-160229 WITNESS: Mark Thies REQUESTER: Public Counsel RESPONDER: Margie Stevens TYPE: Data Request DEPT: Finance REQUEST NO.: PC – 026 TELEPHONE: (509) 495-8978 EMAIL: margie.stevens@avistacorp.com REQUEST: Please provide a copy of Avista’s Washington and total Company operating budgets for each year 2007 through 2015. If gas and electric are provided in separate documents, please provide each document separately. RESPONSE: PC_DR_026 Attachment A is the operating budgets for the total Company as well as broken out by our jurisdictions. Please note that “allocated” jurisdictions indicate that those amounts are broken out amongst the various state jurisdictions. Page 1 of 5 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/06/2016 CASE NO: UE-160228 & UG-160229 WITNESS: Mark Thies REQUESTER: Public Counsel RESPONDER: Tracy Van Orden TYPE: Data Request DEPT: Audit REQUEST NO.: PC – 028 TELEPHONE: (509) 495-4942 EMAIL: tracy.vanorden@avistacorp.com REQUEST: Please provide a copy of all management audits conducted for, or by, Avista during the last ten years. In this response, indicate if such management audits were ordered or required by a regulatory commission. RESPONSE: Due to the volume of documentation associated with this request, a list of all management audits conducted over the last ten years has been provided. Individual reports can be made available upon request. 2007 • Productivity Initiative Program • Employee Reimbursements • Transmission Upgrade Projects • Vehicle Inspections • Avista Utilities Price Index Reporting • Colstrip Fuel Supply - Annual • Colstrip Steam Plant Operating and A&G Costs Audit • Avista Incentive Plan Review 2008 • AVA and AIQ 2007 Incentive Plan Reviews • Customer Account Entries (CAEs) • General Contracts Review • Facilities Services • Douglas County Wells Project • Cash Reconciliations • Project Share Audit • Overtime Review • AIQ Mid-Year Incentive Payout Review • Electronic Funds Transfer Review • Avista Utilities’ Web Redesign Review • Mobile Wireless Device Audit • Avista Utilities Price Index Reporting • Colstrip Fuel Supply - Annual Page 2 of 5 2009 • AVA and AIQ 2008 Incentive Plan Reviews • 2008 Price Reporting Audit • Jackson Prairie Expansion Audit • Demand Side Management Audit • Fuel Card Purchase Audit • Colstrip Fuel and Transportation Audit • 2008 Debt Issuance/Reacquisition Cost Audit – Regulatory Requested 2010 • AVA and AIQ 2009 Incentive Plan Reviews • 2009 Electric and Natural Gas Price Reporting Audit • Colstrip 3&4 Coal Supply and Transportation Audit • Employee and Director Expense Audit • NERC Reliability Standards Review • Internal Reliability Compliance Program Audit • PAR Data Access Audit • 2009 Debt Issuance Costs and Debt Reacquisitions Cost Audit – Regulatory Requested 2011 • Coyote Springs Unit 2 Operating Costs and Contract Review Report • Coyote Sprints Unit 2 Storeroom Inventory Review • Colstrip Fuel and Transportation Audit • Colstrip Operations Audit 2009-2010 • Klamath Falls Lateral Purchase Option-Limited Financial Due Diligence • Avista Corp PAC Accounting Review • Project Share Audit Report • 2010 Electric and Natural Gas Reporting Audit • AMI Post-Implementation Review • Kubra SAS70 Review • Q1 Network Device Configuration • 2010 Debt Issuance Costs and Debt Reacquisitions Review – Regulatory Requested • Regulus SAS 70 Review • RED Post-Implementation Review • Accounting Practices Audit - Regulatory Requested • LIRAP Accounting Practices Audit - Regulatory Requested • Changes to Payment Hierarchy • Email Attachment Study • Review of Avista Corp, Avista Utilities and AIQ 2010 Incentive Plans • Card Verification Value Capture Audit • MV-RS Project Post-Implementation Audit • vmWare ESXi 4.1 Server Configuration Audit • PacifiCorp Transmission and Interconnection Agreement Audit 2012 Page 3 of 5 • Accounting Practices Audit – Regulatory Requested • Debt Issuance and Reacquisition Costs Review – Regulatory Requested • LIRAP Accounting Practices Audit – Regulatory Requested • Avista Corp. and Avista Utilities Incentive Plan Review • Ecova Incentive Plan Review • Price Reporting Audit • Expense Report Audit • Back Billing Procedures Audit • Contract Process Review • Ecova Investment Policy Review • Colstrip Fuel Supply and Transportation Audit • Demand Side Management Audit Follow-Up • WUTC U-101169 Investigation Report Follow Up • Oracle Financial System Upgrade Project Audit • Claims Application System Configuration Audit • DMZ Control Audit • Social Media Assessment • Distribution Management System Implementation Review • Remittance Processing System Replacement Project Audit • Ecova Identity Management Review • Smart Grid Thermostat Pilot Program Review 2013 • Debt Issuance and Reacquisition Costs Review – Regulatory Requirement • Voluntary Severance Incentive Plan Audit • Avista Corp. and Avista Utilities Incentive Plan Review • Facilities Invoice Investigation • Accounting Practices Audit - Regulatory Requirement • Greenhouse Gas Inventory Audit • Low-Income Rate Assistance Program Accounting Practices Audit - Regulatory Requirement • Reliability Compliance Program Assessment • Short-term Disability Plan Review • Spokane Warehouse Controls Review • Price Reporting Audit • Colstrip Power Plant Audit • Compass Project – Bonus Plan Review • Demand Side Management Audit Follow-Up • Corporate Governance Review • Colstrip Fuel Supply and Transportation Audit • Contract Review • Grant County PUD Audit • Compass Project – Regulatory Preparedness Review • Contractor Access Security Audit • Mobile Device Management Review • Compass Project – Wave 1 Data Conversion • Compass Project – Wave 1 Pre/Post Implementation Review • Ecova Other Real Estate Owned (REO) Audit Page 4 of 5 • Change Management Review 2014 • Debt Issuance and Reacquisition Costs Review – Regulatory Requirement • Avista Corp. Incentive Plan Review • Wild Rose Review and Demand Side Management Follow-up • Accounting Practices Audit - Regulatory Requirement • LIRAP Accounting Practices Audit - Regulatory Requirement • Avista Corp. Transaction Bonus Plan • Colstrip Fuel Supply and Transportation Audit • Contract Review – NPL Construction Company • Compass Project – Bonus Plan Review Phase IV • Price Reporting Audit • Asphlund Contract Review • Compass Project – Regulatory Preparedness Review • Compass Project – Third Party Integration • Avista Credit Union IT Audit • IT General Computer Controls Audit • Change Management Review Follow-up • Contractor Access Review Follow-Up • Compass Project – Data Conversion 2015 • Debt Issuance and Reacquisition Costs Audit – Regulatory Requirement • Avista Corp. Incentive Plan Review • Compass Project – Bonus Plan Review • Strategic Investment Review • Price Reporting Audit • Compass Project – Regulatory Preparedness Review • Colstrip Fuel Supply and Transportation Audit • Expense Report Audit • AEL&P Incentive Plan Review • Grant County Power Purchase Agreement Audit • Assignment of Direct Labor • Capital Project Review • Colstrip Power Plant Operations Audit • Contract Review – Nine Mile Project • METALfx Review • Avista Corp. Credit Union IT Audit, Follow-Up • Avista Corp. Credit Union Server Refresh Project Pre-Implementation Audit • Compass Project – Pre/Post Implementation Audit • Avista Corp. Credit Union Server Refresh Project Post-Implementation Audit • Contractor Onboarding and Termination Follow-Up Audit • Data Center Audit • Change Management Follow-Up Review • Change of Status Process Review Page 5 of 5 • GlobalScape Audit • Oracle Financial System Configuration Review • Review Configuration of Active Directory 2016 – Completed YTD • Debt Issuance and Reacquisition Costs Review – Regulatory Requirement • Avista Corp. Incentive Plan Review • Local 77 90/10 Healthcare Premium True-Up Review • 2015 Advanced Metering Infrastructure Pro • Active Directory Follow-up Page 1 of 5 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/06/2016 CASE NO: UE-160228 & UG-160229 WITNESS: Mark Thies REQUESTER: Public Counsel RESPONDER: Tracy Van Orden TYPE: Data Request DEPT: Audit REQUEST NO.: PC – 028 TELEPHONE: (509) 495-4942 EMAIL: tracy.vanorden@avistacorp.com REQUEST: Please provide a copy of all management audits conducted for, or by, Avista during the last ten years. In this response, indicate if such management audits were ordered or required by a regulatory commission. RESPONSE: Due to the volume of documentation associated with this request, a list of all management audits conducted over the last ten years has been provided. Individual reports can be made available upon request. 2007 • Productivity Initiative Program • Employee Reimbursements • Transmission Upgrade Projects • Vehicle Inspections • Avista Utilities Price Index Reporting • Colstrip Fuel Supply - Annual • Colstrip Steam Plant Operating and A&G Costs Audit • Avista Incentive Plan Review 2008 • AVA and AIQ 2007 Incentive Plan Reviews • Customer Account Entries (CAEs) • General Contracts Review • Facilities Services • Douglas County Wells Project • Cash Reconciliations • Project Share Audit • Overtime Review • AIQ Mid-Year Incentive Payout Review • Electronic Funds Transfer Review • Avista Utilities’ Web Redesign Review • Mobile Wireless Device Audit • Avista Utilities Price Index Reporting • Colstrip Fuel Supply - Annual Page 2 of 5 2009 • AVA and AIQ 2008 Incentive Plan Reviews • 2008 Price Reporting Audit • Jackson Prairie Expansion Audit • Demand Side Management Audit • Fuel Card Purchase Audit • Colstrip Fuel and Transportation Audit • 2008 Debt Issuance/Reacquisition Cost Audit – Regulatory Requested 2010 • AVA and AIQ 2009 Incentive Plan Reviews • 2009 Electric and Natural Gas Price Reporting Audit • Colstrip 3&4 Coal Supply and Transportation Audit • Employee and Director Expense Audit • NERC Reliability Standards Review • Internal Reliability Compliance Program Audit • PAR Data Access Audit • 2009 Debt Issuance Costs and Debt Reacquisitions Cost Audit – Regulatory Requested 2011 • Coyote Springs Unit 2 Operating Costs and Contract Review Report • Coyote Sprints Unit 2 Storeroom Inventory Review • Colstrip Fuel and Transportation Audit • Colstrip Operations Audit 2009-2010 • Klamath Falls Lateral Purchase Option-Limited Financial Due Diligence • Avista Corp PAC Accounting Review • Project Share Audit Report • 2010 Electric and Natural Gas Reporting Audit • AMI Post-Implementation Review • Kubra SAS70 Review • Q1 Network Device Configuration • 2010 Debt Issuance Costs and Debt Reacquisitions Review – Regulatory Requested • Regulus SAS 70 Review • RED Post-Implementation Review • Accounting Practices Audit - Regulatory Requested • LIRAP Accounting Practices Audit - Regulatory Requested • Changes to Payment Hierarchy • Email Attachment Study • Review of Avista Corp, Avista Utilities and AIQ 2010 Incentive Plans • Card Verification Value Capture Audit • MV-RS Project Post-Implementation Audit • vmWare ESXi 4.1 Server Configuration Audit • PacifiCorp Transmission and Interconnection Agreement Audit 2012 Page 3 of 5 • Accounting Practices Audit – Regulatory Requested • Debt Issuance and Reacquisition Costs Review – Regulatory Requested • LIRAP Accounting Practices Audit – Regulatory Requested • Avista Corp. and Avista Utilities Incentive Plan Review • Ecova Incentive Plan Review • Price Reporting Audit • Expense Report Audit • Back Billing Procedures Audit • Contract Process Review • Ecova Investment Policy Review • Colstrip Fuel Supply and Transportation Audit • Demand Side Management Audit Follow-Up • WUTC U-101169 Investigation Report Follow Up • Oracle Financial System Upgrade Project Audit • Claims Application System Configuration Audit • DMZ Control Audit • Social Media Assessment • Distribution Management System Implementation Review • Remittance Processing System Replacement Project Audit • Ecova Identity Management Review • Smart Grid Thermostat Pilot Program Review 2013 • Debt Issuance and Reacquisition Costs Review – Regulatory Requirement • Voluntary Severance Incentive Plan Audit • Avista Corp. and Avista Utilities Incentive Plan Review • Facilities Invoice Investigation • Accounting Practices Audit - Regulatory Requirement • Greenhouse Gas Inventory Audit • Low-Income Rate Assistance Program Accounting Practices Audit - Regulatory Requirement • Reliability Compliance Program Assessment • Short-term Disability Plan Review • Spokane Warehouse Controls Review • Price Reporting Audit • Colstrip Power Plant Audit • Compass Project – Bonus Plan Review • Demand Side Management Audit Follow-Up • Corporate Governance Review • Colstrip Fuel Supply and Transportation Audit • Contract Review • Grant County PUD Audit • Compass Project – Regulatory Preparedness Review • Contractor Access Security Audit • Mobile Device Management Review • Compass Project – Wave 1 Data Conversion • Compass Project – Wave 1 Pre/Post Implementation Review • Ecova Other Real Estate Owned (REO) Audit Page 4 of 5 • Change Management Review 2014 • Debt Issuance and Reacquisition Costs Review – Regulatory Requirement • Avista Corp. Incentive Plan Review • Wild Rose Review and Demand Side Management Follow-up • Accounting Practices Audit - Regulatory Requirement • LIRAP Accounting Practices Audit - Regulatory Requirement • Avista Corp. Transaction Bonus Plan • Colstrip Fuel Supply and Transportation Audit • Contract Review – NPL Construction Company • Compass Project – Bonus Plan Review Phase IV • Price Reporting Audit • Asphlund Contract Review • Compass Project – Regulatory Preparedness Review • Compass Project – Third Party Integration • Avista Credit Union IT Audit • IT General Computer Controls Audit • Change Management Review Follow-up • Contractor Access Review Follow-Up • Compass Project – Data Conversion 2015 • Debt Issuance and Reacquisition Costs Audit – Regulatory Requirement • Avista Corp. Incentive Plan Review • Compass Project – Bonus Plan Review • Strategic Investment Review • Price Reporting Audit • Compass Project – Regulatory Preparedness Review • Colstrip Fuel Supply and Transportation Audit • Expense Report Audit • AEL&P Incentive Plan Review • Grant County Power Purchase Agreement Audit • Assignment of Direct Labor • Capital Project Review • Colstrip Power Plant Operations Audit • Contract Review – Nine Mile Project • METALfx Review • Avista Corp. Credit Union IT Audit, Follow-Up • Avista Corp. Credit Union Server Refresh Project Pre-Implementation Audit • Compass Project – Pre/Post Implementation Audit • Avista Corp. Credit Union Server Refresh Project Post-Implementation Audit • Contractor Onboarding and Termination Follow-Up Audit • Data Center Audit • Change Management Follow-Up Review • Change of Status Process Review Page 5 of 5 • GlobalScape Audit • Oracle Financial System Configuration Review • Review Configuration of Active Directory 2016 – Completed YTD • Debt Issuance and Reacquisition Costs Review – Regulatory Requirement • Avista Corp. Incentive Plan Review • Local 77 90/10 Healthcare Premium True-Up Review • 2015 Advanced Metering Infrastructure Pro • Active Directory Follow-up Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/14/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: Public Counsel RESPONDER: Annette Brandon TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: PC – 029 TELEPHONE: (509) 495-4324 EMAIL: annette.brandon@avistacorp.com REQUEST: Please provide a history of Avista’s annual SAIDI and SAIFI for each year 2007 through 2015 separated between Washington and each retail jurisdiction RESPONSE: The table below provides historical annual SAIDI and SAFI by jurisdiction for 2007-2015: *Major event dates are excluded from the results. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/14/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: Public Counsel RESPONDER: Annette Brandon TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: PC – 029 TELEPHONE: (509) 495-4324 EMAIL: annette.brandon@avistacorp.com REQUEST: Please provide a history of Avista’s annual SAIDI and SAIFI for each year 2007 through 2015 separated between Washington and each retail jurisdiction RESPONSE: The table below provides historical annual SAIDI and SAFI by jurisdiction for 2007-2015: *Major event dates are excluded from the results. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/09/2016 CASE NO: UE-160228 & UG-160229 WITNESS: Karen Schuh REQUESTER: Public Counsel RESPONDER: Neil Thorson TYPE: Data Request DEPT: Financial Planning & Analysis REQUEST NO.: PC – 030 TELEPHONE: (509) 495-4776 EMAIL: neil.thorson@avistacorp.com REQUEST: For each year 2007 through 2015, please provide the footage and investment in Washington natural gas distribution mains not related to replacements, i.e., extensions and new business. RESPONSE: The following table provides the footage and investment in natural gas distribution mains in Washington, not related to replacements, from 2007 through 2015: Washington Natural Gas Distribution Mains Not Related to Replacements Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/09/2016 CASE NO: UE-160228 & UG-160229 WITNESS: Karen Schuh REQUESTER: Public Counsel RESPONDER: Neil Thorson TYPE: Data Request DEPT: Financial Planning & Analysis REQUEST NO.: PC – 030 TELEPHONE: (509) 495-4776 EMAIL: neil.thorson@avistacorp.com REQUEST: For each year 2007 through 2015, please provide the footage and investment in Washington natural gas distribution mains not related to replacements, i.e., extensions and new business. RESPONSE: The following table provides the footage and investment in natural gas distribution mains in Washington, not related to replacements, from 2007 through 2015: Washington Natural Gas Distribution Mains Not Related to Replacements Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/09/2016 CASE NO: UE-160228 & UG-160229 WITNESS: Karen Schuh REQUESTER: Public Counsel RESPONDER: Neil Thorson TYPE: Data Request DEPT: Financial Planning & Analysis REQUEST NO.: PC – 031 TELEPHONE: (509) 495-4776 EMAIL: neil.thorson@avistacorp.com REQUEST: For each year 2007 through 2015, please provide the footage and investment in Washington natural gas distribution mains related to replacements. RESPONSE: The following table provides the footage and investment in natural gas distribution mains in Washington, related to replacements, from 2007 through 2015: Washington Natural Gas Distribution Mains Related to Replacements Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/09/2016 CASE NO: UE-160228 & UG-160229 WITNESS: Karen Schuh REQUESTER: Public Counsel RESPONDER: Neil Thorson TYPE: Data Request DEPT: Financial Planning & Analysis REQUEST NO.: PC – 031 TELEPHONE: (509) 495-4776 EMAIL: neil.thorson@avistacorp.com REQUEST: For each year 2007 through 2015, please provide the footage and investment in Washington natural gas distribution mains related to replacements. RESPONSE: The following table provides the footage and investment in natural gas distribution mains in Washington, related to replacements, from 2007 through 2015: Washington Natural Gas Distribution Mains Related to Replacements Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 04/04/2016 CASE NO: UE-160228 & UG-160229 WITNESS: Elizabeth Andrews REQUESTER: UTC Staff - Huang RESPONDER: Paul Kimball TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff – 001 TELEPHONE: (509) 495-4584 EMAIL: paul.kimball@avistacorp.com REQUEST: Please provide copies of any and all data requests submitted to you by any party to this proceeding and your corresponding responses to those data requests. This is a continuing request. RESPONSE: Avista has provided and will continue to provide copies of data requests, along with corresponding data responses, from all parties to this proceeding as they are completed. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 04/04/2016 CASE NO: UE-160228 & UG-160229 WITNESS: Elizabeth Andrews REQUESTER: UTC Staff - Huang RESPONDER: Paul Kimball TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff – 001 TELEPHONE: (509) 495-4584 EMAIL: paul.kimball@avistacorp.com REQUEST: Please provide copies of any and all data requests submitted to you by any party to this proceeding and your corresponding responses to those data requests. This is a continuing request. RESPONSE: Avista has provided and will continue to provide copies of data requests, along with corresponding data responses, from all parties to this proceeding as they are completed. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 04/01/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: UTC Staff - Huang RESPONDER: Jeanne Pluth TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff - 002 TELEPHONE: (509) 495-2204 EMAIL: jeanne.pluth@avistacorp.com REQUEST: Please provide a columnar, 12-month detailed (by sub-account) income statement in Excel format for Avista’s electric operations for the test period, with the 13th column showing the total for the test year for each sub-account; the 14th column showing the budgeted amount for each sub-account for the test year; the 15th column showing the variance amount; and the 16th column showing the variance percentage. For each primary FERC account provide a columnar total. RESPONSE: See the attached worksheet (Staff_DR_002-Attachment A) for the income statement for the twelve months ended September 30, 2015 for Avista Utilities’ electric operations. The Company does not budget at the detailed FERC account level. Budgeted costs have been entered on the first FERC Account line of each functional expense level. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 04/01/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: UTC Staff - Huang RESPONDER: Jeanne Pluth TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff - 002 TELEPHONE: (509) 495-2204 EMAIL: jeanne.pluth@avistacorp.com REQUEST: Please provide a columnar, 12-month detailed (by sub-account) income statement in Excel format for Avista’s electric operations for the test period, with the 13th column showing the total for the test year for each sub-account; the 14th column showing the budgeted amount for each sub-account for the test year; the 15th column showing the variance amount; and the 16th column showing the variance percentage. For each primary FERC account provide a columnar total. RESPONSE: See the attached worksheet (Staff_DR_002-Attachment A) for the income statement for the twelve months ended September 30, 2015 for Avista Utilities’ electric operations. The Company does not budget at the detailed FERC account level. Budgeted costs have been entered on the first FERC Account line of each functional expense level. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 04/01/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: UTC Staff - Huang RESPONDER: Jeanne Pluth TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff - 003 TELEPHONE: (509) 495-2204 EMAIL: jeanne.pluth@avistacorp.com REQUEST: Please provide a columnar, 12-month detailed (by sub-account) income statement in Excel format for Avista’s natural gas operations for the test period, with the 13th column showing the total for the test year for each sub-account; the 14th column showing the budgeted amount for each sub-account for the test year; the 15th column showing the variance amount; and the 16th column showing the variance percentage. For each primary FERC account, provide a columnar total. RESPONSE: See the attached worksheet (Staff_DR_003-Attachment A) for the income statement for the twelve months ended September 30, 2015 for Avista Utilities’ natural gas operations. The Company does not budget at the detailed FERC account level. Budgeted costs have been entered on the first FERC Account line of each functional expense level. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 04/01/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: UTC Staff - Huang RESPONDER: Jeanne Pluth TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff - 003 TELEPHONE: (509) 495-2204 EMAIL: jeanne.pluth@avistacorp.com REQUEST: Please provide a columnar, 12-month detailed (by sub-account) income statement in Excel format for Avista’s natural gas operations for the test period, with the 13th column showing the total for the test year for each sub-account; the 14th column showing the budgeted amount for each sub-account for the test year; the 15th column showing the variance amount; and the 16th column showing the variance percentage. For each primary FERC account, provide a columnar total. RESPONSE: See the attached worksheet (Staff_DR_003-Attachment A) for the income statement for the twelve months ended September 30, 2015 for Avista Utilities’ natural gas operations. The Company does not budget at the detailed FERC account level. Budgeted costs have been entered on the first FERC Account line of each functional expense level. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 04/01/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: UTC Staff - Huang RESPONDER: Jeanne Pluth TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff - 004 TELEPHONE: (509) 495-2204 EMAIL: jeanne.pluth@avistacorp.com REQUEST: Please provide a columnar, 13-month detailed (by sub-account) balance sheet in Excel format for Avista for the test period, with the 14th column showing the average of monthly averages (AMA) for each sub- account, with a columnar total for each primary FERC account. The 15th column should show the AMA balance from the prior calendar year; the 16th column should show the change amount; and the 17th column should show the percentage change from the prior calendar year. RESPONSE: Please see Staff_DR_004-Attachment A for the general ledger for balance sheet accounts for each month between September 30, 2014 and September 30, 2015, including the AMA amount and the AMA amount for the period ended September 30, 2014. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 04/01/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: UTC Staff - Huang RESPONDER: Jeanne Pluth TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff - 004 TELEPHONE: (509) 495-2204 EMAIL: jeanne.pluth@avistacorp.com REQUEST: Please provide a columnar, 13-month detailed (by sub-account) balance sheet in Excel format for Avista for the test period, with the 14th column showing the average of monthly averages (AMA) for each sub- account, with a columnar total for each primary FERC account. The 15th column should show the AMA balance from the prior calendar year; the 16th column should show the change amount; and the 17th column should show the percentage change from the prior calendar year. RESPONSE: Please see Staff_DR_004-Attachment A for the general ledger for balance sheet accounts for each month between September 30, 2014 and September 30, 2015, including the AMA amount and the AMA amount for the period ended September 30, 2014. Avista Corporation Doing Business as Avista Utilities (1) , . , Avista Capital Affiliate Companies See Attached Chart Alaska Energy & Resources Company (AERC) (2) Alaska Electric Light & Power Co. (AEL&P)AJT Mining Properties, Inc. Revised July 1, 2014 ompan es are w o y owne un ess ot erw se n cate . Effective July 1, 2014, Ecova, Inc. was sold. (1) Avista Utilities is a Business Unit, and not a separate Company (2) Effective July 1, 2014, Avista acquired AERC Staff_DR_005 Attachment A Page 1 of 2 Avista Capital, Inc. Avista Energy, Inc.Salix, Inc. Pentzer Corporation Avista Northwest Resources, LLC Avista Development, Inc.Bay Area Manufacturing, Inc. Pentzer Venture Holdings II, Inc. Courtyard Office Center, LLC Advanced Manufacturing & Steam Plant Square LLC 85% Ownership Development, Inc. (DBA MetalFx) 89.20% Ownership Steam Plant Brew Pub LLC (DBA Steam Plant Grill) Revised 12/1/2014 Companies are wholly owned unless otherwise indicated. Staff_DR_005 Attachment A Page 2 of 2 Corporate Secretary Department Current as of December 1, 2015 Annual Meeting Held in May of Each Year Directors: Erik J. Anderson Scott L. Morris Kristianne Blake Marc F. Racicot Donald C. Burke Heidi B. Stanley John F. Kelly R. John Taylor Rebecca (Becky) A. Klein Janet D. Widmann Officers: Corporate Governance/ Nominating Committee Executive Committee Audit Committee Marc F. Racicot R. John Taylor John F. Kelly – Chair John F. Kelly R. John Taylor Scott L. Morris – Chair Heidi B. Stanley Kristianne Blake – Chair Compensation & Organization Committee Finance Committee Environmental, Technology & Operations Committee All Committees are comprised of independent Board members as defined under the rules of the NYSE, with the exception of the Executive Committee (not required to be independent). The Company was formed as The Washington Water Power Company in 1889 and changed its name to Avista Corp. on January 1, 1999. Staff_DR_005 Attachment B Page 1 of 17 Current as of October 1, 2015 ADVANCED MANUFACTURING & DEVELOPMENT, INC. Doing business as METALfx (A Subsidiary of Bay Area Manufacturing, Inc.) (A California Corporation) 200 North Lenore Ave. Willits, CA 95490 Directors: Marian M. Durkin Scott L. Morris Mark T. Thies Officers: Scott L. Morris Chairman of the Board Gordon B. Short President & Chief Executive Officer Ryan L. Krasselt Vice President & Treasurer Mark T. Thies Senior Vice President & Chief Financial Officer Karen S. Feltes Senior Vice President & Corporate Secretary Susan Y. Fleming Assistant Corporate Secretary Jill Porterfield Assistant Corporate Secretary Staff_DR_005 Attachment B Page 2 of 17 Current as of October 23, 2015 AJT MINING PROPERTIES, INC. Directors: Marian M. Durkin Karen S. Feltes Mark T. Thies Dennis P. Vermillion Officers: Dennis P. Vermillion Chairman of the Board Bruce Howard President Connie Hulbert Treasurer and Assistant Corporate Secretary Christy Yearous Vice President and Generation Engineer Debbie Driscoll Corporate Secretary Staff_DR_005 Attachment B Page 3 of 17 Current as of October 23, 2015 ALASKA ELECTRIC LIGHT AND POWER COMPANY Directors: Marian M. Durkin Karen S. Feltes Timothy McLeod Mark T. Thies Dennis P. Vermillion Officers: Dennis P. Vermillion Chairman of the Board Timothy McLeod President Connie Hulbert Vice President, Treasurer & Corporate Secretary Christy Yearous Vice President and Generation Engineer Debbie Driscoll Vice President, Director of Consumer Affairs and Assistant Corporate Secretary Eric Eriksen Vice President, Transmission and Distribution Engineer Rod Ahlbrandt Vice President, Director of Information Technology and Revenue Metering Alec Mesdag Vice President, Director of Energy Services Catherine Johnson Assistant Treasurer and Controller Bryan Farrell Assistant Treasurer and Assistant Generation Engineer Mechanical/Electrical Darrell Wetherall Assistant Corporate Secretary and Assistant Transmission and Distribution Engineer Staff_DR_005 Attachment B Page 4 of 17 Current as of May 8, 2015 ALASKA ENERGY AND RESOURCES COMPANY Directors: Marian M. Durkin Karen S. Feltes Scott L. Morris Mark T. Thies Dennis P. Vermillion Officers: Scott L. Morris Chairman of the Board Dennis P. Vermillion President Timothy McLeod Vice President Connie Hulbert Treasurer Karen S. Feltes Corporate Secretary Susan Y. Fleming Assistant Corporate Secretary Debbie Driscoll Assistant Corporate Secretary Staff_DR_005 Attachment B Page 5 of 17 Current as of October 1, 2015 AVISTA CAPITAL, INC. Spokane, WA 99202 Directors: Marian M. Durkin Scott L. Morris Mark T. Thies Officers: Scott L. Morris Chairman of the Board, President & CEO Mark T. Thies Senior Vice President, Chief Financial Officer & Treasurer Karen S. Feltes Senior Vice President & Corporate Secretary Ryan L. Krasselt Vice President Susan Y. Fleming Assistant Corporate Secretary Don M. Falkner Assistant Treasurer The Company was formed as Avista Corp. before changing its name to Avista Capital on August 17, 1998. Staff_DR_005 Attachment B Page 6 of 17 Current as of November 1, 2015 AVISTA DEVELOPMENT, INC. (A Subsidiary of Avista Capital, Inc.) Spokane, WA 99202 Directors: Marian M. Durkin Scott L. Morris Mark T. Thies Officers: Scott L. Morris Chairman of the Board and CEO Roger D. Woodworth President Mark T. Thies Senior Vice President, Chief Financial Officer & Treasurer Marian M. Durkin Senior Vice President Dennis P. Vermillion Senior Vice President & Environmental Compliance Officer Karen S. Feltes Senior Vice President & Corporate Secretary Susan Y. Fleming Assistant Corporate Secretary Don M. Falkner Assistant Treasurer The Company was formed as WP Finance Co. before changing its name to Avista Development. Pentzer Development, Inc. and Washington Irrigation & Development Company merged with and into Avista Development in October 1998. Staff_DR_005 Attachment B Page 7 of 17 Current as of May 8, 2015 AVISTA ENERGY, INC. (A Subsidiary of Avista Capital, Inc.) 1411 E. Mission Ave. Spokane WA 99202 Directors: Marian M. Durkin Scott L. Morris Mark T. Thies Officers: Scott L. Morris Chairman of the Board, President & CEO Mark T. Thies Senior Vice President, Chief Financial Officer & Treasurer Karen S. Feltes Senior Vice President & Corporate Secretary Tracy Van Orden Controller Susan Y. Fleming Assistant Corporate Secretary Don M. Falkner Assistant Treasurer The Company was formed as WWP Resource Services, Inc., before becoming Avista Energy. Staff_DR_005 Attachment B Page 8 of 17 Current as of October 1, 2015 AVISTA NORTHWEST RESOURCES, LLC (An Affiliate of Avista Capital) Spokane, WA 99202 Member: Avista Capital Officers (Managers): Scott L. Morris President & Chief Executive Officer Mark T. Thies Senior Vice President & Chief Financial Officer Ryan L. Krasselt Vice President & Treasurer Karen S. Feltes Senior Vice President & Corporate Secretary Susan Y. Fleming Assistant Corporate Secretary Most of our LLC’s do not have officers. This particular one was formed with officers as the managers. Staff_DR_005 Attachment B Page 9 of 17 Current as of May 8, 2015 BAY AREA MANUFACTURING, INC. Spokane, WA 99202 Directors: Marian M. Durkin Scott L. Morris Mark T. Thies Officers: Scott L. Morris Chairman, President & Chief Executive Officer Mark T. Thies Senior Vice President, Chief Financial Officer & Treasurer Karen S. Feltes Senior Vice President & Corporate Secretary Susan Y. Fleming Assistant Corporate Secretary Don M. Falkner Assistant Treasurer Staff_DR_005 Attachment B Page 10 of 17 Current as of March 31, 2009 COURTYARD OFFICE CENTER, LLC (An Affiliate of Avista Capital, Inc.) Spokane, WA 99202 Member: Avista Development, Inc. Manager Roger Woodworth Staff_DR_005 Attachment B Page 11 of 17 Current as of May 8, 2015 PENTZER CORPORATION (A Subsidiary of Avista Capital, Inc.) Spokane, WA 99202 Directors: Scott L. Morris Mark T. Thies Jason Thackston Officers: Scott L. Morris Chairman, President & Chief Executive Officer Mark T. Thies Senior Vice President, Chief Financial Officer & Treasurer Karen S. Feltes Senior Vice President & Corporate Secretary Susan Y. Fleming Assistant Corporate Secretary Don M. Falkner Assistant Treasurer Staff_DR_005 Attachment B Page 12 of 17 Current as of May 8, 2015 PENTZER VENTURE HOLDINGS II (A Subsidiary of Pentzer Corporation) Spokane, WA 99202 Directors: Scott L. Morris Mark T. Thies Jason R. Thackston Officers: Scott L. Morris Chairman, President & Chief Executive Officer Mark T. Thies Senior Vice President, Chief Financial Officer & Treasurer Karen S. Feltes Senior Vice President & Corporate Secretary Susan Y. Fleming Assistant Corporate Secretary Don M. Falkner Assistant Treasurer Staff_DR_005 Attachment B Page 13 of 17 Current as of May 8, 2015 SALIX, INC. (A Subsidiary of Avista Capital) Spokane, WA 99202 Directors: Marian M. Durkin Scott L. Morris Mark T. Thies Dennis P. Vermillion Roger D. Woodworth Officers: Robert J. Lafferty President Mark T. Thies Treasurer Karen S. Feltes Corporate Secretary Susan Y. Fleming Assistant Corporate Secretary Staff_DR_005 Attachment B Page 14 of 17 Current as of October 23, 2015 SNETTISHAM ELECTRIC COMPANY Directors: Eric Eriksen Timothy McLeod Jason Thackston Officers: Christy Yearous President Timothy McLeod Vice President Eric Eriksen Treasurer Debbie Driscoll Corporate Secretary Connie Hulbert Assistant Corporate Secretary Staff_DR_005 Attachment B Page 15 of 17 Current as of December 31, 2010 STEAM PLANT BREW PUB, LLC Doing Business as Steam Plant Grill (An Affiliate of Steam Plant Square, LLC) Spokane, WA 99202 Members: Avista Development, Inc. Wells & Co. Manager Roger Woodworth Staff_DR_005 Attachment B Page 16 of 17 Current as of December 31, 2010 STEAM PLANT SQUARE, LLC (An Affiliate of Avista Capital, Inc.) Spokane, WA 99202 Members: Avista Development, Inc. Wells & Co. Manager Roger Woodworth Staff_DR_005 Attachment B Page 17 of 17 Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 04/04/2016 CASE NO: UE-160228 & UG-160229 WITNESS: Mark Thies REQUESTER: UTC Staff - Huang RESPONDER: Paul Kimball TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff – 005 TELEPHONE: (509) 495-4584 EMAIL: paul.kimball@avistacorp.com REQUEST: Please provide a current corporate organization chart for Avista that shows each of its subsidiaries. Provide the names of the directors of each subsidiary. RESPONSE: Please see Staff_DR_005 Attachment A for an organizational chart of Avista and Staff_DR_005 Attachment B for the names of the directors. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 04/04/2016 CASE NO: UE-160228 & UG-160229 WITNESS: Mark Thies REQUESTER: UTC Staff - Huang RESPONDER: Paul Kimball TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff – 005 TELEPHONE: (509) 495-4584 EMAIL: paul.kimball@avistacorp.com REQUEST: Please provide a current corporate organization chart for Avista that shows each of its subsidiaries. Provide the names of the directors of each subsidiary. RESPONSE: Please see Staff_DR_005 Attachment A for an organizational chart of Avista and Staff_DR_005 Attachment B for the names of the directors. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 03/25/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: UTC Staff - Huang RESPONDER: Ryan Finesilver TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff - 006 TELEPHONE: (509) 495-4873 EMAIL: Ryan.finesilver@avistacorp.com REQUEST: Please provide a listing of all penalties and fines included in the test year, citing the account it is located in, the payee, and the amount. RESPONSE: Please see Staff_DR_006 Attachment A for a listing of penalties in the test year. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 03/25/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: UTC Staff - Huang RESPONDER: Ryan Finesilver TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff - 006 TELEPHONE: (509) 495-4873 EMAIL: Ryan.finesilver@avistacorp.com REQUEST: Please provide a listing of all penalties and fines included in the test year, citing the account it is located in, the payee, and the amount. RESPONSE: Please see Staff_DR_006 Attachment A for a listing of penalties in the test year. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 03/25/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: UTC Staff - Huang RESPONDER: Ryan Finesilver TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff - 007 TELEPHONE: (509) 495-4873 EMAIL: Ryan.finesilver@avistacorp.com REQUEST: Please provide a listing of any costs included in the test year related to sporting or entertainment events, including but not limited to season tickets or sky boxes. If applicable, please include any explanation as to the business purpose. RESPONSE: As per the Company’s Regulatory Accounting Guidelines, charges for employee entertainment or attendance at sporting events are to be charged to non-utility accounts. Please see Staff_DR_007 Attachment A for a listing of costs related to sporting and entertainment events that were charged to utility operations in error. These costs were removed in Adjustment 2.12 Miscellaneous Restating and were not part of the Company’s revenue requirement determination. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 03/25/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: UTC Staff - Huang RESPONDER: Ryan Finesilver TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff - 007 TELEPHONE: (509) 495-4873 EMAIL: Ryan.finesilver@avistacorp.com REQUEST: Please provide a listing of any costs included in the test year related to sporting or entertainment events, including but not limited to season tickets or sky boxes. If applicable, please include any explanation as to the business purpose. RESPONSE: As per the Company’s Regulatory Accounting Guidelines, charges for employee entertainment or attendance at sporting events are to be charged to non-utility accounts. Please see Staff_DR_007 Attachment A for a listing of costs related to sporting and entertainment events that were charged to utility operations in error. These costs were removed in Adjustment 2.12 Miscellaneous Restating and were not part of the Company’s revenue requirement determination. 25 Charitable Contributions, Donations and Sponsorships Charitable Contributions and Corporate Donations Corporate contributions provide financial support to organizations and activities benefiting the various communities served by the Company, while supporting business initiatives and fostering relationships with key stakeholders. The costs for these activities are charged “Below the Line”. In order to accurately report the types of contributions made, project numbers have been established for each contribution category, and contributions should be charged to one of the POET (Project, Organization, Expenditure Type, and Task) codes noted below. Project Organization Expenditure Type Task 77700300 825 - Donations 426110 - Dues/Donations - Gen 77700300 825 - Donations 426115 - Art/Cult/Hum 77700300 825 - Donations 426120 - Econ/Comm Devlp 77700300 825 - Donations 426121 - Avista Foundation 77700300 825 - Donations 426122 - Project Share 77700300 825 - Donations 426125 - Education 77700300 825 - Donations 426130 - Environment 77700300 825 - Donations 426135 - Youth Development 77700300 825 - Donations 426140 - Human Services 77700300 825 - Donations 426400 - Political Expend Staff_DR_008 Attachment A Regulatory Accounting Guidelines and Policies Manual Page 1 of 1 Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 03/25/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: UTC Staff - Huang RESPONDER: Ryan Finesilver TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff - 008 TELEPHONE: (509) 495-4873 EMAIL: Ryan.finesilver@avistacorp.com REQUEST: Please provide a listing of all charitable contributions, including names and amounts, included in the test year. RESPONSE: As per the Company’s Regulatory Guidelines, corporate contributions to charities are to be charged to non- utility accounts. Please see Staff_DR_008 Attachment A for a listing of the applicable Project/Task numbers for charitable contributions. No charitable contributions were included in the test year’s revenue requirement calculation. Please see Adjustment 2.12 Miscellaneous Restating for donation items that were included in utility expenses in error. These items were removed from utility operations and were not part of the Company’s revenue requirement determination. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 03/25/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: UTC Staff - Huang RESPONDER: Ryan Finesilver TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff - 008 TELEPHONE: (509) 495-4873 EMAIL: Ryan.finesilver@avistacorp.com REQUEST: Please provide a listing of all charitable contributions, including names and amounts, included in the test year. RESPONSE: As per the Company’s Regulatory Guidelines, corporate contributions to charities are to be charged to non- utility accounts. Please see Staff_DR_008 Attachment A for a listing of the applicable Project/Task numbers for charitable contributions. No charitable contributions were included in the test year’s revenue requirement calculation. Please see Adjustment 2.12 Miscellaneous Restating for donation items that were included in utility expenses in error. These items were removed from utility operations and were not part of the Company’s revenue requirement determination. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 03/25/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: UTC Staff - Huang RESPONDER: Ryan Finesilver TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff - 009 TELEPHONE: (509) 495-4873 EMAIL: Ryan.finesilver@avistacorp.com REQUEST: Please provide a listing of dues or membership fees included in the test year, and please include in the response the percent of dues or fees related to lobbying or political activities. RESPONSE: Please see Staff_DR_009 Attachment A for the requested listing of dues and membership fees (system) included in the test year. As per the Company’s Regulatory Accounting Guidelines, expenses related to lobbying are charged to non-utility as required per WAC 480-90-213/480-100-213. Therefore the percent of dues/fees related to lobbying or political activities included in the test year is 0%. Expenses related to Chamber of Commerce memberships are split 50/50% between utility and non-utility operations. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 03/25/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: UTC Staff - Huang RESPONDER: Ryan Finesilver TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff - 009 TELEPHONE: (509) 495-4873 EMAIL: Ryan.finesilver@avistacorp.com REQUEST: Please provide a listing of dues or membership fees included in the test year, and please include in the response the percent of dues or fees related to lobbying or political activities. RESPONSE: Please see Staff_DR_009 Attachment A for the requested listing of dues and membership fees (system) included in the test year. As per the Company’s Regulatory Accounting Guidelines, expenses related to lobbying are charged to non-utility as required per WAC 480-90-213/480-100-213. Therefore the percent of dues/fees related to lobbying or political activities included in the test year is 0%. Expenses related to Chamber of Commerce memberships are split 50/50% between utility and non-utility operations. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 04/01/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: UTC Staff - Huang RESPONDER: Jeanne Pluth TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff - 010 TELEPHONE: (509) 495-2204 EMAIL: jeanne.pluth@avistacorp.com REQUEST: Please provide a copy of the corporate federal tax returns and supporting “M” schedules for 2012, 2013, and 2014. RESPONSE: Please see the attached files for the Company’s corporate federal tax returns filed for 2012, 2013, and 2014 tax years. • Staff_DR_010 Attachment A - 2012 Tax Return and supporting Schedule “M”(filed in 2013) • Staff_DR_010 Attachment B - 2013 Tax Return and supporting Schedule “M”(filed in 2014) • Staff_DR_010 Attachment C - 2014 Tax Return and supporting Schedule “M”(filed in 2015) Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 04/01/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: UTC Staff - Huang RESPONDER: Jeanne Pluth TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff - 010 TELEPHONE: (509) 495-2204 EMAIL: jeanne.pluth@avistacorp.com REQUEST: Please provide a copy of the corporate federal tax returns and supporting “M” schedules for 2012, 2013, and 2014. RESPONSE: Please see the attached files for the Company’s corporate federal tax returns filed for 2012, 2013, and 2014 tax years. • Staff_DR_010 Attachment A - 2012 Tax Return and supporting Schedule “M”(filed in 2013) • Staff_DR_010 Attachment B - 2013 Tax Return and supporting Schedule “M”(filed in 2014) • Staff_DR_010 Attachment C - 2014 Tax Return and supporting Schedule “M”(filed in 2015) Staff_DR_010-Attachment A - 2012 Page 1 of 9 Staff_DR_010-Attachment A - 2012 Page 2 of 9 Staff_DR_010-Attachment A - 2012 Page 3 of 9 Staff_DR_010-Attachment A - 2012 Page 4 of 9 Staff_DR_010-Attachment A - 2012 Page 5 of 9 Staff_DR_010-Attachment A - 2012 Page 6 of 9 Staff_DR_010-Attachment A - 2012 Page 7 of 9 Staff_DR_010-Attachment A - 2012 Page 8 of 9 Staff_DR_010-Attachment A - 2012 Page 9 of 9 Staff_DR_010-Attachment B - 2013 Page 1 of 12 Staff_DR_010-Attachment B - 2013 Page 2 of 12 Staff_DR_010-Attachment B - 2013 Page 3 of 12 Staff_DR_010-Attachment B - 2013 Page 4 of 12 Staff_DR_010-Attachment B - 2013 Page 5 of 12 Staff_DR_010-Attachment B - 2013 Page 6 of 12 Staff_DR_010-Attachment B - 2013 Page 7 of 12 Staff_DR_010-Attachment B - 2013 Page 8 of 12 Staff_DR_010-Attachment B - 2013 Page 9 of 12 Staff_DR_010-Attachment B - 2013 Page 10 of 12 Staff_DR_010-Attachment B - 2013 Page 11 of 12 Staff_DR_010-Attachment B - 2013 Page 12 of 12 Staff_DR_010-Attachment C - 2014 Page 1 of 11 Staff_DR_010-Attachment C - 2014 Page 2 of 11 Staff_DR_010-Attachment C - 2014 Page 3 of 11 Staff_DR_010-Attachment C - 2014 Page 4 of 11 Staff_DR_010-Attachment C - 2014 Page 5 of 11 Staff_DR_010-Attachment C - 2014 Page 6 of 11 Staff_DR_010-Attachment C - 2014 Page 7 of 11 Staff_DR_010-Attachment C - 2014 Page 8 of 11 Staff_DR_010-Attachment C - 2014 Page 9 of 11 Staff_DR_010-Attachment C - 2014 Page 10 of 11 Staff_DR_010-Attachment C - 2014 Page 11 of 11 Page 1 of 3 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 03/31/2016 CASE NO: UE-160228 & UG-160229 WITNESS: Mark Thies REQUESTER: UTC Staff - Huang RESPONDER: Ian McLelland TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff - 011 TELEPHONE: (509) 495-4868 EMAIL: ian.mclelland@avistacorp.com REQUEST: Please explain any changes in accounting for GAAP or FERC for the years 2013, 2014, and 2015. Include a copy of any narrative incorporated in the Company’s notes to its financial statements and or FERC annual reports contemporaneous with the change in accounting. RESPONSE: 2013 – GAAP Only In February 2013, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2013-02, “Comprehensive Income (Topic 220): Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income.” This ASU does not change current requirements for reporting net income or other comprehensive income in financial statements; however, it requires entities to disclose the effect on the line items of net income for reclassifications out of accumulated other comprehensive income if the item being reclassified is required to be reclassified in its entirety to net income under U.S. GAAP. For other items that are not required to be reclassified in their entirety to net income under U.S. GAAP, an entity is required to cross-reference other disclosures required under U.S. GAAP to provide additional detail about those items. The Company adopted this ASU effective January 1, 2013. The adoption of this ASU required additional disclosures in the Company's financial statements; however, it did not have any impact on the Company's financial condition, results of operations and cash flows. 2013 – GAAP and FERC In December 2011, the FASB issued ASU No. 2011-11, “Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities.” This ASU enhances disclosure requirements about the nature of an entity's right to offset and related arrangements associated with its financial instruments and derivative instruments. ASU No. 2011-11 requires the disclosure of the gross amounts subject to rights of set off, amounts offset in accordance with the accounting standards followed, and the related net exposure. The Company adopted this ASU effective January 1, 2013. The adoption of this ASU required additional disclosures in the Company's Page 2 of 3 financial statements; however, it did not have any impact on the Company's financial condition, results of operations and cash flows. In January 2013, the FASB issued ASU No. 2013-01, “Balance Sheet (Topic 210): Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities.” This ASU clarifies which instruments and transactions are subject to the enhanced disclosure requirements of ASU 2011- 11 regarding the offsetting of financial assets and liabilities. ASU No. 2013-01 limits the scope of ASU No. 2011-11 to only recognized derivative instruments, repurchase agreements and reverse repurchase agreements, and borrowing and lending securities transactions that are offset in accordance with either Accounting Standards Codification (ASC) 210-20-45 or ASC 815-10- 45. The Company adopted this ASU effective January 1, 2013. The adoption of this ASU did not have any impact on the Company's financial condition, results of operations and cash flows. 2014 – GAAP and FERC No new accounting standards were adopted during this year. 2015 – GAAP only In April 2015, the FASB issued ASU No. 2015-03, "Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs." This ASU amends the presentation of debt issuance costs in the financial statements such that an entity presents such costs in the balance sheet as a direct deduction from the related debt liability rather than as a deferred asset. Amortization of the costs will continue to be reported as interest expense. ASU No. 2015-03 is effective for periods beginning on or after December 15, 2015; however, early adoption is permitted. Upon adoption, entities will apply the new guidance retrospectively to all comparable prior periods presented in the financial statements. The Company evaluated this standard and determined that it will early adopt this standard as of December 31, 2015. As such, the Company revised its presentation of debt issuance costs for long-term debt in the Consolidated Balance Sheets for both periods presented. This resulted in a decrease to Other Deferred Charges and a decrease to Long-Term Debt and Capital Leases of $11.4 million as of December 31, 2014. There was no other impact on the Company's financial statements or results of operations. ASU No. 2015-03 did not address the presentation of debt issuance costs associated with line of credit arrangements. Accordingly, in August 2015, the FASB issued ASU No. 2015-15, "Interest - Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements." This ASU incorporates guidance from the Securities and Exchange Commission which states that it would not object to an entity deferring and presenting debt issuance costs as an asset and subsequently amortizing the deferred debt issuance costs ratably over the term of the line of credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. This ASU was effective upon issuance. The presentation outlined in ASU No. 2015-15 is consistent with the Company's historical presentation of line of credit issuance costs; therefore, there is no impact on the Company's financial statements as a result of adopting this accounting standard in 2015. Page 3 of 3 In November 2015, the FASB issued ASU 2015-17 “Income Taxes (Topic 740) - Balance Sheet Classification of Deferred Taxes,” which requires entities to present DTAs and DTLs as noncurrent in a classified balance sheet. The ASU simplifies the current guidance, which requires entities to separately present DTAs and DTLs as current and noncurrent in a classified balance sheet. This ASU is effective for annual periods beginning after December 15, 2016, and interim periods within those years and early adoption is permitted. In addition, upon adoption, entities are permitted to apply the amendments either prospectively or retrospectively. The Company has evaluated this standard and determined that it will early adopt this standard as of December 31, 2015 and it will apply this ASU on a prospective basis. As such, the Consolidated Balance Sheet as of December 31, 2014 was not adjusted to reflect the new ASU. The Company early adopted this ASU to ease the burden of preparing its financial statements and eliminate the need to evaluate deferred taxes for current and noncurrent presentation. 2015 – GAAP and FERC In May 2015, the FASB issued ASU No. 2015-07, "Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent)." This ASU removes, from the fair value hierarchy, investments for which the practical expedient is used to measure fair value at net asset value (NAV). Instead, an entity is required to include those investments as a reconciling line item so that the total fair value amount of investments in the disclosure is consistent with the amount on the balance sheet. Further, entities must provide certain disclosures for investments for which they elect to use the NAV practical expedient to determine fair value. This ASU is effective for periods beginning on or after December 15, 2015 and early adoption is permitted. The Company evaluated this standard and determined that it will early adopt this standard as of December 31, 2015. As required, this ASU is being applied retrospectively to all periods presented. The adoption of this standard did not affect the Company's future financial condition, results of operations and cash flows; however, it did affect the Company's disclosures. In prior years, the Company held investments related to its pension and other postretirement benefit plans that were fair valued using NAV and these amounts were included as level 3 items in the fair value hierarchy. This ASU was adopted retrospectively; therefore, the 2014 amounts have been reclassified to conform to the 2015 presentation. Also, since these amounts are no longer included in the fair value hierarchy as level 3 items, the level 3 reconciliations are no longer applicable and have been excluded from the pension and other postretirement benefits footnote. Page 1 of 3 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 03/31/2016 CASE NO: UE-160228 & UG-160229 WITNESS: Mark Thies REQUESTER: UTC Staff - Huang RESPONDER: Ian McLelland TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff - 011 TELEPHONE: (509) 495-4868 EMAIL: ian.mclelland@avistacorp.com REQUEST: Please explain any changes in accounting for GAAP or FERC for the years 2013, 2014, and 2015. Include a copy of any narrative incorporated in the Company’s notes to its financial statements and or FERC annual reports contemporaneous with the change in accounting. RESPONSE: 2013 – GAAP Only In February 2013, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2013-02, “Comprehensive Income (Topic 220): Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income.” This ASU does not change current requirements for reporting net income or other comprehensive income in financial statements; however, it requires entities to disclose the effect on the line items of net income for reclassifications out of accumulated other comprehensive income if the item being reclassified is required to be reclassified in its entirety to net income under U.S. GAAP. For other items that are not required to be reclassified in their entirety to net income under U.S. GAAP, an entity is required to cross-reference other disclosures required under U.S. GAAP to provide additional detail about those items. The Company adopted this ASU effective January 1, 2013. The adoption of this ASU required additional disclosures in the Company's financial statements; however, it did not have any impact on the Company's financial condition, results of operations and cash flows. 2013 – GAAP and FERC In December 2011, the FASB issued ASU No. 2011-11, “Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities.” This ASU enhances disclosure requirements about the nature of an entity's right to offset and related arrangements associated with its financial instruments and derivative instruments. ASU No. 2011-11 requires the disclosure of the gross amounts subject to rights of set off, amounts offset in accordance with the accounting standards followed, and the related net exposure. The Company adopted this ASU effective January 1, 2013. The adoption of this ASU required additional disclosures in the Company's Page 2 of 3 financial statements; however, it did not have any impact on the Company's financial condition, results of operations and cash flows. In January 2013, the FASB issued ASU No. 2013-01, “Balance Sheet (Topic 210): Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities.” This ASU clarifies which instruments and transactions are subject to the enhanced disclosure requirements of ASU 2011- 11 regarding the offsetting of financial assets and liabilities. ASU No. 2013-01 limits the scope of ASU No. 2011-11 to only recognized derivative instruments, repurchase agreements and reverse repurchase agreements, and borrowing and lending securities transactions that are offset in accordance with either Accounting Standards Codification (ASC) 210-20-45 or ASC 815-10- 45. The Company adopted this ASU effective January 1, 2013. The adoption of this ASU did not have any impact on the Company's financial condition, results of operations and cash flows. 2014 – GAAP and FERC No new accounting standards were adopted during this year. 2015 – GAAP only In April 2015, the FASB issued ASU No. 2015-03, "Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs." This ASU amends the presentation of debt issuance costs in the financial statements such that an entity presents such costs in the balance sheet as a direct deduction from the related debt liability rather than as a deferred asset. Amortization of the costs will continue to be reported as interest expense. ASU No. 2015-03 is effective for periods beginning on or after December 15, 2015; however, early adoption is permitted. Upon adoption, entities will apply the new guidance retrospectively to all comparable prior periods presented in the financial statements. The Company evaluated this standard and determined that it will early adopt this standard as of December 31, 2015. As such, the Company revised its presentation of debt issuance costs for long-term debt in the Consolidated Balance Sheets for both periods presented. This resulted in a decrease to Other Deferred Charges and a decrease to Long-Term Debt and Capital Leases of $11.4 million as of December 31, 2014. There was no other impact on the Company's financial statements or results of operations. ASU No. 2015-03 did not address the presentation of debt issuance costs associated with line of credit arrangements. Accordingly, in August 2015, the FASB issued ASU No. 2015-15, "Interest - Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements." This ASU incorporates guidance from the Securities and Exchange Commission which states that it would not object to an entity deferring and presenting debt issuance costs as an asset and subsequently amortizing the deferred debt issuance costs ratably over the term of the line of credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. This ASU was effective upon issuance. The presentation outlined in ASU No. 2015-15 is consistent with the Company's historical presentation of line of credit issuance costs; therefore, there is no impact on the Company's financial statements as a result of adopting this accounting standard in 2015. Page 3 of 3 In November 2015, the FASB issued ASU 2015-17 “Income Taxes (Topic 740) - Balance Sheet Classification of Deferred Taxes,” which requires entities to present DTAs and DTLs as noncurrent in a classified balance sheet. The ASU simplifies the current guidance, which requires entities to separately present DTAs and DTLs as current and noncurrent in a classified balance sheet. This ASU is effective for annual periods beginning after December 15, 2016, and interim periods within those years and early adoption is permitted. In addition, upon adoption, entities are permitted to apply the amendments either prospectively or retrospectively. The Company has evaluated this standard and determined that it will early adopt this standard as of December 31, 2015 and it will apply this ASU on a prospective basis. As such, the Consolidated Balance Sheet as of December 31, 2014 was not adjusted to reflect the new ASU. The Company early adopted this ASU to ease the burden of preparing its financial statements and eliminate the need to evaluate deferred taxes for current and noncurrent presentation. 2015 – GAAP and FERC In May 2015, the FASB issued ASU No. 2015-07, "Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent)." This ASU removes, from the fair value hierarchy, investments for which the practical expedient is used to measure fair value at net asset value (NAV). Instead, an entity is required to include those investments as a reconciling line item so that the total fair value amount of investments in the disclosure is consistent with the amount on the balance sheet. Further, entities must provide certain disclosures for investments for which they elect to use the NAV practical expedient to determine fair value. This ASU is effective for periods beginning on or after December 15, 2015 and early adoption is permitted. The Company evaluated this standard and determined that it will early adopt this standard as of December 31, 2015. As required, this ASU is being applied retrospectively to all periods presented. The adoption of this standard did not affect the Company's future financial condition, results of operations and cash flows; however, it did affect the Company's disclosures. In prior years, the Company held investments related to its pension and other postretirement benefit plans that were fair valued using NAV and these amounts were included as level 3 items in the fair value hierarchy. This ASU was adopted retrospectively; therefore, the 2014 amounts have been reclassified to conform to the 2015 presentation. Also, since these amounts are no longer included in the fair value hierarchy as level 3 items, the level 3 reconciliations are no longer applicable and have been excluded from the pension and other postretirement benefits footnote. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 04/18/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Karen Schuh REQUESTER: UTC Staff - Huang RESPONDER: Karen Schuh TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff -012 Supplemental 1 TELEPHONE: (509) 495-2293 EMAIL: karen.schuh@avistacorp.com REQUEST: Please treat this as an ongoing data request. Please provide in an Excel work book all actual transfers to plant by Expenditure Request by month for the period October 2015 through December 2016. Where monthly data are not yet available, please provide the projected transfers to plant, indicating those transfers that are projections. Please update your response to this data request as actual monthly totals become available. Provide separate workbooks for electric and natural gas plant transfers. RESPONSE: Please see Staff_DR_012 Attachment A for details regarding the 2015 actual transfers to plant. Please see Staff_DR_012 Attachment B for details regarding the 2016 forecasted transfers to plant for 2016. This was also provided in Schuh Workpapers at 2016 CAP Summary Detail Support.xlsx. The Company will update this request when the 2016 quarterly update of actual transfers to plant and forecasted transfers to plant becomes available. Supplemental 1: Please see Staff_DR_12 Attachment B Supplemental 1 for details of the updated transfers to plant with actual transfers for January and February and forecasted transfers for the remaining months in 2016. The Company will continue to update actual transfers to plant and forecasted transfers to plant, as it becomes available. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 04/18/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Karen Schuh REQUESTER: UTC Staff - Huang RESPONDER: Karen Schuh TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff -012 Supplemental 1 TELEPHONE: (509) 495-2293 EMAIL: karen.schuh@avistacorp.com REQUEST: Please treat this as an ongoing data request. Please provide in an Excel work book all actual transfers to plant by Expenditure Request by month for the period October 2015 through December 2016. Where monthly data are not yet available, please provide the projected transfers to plant, indicating those transfers that are projections. Please update your response to this data request as actual monthly totals become available. Provide separate workbooks for electric and natural gas plant transfers. RESPONSE: Please see Staff_DR_012 Attachment A for details regarding the 2015 actual transfers to plant. Please see Staff_DR_012 Attachment B for details regarding the 2016 forecasted transfers to plant for 2016. This was also provided in Schuh Workpapers at 2016 CAP Summary Detail Support.xlsx. The Company will update this request when the 2016 quarterly update of actual transfers to plant and forecasted transfers to plant becomes available. Supplemental 1: Please see Staff_DR_12 Attachment B Supplemental 1 for details of the updated transfers to plant with actual transfers for January and February and forecasted transfers for the remaining months in 2016. The Company will continue to update actual transfers to plant and forecasted transfers to plant, as it becomes available. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 03/25/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Karen Schuh REQUESTER: UTC Staff - Huang RESPONDER: Karen Schuh TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff -012 TELEPHONE: (509) 495-2293 EMAIL: karen.schuh@avistacorp.com REQUEST: Please treat this as an ongoing data request. Please provide in an Excel work book all actual transfers to plant by Expenditure Request by month for the period October 2015 through December 2016. Where monthly data are not yet available, please provide the projected transfers to plant, indicating those transfers that are projections. Please update your response to this data request as actual monthly totals become available. Provide separate workbooks for electric and natural gas plant transfers. RESPONSE: Please see Staff_DR_012 Attachment A for details regarding the 2015 actual transfers to plant. Please see Staff_DR_012 Attachment B for details regarding the 2016 forecasted transfers to plant for 2016. This was also provided in Schuh Workpapers at 2016 CAP Summary Detail Support.xlsx. The Company will update this request when the 2016 quarterly update of actual transfers to plant and forecasted transfers to plant becomes available. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 03/25/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Karen Schuh REQUESTER: UTC Staff - Huang RESPONDER: Karen Schuh TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff -012 TELEPHONE: (509) 495-2293 EMAIL: karen.schuh@avistacorp.com REQUEST: Please treat this as an ongoing data request. Please provide in an Excel work book all actual transfers to plant by Expenditure Request by month for the period October 2015 through December 2016. Where monthly data are not yet available, please provide the projected transfers to plant, indicating those transfers that are projections. Please update your response to this data request as actual monthly totals become available. Provide separate workbooks for electric and natural gas plant transfers. RESPONSE: Please see Staff_DR_012 Attachment A for details regarding the 2015 actual transfers to plant. Please see Staff_DR_012 Attachment B for details regarding the 2016 forecasted transfers to plant for 2016. This was also provided in Schuh Workpapers at 2016 CAP Summary Detail Support.xlsx. The Company will update this request when the 2016 quarterly update of actual transfers to plant and forecasted transfers to plant becomes available. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 04/11/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Tara Knox & Joe Miller REQUESTER: UTC Staff – Jing Liu RESPONDER: Tara Knox TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff - 013 TELEPHONE: (509) 495-4325 EMAIL: tara.knox@avistacorp.com REQUEST: Please provide the schedule-level usage data and the corresponding temperature data used to support the weather normalization regression model output in T. Knox’s workpaper “2014 Electric Regressions” and J. Miller’s workpaper “2014 Gas Regressions.” For temperature data, if heating degree days (HDDs) and cooling degree days (CDDs) are calculated based on temperature data, please include both the original temperature data in Fahrenheit and the calculated HDDs and CDDs. RESPONSE: Please see Staff_DR_013 Attachment A which contains the data files used in the electric and natural gas regression analysis. Please also see Staff_DR_013 Attachment B which contains a series of files with the daily heating and cooling degree day information organized into a billing cycle basis for 10 years. Due to the volume of the data these attachments are provided in electronic format only. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 04/11/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Tara Knox & Joe Miller REQUESTER: UTC Staff – Jing Liu RESPONDER: Tara Knox TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff - 013 TELEPHONE: (509) 495-4325 EMAIL: tara.knox@avistacorp.com REQUEST: Please provide the schedule-level usage data and the corresponding temperature data used to support the weather normalization regression model output in T. Knox’s workpaper “2014 Electric Regressions” and J. Miller’s workpaper “2014 Gas Regressions.” For temperature data, if heating degree days (HDDs) and cooling degree days (CDDs) are calculated based on temperature data, please include both the original temperature data in Fahrenheit and the calculated HDDs and CDDs. RESPONSE: Please see Staff_DR_013 Attachment A which contains the data files used in the electric and natural gas regression analysis. Please also see Staff_DR_013 Attachment B which contains a series of files with the daily heating and cooling degree day information organized into a billing cycle basis for 10 years. Due to the volume of the data these attachments are provided in electronic format only. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 04/11/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Tara Knox & Joe Miller REQUESTER: UTC Staff – Jing Liu RESPONDER: Tara Knox TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff - 014 TELEPHONE: (509) 495-4325 EMAIL: tara.knox@avistacorp.com REQUEST: Please identify and describe in detail all of the changes in temperature-revenue normalization methodology in the Company’s Commission Basis Reports and general rate cases since 2006. RESPONSE: There are two aspects to the weather normalization process that were established during that time period. One aspect is the basis for the determination of weather sensitivity. The other aspect is the definition of “normal” weather. The current methodology for determining weather sensitivity was first introduced in Docket No. UE- 070804 and UG-070805. An abbreviated form of the case pro forma results of operations was submitted for the 2006 Commission Basis Report, including the proposed weather normalization methodology. Please see Staff_DR_014_Attachment A which is an excerpt from my testimony describing the new methodology, how it differs from the prior methodology and the reasons for the change. The sensitivity determination process adopted here continues to be used in the present case. The definition of “normal” heating and cooling degree days was modified over the course of the next two general rate cases. The Company proposed moving away from the NOAA published 30-year normal to a 25-year rolling average in Docket No. UE-080416 and UG-080417. Finally, the present 30-year rolling average determination for normal heating and cooling degree days was presented in Docket No. UE- 090134 and UG-090135. Please see Staff_DR_014_Attachment B which contains excerpts from my testimony in these two cases, explaining the rationale for the changes in the definition of “normal” heating and cooling degree days. The 2007 Commission Basis Report weather normalization adjustment reflected the new methodology with the NOAA published normals as accepted in the UE-070804/UG-070805 case. The 2008 Commission Basis Report weather normalization adjustment reflected the 25-year rolling average normals as accepted in the UE-080416/UG-080417 case. The 2009 Commission Basis Report weather normalization adjustment reflected the 30-year rolling average normal as accepted in the UE-090134/UG-090135 case. The weather normalization adjustments in all subsequent Commission Basis Reports have reflected the UE-090134/UG-090135 methodology. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 04/11/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Tara Knox & Joe Miller REQUESTER: UTC Staff – Jing Liu RESPONDER: Tara Knox TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff - 014 TELEPHONE: (509) 495-4325 EMAIL: tara.knox@avistacorp.com REQUEST: Please identify and describe in detail all of the changes in temperature-revenue normalization methodology in the Company’s Commission Basis Reports and general rate cases since 2006. RESPONSE: There are two aspects to the weather normalization process that were established during that time period. One aspect is the basis for the determination of weather sensitivity. The other aspect is the definition of “normal” weather. The current methodology for determining weather sensitivity was first introduced in Docket No. UE- 070804 and UG-070805. An abbreviated form of the case pro forma results of operations was submitted for the 2006 Commission Basis Report, including the proposed weather normalization methodology. Please see Staff_DR_014_Attachment A which is an excerpt from my testimony describing the new methodology, how it differs from the prior methodology and the reasons for the change. The sensitivity determination process adopted here continues to be used in the present case. The definition of “normal” heating and cooling degree days was modified over the course of the next two general rate cases. The Company proposed moving away from the NOAA published 30-year normal to a 25-year rolling average in Docket No. UE-080416 and UG-080417. Finally, the present 30-year rolling average determination for normal heating and cooling degree days was presented in Docket No. UE- 090134 and UG-090135. Please see Staff_DR_014_Attachment B which contains excerpts from my testimony in these two cases, explaining the rationale for the changes in the definition of “normal” heating and cooling degree days. The 2007 Commission Basis Report weather normalization adjustment reflected the new methodology with the NOAA published normals as accepted in the UE-070804/UG-070805 case. The 2008 Commission Basis Report weather normalization adjustment reflected the 25-year rolling average normals as accepted in the UE-080416/UG-080417 case. The 2009 Commission Basis Report weather normalization adjustment reflected the 30-year rolling average normal as accepted in the UE-090134/UG-090135 case. The weather normalization adjustments in all subsequent Commission Basis Reports have reflected the UE-090134/UG-090135 methodology. Staff_DR_014_Attachment A Page 1 Staff_DR_014_Attachment A Page 2 Staff_DR_014_Attachment A Page 3 Staff_DR_014_Attachment A Page 4 Staff_DR_014_Attachment B Page 1 Staff_DR_014_Attachment B Page 2 Staff_DR_014_Attachment B Page 3 Staff_DR_014_Attachment B Page 4 Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 04/20/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Karen Schuh REQUESTER: UTC Staff - Huang RESPONDER: Karen Schuh TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff - 015 TELEPHONE: (509) 495-2293 EMAIL: karen.schuh@avistacorp.com REQUEST: Please provide the monthly actual Expenditure Requests (with business case descriptions) for transfers to plant from January–December 2015 and January–December 2016 for the following adjustments. a. Electric: Adjustment 3.09, 3.10, 4.00, 4.01, 4.02, 4.03, 18.04 and 18.05 b. Natural Gas: Adjustment 3.08, 3.09, 4.01, 4.02, 4.03, 18.05 and 18.06 RESPONSE: a. & b. Please see Company witness Ms. Schuh’s electronic and hard copy workpapers where the monthly expenditure requests for transfers to plant from January –December 2015 through June 30, 2018 are provided. The electronic files are named the following: • 2016 CAP Summary Detail Support.xlsx • PF Detail Support.xlsx • 2017 Cross Check Detail.xlsx • 2018 Additions Detail.xlsx Also, please see the Company’s response to Staff_DR_012 Attachment B Supplemental 1 for details of the 2016 January and February actual transfers to plant and revised March through December 2016 transfers to plant. Finally, please see Staff_DR_015 Attachment A for a spreadsheet that links the business case name to the expenditure request name. The business case names and associated expenditure requests are also listed in Ms. Schuh’s Exhibit No. KKS-5 on each business case cover sheet for reference. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 04/20/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Karen Schuh REQUESTER: UTC Staff - Huang RESPONDER: Karen Schuh TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff - 015 TELEPHONE: (509) 495-2293 EMAIL: karen.schuh@avistacorp.com REQUEST: Please provide the monthly actual Expenditure Requests (with business case descriptions) for transfers to plant from January–December 2015 and January–December 2016 for the following adjustments. a. Electric: Adjustment 3.09, 3.10, 4.00, 4.01, 4.02, 4.03, 18.04 and 18.05 b. Natural Gas: Adjustment 3.08, 3.09, 4.01, 4.02, 4.03, 18.05 and 18.06 RESPONSE: a. & b. Please see Company witness Ms. Schuh’s electronic and hard copy workpapers where the monthly expenditure requests for transfers to plant from January –December 2015 through June 30, 2018 are provided. The electronic files are named the following: • 2016 CAP Summary Detail Support.xlsx • PF Detail Support.xlsx • 2017 Cross Check Detail.xlsx • 2018 Additions Detail.xlsx Also, please see the Company’s response to Staff_DR_012 Attachment B Supplemental 1 for details of the 2016 January and February actual transfers to plant and revised March through December 2016 transfers to plant. Finally, please see Staff_DR_015 Attachment A for a spreadsheet that links the business case name to the expenditure request name. The business case names and associated expenditure requests are also listed in Ms. Schuh’s Exhibit No. KKS-5 on each business case cover sheet for reference. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 04/20/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Karen Schuh REQUESTER: UTC Staff - Huang RESPONDER: Karen Schuh TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff - 016 TELEPHONE: (509) 495-2293 EMAIL: karen.schuh@avistacorp.com REQUEST: Referring to Ms. Jennifer Smith’s workpaper for “Pro Forma Capital Additions December 2015 AMA,” Adjustment 3.09, page 3.09-1, column labelled “AMA Balance Per Result of Operations,” the amount for the Accumulated DFIT total $(300,583) does not agree with the Deferred Taxes amount of $(294,027) in Ms. Smith’s Exhibit No. JSS-2, page 1, line 45, column labelled “Actual per Results of Report.” (All amounts are in thousands). Please reconcile the difference. RESPONSE: The total listed in Adjustment 3.09, page 3.09-1, for Accumulated DFIT totaling $(300,583) includes an adjustment listed in Ms. Smith’s Exhibit No.__(JSS-2), page 1, line 45, column labeled (1.01) “Deferred FIT Rate Base” of $(6,556)1. Therefore, the $(294,027) plus the $(6,556) equals the $(300,583) Accumulated DFIT in the total. Please see the table below for a reconciliation: 1 As discussed in Ms. Smith’s testimony (Exhibit No.__(JSS-1T) starting at page 14, line 6, Adjustment (1.01) adjusts the accumulated deferred federal income tax (ADFIT) rate base balance included in the Results of Operations column (1.00) to the adjusted ADFIT balance reflected on an AMA basis. The increase in ADFIT (which is a reduction of rate base) included in this adjustment is primarily due to the annualizing of tax depreciation adjustments for the repairs deduction and bonus depreciation related to the 2015 federal tax return. Results of operations at September 30, 2015 did not reflect ADFIT for repairs deduction or bonus depreciation. (Bonus depreciation for 2015 was not approved by the IRS until December 2015, therefore, the Company did not record the tax benefit until December 2015.) This adjustment restates ADFIT to reflect the impact of both tax deductions as if they had been recorded beginning in January 2015. Line Exhibit No.__(JSS-2) Results of Operations Adjustment 1.01 Workpaper 3.09-1 JSS-2 E-DFIT Plant Cost 37 2,374,570 2,374,570 Accumulated Depreciation 43 (823,973) (823,973) Net Plant before ADFIT 44 1,550,597 1,550,597 Deferred Taxes 45 (294,027) (6,556) (300,583) Net Plant After Deferred Taxes 1,256,570 (6,556) 1,250,014 Deferred Debits and Credits & Other 47 8,204 - Working Capital 48 44,420 - Total Rate Base 49 1,309,194 (6,556) 1,250,014 Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 04/20/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Karen Schuh REQUESTER: UTC Staff - Huang RESPONDER: Karen Schuh TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff - 016 TELEPHONE: (509) 495-2293 EMAIL: karen.schuh@avistacorp.com REQUEST: Referring to Ms. Jennifer Smith’s workpaper for “Pro Forma Capital Additions December 2015 AMA,” Adjustment 3.09, page 3.09-1, column labelled “AMA Balance Per Result of Operations,” the amount for the Accumulated DFIT total $(300,583) does not agree with the Deferred Taxes amount of $(294,027) in Ms. Smith’s Exhibit No. JSS-2, page 1, line 45, column labelled “Actual per Results of Report.” (All amounts are in thousands). Please reconcile the difference. RESPONSE: The total listed in Adjustment 3.09, page 3.09-1, for Accumulated DFIT totaling $(300,583) includes an adjustment listed in Ms. Smith’s Exhibit No.__(JSS-2), page 1, line 45, column labeled (1.01) “Deferred FIT Rate Base” of $(6,556)1. Therefore, the $(294,027) plus the $(6,556) equals the $(300,583) Accumulated DFIT in the total. Please see the table below for a reconciliation: 1 As discussed in Ms. Smith’s testimony (Exhibit No.__(JSS-1T) starting at page 14, line 6, Adjustment (1.01) adjusts the accumulated deferred federal income tax (ADFIT) rate base balance included in the Results of Operations column (1.00) to the adjusted ADFIT balance reflected on an AMA basis. The increase in ADFIT (which is a reduction of rate base) included in this adjustment is primarily due to the annualizing of tax depreciation adjustments for the repairs deduction and bonus depreciation related to the 2015 federal tax return. Results of operations at September 30, 2015 did not reflect ADFIT for repairs deduction or bonus depreciation. (Bonus depreciation for 2015 was not approved by the IRS until December 2015, therefore, the Company did not record the tax benefit until December 2015.) This adjustment restates ADFIT to reflect the impact of both tax deductions as if they had been recorded beginning in January 2015. Line Exhibit No.__(JSS-2) Results of Operations Adjustment 1.01 Workpaper 3.09-1 JSS-2 E-DFIT Plant Cost 37 2,374,570 2,374,570 Accumulated Depreciation 43 (823,973) (823,973) Net Plant before ADFIT 44 1,550,597 1,550,597 Deferred Taxes 45 (294,027) (6,556) (300,583) Net Plant After Deferred Taxes 1,256,570 (6,556) 1,250,014 Deferred Debits and Credits & Other 47 8,204 - Working Capital 48 44,420 - Total Rate Base 49 1,309,194 (6,556) 1,250,014 Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 04/20/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Karen Schuh REQUESTER: UTC Staff - Huang RESPONDER: Karen Schuh TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff - 017 TELEPHONE: (509) 495-2293 EMAIL: karen.schuh@avistacorp.com REQUEST: Referring to Ms. Jennifer Smith’s workpaper for “Pro Forma Capital Additions December 2015 AMA,” Adjustment 3.09, page 3.09-1, column labelled “AMA Balance Per Result of Operations,” the total rate base amount $1,250,014 does not agree with the total rate base amount of $1,309,195 in Ms. Smith’s Exhibit No. JSS-2, page 1, line 50. (All amounts are in thousands). Please explain the difference. RESPONSE: The difference between Ms. Smith’s workpaper for “Pro Forma Capital Additions December 2015 AMA” Adjustment 3.09, page 3.09-1, of $1,250,014 and the amount listed in Exhibit_JSS-2, page 1, line 50 of $1,309,195, is that Exhibit No.__(JSS-2), page 1 includes additional capital on lines 47 and 48 of $8,204 (Deferred Debits and Credits) and $44,420 (Working Capital), respectively. Please see the Company’s response to Staff_DR_016 for a reconciliation showing these amounts. Adjustment 3.09 only includes Gross Plant, Accumulated Depreciation and Deferred Taxes and therefore, should not include these balances as a part of the workpapers. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 04/20/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Karen Schuh REQUESTER: UTC Staff - Huang RESPONDER: Karen Schuh TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff - 017 TELEPHONE: (509) 495-2293 EMAIL: karen.schuh@avistacorp.com REQUEST: Referring to Ms. Jennifer Smith’s workpaper for “Pro Forma Capital Additions December 2015 AMA,” Adjustment 3.09, page 3.09-1, column labelled “AMA Balance Per Result of Operations,” the total rate base amount $1,250,014 does not agree with the total rate base amount of $1,309,195 in Ms. Smith’s Exhibit No. JSS-2, page 1, line 50. (All amounts are in thousands). Please explain the difference. RESPONSE: The difference between Ms. Smith’s workpaper for “Pro Forma Capital Additions December 2015 AMA” Adjustment 3.09, page 3.09-1, of $1,250,014 and the amount listed in Exhibit_JSS-2, page 1, line 50 of $1,309,195, is that Exhibit No.__(JSS-2), page 1 includes additional capital on lines 47 and 48 of $8,204 (Deferred Debits and Credits) and $44,420 (Working Capital), respectively. Please see the Company’s response to Staff_DR_016 for a reconciliation showing these amounts. Adjustment 3.09 only includes Gross Plant, Accumulated Depreciation and Deferred Taxes and therefore, should not include these balances as a part of the workpapers. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 04/20/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Karen Schuh REQUESTER: UTC Staff - Huang RESPONDER: Karen Schuh TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff - 018 TELEPHONE: (509) 495-2293 EMAIL: karen.schuh@avistacorp.com REQUEST: Please provide the same information in the same format as in Ms. Jennifer Smith’s workpaper for “Pro Forma 2016 Limited Capital Additions,” Adjustment 3.10, page 3.10-4, for the following adjustments: a. Electric: Adjustment 3.09, 4.00, 4.01, 4.02, 4.03, 18.04 and 18.05 b. Natural Gas: Adjustment 3.08, 3.09, 4.01, 4.02, 4.03, 18.05 and 18.06 RESPONSE: For the Electric Adjustment 3.09 and Natural Gas Adjustment 3.08 please see the Company’s response to Staff_DR_012 Attachment A. For the remaining adjustments, please see Company witness Ms. Schuh’s electronic and hard copy workpapers where this information has been provided. Electronic Workpaper references are listed in the Company’s response to Staff_DR_015. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 04/20/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Karen Schuh REQUESTER: UTC Staff - Huang RESPONDER: Karen Schuh TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff - 018 TELEPHONE: (509) 495-2293 EMAIL: karen.schuh@avistacorp.com REQUEST: Please provide the same information in the same format as in Ms. Jennifer Smith’s workpaper for “Pro Forma 2016 Limited Capital Additions,” Adjustment 3.10, page 3.10-4, for the following adjustments: a. Electric: Adjustment 3.09, 4.00, 4.01, 4.02, 4.03, 18.04 and 18.05 b. Natural Gas: Adjustment 3.08, 3.09, 4.01, 4.02, 4.03, 18.05 and 18.06 RESPONSE: For the Electric Adjustment 3.09 and Natural Gas Adjustment 3.08 please see the Company’s response to Staff_DR_012 Attachment A. For the remaining adjustments, please see Company witness Ms. Schuh’s electronic and hard copy workpapers where this information has been provided. Electronic Workpaper references are listed in the Company’s response to Staff_DR_015. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 04/20/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith/Mark Thies REQUESTER: UTC Staff - Huang RESPONDER: Bob Brandkamp TYPE: Data Request DEPT: Finance REQUEST NO.: Staff - 019 TELEPHONE: (509) 495-4924 EMAIL: bob.brandkamp@avistacorp.com REQUEST: With reference to Ms. Jennifer Smith’s electronic workpaper “2016 WA PF Insurance Adj.xlsx,” worksheet “2015-18 GL Est,” located in the “CC_INSURANCE” folder, please provide the actual General Liability insurance premium paid for the years 2005 through 2014 in the format below. RESPONSE: Please see Avista’s CONFIDENTIAL response to data request Staff_DR_019C. Please note that Avista’s response to Staff_DR_019C is Confidential per Protective Order in UTC Dockets UE- 160228 and UG-160229. Please see Staff_DR_019C Confidential Attachment A for the requested information. Insurance Company/Coverage Amount 20XX Premiums Paid AELP % Allocation AELP $ Allocation Avista Capital Allocation % Avista Capital Allocation $ Avista Corp Allocation % Avista Corp Allocation $ AEGIS ($35M) AEGIS Continuity Credit AEGIS ($35M) taxes Terrorism EIM ($100M xs $35M)EIM ($100M xs $35M) taxes EIM Distribution Credit Lloyd's of London ($50M xs $135M) Lloyd's Outside Broker Fee Other: Explain? Total 20XX Liability Premiums (Paid) Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 04/20/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith/Mark Thies REQUESTER: UTC Staff - Huang RESPONDER: Bob Brandkamp TYPE: Data Request DEPT: Finance REQUEST NO.: Staff - 019 TELEPHONE: (509) 495-4924 EMAIL: bob.brandkamp@avistacorp.com REQUEST: With reference to Ms. Jennifer Smith’s electronic workpaper “2016 WA PF Insurance Adj.xlsx,” worksheet “2015-18 GL Est,” located in the “CC_INSURANCE” folder, please provide the actual General Liability insurance premium paid for the years 2005 through 2014 in the format below. RESPONSE: Please see Avista’s CONFIDENTIAL response to data request Staff_DR_019C. Please note that Avista’s response to Staff_DR_019C is Confidential per Protective Order in UTC Dockets UE- 160228 and UG-160229. Please see Staff_DR_019C Confidential Attachment A for the requested information. Insurance Company/Coverage Amount 20XX Premiums Paid AELP % Allocation AELP $ Allocation Avista Capital Allocation % Avista Capital Allocation $ Avista Corp Allocation % Avista Corp Allocation $ AEGIS ($35M) AEGIS Continuity Credit AEGIS ($35M) taxes Terrorism EIM ($100M xs $35M)EIM ($100M xs $35M) taxes EIM Distribution Credit Lloyd's of London ($50M xs $135M) Lloyd's Outside Broker Fee Other: Explain? Total 20XX Liability Premiums (Paid) Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 04/20/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith/Mark Thies REQUESTER: UTC Staff - Huang RESPONDER: Bob Brandkamp TYPE: Data Request DEPT: Finance REQUEST NO.: Staff - 020 TELEPHONE: (509) 495-4924 EMAIL: bob.brandkamp@avistacorp.com REQUEST: Please provide the actual D & O insurance premium paid (total company) for the years 2005 through 2014 in the same format as listed in Ms. Jennifer Smith’s electronic workpaper “2016 WA PF Insurance Adj.xlsx,” worksheet “2015-18 D&O Est,” located in the “CC_INSURANCE” folder. RESPONSE: Please see Avista’s CONFIDENTIAL response to data request Staff_DR_020C. Please note that Avista’s response to Staff_DR_020C is Confidential per Protective Order in UTC Dockets UE- 160228 and UG-160229. Please see Staff_DR_020C Confidential Attachment A for the requested information. Data prior to 2008 is not readily available in the format requested. Please see Staff_DR_021 for revised D&O premiums and the associated impact on the overall adjustment. Workpapers are provided as Staff_DR_021C Confidential Attachment A. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 04/20/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith/Mark Thies REQUESTER: UTC Staff - Huang RESPONDER: Bob Brandkamp TYPE: Data Request DEPT: Finance REQUEST NO.: Staff - 020 TELEPHONE: (509) 495-4924 EMAIL: bob.brandkamp@avistacorp.com REQUEST: Please provide the actual D & O insurance premium paid (total company) for the years 2005 through 2014 in the same format as listed in Ms. Jennifer Smith’s electronic workpaper “2016 WA PF Insurance Adj.xlsx,” worksheet “2015-18 D&O Est,” located in the “CC_INSURANCE” folder. RESPONSE: Please see Avista’s CONFIDENTIAL response to data request Staff_DR_020C. Please note that Avista’s response to Staff_DR_020C is Confidential per Protective Order in UTC Dockets UE- 160228 and UG-160229. Please see Staff_DR_020C Confidential Attachment A for the requested information. Data prior to 2008 is not readily available in the format requested. Please see Staff_DR_021 for revised D&O premiums and the associated impact on the overall adjustment. Workpapers are provided as Staff_DR_021C Confidential Attachment A. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 04/20/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: UTC Staff - Huang RESPONDER: Bob Brandkamp/Annette Brandon TYPE: Data Request DEPT: Finance REQUEST NO.: Staff - 021 TELEPHONE: (509) 495-4924 EMAIL: bob.brandkamp@avistacorp.com REQUEST: Referring to Ms. Jennifer Smith’s electronic workpaper “2016 WA PF Insurance Adj.xlsx,” worksheet “2015-18 Prop Calcs for IA-2,” located in the “CC_INURANCE” folder, please provide a functional Excel work sheet showing how Avista calculated its “2015, 2016, 2017 and 2018 Property Premium Estimate,” cells f24, 30, 36, and 42. Any responsive materials provided in Excel format must include all links and should be fully functional, with all workbooks, worksheets, data and formulae left intact. RESPONSE: Please see Avista’s CONFIDENTIAL response to data request Staff_DR_021C. Please note that Avista’s response to Staff_DR_021C is Confidential per Protective Order in UTC Dockets UE- 160228 and UG-160229. Supporting calculations in electronic form for 2015, 2016, 2017, and 2018 Property Premium Estimates are provided in Staff_DR_021C Confidential Attachment A. The attachment includes updated amounts for general liability and director & officer premiums in response to Staff Data Requests 023 (general liability) and 020 (director and officer). The revised adjustment is summarized on tab IA-2 of Staff_DR_021C Confidential Attachment A. This update changes the original 2017 Cross Check Adjustment (4.06) from an increase of $75,686 Washington Electric expense to a reduction of $14,704 for a difference of $90,390 and the 2018 Cross Check Adjustment (18.06) from an increase of $65,708 to an increase of $36,975 for a difference of $28,733. This update also changes the original 2017 Cross Check Adjustment (4.05) from an increase of $21,773 Washington Natural Gas Expense to a reduction of $4,230 for a total difference of $26,003 and the 2018 Cross Check Adjustment (18.03) from an increase of $18,903 to an increase of $10,637 for a total difference of $8,266. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 04/20/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: UTC Staff - Huang RESPONDER: Bob Brandkamp/Annette Brandon TYPE: Data Request DEPT: Finance REQUEST NO.: Staff - 021 TELEPHONE: (509) 495-4924 EMAIL: bob.brandkamp@avistacorp.com REQUEST: Referring to Ms. Jennifer Smith’s electronic workpaper “2016 WA PF Insurance Adj.xlsx,” worksheet “2015-18 Prop Calcs for IA-2,” located in the “CC_INURANCE” folder, please provide a functional Excel work sheet showing how Avista calculated its “2015, 2016, 2017 and 2018 Property Premium Estimate,” cells f24, 30, 36, and 42. Any responsive materials provided in Excel format must include all links and should be fully functional, with all workbooks, worksheets, data and formulae left intact. RESPONSE: Please see Avista’s CONFIDENTIAL response to data request Staff_DR_021C. Please note that Avista’s response to Staff_DR_021C is Confidential per Protective Order in UTC Dockets UE- 160228 and UG-160229. Supporting calculations in electronic form for 2015, 2016, 2017, and 2018 Property Premium Estimates are provided in Staff_DR_021C Confidential Attachment A. The attachment includes updated amounts for general liability and director & officer premiums in response to Staff Data Requests 023 (general liability) and 020 (director and officer). The revised adjustment is summarized on tab IA-2 of Staff_DR_021C Confidential Attachment A. This update changes the original 2017 Cross Check Adjustment (4.06) from an increase of $75,686 Washington Electric expense to a reduction of $14,704 for a difference of $90,390 and the 2018 Cross Check Adjustment (18.06) from an increase of $65,708 to an increase of $36,975 for a difference of $28,733. This update also changes the original 2017 Cross Check Adjustment (4.05) from an increase of $21,773 Washington Natural Gas Expense to a reduction of $4,230 for a total difference of $26,003 and the 2018 Cross Check Adjustment (18.03) from an increase of $18,903 to an increase of $10,637 for a total difference of $8,266. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 04/20/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith/Mark Thies REQUESTER: UTC Staff - Huang RESPONDER: Bob Brandkamp TYPE: Data Request DEPT: Finance REQUEST NO.: Staff - 022 TELEPHONE: (509) 495-4924 EMAIL: bob.brandkamp@avistacorp.com REQUEST: With reference to Ms. Jennifer Smith’s electronic workpaper “2016 WA PF Insurance Adj.xlsx,” worksheet “2015-18 GL Est,” located in the “CC_INSURANCE” folder, please provide the actual 2015 General Liability insurance premium paid by Avista in the format below. Insurance Company/Coverage Amount 2015 Invoiced Premiums1 AEGIS ($35M) AEGIS Continuity Credit AEGIS ($35M) taxes EIM ($100M xs $35M) EIM ($100M xs $35M) taxes EIM Distribution Credit Lloyd's of London ($50M xs $135M) RESPONSE: Please see Avista’s CONFIDENTIAL response to data request Staff_DR_022C. Please note that Avista’s response to Staff_DR_022C is Confidential per Protective Order in UTC Dockets UE- 160228 and UG-160229. See also Avista’s response to Staff_DR_021 and 023. 1 Amounts noted in the DR Request are confidential and should be treated Confidential per Protective Order in UTC Dockets UE-160228 and UG-160229. The Company inadvertently included this data within its detailed electronic workpapers. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 04/20/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith/Mark Thies REQUESTER: UTC Staff - Huang RESPONDER: Bob Brandkamp TYPE: Data Request DEPT: Finance REQUEST NO.: Staff - 022 TELEPHONE: (509) 495-4924 EMAIL: bob.brandkamp@avistacorp.com REQUEST: With reference to Ms. Jennifer Smith’s electronic workpaper “2016 WA PF Insurance Adj.xlsx,” worksheet “2015-18 GL Est,” located in the “CC_INSURANCE” folder, please provide the actual 2015 General Liability insurance premium paid by Avista in the format below. Insurance Company/Coverage Amount 2015 Invoiced Premiums1 AEGIS ($35M) AEGIS Continuity Credit AEGIS ($35M) taxes EIM ($100M xs $35M) EIM ($100M xs $35M) taxes EIM Distribution Credit Lloyd's of London ($50M xs $135M) RESPONSE: Please see Avista’s CONFIDENTIAL response to data request Staff_DR_022C. Please note that Avista’s response to Staff_DR_022C is Confidential per Protective Order in UTC Dockets UE- 160228 and UG-160229. See also Avista’s response to Staff_DR_021 and 023. 1 Amounts noted in the DR Request are confidential and should be treated Confidential per Protective Order in UTC Dockets UE-160228 and UG-160229. The Company inadvertently included this data within its detailed electronic workpapers. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 04/20/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith/Mark Thies REQUESTER: UTC Staff - Huang RESPONDER: Bob Brandkamp TYPE: Data Request DEPT: Finance REQUEST NO.: Staff - 023 TELEPHONE: (509) 495-4924 EMAIL: bob.brandkamp@avistacorp.com REQUEST: With reference to Ms. Jennifer Smith’s electronic workpaper “2016 WA PF Insurance Adj.xlsx,” worksheet “2015-18 GL Est,” located in the “CC_INSURANCE” folder, please provide the basis or rationale that Avista used to gross up the 2015 General Liability invoiced premium by 5% each year to arrive at estimated 2016, 2017 and 2018 General Liability insurance for the total company. RESPONSE: Expectations prior to our 12/31/15 General Liability (GL) renewal was for liability premiums to increase approximately 5% per year for 2016, 2017, and 2018 following premium increases of 8.6% and 5.3% in 2014 and 2015 respectively. However, the actual 2016 GL premium increase based on our 12/31/15 renewal came in lower than expected at 2.3%. Based on this reduction, we have decreased our expectations for GL premium increases in 2017 and 2018 from 5.0% to 2.4%. Revised GL premiums are reflected in tab IA-2 of “Worksheet support for DR 21 DR 23-25.xlsx”. The expectations of approximate 2% increases in GL premiums in 2017 and 2018 are in line with utility industry expectations of rate increases in line with inflationary increases. The Company has provided workpapers and calculated the impact of this change in response to Staff_DR_021. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 04/20/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith/Mark Thies REQUESTER: UTC Staff - Huang RESPONDER: Bob Brandkamp TYPE: Data Request DEPT: Finance REQUEST NO.: Staff - 023 TELEPHONE: (509) 495-4924 EMAIL: bob.brandkamp@avistacorp.com REQUEST: With reference to Ms. Jennifer Smith’s electronic workpaper “2016 WA PF Insurance Adj.xlsx,” worksheet “2015-18 GL Est,” located in the “CC_INSURANCE” folder, please provide the basis or rationale that Avista used to gross up the 2015 General Liability invoiced premium by 5% each year to arrive at estimated 2016, 2017 and 2018 General Liability insurance for the total company. RESPONSE: Expectations prior to our 12/31/15 General Liability (GL) renewal was for liability premiums to increase approximately 5% per year for 2016, 2017, and 2018 following premium increases of 8.6% and 5.3% in 2014 and 2015 respectively. However, the actual 2016 GL premium increase based on our 12/31/15 renewal came in lower than expected at 2.3%. Based on this reduction, we have decreased our expectations for GL premium increases in 2017 and 2018 from 5.0% to 2.4%. Revised GL premiums are reflected in tab IA-2 of “Worksheet support for DR 21 DR 23-25.xlsx”. The expectations of approximate 2% increases in GL premiums in 2017 and 2018 are in line with utility industry expectations of rate increases in line with inflationary increases. The Company has provided workpapers and calculated the impact of this change in response to Staff_DR_021. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 04/20/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith/Mart Thies REQUESTER: UTC Staff - Huang RESPONDER: Bob Brandkamp TYPE: Data Request DEPT: Finance REQUEST NO.: Staff - 024 TELEPHONE: (509) 495-4924 EMAIL: bob.brandkamp@avistacorp.com REQUEST: With reference to Ms. Jennifer Smith’s electronic workpaper “2016 WA PF Insurance Adj.xlsx,” worksheet “2015-18 GL Est,” located in the “CC_INSURANCE” folder, do you contend that a General Liability insurance gross-up estimate of 5 % for the years 2016 through 2018 is commonly used in the utility industry? If your answer is yes, please provide documents and examples to support your answer. RESPONSE: Please see the Company’s response to Staff_DR_023. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 04/20/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith/Mart Thies REQUESTER: UTC Staff - Huang RESPONDER: Bob Brandkamp TYPE: Data Request DEPT: Finance REQUEST NO.: Staff - 024 TELEPHONE: (509) 495-4924 EMAIL: bob.brandkamp@avistacorp.com REQUEST: With reference to Ms. Jennifer Smith’s electronic workpaper “2016 WA PF Insurance Adj.xlsx,” worksheet “2015-18 GL Est,” located in the “CC_INSURANCE” folder, do you contend that a General Liability insurance gross-up estimate of 5 % for the years 2016 through 2018 is commonly used in the utility industry? If your answer is yes, please provide documents and examples to support your answer. RESPONSE: Please see the Company’s response to Staff_DR_023. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 04/20/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith/Mark Thies REQUESTER: UTC Staff - Huang RESPONDER: Bob Brandkamp TYPE: Data Request DEPT: Finance REQUEST NO.: Staff – 025 TELEPHONE: (509) 495-4924 EMAIL: bob.brandkamp@avistacorp.com REQUEST: With reference to Ms. Jennifer Smith’s electronic workpaper “2016 WA PF Insurance Adj.xlsx,” worksheet “2015-18 D&O Est,” located in the “CC_INSURANCE” folder, please provide the basis or rationale that Avista used to gross up 2016 General Liability insurance by 3% each year to arrive at the projected 2017 and 2018 D & O Insurance for the total company. RESPONSE: Our expectation for D & O increases were 3% for 2016, 2017, and 2018 following premium increases of 15% and 3.8% in 2014 and 2015 respectively. However, Avista realized an overall D & O premium decrease of 11.1% at the 12/31/2015 renewal due to a 60.7% increase in our continuity credit combined with premium decreases ranging from 2.8% to 7.7% across our coverage tiers over our primary $35 million layer. Our expectations for 2017 and 2018 D & O premium increases have been adjusted to reflect 0% premium increases for each coverage tier combined with a 5% increase in the continuity credit expected to be received. This results in an overall expected decrease in D & O premium of 1.0% in both 2017 and 2018. Revised D & O premiums are reflected in tab IA-2 of Staff_DR_021C Confidential Attachment A. The impact of this change is shown in Avista’s response to Staff_DR_021. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 04/20/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith/Mark Thies REQUESTER: UTC Staff - Huang RESPONDER: Bob Brandkamp TYPE: Data Request DEPT: Finance REQUEST NO.: Staff – 025 TELEPHONE: (509) 495-4924 EMAIL: bob.brandkamp@avistacorp.com REQUEST: With reference to Ms. Jennifer Smith’s electronic workpaper “2016 WA PF Insurance Adj.xlsx,” worksheet “2015-18 D&O Est,” located in the “CC_INSURANCE” folder, please provide the basis or rationale that Avista used to gross up 2016 General Liability insurance by 3% each year to arrive at the projected 2017 and 2018 D & O Insurance for the total company. RESPONSE: Our expectation for D & O increases were 3% for 2016, 2017, and 2018 following premium increases of 15% and 3.8% in 2014 and 2015 respectively. However, Avista realized an overall D & O premium decrease of 11.1% at the 12/31/2015 renewal due to a 60.7% increase in our continuity credit combined with premium decreases ranging from 2.8% to 7.7% across our coverage tiers over our primary $35 million layer. Our expectations for 2017 and 2018 D & O premium increases have been adjusted to reflect 0% premium increases for each coverage tier combined with a 5% increase in the continuity credit expected to be received. This results in an overall expected decrease in D & O premium of 1.0% in both 2017 and 2018. Revised D & O premiums are reflected in tab IA-2 of Staff_DR_021C Confidential Attachment A. The impact of this change is shown in Avista’s response to Staff_DR_021. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 04/20/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: UTC Staff - Huang RESPONDER: Bob Brandkamp TYPE: Data Request DEPT: Finance REQUEST NO.: Staff - 026 TELEPHONE: (509) 495-4924 EMAIL: bob.brandkamp@avistacorp.com REQUEST: Please provide the FERC account that Avista records the following expenses to: a. General Liability b. Director & Officers Liability c. Property Insurance RESPONSE: a. General Liability – FERC 925 b. Director & Officers Liability – FERC 925 c. Property Insurance – FERC 924 Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 04/20/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: UTC Staff - Huang RESPONDER: Bob Brandkamp TYPE: Data Request DEPT: Finance REQUEST NO.: Staff - 026 TELEPHONE: (509) 495-4924 EMAIL: bob.brandkamp@avistacorp.com REQUEST: Please provide the FERC account that Avista records the following expenses to: a. General Liability b. Director & Officers Liability c. Property Insurance RESPONSE: a. General Liability – FERC 925 b. Director & Officers Liability – FERC 925 c. Property Insurance – FERC 924 Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/06/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Elizabeth Andrews REQUESTER: UTC Staff - Hancock RESPONDER: Karen Schuh TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff - 027 TELEPHONE: (509) 495-2293 EMAIL: karen.schuh@avistacorp.com REQUEST: Re: Post-Attrition Adjustments Please identify all transfers to plant under a given Expenditure Request (ER) for which the total transfers for the year exceeded 1.5% of the total rate base found in the previous year’s Commission Basis Report. Please limit this exercise to the years 2007 through 2015. Please include the name and number of each ER, as well as the amount transferred for the given year. RESPONSE: Please see the transfers to plant under ER’s that are allocated by Washington Electric and Washington Natural Gas that exceeded 1.5% of total rate base found in the previous year’s Commission Basis Report in Staff DR 027 Attachment A. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/06/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Elizabeth Andrews REQUESTER: UTC Staff - Hancock RESPONDER: Karen Schuh TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff - 027 TELEPHONE: (509) 495-2293 EMAIL: karen.schuh@avistacorp.com REQUEST: Re: Post-Attrition Adjustments Please identify all transfers to plant under a given Expenditure Request (ER) for which the total transfers for the year exceeded 1.5% of the total rate base found in the previous year’s Commission Basis Report. Please limit this exercise to the years 2007 through 2015. Please include the name and number of each ER, as well as the amount transferred for the given year. RESPONSE: Please see the transfers to plant under ER’s that are allocated by Washington Electric and Washington Natural Gas that exceeded 1.5% of total rate base found in the previous year’s Commission Basis Report in Staff DR 027 Attachment A. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 04/29/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Elizabeth Andrews REQUESTER: UTC Staff - Hancock RESPONDER: Karen Schuh TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff - 028 TELEPHONE: (509) 495-2293 EMAIL: karen.schuh@avistacorp.com REQUEST: Please confirm that the following ERs, and only these ERs, correspond to the After Attrition Adjustments for the projects collectively known as “Spokane River Projects”. Project Name ER Number Post Falls 4162 Little Falls 4152 Nine Mile 4140 RESPONSE: The Company confirms that these projects and only these projects correspond to the after attrition adjustment “Spokane River Projects”. These are also detailed in Company witness Ms. Andrews electronic workpapers at: Attrition Adj Column M and N – Spokane River Projects and AMI.xlsx. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 04/29/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Elizabeth Andrews REQUESTER: UTC Staff - Hancock RESPONDER: Karen Schuh TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff - 028 TELEPHONE: (509) 495-2293 EMAIL: karen.schuh@avistacorp.com REQUEST: Please confirm that the following ERs, and only these ERs, correspond to the After Attrition Adjustments for the projects collectively known as “Spokane River Projects”. Project Name ER Number Post Falls 4162 Little Falls 4152 Nine Mile 4140 RESPONSE: The Company confirms that these projects and only these projects correspond to the after attrition adjustment “Spokane River Projects”. These are also detailed in Company witness Ms. Andrews electronic workpapers at: Attrition Adj Column M and N – Spokane River Projects and AMI.xlsx. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 04/29/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Karen Schuh REQUESTER: UTC Staff - Hancock RESPONDER: Karen Schuh TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff - 029 TELEPHONE: (509) 495-2293 EMAIL: karen.schuh@avistacorp.com REQUEST: Please explain the discrepancy between the figures reported for ER 4152, ER 4162, and ER 4140 in the following electronic versions Karen Schuh’s workpapers: Exhibit KKS-5 2016 CAP Summary Detail Support.xlsx 2017 Cross Check Detail.xlsx 2018 Additions Detail.xlsx Note: Some figures between the 2017 document and the 2018 document repeat. For an example, see ER 4152 and ER 4140. RESPONSE: ER’s 4152, 4162 and 4140 on Exhibit KKS-5 represent system totals for these ER’s. The referenced workpapers listed above for 2016, 2017 and 2018 represent allocated Washington Electric balances. Therefore, these will differ. In order to calculate an average of monthly averages (AMA) balance as of June 30, 2018 plant additions, the company had to include additions starting in 2017 and calculate the average through June 30, 2018. Therefore, these amounts have been repeated on “2018 Additions Detail.xlsx” in order to calculate the proper June 30, 2018 AMA balance. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 04/29/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Karen Schuh REQUESTER: UTC Staff - Hancock RESPONDER: Karen Schuh TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff - 029 TELEPHONE: (509) 495-2293 EMAIL: karen.schuh@avistacorp.com REQUEST: Please explain the discrepancy between the figures reported for ER 4152, ER 4162, and ER 4140 in the following electronic versions Karen Schuh’s workpapers: Exhibit KKS-5 2016 CAP Summary Detail Support.xlsx 2017 Cross Check Detail.xlsx 2018 Additions Detail.xlsx Note: Some figures between the 2017 document and the 2018 document repeat. For an example, see ER 4152 and ER 4140. RESPONSE: ER’s 4152, 4162 and 4140 on Exhibit KKS-5 represent system totals for these ER’s. The referenced workpapers listed above for 2016, 2017 and 2018 represent allocated Washington Electric balances. Therefore, these will differ. In order to calculate an average of monthly averages (AMA) balance as of June 30, 2018 plant additions, the company had to include additions starting in 2017 and calculate the average through June 30, 2018. Therefore, these amounts have been repeated on “2018 Additions Detail.xlsx” in order to calculate the proper June 30, 2018 AMA balance. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/16/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Elizabeth Andrews REQUESTER: UTC Staff - Hancock RESPONDER: Liz Andrews TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff - 030 TELEPHONE: (509) 495-8601 EMAIL: liz.andrews@avistacorp.com REQUEST: Upon completion of the 2015 Commission Basis Report, please update the Company’s electric and natural gas attrition models for both 2017 and 2018 to reflect the results of the 2015 Commission Basis Report. Please consider the deadline for this request to be seven business days from May 2, 2016. RESPONSE: See the following attachments for the impact of updating the Company’s filed electric and natural gas Attrition Studies (2017 and 2018 (June 2016 ending AMA) ) with Avista’s December 2015 Commission Basis Report (CBR) results. • Staff_DR_030 – Attachment A - Electric and Natural Gas Attrition Summaries. This file provides a listing of the changes to each attrition study compared to the Company’s attrition studies as filed. • Staff_DR_030 – Attachment B – 2017 Electric Attrition Study • Staff_DR_030 – Attachment C – 2017 Natural Gas Attrition Study • Staff_DR_030 – Attachment D – 2018 (ending June 2018 (AMA)) Electric Attrition Study • Staff_DR_030 – Attachment E – 2018 (ending June 2018 (AMA)) Natural Gas Attrition Study • Staff_DR_030 – Attachment F – Electric and Natural Gas Attrition Study workpapers - provided in hard copy and electronic native formats. • Staff_DR_030 – Attachment G – 12.2015 Electric and Natural Gas Commission Basis report workpapers - provided in electronic format only. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/16/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Elizabeth Andrews REQUESTER: UTC Staff - Hancock RESPONDER: Liz Andrews TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff - 030 TELEPHONE: (509) 495-8601 EMAIL: liz.andrews@avistacorp.com REQUEST: Upon completion of the 2015 Commission Basis Report, please update the Company’s electric and natural gas attrition models for both 2017 and 2018 to reflect the results of the 2015 Commission Basis Report. Please consider the deadline for this request to be seven business days from May 2, 2016. RESPONSE: See the following attachments for the impact of updating the Company’s filed electric and natural gas Attrition Studies (2017 and 2018 (June 2016 ending AMA) ) with Avista’s December 2015 Commission Basis Report (CBR) results. • Staff_DR_030 – Attachment A - Electric and Natural Gas Attrition Summaries. This file provides a listing of the changes to each attrition study compared to the Company’s attrition studies as filed. • Staff_DR_030 – Attachment B – 2017 Electric Attrition Study • Staff_DR_030 – Attachment C – 2017 Natural Gas Attrition Study • Staff_DR_030 – Attachment D – 2018 (ending June 2018 (AMA)) Electric Attrition Study • Staff_DR_030 – Attachment E – 2018 (ending June 2018 (AMA)) Natural Gas Attrition Study • Staff_DR_030 – Attachment F – Electric and Natural Gas Attrition Study workpapers - provided in hard copy and electronic native formats. • Staff_DR_030 – Attachment G – 12.2015 Electric and Natural Gas Commission Basis report workpapers - provided in electronic format only. Staff_DR_030 Attachment F Page 1 of 62 Staff_DR_030 Attachment F Page 2 of 62 Staff_DR_030 Attachment F Page 3 of 62 Staff_DR_030 Attachment F Page 4 of 62 Staff_DR_030 Attachment F Page 5 of 62 Staff_DR_030 Attachment F Page 6 of 62 Staff_DR_030 Attachment F Page 7 of 62 Staff_DR_030 Attachment F Page 8 of 62 Staff_DR_030 Attachment F Page 9 of 62 Staff_DR_030 Attachment F Page 10 of 62 Staff_DR_030 Attachment F Page 11 of 62 Staff_DR_030 Attachment F Page 12 of 62 Staff_DR_030 Attachment F Page 13 of 62 Staff_DR_030 Attachment F Page 14 of 62 Staff_DR_030 Attachment F Page 15 of 62 Staff_DR_030 Attachment F Page 16 of 62 Staff_DR_030 Attachment F Page 17 of 62 Staff_DR_030 Attachment F Page 18 of 62 Staff_DR_030 Attachment F Page 19 of 62 Staff_DR_030 Attachment F Page 20 of 62 Staff_DR_030 Attachment F Page 21 of 62 Staff_DR_030 Attachment F Page 22 of 62 Staff_DR_030 Attachment F Page 23 of 62 Staff_DR_030 Attachment F Page 24 of 62 Staff_DR_030 Attachment F Page 25 of 62 Staff_DR_030 Attachment F Page 26 of 62 Staff_DR_030 Attachment F Page 27 of 62 Staff_DR_030 Attachment F Page 28 of 62 Staff_DR_030 Attachment F Page 29 of 62 Staff_DR_030 Attachment F Page 30 of 62 Staff_DR_030 Attachment F Page 31 of 62 Staff_DR_030 Attachment F Page 32 of 62 Staff_DR_030 Attachment F Page 33 of 62 Staff_DR_030 Attachment F Page 34 of 62 Staff_DR_030 Attachment F Page 35 of 62 Staff_DR_030 Attachment F Page 36 of 62 Staff_DR_030 Attachment F Page 37 of 62 Staff_DR_030 Attachment F Page 38 of 62 Staff_DR_030 Attachment F Page 39 of 62 Staff_DR_030 Attachment F Page 40 of 62 Staff_DR_030 Attachment F Page 41 of 62 Staff_DR_030 Attachment F Page 42 of 62 Staff_DR_030 Attachment F Page 43 of 62 Staff_DR_030 Attachment F Page 44 of 62 Staff_DR_030 Attachment F Page 45 of 62 Staff_DR_030 Attachment F Page 46 of 62 Staff_DR_030 Attachment F Page 47 of 62 Staff_DR_030 Attachment F Page 48 of 62 Staff_DR_030 Attachment F Page 49 of 62 Staff_DR_030 Attachment F Page 50 of 62 Staff_DR_030 Attachment F Page 51 of 62 Staff_DR_030 Attachment F Page 52 of 62 Staff_DR_030 Attachment F Page 53 of 62 Staff_DR_030 Attachment F Page 54 of 62 Staff_DR_030 Attachment F Page 55 of 62 Staff_DR_030 Attachment F Page 56 of 62 Staff_DR_030 Attachment F Page 57 of 62 Staff_DR_030 Attachment F Page 58 of 62 Staff_DR_030 Attachment F Page 59 of 62 Staff_DR_030 Attachment F Page 60 of 62 Staff_DR_030 Attachment F Page 61 of 62 Staff_DR_030 Attachment F Page 62 of 62 Page 1 of 4 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/03/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Elizabeth Andrews REQUESTER: UTC Staff - Hancock RESPONDER: David Machado TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff - 031 TELEPHONE: (509) 495-4554 EMAIL: david.machado@avistacorp.com REQUEST: Please calculate the percentage of transfers-to-plant, for each of the years from 2007 through 2015, comprised of generation assets and transmission assets separately. Please identify whether the reported figures are on a system level or a Washington-allocated level. RESPONSE: The illustration below provides a graphical demonstration of the relative amounts of transfers to plant, by functional group. The illustration includes actual transfers to plant from 2007 through 2015 and includes planned capital investment transfers to plant for 2016 and 2017. This illustration is provided on a Washington-allocated basis, and transfers to plant reflect the gross plant balance for each given year. Three comments on this chart have been indicated by bracketed numerals—with the associated comments following the illustration. Page 2 of 4 [1] – The 2015 ET (Enterprise Technology) transfers to plant include $61 million related to Washington’s share of Avista’s new Customer Information System (Project Compass). Excluding this $61 million, the remaining ET transfers to plant, for 2015, of $21.2 million are more consistent with (albeit higher than) the average ET transfers from 2007-2014 of $15.4 million. [2] – The 2016 planned generation transfers to plant include $71.3 million related to Washington’s share of major rehabilitation investments made on three Spokane River hydro projects (Nine Mile, Little Falls, and Post Falls—these projects are included as an after attrition adjustment item). Excluding this $71.3 million, the remaining generation transfers to plant, for 2016, of $28.7 million is more consistent with (albeit higher than) the average generation transfers to plant from 2007-2015 of $16.4 million. [3] – 2017 planned transfers to plant include investment of $71.7 million related to the implementation of advanced metering infrastructure (AMI) in Washington. This project has been included in this illustration as its own distinct group (were this project to be included within functional categories, $30.9 million would be included in the Electric Distribution category, $14.7 million would be included in the Gas category, $12.8 million would be included in the ET category, and 13.3 million would be included in the Other category). Additionally, pages three and four of this response include tabular presentations of this illustration, with the table on page three presenting the balances in dollars and the table on page four presenting the balances as percentages of the total transfers to plant in the given year. Page 3 of 4 Transfers to Plant, by Functional Category – Actual 2007-2015 and Planned 2016-2017 (in dollars): Planned Investment 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 Environmental 3,330,855 283,270 850,487 1,584,310 3,039,302 1,734,270 1,269,967 10,026,941 8,021,074 4,931,428 14,569,176 Gas 2,431,353 13,385,299 9,865,223 4,537,385 14,618,900 4,187,749 21,149,097 15,854,105 20,813,367 20,055,444 23,602,720 Generation 13,285,844 21,321,852 19,062,236 13,408,428 13,595,700 13,679,932 20,628,255 15,156,622 17,567,422 99,953,808 31,689,425 Growth 27,076,871 28,413,058 25,486,095 23,128,642 26,789,512 22,833,592 29,289,857 28,717,537 30,689,866 27,148,289 28,257,967 ET 7,304,727 9,604,673 10,304,028 10,931,957 15,666,399 19,858,981 24,462,364 25,335,450 82,242,961 23,139,401 33,848,957 Other 8,649,955 11,026,501 17,076,270 24,222,651 20,271,468 17,915,639 27,255,720 17,470,331 25,769,410 29,866,442 19,129,222 Electric Electric [1] 119,183,028 121,691,750 118,328,497 124,639,287 152,369,633 132,599,934 171,678,810 171,085,140 267,791,906 280,589,033 302,441,959 [1] – The majority of the difference between 2015 electric distribution transfers to plant and the electric distribution transfers to plant over the recent years is due to the capital investment related to the November 2015 Wind Storm. Page 4 of 4 Transfers to Plant, by Functional Category – Actual 2007-2015 and Planned 2016-2017 (as percentage of annual total): Planned Investment 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 Environmental 2.8% 0.2% 0.7% 1.3% 2.0% 1.3% 0.7% 5.9% 3.0% 1.8% 4.8% Gas 2.0% 11.0% 8.3% 3.6% 9.6% 3.2% 12.3% 9.3% 7.8% 7.1% 7.8% Generation 11.1% 17.5% 16.1% 10.8% 8.9% 10.3% 12.0% 8.9% 6.6% 35.6% 10.5% Growth 22.7% 23.3% 21.5% 18.6% 17.6% 17.2% 17.1% 16.8% 11.5% 9.7% 9.3% ET 6.1% 7.9% 8.7% 8.8% 10.3% 15.0% 14.2% 14.8% 30.7% 8.2% 11.2% Other 7.3% 9.1% 14.4% 19.4% 13.3% 13.5% 15.9% 10.2% 9.6% 10.6% 6.3% Electric Electric 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% Page 1 of 4 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/03/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Elizabeth Andrews REQUESTER: UTC Staff - Hancock RESPONDER: David Machado TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff - 031 TELEPHONE: (509) 495-4554 EMAIL: david.machado@avistacorp.com REQUEST: Please calculate the percentage of transfers-to-plant, for each of the years from 2007 through 2015, comprised of generation assets and transmission assets separately. Please identify whether the reported figures are on a system level or a Washington-allocated level. RESPONSE: The illustration below provides a graphical demonstration of the relative amounts of transfers to plant, by functional group. The illustration includes actual transfers to plant from 2007 through 2015 and includes planned capital investment transfers to plant for 2016 and 2017. This illustration is provided on a Washington-allocated basis, and transfers to plant reflect the gross plant balance for each given year. Three comments on this chart have been indicated by bracketed numerals—with the associated comments following the illustration. Page 2 of 4 [1] – The 2015 ET (Enterprise Technology) transfers to plant include $61 million related to Washington’s share of Avista’s new Customer Information System (Project Compass). Excluding this $61 million, the remaining ET transfers to plant, for 2015, of $21.2 million are more consistent with (albeit higher than) the average ET transfers from 2007-2014 of $15.4 million. [2] – The 2016 planned generation transfers to plant include $71.3 million related to Washington’s share of major rehabilitation investments made on three Spokane River hydro projects (Nine Mile, Little Falls, and Post Falls—these projects are included as an after attrition adjustment item). Excluding this $71.3 million, the remaining generation transfers to plant, for 2016, of $28.7 million is more consistent with (albeit higher than) the average generation transfers to plant from 2007-2015 of $16.4 million. [3] – 2017 planned transfers to plant include investment of $71.7 million related to the implementation of advanced metering infrastructure (AMI) in Washington. This project has been included in this illustration as its own distinct group (were this project to be included within functional categories, $30.9 million would be included in the Electric Distribution category, $14.7 million would be included in the Gas category, $12.8 million would be included in the ET category, and 13.3 million would be included in the Other category). Additionally, pages three and four of this response include tabular presentations of this illustration, with the table on page three presenting the balances in dollars and the table on page four presenting the balances as percentages of the total transfers to plant in the given year. Page 3 of 4 Transfers to Plant, by Functional Category – Actual 2007-2015 and Planned 2016-2017 (in dollars): Planned Investment 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 Environmental 3,330,855 283,270 850,487 1,584,310 3,039,302 1,734,270 1,269,967 10,026,941 8,021,074 4,931,428 14,569,176 Gas 2,431,353 13,385,299 9,865,223 4,537,385 14,618,900 4,187,749 21,149,097 15,854,105 20,813,367 20,055,444 23,602,720 Generation 13,285,844 21,321,852 19,062,236 13,408,428 13,595,700 13,679,932 20,628,255 15,156,622 17,567,422 99,953,808 31,689,425 Growth 27,076,871 28,413,058 25,486,095 23,128,642 26,789,512 22,833,592 29,289,857 28,717,537 30,689,866 27,148,289 28,257,967 ET 7,304,727 9,604,673 10,304,028 10,931,957 15,666,399 19,858,981 24,462,364 25,335,450 82,242,961 23,139,401 33,848,957 Other 8,649,955 11,026,501 17,076,270 24,222,651 20,271,468 17,915,639 27,255,720 17,470,331 25,769,410 29,866,442 19,129,222 Electric Electric [1] 119,183,028 121,691,750 118,328,497 124,639,287 152,369,633 132,599,934 171,678,810 171,085,140 267,791,906 280,589,033 302,441,959 [1] – The majority of the difference between 2015 electric distribution transfers to plant and the electric distribution transfers to plant over the recent years is due to the capital investment related to the November 2015 Wind Storm. Page 4 of 4 Transfers to Plant, by Functional Category – Actual 2007-2015 and Planned 2016-2017 (as percentage of annual total): Planned Investment 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 Environmental 2.8% 0.2% 0.7% 1.3% 2.0% 1.3% 0.7% 5.9% 3.0% 1.8% 4.8% Gas 2.0% 11.0% 8.3% 3.6% 9.6% 3.2% 12.3% 9.3% 7.8% 7.1% 7.8% Generation 11.1% 17.5% 16.1% 10.8% 8.9% 10.3% 12.0% 8.9% 6.6% 35.6% 10.5% Growth 22.7% 23.3% 21.5% 18.6% 17.6% 17.2% 17.1% 16.8% 11.5% 9.7% 9.3% ET 6.1% 7.9% 8.7% 8.8% 10.3% 15.0% 14.2% 14.8% 30.7% 8.2% 11.2% Other 7.3% 9.1% 14.4% 19.4% 13.3% 13.5% 15.9% 10.2% 9.6% 10.6% 6.3% Electric Electric 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/06/2016 CASE NO: UE-160228 & UG-160229 WITNESS: Elizabeth Andrews REQUESTER: UTC Staff - Hancock RESPONDER: Joe Miller TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff – 032 TELEPHONE: (509) 495-4546 EMAIL: joe.miller@avistacorp.com REQUEST: Please provide a comparison between Avista’s electric and natural gas load forecasts, and normalized actual loads, for each of the past five calendar years. Staff acknowledges here that Avista’s load forecasting methodology changed sometime between July 2012 and January 2014. RESPONSE: See Staff_DR_032 Attachment A for the requested information. Per discussions with commission Staff the Company is providing a comparison of both annual usage and customers by rate schedule for the requested time period. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/06/2016 CASE NO: UE-160228 & UG-160229 WITNESS: Elizabeth Andrews REQUESTER: UTC Staff - Hancock RESPONDER: Joe Miller TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff – 032 TELEPHONE: (509) 495-4546 EMAIL: joe.miller@avistacorp.com REQUEST: Please provide a comparison between Avista’s electric and natural gas load forecasts, and normalized actual loads, for each of the past five calendar years. Staff acknowledges here that Avista’s load forecasting methodology changed sometime between July 2012 and January 2014. RESPONSE: See Staff_DR_032 Attachment A for the requested information. Per discussions with commission Staff the Company is providing a comparison of both annual usage and customers by rate schedule for the requested time period. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/11/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jody Morehouse REQUESTER: UTC Staff - Huang RESPONDER: Jody Morehouse/Karen Schuh TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff – 033 TELEPHONE: (509) 495-2293 EMAIL: karen.schuh@avistacorp.com REQUEST: Referring to Karen Schuh’s direct testimony, Exhibit No. __ (KKS-1T), page 34, line 7-13, please provide the all meeting minutes and other documents produced by or provided to the Jackson Prairie Storage Management Committee or its members or representatives with regard to the following capital and O & M projects at the Jackson Prairie Storage: 2016: $1,175,000 2017: $1,117,000 2018: $ 605,000 RESPONSE: Please see Avista’s CONFIDENTIAL response to data request Staff_DR_033C. Please note that Avista’s response to Staff_DR_033C is Confidential per Protective Order in UTC Dockets UE- 160228 and UG-160229. The minutes approving the 2016 budgeted capital amount are included in Staff_DR_033C CONFIDENTIAL Attachment A. Details regarding the 2016 amount, including Avista’s share, is included in Staff_DR_033C CONFIDENTIAL Attachment B. The five year capital budget is included in Staff_DR_033C CONFIDENTIAL Attachment C. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/11/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jody Morehouse REQUESTER: UTC Staff - Huang RESPONDER: Jody Morehouse/Karen Schuh TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff – 033 TELEPHONE: (509) 495-2293 EMAIL: karen.schuh@avistacorp.com REQUEST: Referring to Karen Schuh’s direct testimony, Exhibit No. __ (KKS-1T), page 34, line 7-13, please provide the all meeting minutes and other documents produced by or provided to the Jackson Prairie Storage Management Committee or its members or representatives with regard to the following capital and O & M projects at the Jackson Prairie Storage: 2016: $1,175,000 2017: $1,117,000 2018: $ 605,000 RESPONSE: Please see Avista’s CONFIDENTIAL response to data request Staff_DR_033C. Please note that Avista’s response to Staff_DR_033C is Confidential per Protective Order in UTC Dockets UE- 160228 and UG-160229. The minutes approving the 2016 budgeted capital amount are included in Staff_DR_033C CONFIDENTIAL Attachment A. Details regarding the 2016 amount, including Avista’s share, is included in Staff_DR_033C CONFIDENTIAL Attachment B. The five year capital budget is included in Staff_DR_033C CONFIDENTIAL Attachment C. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/11/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Scott Kinney REQUESTER: UTC Staff - Huang RESPONDER: Mike Mecham/Karen Schuh TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff – 034 TELEPHONE: (509) 495-2293 EMAIL: karen.schuh@avistacorp.com REQUEST: Please provide all documents and invoices supporting the “Colstrip Capital Additions monthly amount of $662,843 for 2016, January through December. This amount was included in Karen Schuh’s electric work paper under “Adjustment 2 Support for 2016” folder, “PF Detail Support.xlsx” file, “WA PF Major(E) worksheet, Cell F8-Q8. RESPONSE: Please see Avista’s CONFIDENTIAL response to data request Staff_DR_034C. Please note that Avista’s response to Staff_DR_034C is Confidential per Protective Order in UTC Dockets UE- 160228 and UG-160229. Please see the Staff_DR_034C CONFIDENTIAL Attachment A for details on the capital projects planned for Colstrip for 2016. The total of all the capital project forms attached represent the system amount of budgeted transfers to plant of $12, 292,000. The monthly transfer to plant of $662,843 is calculated by allocating the $12,292,000 to Washington Electric Operations and dividing by twelve months. See Staff_DR_034 Attachment A for a listing of the dollars associated with each project. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/11/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Scott Kinney REQUESTER: UTC Staff - Huang RESPONDER: Mike Mecham/Karen Schuh TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff – 034 TELEPHONE: (509) 495-2293 EMAIL: karen.schuh@avistacorp.com REQUEST: Please provide all documents and invoices supporting the “Colstrip Capital Additions monthly amount of $662,843 for 2016, January through December. This amount was included in Karen Schuh’s electric work paper under “Adjustment 2 Support for 2016” folder, “PF Detail Support.xlsx” file, “WA PF Major(E) worksheet, Cell F8-Q8. RESPONSE: Please see Avista’s CONFIDENTIAL response to data request Staff_DR_034C. Please note that Avista’s response to Staff_DR_034C is Confidential per Protective Order in UTC Dockets UE- 160228 and UG-160229. Please see the Staff_DR_034C CONFIDENTIAL Attachment A for details on the capital projects planned for Colstrip for 2016. The total of all the capital project forms attached represent the system amount of budgeted transfers to plant of $12, 292,000. The monthly transfer to plant of $662,843 is calculated by allocating the $12,292,000 to Washington Electric Operations and dividing by twelve months. See Staff_DR_034 Attachment A for a listing of the dollars associated with each project. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/04/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: UTC Staff - Huang RESPONDER: Bob Brandkamp/Annette Brandon TYPE: Data Request DEPT: Finance REQUEST NO.: Staff - 035 TELEPHONE: (509) 495-4924 EMAIL: bob.brandkamp@avistacorp.com REQUEST: Please provide all assumptions used to calculate the “Cross Check Insurance Expense, Adjustment 4.06 (electric), Adjustment 4.05 (Gas)” and Adjustment 18.06 (electric), Adjustment 18.03 (Gas).” RESPONSE: Please see the Company’s response to Staff_DR_019 through Staff_DR_026. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/04/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: UTC Staff - Huang RESPONDER: Bob Brandkamp/Annette Brandon TYPE: Data Request DEPT: Finance REQUEST NO.: Staff - 035 TELEPHONE: (509) 495-4924 EMAIL: bob.brandkamp@avistacorp.com REQUEST: Please provide all assumptions used to calculate the “Cross Check Insurance Expense, Adjustment 4.06 (electric), Adjustment 4.05 (Gas)” and Adjustment 18.06 (electric), Adjustment 18.03 (Gas).” RESPONSE: Please see the Company’s response to Staff_DR_019 through Staff_DR_026. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/05/2016 CASE NO: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: UTC Staff - Huang RESPONDER: Ryan Finesilver TYPE: Data Request DEPT: State & Fed Regulation REQUEST NO.: Staff - 036 TELEPHONE: (509) 495-4873 EMAIL: ryan.finesilver@avistacorp.com REQUEST: Please provide all assumptions used to calculate the “Cross Check Property Tax, Adjustment 4.05 (electric), Adjustment 4.06(Gas). RESPONSE: The Cross Check Property Tax adjustment starts with 2015 Restated Property Tax Expenses and adjusts to the estimated 2017 level. Electric: The restated property tax expense related to production and transmission (FERC Accounts 408150 and 408180) are allocated to WA and ID using the Company’s P/T Ratio. Distribution related property tax expenses (FERC Account 408170) are directly assigned to jurisdictions based on their location. The 2017 Pro Forma expense amount is provided in workpaper HPA-1. The 2017 Pro Forma expense amounts are allocated between Production, Transmission, and Distribution based on the 2015 categorical percentage of total amounts. For example, the 2015 amount in account 408150 is $3,326,221 (WA Electric) which is 23.9% of the total property tax expense for Washington electric. That percentage (23.9%) is then applied to the 2017 expense level of $14,780,330 to arrive at the Account 408150 expense of $3,532,500. The WA portion of the 2017 Pro Forma Expense is subtracted from the 2015 Restated Property Tax expense to arrive at the adjustment amount. (See also Avista’s response to ICNU_DR_106.) Natural Gas: Same treatment as above except FERC Account 408190 – R&P Property Tax – Storage is allocated between Washington and Idaho based on the Underground Storage allocation ratio of 63.70% Washington, $17.20% Idaho and 19.10% Oregon. Please see Staff_DR_036 Attachment A for details on the assumptions used for Company workpaper HPA-1 supporting the estimates of property tax expense. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/05/2016 CASE NO: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: UTC Staff - Huang RESPONDER: Ryan Finesilver TYPE: Data Request DEPT: State & Fed Regulation REQUEST NO.: Staff - 036 TELEPHONE: (509) 495-4873 EMAIL: ryan.finesilver@avistacorp.com REQUEST: Please provide all assumptions used to calculate the “Cross Check Property Tax, Adjustment 4.05 (electric), Adjustment 4.06(Gas). RESPONSE: The Cross Check Property Tax adjustment starts with 2015 Restated Property Tax Expenses and adjusts to the estimated 2017 level. Electric: The restated property tax expense related to production and transmission (FERC Accounts 408150 and 408180) are allocated to WA and ID using the Company’s P/T Ratio. Distribution related property tax expenses (FERC Account 408170) are directly assigned to jurisdictions based on their location. The 2017 Pro Forma expense amount is provided in workpaper HPA-1. The 2017 Pro Forma expense amounts are allocated between Production, Transmission, and Distribution based on the 2015 categorical percentage of total amounts. For example, the 2015 amount in account 408150 is $3,326,221 (WA Electric) which is 23.9% of the total property tax expense for Washington electric. That percentage (23.9%) is then applied to the 2017 expense level of $14,780,330 to arrive at the Account 408150 expense of $3,532,500. The WA portion of the 2017 Pro Forma Expense is subtracted from the 2015 Restated Property Tax expense to arrive at the adjustment amount. (See also Avista’s response to ICNU_DR_106.) Natural Gas: Same treatment as above except FERC Account 408190 – R&P Property Tax – Storage is allocated between Washington and Idaho based on the Underground Storage allocation ratio of 63.70% Washington, $17.20% Idaho and 19.10% Oregon. Please see Staff_DR_036 Attachment A for details on the assumptions used for Company workpaper HPA-1 supporting the estimates of property tax expense. Page 1 of 2 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/19/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: E. Andrews / S. Kinney REQUESTER: UTC Staff - Liu RESPONDER: Mike Mecham/Liz Andrews TYPE: Data Request DEPT: Spokane Area Thermal REQUEST NO.: Staff – 037 - Supplemental TELEPHONE: (509) 495-5781 EMAIL: mike.mecham@avistacorp.com REQUEST: With reference to Adjustment 3.12. E- PMM (PF Major Maint Normalize CS2/Colstrip) please provide the following information regarding Colstrip major maintenance: A. Detailed description of the major maintenance plan for Colstrip; B. The start date and projected end date for 2016 - 2018 major maintenance cycle; C. The expense detail by month: - Actual major maintenance expenditures for 2013, 2014 and 2015, identifying which expenditures were expensed as period costs and which were capitalized as to plant accounts; - The actual major maintenance expense as of March 31, 2016; - The most up-to-date budgeted expense known to the company for the remainder of 2016, 2017 and 2018. RESPONSE: Please see Avista’s CONFIDENTIAL response to data request Staff_DR_037C - Supplemental. Please note that Avista’s response to Staff_DR_037C - Supplemental is Confidential per Protective Order in UTC Dockets UE-160228 and UG-160229. A. For a description of the major maintenance plan for Colstrip Unit 4 2016 overhaul, see Staff_DR_037 – Attachment A, which includes a power point presentation of the work to be completed. B. See Staff_DR_037 – Attachment A, page 4. The 2016 Colstrip Unit 4 outage is planned for May 6th through June 26th (51 days). See Staff_DR_037 – Attachment B for planned outages 2017-2021. 2017 outage is planned for 05/4/17 – 06/16/2017 (44 days); no planned outage in 2018. C. See Staff_DR_037 – Attachment C for actual maintenance expenses for the period 2013-2016 (YTD- April). Capitalized expenditures of $6.7 million for 2013, $6.0 million for 2014 and $2.6 million for 2015, can be seen within Confidential Staff_DR_037C – Confidential Attachment A. See also Confidential Staff_DR_037C – Confidential Attachment A for budgeted expense and capital for 2016, 2017 and 2018. Supplemental – 05/20/2016 Per discussions with Staff, additional information regarding O&M and capital transactions is discussed below. The Company does not track Colstrip O&M by major and non-major activity. For Colstrip detailed information is available by month at the journal level within the Company’s general ledger system as provided in the original response. Plant data is grouped by project, recorded to the appropriate O&M FERC account, and allocated to WA and ID based on the Company’s Production/Transmission (P/T) Page 2 of 2 ratio. The Company receives monthly information from the plant operator (Talen Energy), which the Company records through journal entries into the system. Detailed transaction activity is located at the individual plants, and not at Avista. All information provided in attachment Staff_DR_037_Attachment C represents costs paid to third parties. Major Maintenance Expense: Colstrip classifies major maintenance on Units 3 & 4 as overhaul years. Each unit will have overhaul maintenance every third year: Unit 3 was 2014, Unit 4 was 2013, and 2016, is going on now. 2015 was a year where there was no overhaul major maintenance. Available information regarding actual Colstrip major O&M “overhaul costs,” separated by Talen from total Colstrip O&M, is provided in Staff_DR_037C- Supplemental – Confidential Attachment A for years 2013 and 2014.1 Colstrip Capital: 2013-2015 Capital: Talen, as project operator, does not provide monthly transaction detail information to Avista regarding capital projects. However, attached as Confidential Staff_DR_037 – Supplemental Confidential Attachments B and C (2015); D and E (2014); and F and G (2013), are files provided by Talen that lists the Capital budget items scheduled for 2015. Due to the size of these documents, they are being provided electronically only. The dollar amounts for each capital item provided in these documents are totals, not the 15% of Avista’s responsibility. 2016 – 2018 Capital additions: See Exhibit No. (SJK-1T), page 13, lines 4-12 and page 17, lines 4-6 for excerpted language provided below: Colstrip Capital Additions: 2016: $12,292,000 This program includes ongoing capital expenditures associated with normal outage activities on Units 3 & 4 at Colstrip. Every two out of three years, there are planned outages at Colstrip with higher capital program activities. For non-outage years, the program activities are reduced. Avista votes its 15% share of Units 3 & 4 and its approximate 10% share of common facilities to approve or disapprove of the planned expenditures proposed by Talen Energy on behalf of all the owners. See Exhibit No.__(KKS-5), Section 1, pages 20 through 23 for the business case and other information related to this project. Additional workpapers have also been provided with the Company’s filing. Colstrip Capital Additions: 2017: $12,432,000; 6 mos. ended June 2018: 2,518,000 Colstrip capital additions for the periods 2017 and the first half of 2018 are described above related to the modified test year Pro Forma Study. See also Avista’s response to Staff_DR_034C for files provided by Talen that lists the Capital budget items scheduled for 2016. 1 Staff_DR_037C- Supplemental – Confidential Attachment A shows 2014 major O&M “overhaul costs” of $12.6 million system and $1.9 million Avista’s share. Page 1 of 2 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/19/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: E. Andrews / S. Kinney REQUESTER: UTC Staff - Liu RESPONDER: Mike Mecham/Liz Andrews TYPE: Data Request DEPT: Spokane Area Thermal REQUEST NO.: Staff – 037 - Supplemental TELEPHONE: (509) 495-5781 EMAIL: mike.mecham@avistacorp.com REQUEST: With reference to Adjustment 3.12. E- PMM (PF Major Maint Normalize CS2/Colstrip) please provide the following information regarding Colstrip major maintenance: A. Detailed description of the major maintenance plan for Colstrip; B. The start date and projected end date for 2016 - 2018 major maintenance cycle; C. The expense detail by month: - Actual major maintenance expenditures for 2013, 2014 and 2015, identifying which expenditures were expensed as period costs and which were capitalized as to plant accounts; - The actual major maintenance expense as of March 31, 2016; - The most up-to-date budgeted expense known to the company for the remainder of 2016, 2017 and 2018. RESPONSE: Please see Avista’s CONFIDENTIAL response to data request Staff_DR_037C - Supplemental. Please note that Avista’s response to Staff_DR_037C - Supplemental is Confidential per Protective Order in UTC Dockets UE-160228 and UG-160229. A. For a description of the major maintenance plan for Colstrip Unit 4 2016 overhaul, see Staff_DR_037 – Attachment A, which includes a power point presentation of the work to be completed. B. See Staff_DR_037 – Attachment A, page 4. The 2016 Colstrip Unit 4 outage is planned for May 6th through June 26th (51 days). See Staff_DR_037 – Attachment B for planned outages 2017-2021. 2017 outage is planned for 05/4/17 – 06/16/2017 (44 days); no planned outage in 2018. C. See Staff_DR_037 – Attachment C for actual maintenance expenses for the period 2013-2016 (YTD- April). Capitalized expenditures of $6.7 million for 2013, $6.0 million for 2014 and $2.6 million for 2015, can be seen within Confidential Staff_DR_037C – Confidential Attachment A. See also Confidential Staff_DR_037C – Confidential Attachment A for budgeted expense and capital for 2016, 2017 and 2018. Supplemental – 05/20/2016 Per discussions with Staff, additional information regarding O&M and capital transactions is discussed below. The Company does not track Colstrip O&M by major and non-major activity. For Colstrip detailed information is available by month at the journal level within the Company’s general ledger system as provided in the original response. Plant data is grouped by project, recorded to the appropriate O&M FERC account, and allocated to WA and ID based on the Company’s Production/Transmission (P/T) Page 2 of 2 ratio. The Company receives monthly information from the plant operator (Talen Energy), which the Company records through journal entries into the system. Detailed transaction activity is located at the individual plants, and not at Avista. All information provided in attachment Staff_DR_037_Attachment C represents costs paid to third parties. Major Maintenance Expense: Colstrip classifies major maintenance on Units 3 & 4 as overhaul years. Each unit will have overhaul maintenance every third year: Unit 3 was 2014, Unit 4 was 2013, and 2016, is going on now. 2015 was a year where there was no overhaul major maintenance. Available information regarding actual Colstrip major O&M “overhaul costs,” separated by Talen from total Colstrip O&M, is provided in Staff_DR_037C- Supplemental – Confidential Attachment A for years 2013 and 2014.1 Colstrip Capital: 2013-2015 Capital: Talen, as project operator, does not provide monthly transaction detail information to Avista regarding capital projects. However, attached as Confidential Staff_DR_037 – Supplemental Confidential Attachments B and C (2015); D and E (2014); and F and G (2013), are files provided by Talen that lists the Capital budget items scheduled for 2015. Due to the size of these documents, they are being provided electronically only. The dollar amounts for each capital item provided in these documents are totals, not the 15% of Avista’s responsibility. 2016 – 2018 Capital additions: See Exhibit No. (SJK-1T), page 13, lines 4-12 and page 17, lines 4-6 for excerpted language provided below: Colstrip Capital Additions: 2016: $12,292,000 This program includes ongoing capital expenditures associated with normal outage activities on Units 3 & 4 at Colstrip. Every two out of three years, there are planned outages at Colstrip with higher capital program activities. For non-outage years, the program activities are reduced. Avista votes its 15% share of Units 3 & 4 and its approximate 10% share of common facilities to approve or disapprove of the planned expenditures proposed by Talen Energy on behalf of all the owners. See Exhibit No.__(KKS-5), Section 1, pages 20 through 23 for the business case and other information related to this project. Additional workpapers have also been provided with the Company’s filing. Colstrip Capital Additions: 2017: $12,432,000; 6 mos. ended June 2018: 2,518,000 Colstrip capital additions for the periods 2017 and the first half of 2018 are described above related to the modified test year Pro Forma Study. See also Avista’s response to Staff_DR_034C for files provided by Talen that lists the Capital budget items scheduled for 2016. 1 Staff_DR_037C- Supplemental – Confidential Attachment A shows 2014 major O&M “overhaul costs” of $12.6 million system and $1.9 million Avista’s share. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/11/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: E. Andrews / S. Kinney REQUESTER: UTC Staff - Liu RESPONDER: Mike Mecham/Liz Andrews TYPE: Data Request DEPT: Spokane Area Thermal REQUEST NO.: Staff - 037 TELEPHONE: (509) 495-5781 EMAIL: mike.mecham@avistacorp.com REQUEST: With reference to Adjustment 3.12. E- PMM (PF Major Maint Normalize CS2/Colstrip) please provide the following information regarding Colstrip major maintenance: A. Detailed description of the major maintenance plan for Colstrip; B. The start date and projected end date for 2016 - 2018 major maintenance cycle; C. The expense detail by month: - Actual major maintenance expenditures for 2013, 2014 and 2015, identifying which expenditures were expensed as period costs and which were capitalized as to plant accounts; - The actual major maintenance expense as of March 31, 2016; - The most up-to-date budgeted expense known to the company for the remainder of 2016, 2017 and 2018. RESPONSE: Please see Avista’s CONFIDENTIAL response to data request Staff_DR_037C. Please note that Avista’s response to Staff_DR_037C is Confidential per Protective Order in UTC Dockets UE- 160228 and UG-160229. A. For a description of the major maintenance plan for Colstrip Unit 4 2016 overhaul, see Staff_DR_037 – Attachment A, which includes a power point presentation of the work to be completed. B. See Staff_DR_037 – Attachment A, page 4. The 2016 Colstrip Unit 4 outage is planned for May 6th through June 26th (51 days). See Staff_DR_037 – Attachment B for planned outages 2017- 2021. 2017 outage is planned for 05/4/17 – 06/16/2017 (44 days); no planned outage in 2018. C. See Staff_DR_037 – Attachment C for actual maintenance expenses for the period 2013-2016 (YTD-April). Capitalized expenditures of $6.7 million for 2013, $6.0 million for 2014 and $2.6 million for 2015, can be seen within Confidential Staff_DR_037C – Confidential Attachment A. See also Confidential Staff_DR_037C – Confidential Attachment A for budgeted expense and capital for 2016, 2017 and 2018. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/11/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: E. Andrews / S. Kinney REQUESTER: UTC Staff - Liu RESPONDER: Mike Mecham/Liz Andrews TYPE: Data Request DEPT: Spokane Area Thermal REQUEST NO.: Staff - 037 TELEPHONE: (509) 495-5781 EMAIL: mike.mecham@avistacorp.com REQUEST: With reference to Adjustment 3.12. E- PMM (PF Major Maint Normalize CS2/Colstrip) please provide the following information regarding Colstrip major maintenance: A. Detailed description of the major maintenance plan for Colstrip; B. The start date and projected end date for 2016 - 2018 major maintenance cycle; C. The expense detail by month: - Actual major maintenance expenditures for 2013, 2014 and 2015, identifying which expenditures were expensed as period costs and which were capitalized as to plant accounts; - The actual major maintenance expense as of March 31, 2016; - The most up-to-date budgeted expense known to the company for the remainder of 2016, 2017 and 2018. RESPONSE: Please see Avista’s CONFIDENTIAL response to data request Staff_DR_037C. Please note that Avista’s response to Staff_DR_037C is Confidential per Protective Order in UTC Dockets UE- 160228 and UG-160229. A. For a description of the major maintenance plan for Colstrip Unit 4 2016 overhaul, see Staff_DR_037 – Attachment A, which includes a power point presentation of the work to be completed. B. See Staff_DR_037 – Attachment A, page 4. The 2016 Colstrip Unit 4 outage is planned for May 6th through June 26th (51 days). See Staff_DR_037 – Attachment B for planned outages 2017- 2021. 2017 outage is planned for 05/4/17 – 06/16/2017 (44 days); no planned outage in 2018. C. See Staff_DR_037 – Attachment C for actual maintenance expenses for the period 2013-2016 (YTD-April). Capitalized expenditures of $6.7 million for 2013, $6.0 million for 2014 and $2.6 million for 2015, can be seen within Confidential Staff_DR_037C – Confidential Attachment A. See also Confidential Staff_DR_037C – Confidential Attachment A for budgeted expense and capital for 2016, 2017 and 2018. Colstrip Power Plant Unit 4 2016 Overhaul Challenge Review Meeting April 13, 2016 Staff_DR_037 Attachment A Page 1 of 17 Agenda Welcome & Opening Remarks –Neil Dennehy Overview of Outage –Russ Dunn Safety & Environmental –Todd Wulf Turbine / Generator Projects –Kyle Lewis/ Shane Hensleigh Boiler Projects & Valves –Kelly Brainard TIP Project –Kelly Brainard Balance Of Plant Projects –Rick Borsheim Outage Organization –Russ Dunn Closing –Russ Dunn Staff_DR_037 Attachment A Page 2 of 17 Colstrip U4 Challenge Review Neil Dennehy Welcome and Opening Remarks Staff_DR_037 Attachment A Page 3 of 17 Colstrip U4 –Overview of Outage Russ Dunn Duration: May 6th to June 26 -51 Days Original Dates May 9th to June 28th Critical Path –Smart Burn Installation Cooling Tower/Circulation Water line Turbine Outage Boiler Repairs Key Outage Challenges Safety / Human Performance Craft Resource Availability Staff_DR_037 Attachment A Page 4 of 17 Colstrip U4 –Safety & Environmental Todd Wulf Safety Pre-Outage: Asbestos surveys –to reduce risk of surprises/delays Contractor Safety Orientation: May 11 On-site Rally April 21 Outage: On-site Safety Professional: 7 days a week Weekly Contractor Safety Meetings Overhaul Safety Initiatives: 2nd & 5th week Environmental Contractor MSDS process Staff_DR_037 Attachment A Page 5 of 17 Colstrip U4 –Turbine / Generator Projects Kyle Lewis/Shane Hensleigh Scope Generator Visual Inspection and H2 Seal inspection Turbine Valve Overhaul HP Turbine Switchgear Arc Suppression System installation on 4 Busses, 4A1,4A2,4A3,4A4 Turbine Accessories Major Work FW Heater replacement BFP Repairs BFBP Repairs Feed-water Heater Eddy Current Testing Condenser Tube Cleaning &Eddy Current Testing Staff_DR_037 Attachment A Page 6 of 17 Colstrip U4 –Boiler Projects Kelly Brainard Boiler O&M Work Boiler inspect & repair BWCP inspect & test Miscellaneous Valve Inspection and Repair Mill Inspections and Repair Coal Pipe Repair and Replace Bottom Ash Crusher Replacement Air Preheater Inspect and Repair Staff_DR_037 Attachment A Page 7 of 17 Colstrip U4 –Boiler Projects Kelly Brainard Boiler Capital Work Major Work Coutant Slope Tube Repair Low Nox Burner/Smart Burn Installation Boiler Water Wall Repair Nose Arch Repair Installation of New Retracts Reheat Terminal Tube Repair FD Fan Motor Rewind Staff_DR_037 Attachment A Page 8 of 17 Colstrip U4 –TIP Inspection Kelly Brainard TIP Major Work Inspection of Hot Reheat & Main Steam Piping Hot Reheat Steams and Girth Welds Main Steam Girth Welds FAC Inspection Several locations on Feedwater Piping, Warm Up Lines and Misc. Piping Risk / Contingency Analysis Identifying area of concern with NDE testing which may require additional testing or need repair. Staff_DR_037 Attachment A Page 9 of 17 Colstrip U4 –Balance of Plant Rick Borsheim Water Treatment Major Work Cooling Tower Structure Inspection and Repair Replace Circulating Water Pump and Motor 4 Cooling Tower Fan Motors replacements 4 Cooling Tower Fan Gear Box replacements Inspect Cooling Tower Circulating Pipe Repair Fiberglass 108” Circulating Distribution Line Clean & Inspect Cooling Tower Basin, Flumes & Distribution Pipes & Headers Fuels Area Major Work Replace #61 and #62 Belt Inspect and Repair Cascade Coal Drag Chains Replace #45 belt Gear box Staff_DR_037 Attachment A Page 10 of 17 Colstrip U4 –Balance of Plant Rick Borsheim Scrubbers Major Work Major Clean on 4 of the Scrubber Vessel Wash Tray tank inspection and repair I.D. Fan Motor Testing Replace ID fan Motor Stack Inspection General Maintenance Various piping systems inspection & repair Staff_DR_037 Attachment A Page 11 of 17 COLSTRIP 2016 UNIT 4 SCHEDULE INFORMATION Scheduling •Primavera software used for Talen Craft Scheduling •Schedule updated by Project Managers by 16:00 pm Monday thru Friday •Scheduler will analyze and report daily critical path and near critical paths to OCC Manpower •Talen –5 10 (one shift) •NAES –6 10 (two shifts) Boiler •NAES –7 10 (two shifts) Smart Burn •Siemens –6 10 (two shift weeks to follow) •Valve Contractor –6 10 (one shift) first 4 weeks Description Approx Talen Man Hours Approx Contractor Man Hours Approx Total Man Hours POU416 Overhaul Total 44,180 238,750 282,930 OHLBLR 1,000 200,000 201,000 OHLBLACC 7,000 80 7,080 OHLVLV 300 5,500 5,800 OHLTRB 2,500 4,000 6,500 OHTRBACC 7,000 250 7,250 OHLELEC 5,000 200 5,200 OHLINST 2,500 0 2,500 OHLFUELS 4,000 120 4,120 OHLSCRB 9,000 500 9,500 OHLWTTRT 2,600 10,000 12,600 OHTIP 40 1,500 1,540 OHBOP 300 0 300 OHFP 900 100 1,000 OHMILLS 2,000 15,000 17,000 POWENG 40 1,500 1,540 Staff_DR_037 Attachment A Page 12 of 17 Summary (reported in Millions) Sub Account Description Original Budget Current Plan Variance 106/500/503/ 600/700 Overhaul & Special Projects (O&M) $18.589 $18.589 $0.000 900 Capital $42.241 $42.241 $0.000 Totals $60.830 $60.830 $0.000 Staff_DR_037 Attachment A Page 13 of 17 Outage Site Manager Russ Dunn Safety Todd Wulf Marie Felice-Luebeck Zach Gilliland Scheduler Dave Johnson Operations Bill Deselms Outage Engineer Boiler Kelly Brainard Outage Engineer Balance of Plant Outage Engineer Turbine / Generator Shane Hensleigh Fuels Jesse Robertson Water Treatment Matt Potts Scrubbers Scott McManus Valves Randy Smith / Dana Miller Boiler Accessoires Kelly Brainard Dayla Topp Dave Houser Shawn Hage Boiler Dave Houser/Dayla Topp Turbine Accessories Shane Hensleigh Electrical AJ Barnes Instrument Don Peplow Operations Support Miars Candrian Late Shift Coverage Capital Project Managers Boiler Project -Dave Houser FD Fan Motor -Jon Boucher Coutant Slope –Dave Houser Reheat/Piping -Kelly Brainard Smart Burn /Air Preheater -Katie Lewis UNIT 4 2016 OVERHAUL ORGANIZATION Team Leader: Joe Kerzmann Team Leader: Ole Peterson Team Leader: Duane McPherson Team Leader: Mick Petersen Team Leader: Todd Olmstead Team Leader: Rob Hays Special Maintenance Condition Assessment-Kelly Brainard Team Leader: Rick Miller Mills Dick Hofacker Outage Control Center Staffed Mon-Fri 6:30-16:30 Cell phone 24x7 Russ Dunn Robin Shahan Jim Rogers Eric Petritz Rick Borsheim Steve Cox Cost Analysis Kathy Christian Layout Coordinator Brenda Menahan Team Leader: Ron Button Capital Project Managers Generator/Battery -Kyle Lewis Turbine Acc -Shane Hensleigh Switchgear -Doug Rust Over Speed -Mike Myers Capital Project Managers CircPump & Motor /CT Fill/CT Acid Supply-Jen Petritz Special Maintenance Stack Inspection-Paul Shook Special Maintenance DCS Updates & Burner Mgmt-Mike Myers Eddy Current Test-Shane Hensleigh Turbine Kyle Lewis Fire Protection Tom Reimers Staff_DR_037 Attachment A Page 14 of 17 Objective Colstrip Plant Unit 4 Daily Outage Report Day 01 of 50 MMMM DD, 2016 Safety: Monitor Stop Light Status: No. of events past 24 hours: Total no. of events for the outage: First Aid Recordable Lost Time Total Talen 0 NAES 0 Contractors 0 Total 0 0 0 0 Environmental Events: No New Incidents No. of events past 24 hours: 0 Total no. of events for the outage: 0 Human Performance.  . Critical Path Status: Critical Path:  Boiler Repairs  Circulating Water System  Smart Burn Installation  HP Turbine Repairs Days Days Days Days 0 0 0 0 Behind Behind Behind Behind Near Critical: Boiler Repairs Days 0 /Behind Breaker Close Milestone: 05/06/16, 0050 Breaker Close Forecast: 06/25/16, 2300 Staff_DR_037 Attachment A Page 15 of 17 Previous 24 hour Accomplishments  x Focus for next 24 hours:  x Technical / Engineering issues:  x Material issues and key components off site:  x Boiler Tube Repairs as of mm-dd-14 Water Tube Repair Description Totals Complete % Water Tubes cut out Water Tubes welds Steam Tube Repair Description Totals Complete % Steam Tubes cut out Steam Tubes welds Weld Quality Stats # Welds Checked NDE # Rejects Reject Rate Clearance Performance: Working Active Distributed Planned Released Closed Talen  Outage/Project Update:. x Staff_DR_037 Attachment A Page 16 of 17 Colstrip U4 –Closing Russ Dunn Questions Action Items Wrap-up Staff_DR_037 Attachment A Page 17 of 17 Page 1 of 2 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/11/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: E. Andrews / S. Kinney REQUESTER: UTC Staff - Liu RESPONDER: Mike Mecham/Liz Andrews TYPE: Data Request DEPT: Spokane Area Thermal REQUEST NO.: Staff - 038 TELEPHONE: (509) 495-5781 EMAIL: mike.mecham@avistacorp.com REQUEST: With reference to Adjustment 3.12. E- PMM (PF Major Maint Normalize CS2/Colstrip), please provide the following information regarding Coyote Springs 2 (CS2) major maintenance: A. Detailed description of the major maintenance plan for CS2; B. The projected start date and end date for the next maintenance cycle; C. Actual major maintenance expenditures for 2013, 2014, 2015 and 2016, identifying which expenditures were expensed as period costs and which were capitalized as to plant accounts; D. Support for projected expense of $6.5 million in 2020. RESPONSE: A. Prior to renegotiating the Long Term Service Agreement (LTSA) with GE the normal major maintenance cycle (a Hot Gas Path inspection or a ‘Major’ inspection) was on a 24,000 fired hour basis. This means that every 24,000 fired hours, previously identified parts within the combustion portion of the gas turbine required replacement. In the previous LTSA many of the parts that were to be used in the Hot Gas Path inspection that was scheduled for 2016 were not new but rebuilt, therefore not capitalized but expensed. Part of the LTSA renegotiation was to purchase Advanced Gas Path –capitalized (new) parts for the combustion turbine, which will be utilized instead of the Hot Gas Path - expensed parts that were previously planned to be installed in 2016. These Advanced Gas Path parts will be installed as new, upgraded parts, and will increase the MW Generation at Coyote Springs 2 while reducing the Heat Rate, and allow for an increased number of fired hours (32,000 hours instead of 24,000 hours) before requiring Major maintenance. B. The 2016 project start date was April 30, 2016 with an expected completion date of May 25, 2016. As noted in A above, this work will be capitalized. No major maintenance expense will occur in 2016. C. There were no actual major maintenance expenses during 2013-2015 as the prior Hot Gas Path major overhaul occurred in 2012. Related to 2016, see A above. D. The $6.5 million shown on workpaper Adjustment 3.12 E-PPM (PF Major Maintenance Normalize CS2/Colstrip) for 2020 was for illustrative purposes only and was not included in this case. This amount had been the amount previously expected for the Hot Gas Path major maintenance originally planned for 2016 prior to the renegotiation of the LTSA contract and prior to the renegotiation to purchase the Advanced Gas Path. As noted in A above, with this revised Advanced Hot Gas Path maintenance work to be completed in 2016, increasing the Page 2 of 2 required number of fired hours to 32,000 hours before requiring the next Major maintenance, the next planned maintenance is not expected prior to 2022. The cost of the 2022 major maintenance is not known at this time. Page 1 of 2 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/11/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: E. Andrews / S. Kinney REQUESTER: UTC Staff - Liu RESPONDER: Mike Mecham/Liz Andrews TYPE: Data Request DEPT: Spokane Area Thermal REQUEST NO.: Staff - 038 TELEPHONE: (509) 495-5781 EMAIL: mike.mecham@avistacorp.com REQUEST: With reference to Adjustment 3.12. E- PMM (PF Major Maint Normalize CS2/Colstrip), please provide the following information regarding Coyote Springs 2 (CS2) major maintenance: A. Detailed description of the major maintenance plan for CS2; B. The projected start date and end date for the next maintenance cycle; C. Actual major maintenance expenditures for 2013, 2014, 2015 and 2016, identifying which expenditures were expensed as period costs and which were capitalized as to plant accounts; D. Support for projected expense of $6.5 million in 2020. RESPONSE: A. Prior to renegotiating the Long Term Service Agreement (LTSA) with GE the normal major maintenance cycle (a Hot Gas Path inspection or a ‘Major’ inspection) was on a 24,000 fired hour basis. This means that every 24,000 fired hours, previously identified parts within the combustion portion of the gas turbine required replacement. In the previous LTSA many of the parts that were to be used in the Hot Gas Path inspection that was scheduled for 2016 were not new but rebuilt, therefore not capitalized but expensed. Part of the LTSA renegotiation was to purchase Advanced Gas Path –capitalized (new) parts for the combustion turbine, which will be utilized instead of the Hot Gas Path - expensed parts that were previously planned to be installed in 2016. These Advanced Gas Path parts will be installed as new, upgraded parts, and will increase the MW Generation at Coyote Springs 2 while reducing the Heat Rate, and allow for an increased number of fired hours (32,000 hours instead of 24,000 hours) before requiring Major maintenance. B. The 2016 project start date was April 30, 2016 with an expected completion date of May 25, 2016. As noted in A above, this work will be capitalized. No major maintenance expense will occur in 2016. C. There were no actual major maintenance expenses during 2013-2015 as the prior Hot Gas Path major overhaul occurred in 2012. Related to 2016, see A above. D. The $6.5 million shown on workpaper Adjustment 3.12 E-PPM (PF Major Maintenance Normalize CS2/Colstrip) for 2020 was for illustrative purposes only and was not included in this case. This amount had been the amount previously expected for the Hot Gas Path major maintenance originally planned for 2016 prior to the renegotiation of the LTSA contract and prior to the renegotiation to purchase the Advanced Gas Path. As noted in A above, with this revised Advanced Hot Gas Path maintenance work to be completed in 2016, increasing the Page 2 of 2 required number of fired hours to 32,000 hours before requiring the next Major maintenance, the next planned maintenance is not expected prior to 2022. The cost of the 2022 major maintenance is not known at this time. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/18/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Elizabeth Andrews REQUESTER: UTC Staff – Hancock RESPONDER: Tara Knox TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff - 039 TELEPHONE: (509) 495-4325 EMAIL: tara.knox@avistacorp.com REQUEST: Please provide the full “E-REV” and “GSFM” models, which are used to estimate future billing determinants. RESPONSE: Please see Avista’s CONFIDENTIAL response to data request no. Staff – 039C. Please note that Avista’s response to Staff – 039C is Confidential per Protective Order in UTC Dockets 160228 & UG-160229. The complete “E-REV” electric revenue forecast model that contributed the forecast billing determinants for the weighted revenue growth calculation in the Company’s electric attrition model is provided as Staff_DR_039C CONFIDENTIAL Attachment A. The complete “GSFM” natural gas revenue forecast model that contributed the forecast billing determinants for the weighted revenue growth calculation in the Company’s natural gas attrition model is provided as Staff_DR_039C CONFIDENTIAL Attachment B. These attachments are being provided in electronic format only due to size. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/18/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Elizabeth Andrews REQUESTER: UTC Staff – Hancock RESPONDER: Tara Knox TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff - 039 TELEPHONE: (509) 495-4325 EMAIL: tara.knox@avistacorp.com REQUEST: Please provide the full “E-REV” and “GSFM” models, which are used to estimate future billing determinants. RESPONSE: Please see Avista’s CONFIDENTIAL response to data request no. Staff – 039C. Please note that Avista’s response to Staff – 039C is Confidential per Protective Order in UTC Dockets 160228 & UG-160229. The complete “E-REV” electric revenue forecast model that contributed the forecast billing determinants for the weighted revenue growth calculation in the Company’s electric attrition model is provided as Staff_DR_039C CONFIDENTIAL Attachment A. The complete “GSFM” natural gas revenue forecast model that contributed the forecast billing determinants for the weighted revenue growth calculation in the Company’s natural gas attrition model is provided as Staff_DR_039C CONFIDENTIAL Attachment B. These attachments are being provided in electronic format only due to size. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/11/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Karen Schuh REQUESTER: UTC Staff - Hancock RESPONDER: Karen Schuh TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff – 040 TELEPHONE: (509) 495-2293 EMAIL: karen.schuh@avistacorp.com REQUEST: Please provide a list and detailed description of the electric projects associated with the ten largest transfers to Intangible Plant that have been placed into service between 2007 and 2015. RESPONSE: Please see Staff_DR_040 Attachment A for a detailed listing of all transfers to plant in Electric FERC accounts 301 through 303 Intangible plant for the years 2007 through 2015. The ten largest transfers are highlighted in pink. Due to the nature of a majority of these software projects these transfers by ER break down into several smaller transfers to plant for many different projects within each ER. A detailed list for each of the top ten ER’s with the underlying project descriptions is provided in separate tabs. Additional information related to these items is available for on-site review or sample selection. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/11/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Karen Schuh REQUESTER: UTC Staff - Hancock RESPONDER: Karen Schuh TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff – 040 TELEPHONE: (509) 495-2293 EMAIL: karen.schuh@avistacorp.com REQUEST: Please provide a list and detailed description of the electric projects associated with the ten largest transfers to Intangible Plant that have been placed into service between 2007 and 2015. RESPONSE: Please see Staff_DR_040 Attachment A for a detailed listing of all transfers to plant in Electric FERC accounts 301 through 303 Intangible plant for the years 2007 through 2015. The ten largest transfers are highlighted in pink. Due to the nature of a majority of these software projects these transfers by ER break down into several smaller transfers to plant for many different projects within each ER. A detailed list for each of the top ten ER’s with the underlying project descriptions is provided in separate tabs. Additional information related to these items is available for on-site review or sample selection. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/11/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Elizabeth Andrews/Karen Schuh REQUESTER: UTC Staff - Hancock RESPONDER: Karen Schuh TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff – 041 TELEPHONE: (509) 495-2293 EMAIL: karen.schuh@avistacorp.com REQUEST: Please provide Avista’s estimates of the Intangible, Production, Transmission, Distribution, and General components of Accumulated Depreciation and Amortizations for the 2007 through 2010 CBRs? Please provide those figures along with a description of how those estimates were produced. RESPONSE: After discussions with Staff it was determined that the actual components of Accumulated Depreciation and Amortizations would be preferable. Prior to 2010 the Company did not break out the functional groups of Accumulated Depreciation and Amortizations on the CBR’s. The functional breakout was located in the Results of Operations Reports that feed into the CBR’s and therefore, breakouts were done for another purpose. Therefore, the Company has included the actual functionalization of the Washington Electric Accumulated Depreciation and Amortization balances for the 2007 through 2010 CBRs in Staff_DR_041 Attachment A. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/11/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Elizabeth Andrews/Karen Schuh REQUESTER: UTC Staff - Hancock RESPONDER: Karen Schuh TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff – 041 TELEPHONE: (509) 495-2293 EMAIL: karen.schuh@avistacorp.com REQUEST: Please provide Avista’s estimates of the Intangible, Production, Transmission, Distribution, and General components of Accumulated Depreciation and Amortizations for the 2007 through 2010 CBRs? Please provide those figures along with a description of how those estimates were produced. RESPONSE: After discussions with Staff it was determined that the actual components of Accumulated Depreciation and Amortizations would be preferable. Prior to 2010 the Company did not break out the functional groups of Accumulated Depreciation and Amortizations on the CBR’s. The functional breakout was located in the Results of Operations Reports that feed into the CBR’s and therefore, breakouts were done for another purpose. Therefore, the Company has included the actual functionalization of the Washington Electric Accumulated Depreciation and Amortization balances for the 2007 through 2010 CBRs in Staff_DR_041 Attachment A. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/11/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Elizabeth Andrews/Karen Schuh REQUESTER: UTC Staff - Hancock RESPONDER: Karen Schuh TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff – 042 TELEPHONE: (509) 495-2293 EMAIL: karen.schuh@avistacorp.com REQUEST: Regarding electric service, what are the ten largest production plant retirements made since 2007? Please provide the studies and other documents that supported Avista’s decision to retire the production plants identified under this data request. RESPONSE: The Company has not retired a full production plant since 2007. Please see Staff_DR_042 Attachment A for a listing of the ten largest retirements from production plant FERC accounts since 2007. The studies and other documents supporting the retirement of these components are stored off-site, and it would be unduly burdensome to retrieve and copy all documentation. If there are specific items on Attachment A for which Staff would like to view documentation, Avista will retrieve and copy, or make available for viewing at Avista’s main office. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/11/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Elizabeth Andrews/Karen Schuh REQUESTER: UTC Staff - Hancock RESPONDER: Karen Schuh TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff – 042 TELEPHONE: (509) 495-2293 EMAIL: karen.schuh@avistacorp.com REQUEST: Regarding electric service, what are the ten largest production plant retirements made since 2007? Please provide the studies and other documents that supported Avista’s decision to retire the production plants identified under this data request. RESPONSE: The Company has not retired a full production plant since 2007. Please see Staff_DR_042 Attachment A for a listing of the ten largest retirements from production plant FERC accounts since 2007. The studies and other documents supporting the retirement of these components are stored off-site, and it would be unduly burdensome to retrieve and copy all documentation. If there are specific items on Attachment A for which Staff would like to view documentation, Avista will retrieve and copy, or make available for viewing at Avista’s main office. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/13/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Karen Schuh REQUESTER: UTC Staff - Huang RESPONDER: Karen Schuh TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff – 043 TELEPHONE: (509) 495-2293 EMAIL: karen.schuh@avistacorp.com REQUEST: Please provide in an Excel workbook all forecasted plant transfers by Expenditure Request by month for the period January 2015 through December 2015. Please use the same format as in Avista’s response to UTC Staff Data Request No. 12, Attachment A. Provide separate workbooks for electric and natural gas forecasted plant additions. RESPONSE: The Company does not have January 2015 through December 2015 forecasted transfers to plant by Expenditure request on a Washington Electric and Natural Gas allocated level. The excel model that generates this information was developed in mid-2015 and does not have the 2015 forecasted information by service and jurisdiction. The Company does have the system total of Expenditure Request’s (ER) by month subtotaled by functional group. Please see Staff_DR_043 Attachment A, which represents the Company’s 2015 Washington Electric and Natural Gas 2015 adjustment filed in Docket Nos. UE-150204 & UG- 150205. Tab “CAP15.3” shows the system total of Expenditure Request’s (ER) by month subtotaled by functional group. Tabs “15.2 – AMA Calc” and “15.1-Allocations” then calculate the AMA balance of the annual ER total, by functional group and allocates these balances to Washington Electric and Natural Gas. The first tab “CAP15” summarizes the Washington 2015 additions on an EOP basis and an AMA basis and calculates the associated accumulated depreciation and accumulated deferred federal income taxes. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/13/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Karen Schuh REQUESTER: UTC Staff - Huang RESPONDER: Karen Schuh TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff – 043 TELEPHONE: (509) 495-2293 EMAIL: karen.schuh@avistacorp.com REQUEST: Please provide in an Excel workbook all forecasted plant transfers by Expenditure Request by month for the period January 2015 through December 2015. Please use the same format as in Avista’s response to UTC Staff Data Request No. 12, Attachment A. Provide separate workbooks for electric and natural gas forecasted plant additions. RESPONSE: The Company does not have January 2015 through December 2015 forecasted transfers to plant by Expenditure request on a Washington Electric and Natural Gas allocated level. The excel model that generates this information was developed in mid-2015 and does not have the 2015 forecasted information by service and jurisdiction. The Company does have the system total of Expenditure Request’s (ER) by month subtotaled by functional group. Please see Staff_DR_043 Attachment A, which represents the Company’s 2015 Washington Electric and Natural Gas 2015 adjustment filed in Docket Nos. UE-150204 & UG- 150205. Tab “CAP15.3” shows the system total of Expenditure Request’s (ER) by month subtotaled by functional group. Tabs “15.2 – AMA Calc” and “15.1-Allocations” then calculate the AMA balance of the annual ER total, by functional group and allocates these balances to Washington Electric and Natural Gas. The first tab “CAP15” summarizes the Washington 2015 additions on an EOP basis and an AMA basis and calculates the associated accumulated depreciation and accumulated deferred federal income taxes. Page 1 of 2 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/17/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Scott Kinney REQUESTER: UTC Staff - Huang RESPONDER: Heide Evans/Karen Schuh TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff – 044 TELEPHONE: (509) 495-2293 EMAIL: karen.schuh@avistacorp.com REQUEST: Please provide the “FERC Construction Monthly Report” for the following Expenditure Request by month for the period September 2015 through December 2016. Please provide your response to this data request as actual monthly reports become available. This is a continuing request. 4140 Hydro 331-336 Nine Mile Redevelopment 4152 Hydro 331-336 Little Falls Powerhouse Redevelopment 4161 Hydro 331-336 CG HED U#1 Refurbishment 4162 Hydro 331-336 PF S Channel Gate Replacement RESPONSE: Please see Avista’s CONFIDENTIAL response to data request Staff_DR_044C. Please note that Avista’s response to Staff_DR_044C is Confidential per Protective Order in UTC Dockets UE- 160228 and UG-160229. Please see the FERC Monthly Construction Reports for September 2015 through April 2016 in Staff_DR_044C Confidential Attachments A-Q for the Nine Mile Redevelopment and the Post Falls South Channel Gate Replacement. The Post Falls South Channel Gate Replacement went into service in February of 2016, however, monthly construction reports will continue until the hoist motors are replaced. This is currently anticipated to take place in May. The Company will update this request monthly with the Nine Mile Redevelopment and Post Falls South Channel Gate Replacement reports as they become available. The Little Falls Powerhouse Redevelopment is not a FERC regulated dam and therefore, does not have FERC Construction reports. The Cabinet Gorge HED Unit one Refurbishment also does not have a FERC Monthly Construction reports because it is a refurbishment. Staff_DR_044C Confidential Attachment A – Nine Mile HED Monthly Report, September 2015 Staff_DR_044C Confidential Attachment B – Post Falls Hydroelectric Development, September 2015 Staff_DR_044C Confidential Attachment C – Nine Mile HED Monthly Report, October 2015 Staff_DR_044C Confidential Attachment D - Post Falls Hydroelectric Development, October 2015 Staff_DR_044C Confidential Attachment E - Nine Mile HED Monthly Report, November 2015 Staff_DR_044C Confidential Attachment F - Post Falls Hydroelectric Development, November 2015 Staff_DR_044C Confidential Attachment G - Nine Mile HED Monthly Report, December 2015 Staff_DR_044C Confidential Attachment H - Post Falls Hydroelectric Development, December 2015 Staff_DR_044C Confidential Attachment I - Nine Mile HED Monthly Report, January 2016 Page 2 of 2 Staff_DR_044C Confidential Attachment J - Post Falls Hydroelectric Development, January 2016 Staff_DR_044C Confidential Attachment K - Nine Mile HED Monthly Report, February 2016 Staff_DR_044C Confidential Attachment L - Post Falls Hydroelectric Development, February 2016 Staff_DR_044C Confidential Attachment M - Nine Mile HED Monthly Report, March 2016 Staff_DR_044C Confidential Attachment N - Post Falls Hydroelectric Development, March 2016 Staff_DR_044C Confidential Attachment O - Nine Mile HED Monthly Report, April 2016 Staff_DR_044C Confidential Attachment P - Post Falls Hydroelectric Development, April 2016 SUPPLEMENTAL 1: Please see the updated FERC construction reports for the month of May for the Nine Mile and Post Falls projects in the following attachments: Staff_DR_044C Confidential Attachment Q - Nine Mile HED Monthly Report, May 2016 Staff_DR_044C Confidential Attachment R- Post Falls Hydroelectric Development, May 2016 Page 1 of 2 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/17/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Scott Kinney REQUESTER: UTC Staff - Huang RESPONDER: Heide Evans/Karen Schuh TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff – 044 TELEPHONE: (509) 495-2293 EMAIL: karen.schuh@avistacorp.com REQUEST: Please provide the “FERC Construction Monthly Report” for the following Expenditure Request by month for the period September 2015 through December 2016. Please provide your response to this data request as actual monthly reports become available. This is a continuing request. 4140 Hydro 331-336 Nine Mile Redevelopment 4152 Hydro 331-336 Little Falls Powerhouse Redevelopment 4161 Hydro 331-336 CG HED U#1 Refurbishment 4162 Hydro 331-336 PF S Channel Gate Replacement RESPONSE: Please see Avista’s CONFIDENTIAL response to data request Staff_DR_044C. Please note that Avista’s response to Staff_DR_044C is Confidential per Protective Order in UTC Dockets UE- 160228 and UG-160229. Please see the FERC Monthly Construction Reports for September 2015 through April 2016 in Staff_DR_044C Confidential Attachments A-Q for the Nine Mile Redevelopment and the Post Falls South Channel Gate Replacement. The Post Falls South Channel Gate Replacement went into service in February of 2016, however, monthly construction reports will continue until the hoist motors are replaced. This is currently anticipated to take place in May. The Company will update this request monthly with the Nine Mile Redevelopment and Post Falls South Channel Gate Replacement reports as they become available. The Little Falls Powerhouse Redevelopment is not a FERC regulated dam and therefore, does not have FERC Construction reports. The Cabinet Gorge HED Unit one Refurbishment also does not have a FERC Monthly Construction reports because it is a refurbishment. Staff_DR_044C Confidential Attachment A – Nine Mile HED Monthly Report, September 2015 Staff_DR_044C Confidential Attachment B – Post Falls Hydroelectric Development, September 2015 Staff_DR_044C Confidential Attachment C – Nine Mile HED Monthly Report, October 2015 Staff_DR_044C Confidential Attachment D - Post Falls Hydroelectric Development, October 2015 Staff_DR_044C Confidential Attachment E - Nine Mile HED Monthly Report, November 2015 Staff_DR_044C Confidential Attachment F - Post Falls Hydroelectric Development, November 2015 Staff_DR_044C Confidential Attachment G - Nine Mile HED Monthly Report, December 2015 Staff_DR_044C Confidential Attachment H - Post Falls Hydroelectric Development, December 2015 Staff_DR_044C Confidential Attachment I - Nine Mile HED Monthly Report, January 2016 Page 2 of 2 Staff_DR_044C Confidential Attachment J - Post Falls Hydroelectric Development, January 2016 Staff_DR_044C Confidential Attachment K - Nine Mile HED Monthly Report, February 2016 Staff_DR_044C Confidential Attachment L - Post Falls Hydroelectric Development, February 2016 Staff_DR_044C Confidential Attachment M - Nine Mile HED Monthly Report, March 2016 Staff_DR_044C Confidential Attachment N - Post Falls Hydroelectric Development, March 2016 Staff_DR_044C Confidential Attachment O - Nine Mile HED Monthly Report, April 2016 Staff_DR_044C Confidential Attachment P - Post Falls Hydroelectric Development, April 2016 SUPPLEMENTAL 1: Please see the updated FERC construction reports for the month of May for the Nine Mile and Post Falls projects in the following attachments: Staff_DR_044C Confidential Attachment Q - Nine Mile HED Monthly Report, May 2016 Staff_DR_044C Confidential Attachment R- Post Falls Hydroelectric Development, May 2016 Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/11/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Karen Schuh REQUESTER: UTC Staff - Huang RESPONDER: Karen Schuh TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff – 045 TELEPHONE: (509) 495-2293 EMAIL: karen.schuh@avistacorp.com REQUEST: Please provide Washington allocation factors for the following Expenditure Request for 2016 for Washington Natural Gas operation. 3008 Gas Distribution 374-387 Aldyl -A Pipe Replacement $18,885,000 5005 Software 303 Information Technology Refresh Program $18,000,526 3007 Gas Distribution 374-387 Isolated Steel Replacement $3,550,000 3005 Gas Distribution 374-387 Gas Distribution Non-Revenue Blanket $6,000,000 7139 General 389-391 / 393- 395 / 397-398 Netwk Bldg Purchase and Renovation $9,600,000 RESPONSE: Please see Staff_DR_045 Attachment A for the Natural Gas Operations Allocation factors for the Expenditure Requests listed above. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/11/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Karen Schuh REQUESTER: UTC Staff - Huang RESPONDER: Karen Schuh TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff – 045 TELEPHONE: (509) 495-2293 EMAIL: karen.schuh@avistacorp.com REQUEST: Please provide Washington allocation factors for the following Expenditure Request for 2016 for Washington Natural Gas operation. 3008 Gas Distribution 374-387 Aldyl -A Pipe Replacement $18,885,000 5005 Software 303 Information Technology Refresh Program $18,000,526 3007 Gas Distribution 374-387 Isolated Steel Replacement $3,550,000 3005 Gas Distribution 374-387 Gas Distribution Non-Revenue Blanket $6,000,000 7139 General 389-391 / 393- 395 / 397-398 Netwk Bldg Purchase and Renovation $9,600,000 RESPONSE: Please see Staff_DR_045 Attachment A for the Natural Gas Operations Allocation factors for the Expenditure Requests listed above. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/11/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Karen Schuh REQUESTER: UTC Staff - Huang RESPONDER: Karen Schuh TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff – 046 TELEPHONE: (509) 495-2293 EMAIL: karen.schuh@avistacorp.com REQUEST: Please provide Washington allocation factors for the following Expenditure Request by for 2016 Washington Electric operation. 4140 Hydro 331-336 Nine Mile Redevelopment $73,193,360 4152 Hydro 331-336 Little Falls Powerhouse Redevelopment $22,891,899 4161 Hydro 331-336 CG HED U#1 Refurbishment $14,702,335 4162 Hydro 331-336 PF S Channel Gate Replacement $14,092,240 5005 Software 303 Information Technology Refresh Program $18,000,526 4116 Thermal 311-316 Colstrip Capital Additions $12,292,000 RESPONSE: Please see Staff_DR_046 Attachment A for the Washington Electric allocation factors for the Expenditure Requests listed above. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/11/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Karen Schuh REQUESTER: UTC Staff - Huang RESPONDER: Karen Schuh TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff – 046 TELEPHONE: (509) 495-2293 EMAIL: karen.schuh@avistacorp.com REQUEST: Please provide Washington allocation factors for the following Expenditure Request by for 2016 Washington Electric operation. 4140 Hydro 331-336 Nine Mile Redevelopment $73,193,360 4152 Hydro 331-336 Little Falls Powerhouse Redevelopment $22,891,899 4161 Hydro 331-336 CG HED U#1 Refurbishment $14,702,335 4162 Hydro 331-336 PF S Channel Gate Replacement $14,092,240 5005 Software 303 Information Technology Refresh Program $18,000,526 4116 Thermal 311-316 Colstrip Capital Additions $12,292,000 RESPONSE: Please see Staff_DR_046 Attachment A for the Washington Electric allocation factors for the Expenditure Requests listed above. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/18/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Karen Schuh REQUESTER: UTC Staff - Huang RESPONDER: Karen Schuh TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff – 047 TELEPHONE: (509) 495-2293 EMAIL: karen.schuh@avistacorp.com REQUEST: What does “Residual CWIP” mean? How does that work in calculation of AMA rate base amount? RESPONSE: The term “Residual CWIP”, as used in Schuh Workapapers and is an internal term used to describe a situation where, for example, there is a project that was originally planned to transfer-to-plant during the previous year (2015), but it was later determined that it would transfer-to-plant in 2016. These project costs are in Construction Work in Progress at the end of 2015, and will be added to the total transfer-to-plant balance in 2016. In the Company’s original filing, for the purpose of a calculating AMA rate base, these specific projects were estimated to be placed in service in the middle of 2016, as a conservative estimate. When completing Staff_DR_012 Attachment B Supplemental, the Company had more information regarding these projects, and placed these projects in the appropriate months that they will transfer during 2016. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/18/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Karen Schuh REQUESTER: UTC Staff - Huang RESPONDER: Karen Schuh TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff – 047 TELEPHONE: (509) 495-2293 EMAIL: karen.schuh@avistacorp.com REQUEST: What does “Residual CWIP” mean? How does that work in calculation of AMA rate base amount? RESPONSE: The term “Residual CWIP”, as used in Schuh Workapapers and is an internal term used to describe a situation where, for example, there is a project that was originally planned to transfer-to-plant during the previous year (2015), but it was later determined that it would transfer-to-plant in 2016. These project costs are in Construction Work in Progress at the end of 2015, and will be added to the total transfer-to-plant balance in 2016. In the Company’s original filing, for the purpose of a calculating AMA rate base, these specific projects were estimated to be placed in service in the middle of 2016, as a conservative estimate. When completing Staff_DR_012 Attachment B Supplemental, the Company had more information regarding these projects, and placed these projects in the appropriate months that they will transfer during 2016. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/16/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Andrews REQUESTER: UTC Staff - White RESPONDER: Ryan Finesilver TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff - 048 TELEPHONE: (509) 495-4873 EMAIL: ryan.finesilver@avistacorp.com REQUEST: Please provide (in Excel format) detailed income data reconciling to the following accounts for the following time periods as shown in the file Eliminate B O Tax, tab E-EBO-3: FERC account Revenue Class Time Period Revenue in Analysis 440000 01 Residential 2014.12 $803,858 442200 21 Firm Commercial 2015.02 $926,287 442300 31 Firm-Industrial 2015.08 $ 83,650 RESPONSE: Please see Staff_DR_048 Attachment A for the requested summary information. The detail transactions are provided electronically only. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/16/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Andrews REQUESTER: UTC Staff - White RESPONDER: Ryan Finesilver TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff - 048 TELEPHONE: (509) 495-4873 EMAIL: ryan.finesilver@avistacorp.com REQUEST: Please provide (in Excel format) detailed income data reconciling to the following accounts for the following time periods as shown in the file Eliminate B O Tax, tab E-EBO-3: FERC account Revenue Class Time Period Revenue in Analysis 440000 01 Residential 2014.12 $803,858 442200 21 Firm Commercial 2015.02 $926,287 442300 31 Firm-Industrial 2015.08 $ 83,650 RESPONSE: Please see Staff_DR_048 Attachment A for the requested summary information. The detail transactions are provided electronically only. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/16/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: UTC Staff - White RESPONDER: Ryan Finesilver TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff - 049 TELEPHONE: (509) 495-4873 EMAIL: ryan.finesilver@avistacorp.com REQUEST: Please provide (in Excel format) details income data reconciling to the following accounts for the following time periods as shown in the file Eliminate B O Tax, tab G-EBO-3: FERC account Revenue Class Time Period Revenue in Analysis 480000 01 Residential 2015.01 $600,610 481200 21 Firm Commercial 2014.12 $300,631 RESPONSE: Please see Staff_DR_049 Attachment A for the requested summary information. The detail transactions are provided electronically only. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/16/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: UTC Staff - White RESPONDER: Ryan Finesilver TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff - 049 TELEPHONE: (509) 495-4873 EMAIL: ryan.finesilver@avistacorp.com REQUEST: Please provide (in Excel format) details income data reconciling to the following accounts for the following time periods as shown in the file Eliminate B O Tax, tab G-EBO-3: FERC account Revenue Class Time Period Revenue in Analysis 480000 01 Residential 2015.01 $600,610 481200 21 Firm Commercial 2014.12 $300,631 RESPONSE: Please see Staff_DR_049 Attachment A for the requested summary information. The detail transactions are provided electronically only. Staff_DR_050 Attachment A Page 1 of 2 Staff_DR_050 Attachment A Page 2 of 2 Staff_DR_050 Attachment B Page 1 of 4 Staff_DR_050 Attachment B Page 2 of 4 Staff_DR_050 Attachment B Page 3 of 4 Staff_DR_050 Attachment B Page 4 of 4 Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/16/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: UTC Staff - White RESPONDER: Ryan Finesilver TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff - 050 TELEPHONE: (509) 495-4873 EMAIL: ryan.finesilver@avistacorp.com REQUEST: Spokane Municipal Code, Title 08 Taxation and Revenue / Chapter 08.10 Utilities, Franchise Taxes / Section 08.10.030 Business Activities Subject to Tax – Amounts states: “A. There is levied upon and shall be collected from all persons engaging in the following utility business activities a utility gross receipts tax or license fee measured by multiplying the rate specified times the gross income as follows: 1. Selling, wheeling, or furnishing electric light or power: Six percent of gross income.” Please explain why the company’s tariff Schedule 58 includes a tax for Spokane of 6.38%. RESPONSE: In 1991, The City of Spokane passed Ordinance No. C-30272 clarifying the computation of gross income to also include the impact of any tax levied pursuant to that ordinance. The change to the ordinance essentially places a tax on the tax which resulted in the higher tax rate of 6.38%. Please see Staff_DR_050 Attachment A for a copy of the City of Spokane’s letter to Washington Water Power (Avista) regarding the ordinance change. Please also see Staff_DR_050 Attachment B for a copy of Washington Water Power’s (Avista) 1991 Tariffs inclusive of the calculation of the 6.38% tax rate. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/16/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: UTC Staff - White RESPONDER: Ryan Finesilver TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff - 050 TELEPHONE: (509) 495-4873 EMAIL: ryan.finesilver@avistacorp.com REQUEST: Spokane Municipal Code, Title 08 Taxation and Revenue / Chapter 08.10 Utilities, Franchise Taxes / Section 08.10.030 Business Activities Subject to Tax – Amounts states: “A. There is levied upon and shall be collected from all persons engaging in the following utility business activities a utility gross receipts tax or license fee measured by multiplying the rate specified times the gross income as follows: 1. Selling, wheeling, or furnishing electric light or power: Six percent of gross income.” Please explain why the company’s tariff Schedule 58 includes a tax for Spokane of 6.38%. RESPONSE: In 1991, The City of Spokane passed Ordinance No. C-30272 clarifying the computation of gross income to also include the impact of any tax levied pursuant to that ordinance. The change to the ordinance essentially places a tax on the tax which resulted in the higher tax rate of 6.38%. Please see Staff_DR_050 Attachment A for a copy of the City of Spokane’s letter to Washington Water Power (Avista) regarding the ordinance change. Please also see Staff_DR_050 Attachment B for a copy of Washington Water Power’s (Avista) 1991 Tariffs inclusive of the calculation of the 6.38% tax rate. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/19/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: UTC Staff - White RESPONDER: Ryan Finesilver TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff - 051 TELEPHONE: (509) 495-4873 EMAIL: ryan.finesilver@avistacorp.com REQUEST: Please provide a narrative explanation and calculations (in Excel format) explaining how the ‘jurisdictional four factor’ allocation factors of 67.9% (WA) and 32.1% (ID) were developed (as shown in the file 1) 2015 inj dam adj.xls tab E-ID-1). RESPONSE: Please see the Company’s response to ICNU_DR_035. Please also see Ms. Smith’s workpapers “Allocation factors” for the calculation of the 67.9%. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/19/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: UTC Staff - White RESPONDER: Ryan Finesilver TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff - 051 TELEPHONE: (509) 495-4873 EMAIL: ryan.finesilver@avistacorp.com REQUEST: Please provide a narrative explanation and calculations (in Excel format) explaining how the ‘jurisdictional four factor’ allocation factors of 67.9% (WA) and 32.1% (ID) were developed (as shown in the file 1) 2015 inj dam adj.xls tab E-ID-1). RESPONSE: Please see the Company’s response to ICNU_DR_035. Please also see Ms. Smith’s workpapers “Allocation factors” for the calculation of the 67.9%. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/17/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: UTC Staff - White RESPONDER: Ryan Finesilver TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff - 052 TELEPHONE: (509) 495-4873 EMAIL: ryan.finesilver@avistacorp.com REQUEST: The company-filed Excel workbook titled $ 2013 Net Gains Losses – Test Year.xlsw is apparently corrupted, possibly due to the use of special characters ($, -) in the file name. Please provide a copy of this file without the special characters in the title. RESPONSE: The Company is unable to locate the referenced workpaper. The Net Gains and Losses adjustment is supported by workpaper 2016 Net Gains & Losses.xlsx as included with the Company’s workpapers. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/17/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: UTC Staff - White RESPONDER: Ryan Finesilver TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff - 052 TELEPHONE: (509) 495-4873 EMAIL: ryan.finesilver@avistacorp.com REQUEST: The company-filed Excel workbook titled $ 2013 Net Gains Losses – Test Year.xlsw is apparently corrupted, possibly due to the use of special characters ($, -) in the file name. Please provide a copy of this file without the special characters in the title. RESPONSE: The Company is unable to locate the referenced workpaper. The Net Gains and Losses adjustment is supported by workpaper 2016 Net Gains & Losses.xlsx as included with the Company’s workpapers. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/11/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Karen Schuh REQUESTER: UTC Staff - Huang RESPONDER: Karen Schuh TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff – 053 TELEPHONE: (509) 495-2293 EMAIL: karen.schuh@avistacorp.com REQUEST: Referring to Karen Schuh’s Exhibit No.___(KKS-5), Section 1, page 102, please provide the actual total annual amount spent from 2010 to 2015 for Little Falls Powerhouse Redevelopment RESPONSE: Please see Staff_DR_053 Attachment A for the annual amount spent from 2010 to 2015 for the Little Falls Powerhouse Redevelopment. Please note the amounts listed on KKS-5, Section 1, page 102 represent transfers to plant, and Staff_DR_053 Attachment A represents capital spend as requested above. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/11/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Karen Schuh REQUESTER: UTC Staff - Huang RESPONDER: Karen Schuh TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff – 053 TELEPHONE: (509) 495-2293 EMAIL: karen.schuh@avistacorp.com REQUEST: Referring to Karen Schuh’s Exhibit No.___(KKS-5), Section 1, page 102, please provide the actual total annual amount spent from 2010 to 2015 for Little Falls Powerhouse Redevelopment RESPONSE: Please see Staff_DR_053 Attachment A for the annual amount spent from 2010 to 2015 for the Little Falls Powerhouse Redevelopment. Please note the amounts listed on KKS-5, Section 1, page 102 represent transfers to plant, and Staff_DR_053 Attachment A represents capital spend as requested above. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/18/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Karen Schuh REQUESTER: UTC Staff - Huang RESPONDER: Karen Schuh TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff – 054 TELEPHONE: (509) 495-2293 EMAIL: karen.schuh@avistacorp.com REQUEST: ER 4152: Little Falls Powerhouse Redevelopment Referring to Karen Schuh’s workpaper, folder labelled “Adjustment 2 Support 2016”, Excel file “2016 CAP Summary Detail Support.xlsx”, worksheet “CAP16.3”, please explain why Avista includes $14,321,899 (Cell S95) Residual CWIP as of 12/31/2014 to its total amount for ER 4152. (8,570,000+14,321,899=22,891,899) RESPONSE: Please see the Company’s response to Staff_DR_047. All balances included in column S are project costs included in Construction Work in Progress at the end of 2015, and as necessary to reflect the total transfer-to-plant amounts, were added here to add to the total transfer-to-plant balance in 2016. Please note, column S, on worksheet “CAP 16.3” should be labeled “Residual CWIP at 12/31/15”. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/18/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Karen Schuh REQUESTER: UTC Staff - Huang RESPONDER: Karen Schuh TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff – 054 TELEPHONE: (509) 495-2293 EMAIL: karen.schuh@avistacorp.com REQUEST: ER 4152: Little Falls Powerhouse Redevelopment Referring to Karen Schuh’s workpaper, folder labelled “Adjustment 2 Support 2016”, Excel file “2016 CAP Summary Detail Support.xlsx”, worksheet “CAP16.3”, please explain why Avista includes $14,321,899 (Cell S95) Residual CWIP as of 12/31/2014 to its total amount for ER 4152. (8,570,000+14,321,899=22,891,899) RESPONSE: Please see the Company’s response to Staff_DR_047. All balances included in column S are project costs included in Construction Work in Progress at the end of 2015, and as necessary to reflect the total transfer-to-plant amounts, were added here to add to the total transfer-to-plant balance in 2016. Please note, column S, on worksheet “CAP 16.3” should be labeled “Residual CWIP at 12/31/15”. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/23/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Karen Schuh REQUESTER: UTC Staff - Huang RESPONDER: Karen Schuh TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff – 055 TELEPHONE: (509) 495-2293 EMAIL: karen.schuh@avistacorp.com REQUEST: ER 4161: CG HED U#1 Refurbishment Referring to Karen Schuh’s workpaper, folder labelled “Adjustment 2 Support 2016”, Excel file “2016 CAP Summary Detail Support.xlsx”, worksheet “CAP16.3”, please explain why the capital addition for ER 4161 is purely due to $14,702,335 (Cell S96) Residual CWIP as of 12/31/2014. RESPONSE: Please see the Company’s response to Staff_DR_047. All balances included in column S are project costs included in Construction Work in Progress at the end of 2015, and as necessary to reflect the total transfer-to-plant amounts, were added here to add to the total transfer-to-plant balance in 2016. Please note, column S, on worksheet “CAP 16.3” should be labeled “Residual CWIP at 12/31/15”. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/23/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Karen Schuh REQUESTER: UTC Staff - Huang RESPONDER: Karen Schuh TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff – 055 TELEPHONE: (509) 495-2293 EMAIL: karen.schuh@avistacorp.com REQUEST: ER 4161: CG HED U#1 Refurbishment Referring to Karen Schuh’s workpaper, folder labelled “Adjustment 2 Support 2016”, Excel file “2016 CAP Summary Detail Support.xlsx”, worksheet “CAP16.3”, please explain why the capital addition for ER 4161 is purely due to $14,702,335 (Cell S96) Residual CWIP as of 12/31/2014. RESPONSE: Please see the Company’s response to Staff_DR_047. All balances included in column S are project costs included in Construction Work in Progress at the end of 2015, and as necessary to reflect the total transfer-to-plant amounts, were added here to add to the total transfer-to-plant balance in 2016. Please note, column S, on worksheet “CAP 16.3” should be labeled “Residual CWIP at 12/31/15”. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/23/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Karen Schuh REQUESTER: UTC Staff - Huang RESPONDER: Karen Schuh TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff – 056 TELEPHONE: (509) 495-2293 EMAIL: karen.schuh@avistacorp.com REQUEST: ER 4162: PF S Channel Gate Replacement Referring to Karen Schuh’s workpaper, folder labelled “Adjustment 2 Support 2016”, Excel file “2016 CAP Summary Detail Support.xlsx”, worksheet “CAP16.3”, please explain why the capital addition for ER 4161 is purely due to $14,092,240 (Cell S97) Residual CWIP as of 12/31/2014. RESPONSE: Please see the Company’s response to Staff_DR_047. All balances included in column S are project costs included in Construction Work in Progress at the end of 2015, and as necessary to reflect the total transfer-to-plant amounts, were added here to add to the total transfer-to-plant balance in 2016. Please note, column S, on worksheet “CAP 16.3” should be labeled “Residual CWIP at 12/31/15”. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/23/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Karen Schuh REQUESTER: UTC Staff - Huang RESPONDER: Karen Schuh TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff – 056 TELEPHONE: (509) 495-2293 EMAIL: karen.schuh@avistacorp.com REQUEST: ER 4162: PF S Channel Gate Replacement Referring to Karen Schuh’s workpaper, folder labelled “Adjustment 2 Support 2016”, Excel file “2016 CAP Summary Detail Support.xlsx”, worksheet “CAP16.3”, please explain why the capital addition for ER 4161 is purely due to $14,092,240 (Cell S97) Residual CWIP as of 12/31/2014. RESPONSE: Please see the Company’s response to Staff_DR_047. All balances included in column S are project costs included in Construction Work in Progress at the end of 2015, and as necessary to reflect the total transfer-to-plant amounts, were added here to add to the total transfer-to-plant balance in 2016. Please note, column S, on worksheet “CAP 16.3” should be labeled “Residual CWIP at 12/31/15”. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/18/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Karen Schuh REQUESTER: UTC Staff - Huang RESPONDER: Karen Schuh TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff – 057 TELEPHONE: (509) 495-2293 EMAIL: karen.schuh@avistacorp.com REQUEST: ER 5005: Information Technology Refresh Program ER 3008: Aldyl -A Pipe Replacement Referring to Karen Schuh’s Exhibit No.___(KKS-5), please provide the actual total annual amount spent from 2007 to 2015 for the ER 5005: Information Technology Refresh Program and ER 3008: Aldyl -A Pipe Replacement. RESPONSE: Please see Staff_DR_057 Attachment A and Attachment B for the annual amount spent from 2007 to 2015 for the Information Technology Refresh Program and the Aldyl A Pipe Replacement Project. Please note the amounts listed on KKS-5 represent transfers-to-plant and Staff_DR_057 Attachments A and B represent capital spend as requested above. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/18/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Karen Schuh REQUESTER: UTC Staff - Huang RESPONDER: Karen Schuh TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff – 057 TELEPHONE: (509) 495-2293 EMAIL: karen.schuh@avistacorp.com REQUEST: ER 5005: Information Technology Refresh Program ER 3008: Aldyl -A Pipe Replacement Referring to Karen Schuh’s Exhibit No.___(KKS-5), please provide the actual total annual amount spent from 2007 to 2015 for the ER 5005: Information Technology Refresh Program and ER 3008: Aldyl -A Pipe Replacement. RESPONSE: Please see Staff_DR_057 Attachment A and Attachment B for the annual amount spent from 2007 to 2015 for the Information Technology Refresh Program and the Aldyl A Pipe Replacement Project. Please note the amounts listed on KKS-5 represent transfers-to-plant and Staff_DR_057 Attachments A and B represent capital spend as requested above. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/18/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Karen Schuh REQUESTER: UTC Staff - Huang RESPONDER: Karen Schuh TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff – 058 TELEPHONE: (509) 495-2293 EMAIL: karen.schuh@avistacorp.com REQUEST: Referring to Karen Schuh’s Exhibit No.___(KKS-5), Section 3, page 40, this is a memorandum dated 2/2/16 from Mike Faulkenberry, Director of Natural Gas. According to Mike Faulkenberry, paragraph 2, this program started in November 2011. Please provide the actual total annual amount spent from 2011 to 2015 for the ER 3007: Isolated Steel Replacement. RESPONSE: Please see Staff_DR_058 Attachment A for the annual amount spent from 2011 to 2015 for Isolated Steel Replacement Project. Please note the amounts listed on KKS-5, represent transfers-to-plant and Staff_DR_058 Attachment A represents capital spend as requested above. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/18/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Karen Schuh REQUESTER: UTC Staff - Huang RESPONDER: Karen Schuh TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff – 058 TELEPHONE: (509) 495-2293 EMAIL: karen.schuh@avistacorp.com REQUEST: Referring to Karen Schuh’s Exhibit No.___(KKS-5), Section 3, page 40, this is a memorandum dated 2/2/16 from Mike Faulkenberry, Director of Natural Gas. According to Mike Faulkenberry, paragraph 2, this program started in November 2011. Please provide the actual total annual amount spent from 2011 to 2015 for the ER 3007: Isolated Steel Replacement. RESPONSE: Please see Staff_DR_058 Attachment A for the annual amount spent from 2011 to 2015 for Isolated Steel Replacement Project. Please note the amounts listed on KKS-5, represent transfers-to-plant and Staff_DR_058 Attachment A represents capital spend as requested above. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/19/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Karen Schuh REQUESTER: UTC Staff - Huang RESPONDER: Karen Schuh TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff – 059 TELEPHONE: (509) 495-2293 EMAIL: karen.schuh@avistacorp.com REQUEST: ER 3005: Gas Distribution Non-Revenue Blanket Referring to Karen Schuh’s Exhibit No.___(KKS-5), Section 3, page 48, this is a memorandum dated 2/5/16 from Mike Faulkenberry, Director of Natural Gas. According to Mike Faulkenberry, paragraph 2, “the work in this program is mostly reactionary and is difficult to predict aside from using historical trends.” Please reconcile Mr. Faulkenberry’s statement with Avista’s forecast capital spend in 2016 for this program. For each capital addition included in this program, please provide the justification for the inclusion of each 2016 capital addition related to the Isolated Steel Replacement program. RESPONSE: ER 3005 – Gas Distribution Non-Revenue Blanket as described in Exhibit No.___(KKS-5) is difficult to predict aside from using historical trends, therefore, the Company looks at an overall five year historical average level of plant for this project, which for 2011 through 2015 represented $2.347 million on a Washington allocated basis. Please see Staff_DR_059 Attachment A for the detailed calculation. Therefore, the budgeted amount for 2016 is $2.442 million and represents a 4% increase to the historical average. The Company then allocates this to each month based on knowledge of the work in each month. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/19/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Karen Schuh REQUESTER: UTC Staff - Huang RESPONDER: Karen Schuh TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff – 059 TELEPHONE: (509) 495-2293 EMAIL: karen.schuh@avistacorp.com REQUEST: ER 3005: Gas Distribution Non-Revenue Blanket Referring to Karen Schuh’s Exhibit No.___(KKS-5), Section 3, page 48, this is a memorandum dated 2/5/16 from Mike Faulkenberry, Director of Natural Gas. According to Mike Faulkenberry, paragraph 2, “the work in this program is mostly reactionary and is difficult to predict aside from using historical trends.” Please reconcile Mr. Faulkenberry’s statement with Avista’s forecast capital spend in 2016 for this program. For each capital addition included in this program, please provide the justification for the inclusion of each 2016 capital addition related to the Isolated Steel Replacement program. RESPONSE: ER 3005 – Gas Distribution Non-Revenue Blanket as described in Exhibit No.___(KKS-5) is difficult to predict aside from using historical trends, therefore, the Company looks at an overall five year historical average level of plant for this project, which for 2011 through 2015 represented $2.347 million on a Washington allocated basis. Please see Staff_DR_059 Attachment A for the detailed calculation. Therefore, the budgeted amount for 2016 is $2.442 million and represents a 4% increase to the historical average. The Company then allocates this to each month based on knowledge of the work in each month. NO WARRANTY OR REPRESENTATION, EXPRESS OR IMPLIED, IS MADE AS TO THE ACCURACY OF THE INFORMATION CONTAINED HEREIN, ANDTHE SAME IS SUBMITTED SUBJECT TO ERRORS, OMISSIONS, CHANGE OF PRICE, RENTAL OR OTHER CONDITIONS, PRIOR SALE, LEASE ORFINANCING, OR WITHDRAWAL WITHOUT NOTICE, AND OF ANY SPECIAL LISTING CONDITIONS IMPOSED BY OUR PRINCIPALS NO WARRANTIESOR REPRESENTATIONS ARE MADE AS TO THE CONDITION OF THE PROPERTY OR ANY HAZARDS CONTAINED THEREIN ARE ANY TO BE IMPLIED. 107 S. Howard, Suite 500Spokane, WA 99201 +1 509 623 1000 naiblack.com Office/Retail Building For Sale 1717 W. 4th & 417 S. Ash, Spokane, WA 99204 Property Features • Improvements: 31,540 SF± - Office Building South: 22,134 SF± ·Built in 1962 & Includes Daylight Lower Level - Office Building North: 6,696 SF± ·Built in 1998 & Includes Daylight Lower Level - Detached Garage/Storage: 2,710 SF± ·Built in 1963 & 2002 - Office Buildings Connected by Underground Hallway - Loading Dock With Functioning Conveyor Belt - Well Maintained Mechanical, Electrical & Overall Building Amenities • Lot Size: 2.32 Acres ± (Combined) • Parking: 119 Car Parks (Including 4 ADA Spaces • Parcel #’s: 25241.3812 & 25241.3925 • Zoning: DTG (Downtown General) • Excellent Location on the Periphery of Downtown Spokane With Visible Signage from I-90 • Virtual Tour: www.tourfactory.com/1202537 Sale Price: $2,480,000 $2,250,000 Office/Medical Campus Opportunity Former AAA Corporate Center For Sale –Price Reduced! NO WARRANTY OR REPRESENTATION, EXPRESS OR IMPLIED, IS MADE AS TO THE ACCURACYOF THE INFORMATION CONTAINED HEREIN, AND THE SAME IS SUBMITTED SUBJECT TOERRORS, OMISSIONS, CHANGE OF PRICE, RENTAL OR OTHER CONDITIONS, PRIOR SALE, LEASEOR FINANCING, OR WITHDRAWAL WITHOUT NOTICE, AND OF ANY SPECIAL LISTINGCONDITIONS IMPOSED BY OUR PRINCIPALS NO WARRANTIES OR REPRESENTATIONS AREMADE AS TO THE CONDITION OF THE PROPERTY OR ANY HAZARDS CONTAINED THEREIN AREANY TO BE IMPLIED. Staff_DR_060 Attachment B Page 1 of 14 Office/Retail Building For SaleFor Sale Former AAA Corp. Center Property Location • Centrally Located with Good Access to/from Interstate-90 • Positioned Near the Central Business District, Medical District & Browne’s Addition Staff_DR_060 Attachment B Page 2 of 14 For Sale Former AAA Corp. Center Staff_DR_060 Attachment B Page 3 of 14 For Sale Former AAA Corp. Center Staff_DR_060 Attachment B Page 4 of 14 For Sale Former AAA Corp. Center Staff_DR_060 Attachment B Page 5 of 14 For Sale Former AAA Corp. Center Staff_DR_060 Attachment B Page 6 of 14 Office/Retail Building For SaleFor Sale Former AAA Corp. Center Staff_DR_060 Attachment B Page 7 of 14 Staff_DR_060 Attachment B Page 8 of 14 SPOKANE COUNTY PROPERTY TAX AND OTHER ASSESSMENT CHARGES STATEMENT TAX AND OTHER CHARGES DETAIL Spokane County Treasurer Spokane, WA 99210 Location: 1116 W. Broadway, Room 201Spokane, WA99260 Phone: (509) 477-4713Office Hours: Mon-Thurs, 8:30 - 4:00 Fri, 8:30 - 1:00 For payment options, please visit our website www.spokanecounty.org/treasurer YOUR CANCELLED CHECK IS YOUR RECEIPT YOUR CANCELLED CHECK IS YOUR RECEIPT 2ND HALF 1ST HALForFULL RETURN THIS STUB WITH SECONDHALF PAYMENT RETURN THIS STUB WITH FIRSTHALF OR FULL PAYMENT P.O. Box 199 Interest /Penalty on delinquent tax is calculated to April 30th. If paying before April 30th, call for current amount due. v7 1/22/15 2015 25241.3812 85538*292**50***1.482**1/4**************AUTO**3-DIGIT 980 AAA WASHINGTON/INLAND 1745 114TH AVE SE BELLEVUE WA 98004-6968 Parcel Number: 25241.3812 Make check payable to: Spokane County Treasurer Payment must be hand delivered or postmarked by October 31, 2015. By law there is no GRACE PERIOD. AAA WASHINGTON/INLAND 1745 114TH AVE SE BELLEVUE WA 98004 25241-3812 000000000000015472212015 If Minimum Amount Due was paid for 1st Half, 2nd Half amount due is $ 15,472.21 PO Box 199 Spokane, WA 99210-0199 Parcel Number: 25241.3812 Make check payable to: Spokane County Treasurer Payment must be hand delivered or postmarked by April 30, 2015. By law there is no GRACE PERIOD. AAA WASHINGTON/INLAND 1745 114TH AVE SE BELLEVUE WA 98004 Prior Amount Owing 1st Half 2015 Charges Payment Options: (A) Minimum Amount Due (B) OR All Amounts Owing $ 0.00 $ 15,472.21 $ 15,472.21 $ 30,944.42 25241-3812 000154722100030944422015 PO Box 199 Spokane, WA 99210-0199 Parcel#: 25241.3812 Tax Code: 0010 Property Location: 1717 W 4TH AVE Legal Desc:CANNONS ADDITION ALL BLK 15 & ALL VAC ALLEY LYG WITHIN Prior Amount Owing First Half 2015 ChargesMinimum Amount Due By 4/30/2015 Second Half 2015 Due By 10/31/2015All Amounts Owing $ 0.00 $ 15,472.21 $ 15,472.21 $ 15,472.21 $ 30,944.42 Taxable Value Levy Rate Regular Tax Conservation Weed 2,173,000 14.23718868 30,937.41 5.21 1.80Distribution of your Tax Levy of $30,937.41 Voter Approved = $13,837.83 or 44% A B C D Description Split % Split $ A = SCHOOL DIST 081 ..... 42.2 ...13,077.17 B = CITY OF SPOKANE ..... 31.3 ....9,669.96 C = STATE ............... 15.9 ....4,919.62 D = COUNTY .............. 10.6 ....3,270.66 Total Taxes:............... ...30,937.41 Staff_DR_060 Attachment B Page 9 of 14 SPOKANE COUNTY PROPERTY TAX AND OTHER ASSESSMENT CHARGES STATEMENT TAX AND OTHER CHARGES DETAIL Spokane County Treasurer Spokane, WA 99210 Location: 1116 W. Broadway, Room 201Spokane, WA99260 Phone: (509) 477-4713Office Hours: Mon-Thurs, 8:30 - 4:00 Fri, 8:30 - 1:00 For payment options, please visit our website www.spokanecounty.org/treasurer YOUR CANCELLED CHECK IS YOUR RECEIPT YOUR CANCELLED CHECK IS YOUR RECEIPT 2ND HALF 1ST HALForFULL RETURN THIS STUB WITH SECONDHALF PAYMENT RETURN THIS STUB WITH FIRSTHALF OR FULL PAYMENT P.O. Box 199 Interest /Penalty on delinquent tax is calculated to April 30th. If paying before April 30th, call for current amount due. v7 1/22/15 2015 25241.3925 85538*292**50***1.482**2/4**************AUTO**3-DIGIT 980 AAA WASHINGTON/INLAND 1745 114TH AVE SE BELLEVUE WA 98004-6968 Parcel Number: 25241.3925 Make check payable to: Spokane County Treasurer Payment must be hand delivered or postmarked by October 31, 2015. By law there is no GRACE PERIOD. AAA WASHINGTON/INLAND 1745 114TH AVE SE BELLEVUE WA 98004 25241-3925 000000000000001077822015 If Minimum Amount Due was paid for 1st Half, 2nd Half amount due is $ 1,077.82 PO Box 199 Spokane, WA 99210-0199 Parcel Number: 25241.3925 Make check payable to: Spokane County Treasurer Payment must be hand delivered or postmarked by April 30, 2015. By law there is no GRACE PERIOD. AAA WASHINGTON/INLAND 1745 114TH AVE SE BELLEVUE WA 98004 Prior Amount Owing 1st Half 2015 Charges Payment Options: (A) Minimum Amount Due (B) OR All Amounts Owing $ 0.00 $ 1,077.81 $ 1,077.81 $ 2,155.63 25241-3925 000010778100002155632015 PO Box 199 Spokane, WA 99210-0199 Parcel#: 25241.3925 Tax Code: 0010 Property Location: 417 S ASH ST Legal Desc:CANNONS ADD LTS 7 & 8, BLK 16 TOGETHER W/ S 1/2 OF VAC ALLEY LYG N & ADJ TO SD LTS. Prior Amount Owing First Half 2015 ChargesMinimum Amount Due By 4/30/2015 Second Half 2015 Due By 10/31/2015All Amounts Owing $ 0.00 $ 1,077.81 $ 1,077.81 $ 1,077.82 $ 2,155.63 Taxable Value Levy Rate Regular Tax Conservation Weed 150,930 14.23718868 2,148.81 5.02 1.80Distribution of your Tax Levy of $2,148.81 Voter Approved = $961.13 or 44% A B C D Description Split % Split $ A = SCHOOL DIST 081 ..... 42.2 ......908.29 B = CITY OF SPOKANE ..... 31.3 ......671.65 C = STATE ............... 15.9 ......341.70 D = COUNTY .............. 10.6 ......227.17 Total Taxes:............... ....2,148.81 Staff_DR_060 Attachment B Page 10 of 14 ĜȱȱTHIS IS NOT A BILL SEE INSIDE FOR DETAILS v5 2/27/14 ȱ ȱ¢ȱ 1116 W Broadway Ave. Spokane, WA 99260-0010 If you are a senior citizen or disabled, the State of Washington has two programs that may lower or defer your property taxes and/or special assessments. If you are not currently enrolled in the Senior/Disabled exemption program and would like an application, please mail the attached post card to the Spokane County Assessor’s 2I¿FH3RVWDJH5HTXLUHG SENIOR CITIZEN AND DISABLED PERSON’S EXEMPTION PROGRAM: <RXPD\TXDOLI\IRUDUHGXFWLRQin your property taxes if you meet the following criteria: Your total income cannot exceed the State of :DVKLQJWRQOLPLWRIIRUWKHSURJUDPDQGWKHKRPHIRUZKLFK\RXDUH¿OLQJPXVWEH\RXUSULQFLSDO residence. You must also meet one of the following criteria: 1) You are at least 61 years old on December 31; or 2) You are retired because of a physical disability; or 3) You are a widow(er) at least 57 years ROGZKRVHVSRXVHKDGDQDSSURYHGH[HPSWLRQRQ¿OHZLWKWKH$VVHVVRUDWWLPHRIGHDWK,I\RXTXDOLI\and receive an exemption, you must reapply every six years. You must also notify the Assessor of any change in circumstances affecting your eligibility. For information on exemptions, please visit our website www.spokanecounty.org/assessor. 463***49***0.382**1/1* INLAND AUTOMOBILE ASSOCIATION 1717 W 4TH AVE SPOKANE WA 99204-1701 25241.3925 Parcel Number: 25241.3925 Date: 05/30/2014 Tax Code Area: 10Parcel Number: 25241.3925 Property Address: 417 S ASH ST Legal Description: CANNONS ADD LTS 7 & 8, BLK 16 TOGETHER W/ S 1/2 OF VAC ALLEY LYG N & ADJ TO SD LTS. Staff_DR_060 Attachment B Page 11 of 14 In Washington, property is assessed at one hundred percent of the true and fair value unless otherwise provided by law. The true and fair value is defined in WAC 458-07-030 as market value. Additional Assessment, Levy, Tax and Property Information can be viewed at http://www.spokanecounty.org/assessor APPEALING YOUR ASSESSED VALUE: If you do not agree with the value the Assessor has determined for your property, you may appeal to the Spokane County Board of Equalization (BOE). You may appeal either the true and fair value and/or current use assessed value. An DSSHDOSHWLWLRQPD\EHREWDLQHGIURPWKH%2(7KHLUQXPEHULV3HWLWLRQVIRUDKHDULQJPXVWEH¿OHGZLWKWKH%2(RQRUbefore July 1st of the assessment year, or within 30 days of the date of the valuation notice, whichever date is later. Petitions received after WKRVHGDWHVZLOOEHGHQLHGRQWKHJURXQGVRIQRWKDYLQJEHHQWLPHO\¿OHG7KH%2(ZLOOFRQYHQHEHJLQQLQJ-XO\WK CURRENT USE ASSESSMENT INFORMATION: The Open Space Taxation Act allows property owners to apply to have their open space, farm and agriculture, and timber lands valued at the “current use,” rather than their “highest and best use.” If the application is approved, and an agreement with Spokane County is signed, a portion of the property taxes are deferred (not reduced or exempted) in exchange for KDYLQJWKHXVHRIWKHSURSHUW\UHPDLQDVDJUHHG&XUUHQWXVHFODVVL¿FDWLRQLQFOXGHVRSHQVSDFHDJULFXOWXUHDQGWLPEHUODQGV5&:and 84.34) v5 2/27/14 25241.3925 Parcel Number: 25241.3925 LAST DATE TO APPEAL: JULY 01, 2014 Valuation Questions please contact Appraiser: 66 via email at www.spokanecounty.org/contactassessor Phone: (509) 477-5916 THIS ASSESSED VALUE AFFECTS 2015 TAXES Description Valuation of Real Property Valuation of Real Property inOpen Space, Mixed Land Usesand Designated Forest Land. 2013 Value Land Buildings, etc. Total Value $138,130 $12,800 $150,930 Classified Land Buildings, etc. Total Value 2014 Value Land Buildings, etc. Total Value $138,130 $12,800 $150,930 Classified Land Buildings, etc. Total Value Exemption:Yes NoXPhone: 477-5754 463 Staff_DR_060 Attachment B Page 12 of 14 ĜȱȱTHIS IS NOT A BILL SEE INSIDE FOR DETAILS v5 2/27/14 ȱ ȱ¢ȱ 1116 W Broadway Ave. Spokane, WA 99260-0010 If you are a senior citizen or disabled, the State of Washington has two programs that may lower or defer your property taxes and/or special assessments. If you are not currently enrolled in the Senior/Disabled exemption program and would like an application, please mail the attached post card to the Spokane County Assessor’s 2I¿FH3RVWDJH5HTXLUHG SENIOR CITIZEN AND DISABLED PERSON’S EXEMPTION PROGRAM: <RXPD\TXDOLI\IRUDUHGXFWLRQin your property taxes if you meet the following criteria: Your total income cannot exceed the State of :DVKLQJWRQOLPLWRIIRUWKHSURJUDPDQGWKHKRPHIRUZKLFK\RXDUH¿OLQJPXVWEH\RXUSULQFLSDO residence. You must also meet one of the following criteria: 1) You are at least 61 years old on December 31; or 2) You are retired because of a physical disability; or 3) You are a widow(er) at least 57 years ROGZKRVHVSRXVHKDGDQDSSURYHGH[HPSWLRQRQ¿OHZLWKWKH$VVHVVRUDWWLPHRIGHDWK,I\RXTXDOLI\and receive an exemption, you must reapply every six years. You must also notify the Assessor of any change in circumstances affecting your eligibility. For information on exemptions, please visit our website www.spokanecounty.org/assessor. 463***49***0.382**2/1* INLAND AUTOMOBILE ASSOCIATION 1717 W 4TH AVE SPOKANE WA 99204-1701 25241.3812 Parcel Number: 25241.3812 Date: 05/30/2014 Tax Code Area: 10Parcel Number: 25241.3812 Property Address: 1717 W 4TH AVE Legal Description: CANNONS ADDITION ALL BLK 15 & ALL VAC ALLEY LYG WITHIN Staff_DR_060 Attachment B Page 13 of 14 In Washington, property is assessed at one hundred percent of the true and fair value unless otherwise provided by law. The true and fair value is defined in WAC 458-07-030 as market value. Additional Assessment, Levy, Tax and Property Information can be viewed at http://www.spokanecounty.org/assessor APPEALING YOUR ASSESSED VALUE: If you do not agree with the value the Assessor has determined for your property, you may appeal to the Spokane County Board of Equalization (BOE). You may appeal either the true and fair value and/or current use assessed value. An DSSHDOSHWLWLRQPD\EHREWDLQHGIURPWKH%2(7KHLUQXPEHULV3HWLWLRQVIRUDKHDULQJPXVWEH¿OHGZLWKWKH%2(RQRUbefore July 1st of the assessment year, or within 30 days of the date of the valuation notice, whichever date is later. Petitions received after WKRVHGDWHVZLOOEHGHQLHGRQWKHJURXQGVRIQRWKDYLQJEHHQWLPHO\¿OHG7KH%2(ZLOOFRQYHQHEHJLQQLQJ-XO\WK CURRENT USE ASSESSMENT INFORMATION: The Open Space Taxation Act allows property owners to apply to have their open space, farm and agriculture, and timber lands valued at the “current use,” rather than their “highest and best use.” If the application is approved, and an agreement with Spokane County is signed, a portion of the property taxes are deferred (not reduced or exempted) in exchange for KDYLQJWKHXVHRIWKHSURSHUW\UHPDLQDVDJUHHG&XUUHQWXVHFODVVL¿FDWLRQLQFOXGHVRSHQVSDFHDJULFXOWXUHDQGWLPEHUODQGV5&:and 84.34) v5 2/27/14 25241.3812 Parcel Number: 25241.3812 LAST DATE TO APPEAL: JULY 01, 2014 Valuation Questions please contact Appraiser: 66 via email at www.spokanecounty.org/contactassessor Phone: (509) 477-5916 THIS ASSESSED VALUE AFFECTS 2015 TAXES Description Valuation of Real Property Valuation of Real Property inOpen Space, Mixed Land Usesand Designated Forest Land. 2013 Value Land Buildings, etc. Total Value $1,125,000 $1,050,800 $2,175,800 Classified Land Buildings, etc. Total Value 2014 Value Land Buildings, etc. Total Value $1,125,000 $1,048,000 $2,173,000 Classified Land Buildings, etc. Total Value Exemption:Yes NoXPhone: 477-5754 463 Staff_DR_060 Attachment B Page 14 of 14 • Parcel: 35173.1003 • Building Square Footage: ±50,942 Main Level: ±35,608 RSF Lower level: ±14,434 RSF (storage) • Parking Exterior: 61 (including 29 fenced) Secured Interior: 48 • Five (5) rooftop units, two (2) basement Reznor heating units • Ideal re-development opportunity • Year Built: 1954 PROPERTY INFORMATION Craig Soehren 509.755.7548 or craigs@khco.com No warranty or representation, expressed or implied, is made by Kiemle & Hagood Company, its agents or its employees as to the accuracy of the information contained herein. All information furnished is from sources deemed reliable and submitted subject to errors, omissions, change of terms and conditions, prior sale, lease or financing, or withdrawal without notice. No one should rely solely on the above information, but instead should conduct their own investigation to independently satisfy themselves. 509.838.6541 khco.com Sale Price: $2,975,000.00 FOR SALE NÏÏ 627 E Sprague 627 E. Sprague Avenue Spokane, WA 99202 U DISTRICT OFFICETECH BUILDING Staff_DR_060 Attachment C Page 1 of 10 509.838.6541 khco.com Craig Soehren 509.755.7548 or craigs@khco.com Kiemle & Hagood Company respects the intellectual property of others:If you believe the copyright in your work has been violated though this Website, please contact our office for notice of claims of copyright infringement. For your complaint to be valid under the Digital Millennium Copyright Act of 1998 (DMCA), you must provide the following information when providing notice of the claimed copyright infringement: Identify the material on the Website that you believe infringes your work, with enough detail so that we may locate it on the Website; provide your address, telephone number and email address; provide a statement that you have a good faith belief that the disputed use in not authorized by the copyright owner, its agent, or the law; provide a statement that the information in the notification is accurate, and under penalty of perjury, that the complaining party is authorized to act on behalf of owner of an exclusive right that is allegedly infringed; provide your physical or electronic signature.Upon receiving your complaint, Kiemle & Hagood Company will, upon review, remove content that you believe infringes your copyright if the complaint is found valid. Staff_DR_060 Attachment C Page 2 of 10 No warranty or representation, expressed or implied, is made by Kiemle & Hagood Company, its agents or its employees as to the accuracy of the information contained herein. All information furnished is from sources deemed reliable and submitted subject to errors, omissions, change of terms and conditions, prior sale, lease or financing, or withdrawal without notice. No one should rely solely on the above information, but instead should conduct their own investigation to independently satisfy themselves. 509.838.6541 khco.com NÏ 627 E. SPRAGUE AVE FOR SALE 627 E. Sprague Avenue Spokane, WA 99202 Craig Soehren 509.755.7548 or craigs@khco.com Staff_DR_060 Attachment C Page 3 of 10 Staff_DR_060 Attachment C Page 4 of 10 Staff_DR_060 Attachment C Page 5 of 10 Staff_DR_060 Attachment C Page 6 of 10 Staff_DR_060 Attachment C Page 7 of 10 ĜȱȱTHIS IS NOT A BILL SEE INSIDE FOR DETAILS v5 2/27/14 ȱ ȱ¢ȱ 1116 W Broadway Ave. Spokane, WA 99260-0010 If you are a senior citizen or disabled, the State of Washington has two programs that may lower or defer your property taxes and/or special assessments. If you are not currently enrolled in the Senior/Disabled exemption program and would like an application, please mail the attached post card to the Spokane County Assessor’s 2I¿FH3RVWDJH5HTXLUHG SENIOR CITIZEN AND DISABLED PERSON’S EXEMPTION PROGRAM: <RXPD\TXDOLI\IRUDUHGXFWLRQin your property taxes if you meet the following criteria: Your total income cannot exceed the State of :DVKLQJWRQOLPLWRIIRUWKHSURJUDPDQGWKHKRPHIRUZKLFK\RXDUH¿OLQJPXVWEH\RXUSULQFLSDO residence. You must also meet one of the following criteria: 1) You are at least 61 years old on December 31; or 2) You are retired because of a physical disability; or 3) You are a widow(er) at least 57 years ROGZKRVHVSRXVHKDGDQDSSURYHGH[HPSWLRQRQ¿OHZLWKWKH$VVHVVRUDWWLPHRIGHDWK,I\RXTXDOLI\and receive an exemption, you must reapply every six years. You must also notify the Assessor of any change in circumstances affecting your eligibility. For information on exemptions, please visit our website www.spokanecounty.org/assessor. 57070*43**70***0.212**1/1************AUTO**5-DIGIT 99201 DBSI SPRAGUE, LLC ETAL C/O KIEMLE & HAGOOD CO 601 W MAIN AVE STE 400 SPOKANE WA 99201-0613 35173.1003 Parcel Number: 35173.1003 Date: 05/30/2014 Tax Code Area: 14Parcel Number: 35173.1003 Property Address: 627 E SPRAGUE AVE Legal Description: RAILROAD 1ST TO 3RD E150FT B1 &PT OF VAC ST B1 S48.5 FT OF E150FT OF VAC RIVERSIDE AVE BET B1&2 & W3 Staff_DR_060 Attachment C Page 8 of 10 In Washington, property is assessed at one hundred percent of the true and fair value unless otherwise provided by law. The true and fair value is defined in WAC 458-07-030 as market value. Additional Assessment, Levy, Tax and Property Information can be viewed at http://www.spokanecounty.org/assessor APPEALING YOUR ASSESSED VALUE: If you do not agree with the value the Assessor has determined for your property, you may appeal to the Spokane County Board of Equalization (BOE). You may appeal either the true and fair value and/or current use assessed value. An DSSHDOSHWLWLRQPD\EHREWDLQHGIURPWKH%2(7KHLUQXPEHULV3HWLWLRQVIRUDKHDULQJPXVWEH¿OHGZLWKWKH%2(RQRUbefore July 1st of the assessment year, or within 30 days of the date of the valuation notice, whichever date is later. Petitions received after WKRVHGDWHVZLOOEHGHQLHGRQWKHJURXQGVRIQRWKDYLQJEHHQWLPHO\¿OHG7KH%2(ZLOOFRQYHQHEHJLQQLQJ-XO\WK CURRENT USE ASSESSMENT INFORMATION: The Open Space Taxation Act allows property owners to apply to have their open space, farm and agriculture, and timber lands valued at the “current use,” rather than their “highest and best use.” If the application is approved, and an agreement with Spokane County is signed, a portion of the property taxes are deferred (not reduced or exempted) in exchange for KDYLQJWKHXVHRIWKHSURSHUW\UHPDLQDVDJUHHG&XUUHQWXVHFODVVL¿FDWLRQLQFOXGHVRSHQVSDFHDJULFXOWXUHDQGWLPEHUODQGV5&:and 84.34) v5 2/27/14 35173.1003 Parcel Number: 35173.1003 LAST DATE TO APPEAL: JULY 01, 2014 Valuation Questions please contact Appraiser: 115 via email at www.spokanecounty.org/contactassessor Phone: (509) 477-5910 THIS ASSESSED VALUE AFFECTS 2015 TAXES Description Valuation of Real Property Valuation of Real Property inOpen Space, Mixed Land Usesand Designated Forest Land. 2013 Value Land Buildings, etc. Total Value $391,500 $2,320,200 $2,711,700 Classified Land Buildings, etc. Total Value 2014 Value Land Buildings, etc. Total Value $391,500 $2,082,300 $2,473,800 Classified Land Buildings, etc. Total Value Exemption:Yes NoXPhone: 477-5754 57070 Staff_DR_060 Attachment C Page 9 of 10 SPOKANE COUNTY PROPERTY TAX AND OTHER ASSESSMENT CHARGES STATEMENT TAX AND OTHER CHARGES DETAIL Spokane County Treasurer Spokane, WA 99210 Location: 1116 W. Broadway, Room 201Spokane, WA99260 Phone: (509) 477-4713Office Hours: Mon-Thurs, 8:30 - 4:00 Fri, 8:30 - 1:00 For payment options, please visit our website www.spokanecounty.org/treasurer YOUR CANCELLED CHECK IS YOUR RECEIPT YOUR CANCELLED CHECK IS YOUR RECEIPT 2ND HALF 1ST HALForFULL RETURN THIS STUB WITH SECONDHALF PAYMENT RETURN THIS STUB WITH FIRSTHALF OR FULL PAYMENT P.O. Box 199 Interest /Penalty on delinquent tax is calculated to April 30th. If paying before April 30th, call for current amount due. v7 1/22/15 2015 35173.1003 750***09***0.762**1/1* DBSI SPRAGUE, LLC C/O KIEMLE & HAGOOD 601 W MAIN STE 400 SPOKANE WA 99201 Parcel Number: 35173.1003 Make check payable to: Spokane County Treasurer Payment must be hand delivered or postmarked by October 31, 2015. By law there is no GRACE PERIOD. DBSI SPRAGUE, LLC C/O KIEMLE & HAGOOD 601 W MAIN STE 400 SPOKANE WA 99201 35173-1003 000000000000017613462015 If Minimum Amount Due was paid for 1st Half, 2nd Half amount due is $ 17,613.46 PO Box 199 Spokane, WA 99210-0199 Parcel Number: 35173.1003 Make check payable to: Spokane County Treasurer Payment must be hand delivered or postmarked by April 30, 2015. By law there is no GRACE PERIOD. DBSI SPRAGUE, LLC C/O KIEMLE & HAGOOD 601 W MAIN STE 400 SPOKANE WA 99201 Prior Amount Owing 1st Half 2015 Charges Payment Options: (A) Minimum Amount Due (B) OR All Amounts Owing $ 0.00 $ 17,613.45 $ 17,613.45 $ 35,226.91 35173-1003 000176134500035226912015 PO Box 199 Spokane, WA 99210-0199 Parcel#: 35173.1003 Tax Code: 0014 Property Location: 627 E SPRAGUE AVE Legal Desc:RAILROAD 1ST TO 3RD E150FT B1 &PT OF VAC ST B1 S48.5 FT OF E150FT OF VAC RIVERSIDE AVE BET B1&2 & W37.50FT VAC HATCH ST ADJ Prior Amount Owing First Half 2015 ChargesMinimum Amount Due By 4/30/2015 Second Half 2015 Due By 10/31/2015All Amounts Owing $ 0.00 $ 17,613.45 $ 17,613.45 $ 17,613.46 $ 35,226.91 Taxable Value Levy Rate Regular Tax Conservation Weed 2,473,800 14.23718868 35,219.96 5.15 1.80Distribution of your Tax Levy of $35,219.96 Voter Approved = $15,753.34 or 44% A B C D Description Split % Split $ A = SCHOOL DIST 081 ..... 42.2 ...14,887.39 B = CITY OF SPOKANE ..... 31.3 ...11,008.53 C = STATE ............... 15.9 ....5,600.63 D = COUNTY .............. 10.6 ....3,723.41 Total Taxes:............... ...35,219.96 Staff_DR_060 Attachment C Page 10 of 10 PROPERTY INFORMATION James G. Quigley 509.755.7560 or jgq@khco.com No warranty or representation, expressed or implied, is made by Kiemle & Hagood Company, its agents or its employees as to the accuracy of the information contained herein. All information furnished is from sources deemed reliable and submitted subject to errors, omissions, change of terms and conditions, prior sale, lease or financing, or withdrawal without notice. No one should rely solely on the above information, but instead should conduct their own investigation to independently satisfy themselves. 509.838.6541 khco.com Sale Price: $3,500,000 $3,200,000 FOR SALE Former Hostess Bakery Facility 803 N. Post Street, Spokane, WA 99201OWNE R MOTIV A T E D ! LIGH T WAREH O U S E AND RETAI L SPACE Outstanding Location Close to Downtown & I-90 MIXED USE / REDEVELOPMENT OPPORTUNITY PROPERTY SIZE: Land: ±76,800 SF / 1.76 AC Building Gross: ±111,468 • Sale Price: $3,500,000 $3,200,000 • Land SF: ±76,800 SF / 1.76 Acres - Paved Parking Area and Easy Access • Parcel Number: 35182.4301 • 2014 Taxes: $16,362.32 • Great Location near Downtown, Spokane Arena, and The Flour Mill. Staff_DR_060 Attachment D Page 1 of 3 James G. Quigley 509.755.7560 or jgq@khco.com No warranty or representation, expressed or implied, is made by Kiemle & Hagood Company, its agents or its employees as to the accuracy of the information contained herein. All information furnished is from sources deemed reliable and submitted subject to errors, omissions, change of terms and conditions, prior sale, lease or financing, or withdrawal without notice. No one should rely solely on the above information, but instead should conduct their own investigation to independently satisfy themselves. 509.838.6541 khco.com DEMOGRAPHICS 1 Mile 3 Miles 5 Miles 10 Miles 2011 Est Population 14,942 108,616 210,435 354,367 2010 Census Population 14,242 107,427 207,725 349,195 2016 Proj Population 16,611 113,960 221,963 375,421 Historical Change 00-10 0.1% 0.1% 0.4% 0.8% Projected Change 11-16 2.2% 1.0% 1.1% 1.2% 2011 Est Average HHI $33,275 $50,174 $53,355 $59,629 2011 Est Median HHI $22,955 $38,260 $42,369 $48,137 2011 Est Daytime Demos 51,240 136,871 213,344 315,357 AERIAL VIEWS FOR SALE Former Hostess Bakery Facility 803 N. Post Street, Spokane, WA 99201  803 N. Post St Medical District Central Business District University District Spokane River 803 N. Post St Staff_DR_060 Attachment D Page 2 of 3 James G. Quigley 509.755.7560 or jgq@khco.com No warranty or representation, expressed or implied, is made by Kiemle & Hagood Company, its agents or its employees as to the accuracy of the information contained herein. All information furnished is from sources deemed reliable and submitted subject to errors, omissions, change of terms and conditions, prior sale, lease or financing, or withdrawal without notice. No one should rely solely on the above information, but instead should conduct their own investigation to independently satisfy themselves. 509.838.6541 khco.com Sale Price: $3,500,000 $3,200,000 Building Gross: ±111,468 SF FOR SALE Former Hostess Bakery Facility 803 N. Post Street, Spokane, WA 99201 Staff_DR_060 Attachment D Page 3 of 3 From: Dawn McClenahan To: Mark McLees, Erik Nelson Re: / ESCROW SUMMARY REPORT- Thank you for the following order Property Address: 1717 W 4th Ave, Spokane, WA 99204 Escrow Team Escrow Officer: Dawn McClenahan Escrow Number: 4251-2461477 (Dm) Escrow Offr E-Mail: dmcclenahan@firstam.com Escrow Open Date: June 02, 2015 Escrow Assistant: Shelley Niehenke Est. Close Date: Escrow Asst E-Mail: sniehenke@firstam.com Sale Price: 2,050,000.00 Phone: (509)456-0550 Fax: (866)510-4167 Location: First American Title Insurance 40 E Spokane Falls Blvd Spokane, WA 99202 Contingent: Buyer Information: Buyer 1: Avista Corporation Home Phone: Address: P.O. Box 3727 Work Phone: (509)495-2436 Spokane, WA 99220-3727 Mobile Phone: Email: rod.price@avistacorp.com Fax: Selling Agent Information: Agent: Erik Nelson Office Phone: (509)755-7514 Company:Kiemle & Hagood Company Fax: (509)458-4014 Address: 601 W MAIN ST STE 400 Mobile Phone: (509)220-4042 SPOKANE, WA 99201-0613 Email: erik.nelson@khco.com Seller Information: Seller 1: AAA Washington Home Phone: Address: 1745 114th Ave. S.E. Work Phone: (425)646-2134 Bellevue, WA 98004 Mobile Phone: Email: johniwanski@aaawin.com Fax: Listing Agent Information: Agent: Mark McLees Office Phone: (509)622-3554 Company:NAI Black Commercial Fax: (509)622-3599 Address: 107 S HOWARD ST STE 500 Mobile Phone: SPOKANE, WA 99201-3818 Email: mmclees@naiblack.com Lender Information: Company: Office Phone: Address: Fax: Email: Attention: Loan No: Title Co. Information: Company:First American Title Insurance Company Office Phone: (509)456-0550 Address: 40 E Spokane Falls Blvd,Spokane, WA Fax: (866)537-9602 Spokane, WA 99202 Email: Title Ofcr: Scott Fonte Order No: 4251-2461477 Staff_DR_060 Attachment E Page 1 of 1 First American Title First American Title Insurance Company 40 E Spokane Falls Blvd Spokane, WA 99202 Phn - (509)456-0550 Fax - (866)537-9602 ESCROW COMPANY INFORMATION: Escrow Officer/Closer: Dawn McClenahan dmcclenahan@firstam.com First American Title Insurance Company 40 E Spokane Falls Blvd, Spokane, WA 99202 Phone: (509)835-8937 - Fax: (866)690-8931 TITLE COMPANY INFORMATION Scott Fonte Title Officer Phone: (509)835-8943 Fax: (866) 537-9602 sfonte@firstam.com Barb Cagle Title Officer Phone: (509)835-8945 Fax: (866)537-9602 bcagle@firstam.com To: Kiemle & Hagood Company 601 W Main Street, Suite 400 Spokane, WA 99201 Attn: Erik Nelson File No.: 4251-2461477 Your Ref No.: AAA Washington/Avista Corp Re: Property Address: 1717 W 4th Ave, Spokane, WA 99204 COMMITMENT FOR TITLE INSURANCE Issued by FIRST AMERICAN TITLE INSURANCE COMPANY Agreement to Issue Policy We agree to issue a policy to you according to the terms of this Commitment. When we show the policy amount and your name as the proposed insured in Schedule A, this Commitment becomes effective as of the Commitment Date shown in Schedule A. If the Requirements shown in this Commitment have not been met within six months after the Commitment Date, our obligation under this Commitment will end. Also, our obligation under this Commitment will end when the Policy is issued and then our obligation to you will be under the Policy. Our obligation under this Commitment is limited by the following: The Provisions in Schedule A. The Requirements in Schedule B-I. The General Exceptions and Exceptions in Schedule B-II. The Conditions. This Commitment is not valid without Schedule A and Section I and II of Schedule B. = Staff_DR_060 Attachment F Page 1 of 12 Form No. 1068-2 Commitment No.: 4251-2461477 ALTA Plain Language Commitment Page 2 of 12 First American Title = SCHEDULE A 1. Commitment Date: May 20, 2015 at 7:30 A.M. 2. Policy or Policies to be issued: AMOUNT PREMIUM TAX Standard Owner's Policy $ 2,050,000.00 $ 3,703.00 $ 322.16 Proposed Insured: Avista Corporation 3. (A) The estate or interest in the land described in this Commitment is: Fee Simple (B) Title to said estate or interest at the date hereof is vested in: INLAND AUTOMOBILE ASSOCIATION, A WASHINGTON CORPORATION 4. The land referred to in this Commitment is described as follows: Real property in the County of Spokane, State of Washington, described as follows: PARCEL A: LOTS 1-12, INCLUSIVE, BLOCK 15, CANNON'S ADDITION ACCORDING TO PLAT RECORDED IN VOLUME “B” OF PLATS, PAGE 52; TOGETHER WITH THE ALLEY VACATED BY ORDINANCE NO. C19089, WHICH WOULD ATTACH BY OPERATING OF LAW; EXCEPTING THEREFROM THAT PORTION OF LOT 12 CONVEYED TO THE CITY OF SPOKANE BY WARRANTY DEED REOCRDED UNDER AUDITOR'S NO. 957463B, DESCRIBED AS FOLLOWS: BEGINNING AT THE SOUTHEAST CORNER OF SAID LOT 12; THENCE WEST ALONG THE SOUTH LINE OF SAID LOT A DISTANCE OF 3 FEET; THENCE NORTHEASTERLY TO A POINT ON THE EAST LINE OF SAID LOT A DISTANCE OF 2 FEET NORTH OF THE SOUTHEAST CORNER THEREOF; THENCE SOUTH ALONG THE EAST LINE OF SAID LOT TO THE POINT OF BEGINNING; SITUATE IN THE CITY OF SPOKANE, COUNTY OF SPOKANE, STATE OF WASHINGTON. PARCEL B: LOT 7, AND ALL OF LOT 8, BLOCK 16, CANNON'S ADDITION, ACCORDING TO PLAT RECORDED IN VOLUME “B” OF PLATS, PAGE 52; TOGETHER WITH THAT PORTION OF THE ALLEY VACATED BY ORDINANCE NO. C-29078, RECORDED JUNE 16, 1988 UNDER RECORDING NO. 8806160121, WHICH WOULD ATTACHED BY OPERATION OF LAW; EXCEPTING THEREFROM THOSE PORTIONS THEREOF LYING SOUTHERLY OF THE FOLLOWING DESCRIBED LINE FOR HIGHWAY PURPOSES: BEGINNING AT A POINT OPPOSITE HIGHWAY ENGINEER'S STATION A 360+00 ON THE RAMP A CENTER LINE SURVEY OF SR 90 (PSH NO. 2), SPOKANE: WEST CORPORATE LIMITS TO CEDAR Staff_DR_060 Attachment F Page 2 of 12 Form No. 1068-2 Commitment No.: 4251-2461477 ALTA Plain Language Commitment Page 3 of 12 First American Title STREET AND 20 FEET NORTHWESTERLY THEREOF; THENCE NORTHEASTERLY TO A POINT OPPOSITE HIGHWAY ENGINEER'S STATION A 360+50 ON SAID CENTER LINE AND 50 FEET NORTHWESTERLY THEREOF; THENCE NORTHEASTERLY TO A POINT OPPOSITE HIGHWAY ENGINEER'S STATION P.C. A 362+44.78 ON SAID CENTERLINE AND 40 FEET NORTHWESTERLY THEREOF AND THE END OF THIS LINE DESCRIPTION; SITUATE IN THE CITY OF SPOKANE, COUNTY OF SPOKANE, STATE OF WASHINGTON. APN: 25241.3812 APN: 25241.3925 = Staff_DR_060 Attachment F Page 3 of 12 Form No. 1068-2 Commitment No.: 4251-2461477 ALTA Plain Language Commitment Page 4 of 12 First American Title = SCHEDULE B SECTION I REQUIREMENTS The following requirements must be met: (A) Pay the agreed amounts for the interest in the land and/or the mortgage to be insured. (B) Pay us the premiums, fees and charges for the policy. (C) Documents satisfactory to us creating the interest in the land and/or the mortgage to be insured must be signed, delivered and recorded: (D) You must tell us in writing the name of anyone not referred to in this Commitment who will get an interest in the land or who will make a loan on the land. We may then make additional requirements or exceptions. (E) Releases(s) or Reconveyance(s) of Item(s): (F) Other: (G) You must give us the following information: 1. Any off record leases, surveys, etc. 2. Statement(s) of Identity, all parties. 3. Other: SCHEDULE B SECTION II GENERAL EXCEPTIONS PART ONE: A. Taxes or assessments which are not shown as existing liens by the records of any taxing authority that levies taxes or assessments on real property or by the public records. B. Any facts, rights, interests, or claims which are not shown by the public records but which could be ascertained by an inspection of said land or by making inquiry of persons in possession thereof. C. Easements, claims of easement or encumbrances which are not shown by the public records. D. Discrepancies, conflicts in boundary lines, shortage in area, encroachments, or any other facts which a correct survey would disclose, and which are not shown by the public records. E. (A) Unpatented mining claims; (B) Reservations or exceptions in patents or in Acts authorizing the issuance thereof; (C) Water rights, claims or title to water; whether or not the matters excepted under (A), (B) or (C) are shown by the public records; (D) Indian Tribal Codes or Regulations, Indian Treaty or Aboriginal Rights, including easements or equitable servitudes. F. Any lien, or right to a lien, for services, labor or materials or medical assistance heretofore or hereafter furnished, imposed by law and not shown by the public records. G. Any service, installation, connection, maintenance, construction, tap or reimbursement charges/costs for sewer, water, garbage or electricity. H. Defects, liens, encumbrances, adverse claims or other matters, if any, created, first appearing in the public records or attaching subsequent to the effective date hereof, but prior to the date the proposed insured acquires of record for value the escrow or interest or mortgage(s) thereon covered by this Commitment. = Staff_DR_060 Attachment F Page 4 of 12 Form No. 1068-2 Commitment No.: 4251-2461477 ALTA Plain Language Commitment Page 5 of 12 First American Title = SCHEDULE B SECTION II EXCEPTIONS PART TWO: Any policy we issue will have the following exceptions unless they are taken care of to our satisfaction. The printed exceptions and exclusions from the coverage of the policy or policies are available from the office which issued this Commitment. Copies of the policy forms should be read. 1. Lien of the Real Estate Excise Sales Tax and Surcharge upon any sale of said premises, if unpaid. As of the date herein, the excise tax rate for the City of Spokane is at 1.78 %. Levy/Area Code: 0010 2. General Taxes for the year 2015. The first half becomes delinquent after April 30th. The second half becomes delinquent after October 31st. Tax Account No.: 25241.3812 1st Half Amount Billed: $ 15,472.21 Amount Paid: $ 15,472.21 Amount Due: $0.00 Assessed Land Value: $ 1,125,000.00 Assessed Improvement Value: $ 1,048,000.00 2nd Half Amount Billed: $ 15,472.21 Amount Paid: $0.00 Amount Due: $ 15,472.21 Assessed Land Value: $ 1,125,000.00 Assessed Improvement Value: $ 1,048,000.00 Affects: Parcel A 3. General Taxes for the year 2015. The first half becomes delinquent after April 30th. The second half becomes delinquent after October 31st. Tax Account No.: 25241.3925 1st Half Amount Billed: $ 1,077.81 Amount Paid: $ 1,077.81 Amount Due: $0.00 Assessed Land Value: $ 138,130.00 Assessed Improvement Value: $ 12,800.00 2nd Half Amount Billed: $ 1,077.82 Amount Paid: $0.00 Amount Due: $ 1,077.82 Assessed Land Value: $ 138,130.00 Assessed Improvement Value: $ 12,800.00 Affects: Parcel B 4. Any tax, fee, assessments or charges as may be levied by City of Spokane. Staff_DR_060 Attachment F Page 5 of 12 Form No. 1068-2 Commitment No.: 4251-2461477 ALTA Plain Language Commitment Page 6 of 12 First American Title 5. Easement, including terms and provisions contained therein: Recorded: October 21, 1952 Recording Information: 130735B; Vol. 632, Pg. 150 In Favor of: The Washington Water Power Company, a corporation, its successors and assigns For: To erect, construct, reconstruct and maintain an electrical distribution line and appurtenances Affects: Parcel B 6. Easement, including terms and provisions contained therein: Recorded: October 29, 1952 Recording Information: 132279B; Vol. 632, Pg. 468 In Favor of: The Washington Water Power Company For: An electrical distribution line Affects: Portion of Parcel A 7. Easement, including terms and provisions contained therein: Recorded: October 28, 1952 Recording Information: 132056B; Vol. 632, Pg. 434 In Favor of: The Washington Water Power Company For: An electrical distribution line Affects: Portion of Parcel A 8. Easement, including terms and provisions contained therein: Recorded: April 18, 1963 Recording Information: 931148B; Vol. 812, Pg. 775 In Favor of: The Washington Water Power Company For: An electrical distribution line Affects: Portion of Parcel A 9. Easement, including terms and provisions contained therein: Recorded: April 13, 1963 Recording Information: 931150B; Vol. 813, Pg. 37 In Favor of: The Washington Water Power Company For: An electrical distribution line Affects: Portion of Parcel A 10. Easement and conditions contained therein as reserved by: Ordinance No.: C-29078 Approved On: June 06, 1988 Recording Information: 8806160121; ; Vol. 975, Pg. 681 For: Utility services Affects: Parcel B 11. Terms, covenants, conditions and restrictions as contained in recorded Lot Line Adjustment (Boundary Line Revisions): Recorded: September 12, 1997 Recording Information: 4140630 Affects: Parcel A Staff_DR_060 Attachment F Page 6 of 12 Form No. 1068-2 Commitment No.: 4251-2461477 ALTA Plain Language Commitment Page 7 of 12 First American Title 12. Conditions, notes, easements, provisions and/or encroachments contained and/or delineated on the face of the Survey No. 4179425, recorded in volume 79 of surveys, at page(s) 87, in Spokane County, Washington. Affects: Parcel A 13. Terms, covenants, conditions and restrictions as contained in recorded Lot Line Adjustment (Boundary Line Revisions): Recorded: May 27, 1998 Recording Information: 4225051 Affects: Parcel B 14. According to registration information on file with the State of Washington Secretary of State, Inland Automobile Association, has been an inactive corporation since January 31, 2003, date of license expiration. Evidence must be submitted that said entity has been reinstated or had a valid name change. 15. Evidence of the authority of the officers of Inland Automobile Association, a Washington non- profit corporation, to execute the forthcoming instrument. Current Articles of Incorporation and By-Laws should be furnished both for said corporation and for any higher discipline or organization to which it is responsible. It should be noted that in the case of a sale of all or substantially all of the property and assets of a corporation, regardless of the requirements of the organizations involved, the Washington Non- Profit Corporation Act (RCW 24.03.215) requires a special procedure. If there are not members having voting rights, the act requires a sale to be authorized by majority vote of the directors. If there are member having voting rights, the act requires the following: 1. That the Board of Directors adopt a resolution recommending the sale and directing that it be put to a vote of the membership; 2. That written notice of the meeting stating one of the purposes is to secure approval of the transaction to be given to each member, in accordance with the Articles and By-Laws, but in no case to be delivered less than 10, nor more than 50, days before the meeting; 3. That authorization at such meeting requires a two-thirds vote of the membership present; and 4. That after such meeting the Board of Directors approve such transaction by appropriate resolution. 16. The right, title or interest of AAA Washington, as disclosed by Spokane County Tax Rolls. = Staff_DR_060 Attachment F Page 7 of 12 Form No. 1068-2 Commitment No.: 4251-2461477 ALTA Plain Language Commitment Page 8 of 12 First American Title = INFORMATIONAL NOTES This property may be subject to a charge by Spokane County for sewer construction, referred to as a Capital Facilities Rate (CFR). This charge is in addition to the monthly charge for sewer services. Please contact the Division of Utilities Billing Section at (509) 477-3604, for further information. A. Effective January 1, 1997, and pursuant to amendment of Washington State Statutes relating to standardization of recorded documents, certain format and content requirements must be met (refer to RCW 65.04.045). Failure to comply may result in rejection of the document by the recorder or additional fees being charged, subject to the Auditor's discretion. B. Any sketch attached hereto is done so as a courtesy only and is not part of any title commitment or policy. It is furnished solely for the purpose of assisting in locating the premises and First American expressly disclaims any liability which may result from reliance made upon it. C. The description can be abbreviated as suggested below if necessary to meet standardization requirements. The full text of the description must appear in the document(s) to be insured. LOTS 1-12, BLOCK 15 AND LOT 8 AND PTN LOT 7, BLOCK 16, CANNON'S ADD., VOL. “B”, P. 52, SPOKANE COUNTY APN: 25241.3812 APN: 25241.3925 D. The following deeds affecting the property herein described have been recorded within 36 months of the effective date of this commitment: NONE Property Address: 1717 W 4th Ave, Spokane, WA 99204 NOTE: The forthcoming Mortgagee's Policy will be the ALTA 2006 Policy unless otherwise noted on Schedule A herein. Staff_DR_060 Attachment F Page 8 of 12 Form No. 1068-2 Commitment No.: 4251-2461477 ALTA Plain Language Commitment Page 9 of 12 First American Title CONDITIONS 1. DEFINITIONS (a)"Mortgage" means mortgage, deed of trust or other security instrument. (b)"Public Records" means title records that give constructive notice of matters affecting the title according to the state law where the land is located. 2. LATER DEFECTS The Exceptions in Schedule B - Section II may be amended to show any defects, liens or encumbrances that appear for the first time in the public records or are created or attached between the Commitment Date and the date on which all of the Requirements (a) and (c) of Schedule B - Section I are met. We shall have no liability to you because of this amendment. 3. EXISTING DEFECTS If any defects, liens or encumbrances existing at Commitment Date are not shown in Schedule B, we may amend Schedule B to show them. If we do amend Schedule B to show these defects, liens or encumbrances, we shall be liable to you according to Paragraph 4 below unless you knew of this information and did not tell us about it in writing. 4. LIMITATION OF OUR LIABILITY Our only obligation is to issue to you the Policy referred to in this Commitment, when you have met its Requirements. If we have any liability to you for any loss you incur because of an error in this Commitment, our liability will be limited to your actual loss caused by your relying on this Commitment when you acted in good faith to: comply with the Requirements shown in Schedule B - Section I or eliminate with our written consent any Exceptions shown in Schedule B - Section II. We shall not be liable for more than the Policy Amount shown in Schedule A of this Commitment and our liability is subject to the terms of the Policy form to be issued to you. 5. CLAIMS MUST BE BASED ON THIS COMMITMENT Any claim, whether or not based on negligence, which you may have against us concerning the title to the land must be based on this commitment and is subject to its terms. = Staff_DR_060 Attachment F Page 9 of 12 Form No. 1068-2 Commitment No.: 4251-2461477 ALTA Plain Language Commitment Page 10 of 12 First American Title = First American Title Insurance Company 40 E Spokane Falls Blvd Spokane, WA 99202 Phn - (509)456-0550 Fax - (866)537-9602 Privacy Information We Are Committed to Safeguarding Customer Information In order to better serve your needs now and in the future, we may ask you to provide us with certain information. We understand that you may be concerned about what we will do with such information - particularly any personal or financial information. We agree that you have a right to know how we will utilize the personal information you provide to us. Therefore, together with our subsidiaries we have adopted this Privacy Policy to govern the use and handling of your personal information. Applicability This Privacy Policy governs our use of the information that you provide to us. It does not govern the manner in which we may use information we have obtained from any other source, such as information obtained from a public record or from another person or entity. First American has also adopted broader guidelines that govern our use of personal information regardless of its source. First American calls these guidelines its Fair Information Values. Types of Information Depending upon which of our services you are utilizing, the types of nonpublic personal information that we may collect include: • Information we receive from you on applications, forms and in other communications to us, whether in writing, in person, by telephone or any other means; • Information about your transactions with us, our affiliated companies, or others; and • Information we receive from a consumer reporting agency. Use of Information We request information from you for our own legitimate business purposes and not for the benefit of any nonaffiliated party. Therefore, we will not release your information to nonaffiliated parties except: (1) as necessary for us to provide the product or service you have requested of us; or (2) as permitted by law. We may, however, store such information indefinitely, including the period after which any customer relationship has ceased. Such information may be used for any internal purpose, such as quality control efforts or customer analysis. We may also provide all of the types of nonpublic personal information listed above to one or more of our affiliated companies. Such affiliated companies include financial service providers, such as title insurers, property and casualty insurers, and trust and investment advisory companies, or companies involved in real estate services, such as appraisal companies, home warranty companies and escrow companies. Furthermore, we may also provide all the information we collect, as described above, to companies that perform marketing services on our behalf, on behalf of our affiliated companies or to other financial institutions with whom we or our affiliated companies have joint marketing agreements. Former Customers Even if you are no longer our customer, our Privacy Policy will continue to apply to you. Confidentiality and Security We will use our best efforts to ensure that no unauthorized parties have access to any of your information. We restrict access to nonpublic personal information about you to those individuals and entities who need to know that information to provide products or services to you. We will use our best efforts to train and oversee our employees and agents to ensure that your information will be handled responsibly and in accordance with this Privacy Policy and First American's Fair Information Values. We currently maintain physical, electronic, and procedural safeguards that comply with federal regulations to guard your nonpublic personal information. Information Obtained Through Our Web Site First American Financial Corporation is sensitive to privacy issues on the Internet. We believe it is important you know how we treat the information about you we receive on the Internet. In general, you can visit First American or its affiliates’ Web sites on the World Wide Web without telling us who you are or revealing any information about yourself. Our Web servers collect the domain names, not the e-mail addresses, of visitors. This information is aggregated to measure the number of visits, average time spent on the site, pages viewed and similar information. First American uses this information to measure the use of our site and to develop ideas to improve the content of our site. There are times, however, when we may need information from you, such as your name and email address. When information is needed, we will use our best efforts to let you know at the time of collection how we will use the personal information. Usually, the personal information we collect is used only by us to respond to your inquiry, process an order or allow you to access specific account/profile information. If you choose to share any personal information with us, we will only use it in accordance with the policies outlined above. Business Relationships First American Financial Corporation's site and its affiliates' sites may contain links to other Web sites. While we try to link only to sites that share our high standards and respect for privacy, we are not responsible for the content or the privacy practices employed by other sites. Cookies Some of First American's Web sites may make use of "cookie" technology to measure site activity and to customize information to your personal tastes. A cookie is an element of data that a Web site can send to your browser, which may then store the cookie on your hard drive. FirstAm.com uses stored cookies. The goal of this technology is to better serve you when visiting our site, save you time when you are here and to provide you with a more meaningful and productive Web site experience. -------------------------------------------------------------------------------- Fair Information Values Fairness We consider consumer expectations about their privacy in all our businesses. We only offer products and services that assure a favorable balance between consumer benefits and consumer privacy. Public Record We believe that an open public record creates significant value for society, enhances consumer choice and creates consumer opportunity. We actively support an open public record and emphasize its importance and contribution to our economy. Use We believe we should behave responsibly when we use information about a consumer in our business. We will obey the laws governing the collection, use and dissemination of data. Accuracy We will take reasonable steps to help assure the accuracy of the data we collect, use and disseminate. Where possible, we will take reasonable steps to correct inaccurate information. When, as with the public record, we cannot correct inaccurate information, we will take all reasonable steps to assist consumers in identifying the source of the erroneous data so that the consumer can secure the required corrections. Education We endeavor to educate the users of our products and services, our employees and others in our industry about the importance of consumer privacy. We will instruct our employees on our fair information values and on the responsible collection and use of data. We will encourage others in our industry to collect and use information in a responsible manner. Security We will maintain appropriate facilities and systems to protect against unauthorized access to and corruption of the data we maintain. Form 50-PRIVACY (9/1/10) Page 1 of 1 Privacy Information (2001-2010 First American Financial Corporation) Staff_DR_060 Attachment F Page 10 of 12 Form No. 1068-2 Commitment No.: 4251-2461477 ALTA Plain Language Commitment Page 11 of 12 First American Title FIRST AMERICAN TITLE INSURANCE COMPANY Exhibit "A" Vested Owner: INLAND AUTOMOBILE ASSOCIATION, A WASHINGTON CORPORATION Real property in the County of Spokane, State of Washington, described as follows: PARCEL A: LOTS 1-12, INCLUSIVE, BLOCK 15, CANNON'S ADDITION ACCORDING TO PLAT RECORDED IN VOLUME “B” OF PLATS, PAGE 52; TOGETHER WITH THE ALLEY VACATED BY ORDINANCE NO. C19089, WHICH WOULD ATTACH BY OPERATING OF LAW; EXCEPTING THEREFROM THAT PORTION OF LOT 12 CONVEYED TO THE CITY OF SPOKANE BY WARRANTY DEED REOCRDED UNDER AUDITOR'S NO. 957463B, DESCRIBED AS FOLLOWS: BEGINNING AT THE SOUTHEAST CORNER OF SAID LOT 12; THENCE WEST ALONG THE SOUTH LINE OF SAID LOT A DISTANCE OF 3 FEET; THENCE NORTHEASTERLY TO A POINT ON THE EAST LINE OF SAID LOT A DISTANCE OF 2 FEET NORTH OF THE SOUTHEAST CORNER THEREOF; THENCE SOUTH ALONG THE EAST LINE OF SAID LOT TO THE POINT OF BEGINNING; SITUATE IN THE CITY OF SPOKANE, COUNTY OF SPOKANE, STATE OF WASHINGTON. PARCEL B: LOT 7, AND ALL OF LOT 8, BLOCK 16, CANNON'S ADDITION, ACCORDING TO PLAT RECORDED IN VOLUME “B” OF PLATS, PAGE 52; TOGETHER WITH THAT PORTION OF THE ALLEY VACATED BY ORDINANCE NO. C-29078, RECORDED JUNE 16, 1988 UNDER RECORDING NO. 8806160121, WHICH WOULD ATTACHED BY OPERATION OF LAW; EXCEPTING THEREFROM THOSE PORTIONS THEREOF LYING SOUTHERLY OF THE FOLLOWING DESCRIBED LINE FOR HIGHWAY PURPOSES: BEGINNING AT A POINT OPPOSITE HIGHWAY ENGINEER'S STATION A 360+00 ON THE RAMP A CENTER LINE SURVEY OF SR 90 (PSH NO. 2), SPOKANE: WEST CORPORATE LIMITS TO CEDAR STREET AND 20 FEET NORTHWESTERLY THEREOF; THENCE NORTHEASTERLY TO A POINT OPPOSITE HIGHWAY ENGINEER'S STATION A 360+50 ON SAID CENTER LINE AND 50 FEET NORTHWESTERLY THEREOF; THENCE NORTHEASTERLY TO A POINT OPPOSITE HIGHWAY ENGINEER'S STATION P.C. A 362+44.78 ON SAID CENTERLINE AND 40 FEET NORTHWESTERLY THEREOF AND THE END OF THIS LINE DESCRIPTION; SITUATE IN THE CITY OF SPOKANE, COUNTY OF SPOKANE, STATE OF WASHINGTON. Tax Parcel Number: 25241.3812 and 25241.3925 Situs Address: 1717 W 4th Ave, Spokane, WA 99204 Staff_DR_060 Attachment F Page 11 of 12 Form No. 1068-2 Commitment No.: 4251-2461477 ALTA Plain Language Commitment Page 12 of 12 First American Title ___________________________________ ____________________________________ BUYER SELLER ___________________________________ ____________________________________ BUYER SELLER Staff_DR_060 Attachment F Page 12 of 12 Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/25/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Karen Schuh REQUESTER: Staff - Huang RESPONDER: Rod Price TYPE: Data Request DEPT: Real Estate REQUEST NO.: Staff – 060 TELEPHONE: (509) 495-2436 EMAIL: rod.price@avistacorp.com REQUEST: ER 7139: Network Building Purchase and Renovation Referring to Karen Schuh’s Exhibit No.___(KKS-5), Section 2, page 13, please provide all studies, memoranda and supporting documents regarding the purchase of the 2.32 acre lot located at 1717 W. 4th St. Spokane, WA. Please update your response to this data request as actual monthly totals become available. RESPONSE: In May of 2015 the Avista Real Estate department was tasked with researching potential properties in order to consolidate Avista’s network operations from several relocations to a single location do to the constraints at the Downtown Post Street Location. A study that supports the space needed to accommodate the employees is in Staff_DR_060 Attachment A. The Company contracted the help of commercial agents from Kiemle & Hagood Company to help in the search based on specific criteria needed for the new location. The Company thoroughly searched and inspected several alternative properties in addition to the 1717 W. 4th location and found that they were priced too high, would need substantial clean up and demolition, or had potential environmental concerns. Please see Staff_DR_060 Attachments B-D for details of the property purchased and two other properties considered. After thoroughly vetting all properties, the Company decided that the property located at 1717 W. 4th, Spokane, WA was the best alternative based on location and proximity to downtown, central Spokane, price, lot size, ability to expand, and its fit into the Company’s overall strategic operational plan. Through the advice of external commercial real estate agents and using comparable sales data at the time, the Company settled on a purchase price that was well below the original list price. Documents supporting the final purchase are located in Staff_DR_060 Attachment E and Attachment F. Also see Avista’s responses to Staff DR’s 061 and 062. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/25/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Karen Schuh REQUESTER: Staff - Huang RESPONDER: Rod Price TYPE: Data Request DEPT: Real Estate REQUEST NO.: Staff – 060 TELEPHONE: (509) 495-2436 EMAIL: rod.price@avistacorp.com REQUEST: ER 7139: Network Building Purchase and Renovation Referring to Karen Schuh’s Exhibit No.___(KKS-5), Section 2, page 13, please provide all studies, memoranda and supporting documents regarding the purchase of the 2.32 acre lot located at 1717 W. 4th St. Spokane, WA. Please update your response to this data request as actual monthly totals become available. RESPONSE: In May of 2015 the Avista Real Estate department was tasked with researching potential properties in order to consolidate Avista’s network operations from several relocations to a single location do to the constraints at the Downtown Post Street Location. A study that supports the space needed to accommodate the employees is in Staff_DR_060 Attachment A. The Company contracted the help of commercial agents from Kiemle & Hagood Company to help in the search based on specific criteria needed for the new location. The Company thoroughly searched and inspected several alternative properties in addition to the 1717 W. 4th location and found that they were priced too high, would need substantial clean up and demolition, or had potential environmental concerns. Please see Staff_DR_060 Attachments B-D for details of the property purchased and two other properties considered. After thoroughly vetting all properties, the Company decided that the property located at 1717 W. 4th, Spokane, WA was the best alternative based on location and proximity to downtown, central Spokane, price, lot size, ability to expand, and its fit into the Company’s overall strategic operational plan. Through the advice of external commercial real estate agents and using comparable sales data at the time, the Company settled on a purchase price that was well below the original list price. Documents supporting the final purchase are located in Staff_DR_060 Attachment E and Attachment F. Also see Avista’s responses to Staff DR’s 061 and 062. Page 1 of 2 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/19/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Karen K. Schuh REQUESTER: UTC Staff - Huang RESPONDER: Lindsay L. Miller TYPE: Data Request DEPT: Facilities Management REQUEST NO.: Staff - 061 TELEPHONE: (509) 495-2859 EMAIL: lindsay.miller@avistacorp.com REQUEST: ER 7139: Network Building Purchase and Renovation Referring to Karen Schuh’s Exhibit No.___(KKS-5), Section 2, page 14 (bottom left corner), please provide all progress reports, related to the milestones set forth and listed below, regarding the purchase of the 2.32 acre lot located at 1717 W. 4th St. Spokane, WA. Please update your response to this data request as actual monthly totals become available. Milestones (high level targets) July15 Lot purchased & closed August 15 Begin Office Bldg renovation/construction December 15 Office bldg. renovation complete, move in Atlas/AMI/Steam plant March 16 Begin Downtown Network construction December 16 Downtown network Bldgs complete RESPONSE: After completion of the business case and purchase of the land, as further discussed in Staff_DR_060, the Company revised the milestones and dates of the purchase and renovation of the network building. More information was obtained and two separate schedules were developed, one for the renovation of the existing building and one for the construction of the new downtown network building were developed. Please see below for a high level schedule and milestone for these two projects: Renovation of existing building: July 10, 2015 Lot purchase closed July 29, 2015 Contracts executed for design and engineering services July 29, 2015 Design and engineering process began for renovation October 2, 2015 100% Drawing set due for renovation October 26, 2015 Office Building renovation construction begins April 15, 2016 1st Floor Office Building renovation construction complete May 12, 2016 Basement Office Building renovation construction complete During the due diligence phase of the purchase process items were uncovered that required us to replace a number of existing main building systems in the large building on the site. Due to these discoveries a more in depth design and engineering phase was required for the renovation of the existing building. The entire mechanical system was replaced as well as the electrical service and subsequent main and distribution panels. These discoveries added scope to the renovation caused the schedule to move out to accommodate the additional work required both in design and construction. Page 2 of 2 New Downtown Network Building: Sept. 3, 2015 Design and Engineering process began for new building October 2015 Apply for Road Vacation with City of Spokane June 2016 100% Drawing set due for new building design September 2016 Road vacation between lots complete September 2016 Downtown Network building construction begins May 2017 Downtown Network building construction complete To maximize the land purchase and the layout options for the Downtown Network building the design required the vacation of a road between two Avista properties. This milestone needs to be resolved before we can begin construction of the Downtown Network building. Therefore the construction start date was pushed out to allow for the road vacation to be completed thru the city. This data response will be updated as the milestones and schedule has significant changes. Page 1 of 2 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/19/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Karen K. Schuh REQUESTER: UTC Staff - Huang RESPONDER: Lindsay L. Miller TYPE: Data Request DEPT: Facilities Management REQUEST NO.: Staff - 061 TELEPHONE: (509) 495-2859 EMAIL: lindsay.miller@avistacorp.com REQUEST: ER 7139: Network Building Purchase and Renovation Referring to Karen Schuh’s Exhibit No.___(KKS-5), Section 2, page 14 (bottom left corner), please provide all progress reports, related to the milestones set forth and listed below, regarding the purchase of the 2.32 acre lot located at 1717 W. 4th St. Spokane, WA. Please update your response to this data request as actual monthly totals become available. Milestones (high level targets) July15 Lot purchased & closed August 15 Begin Office Bldg renovation/construction December 15 Office bldg. renovation complete, move in Atlas/AMI/Steam plant March 16 Begin Downtown Network construction December 16 Downtown network Bldgs complete RESPONSE: After completion of the business case and purchase of the land, as further discussed in Staff_DR_060, the Company revised the milestones and dates of the purchase and renovation of the network building. More information was obtained and two separate schedules were developed, one for the renovation of the existing building and one for the construction of the new downtown network building were developed. Please see below for a high level schedule and milestone for these two projects: Renovation of existing building: July 10, 2015 Lot purchase closed July 29, 2015 Contracts executed for design and engineering services July 29, 2015 Design and engineering process began for renovation October 2, 2015 100% Drawing set due for renovation October 26, 2015 Office Building renovation construction begins April 15, 2016 1st Floor Office Building renovation construction complete May 12, 2016 Basement Office Building renovation construction complete During the due diligence phase of the purchase process items were uncovered that required us to replace a number of existing main building systems in the large building on the site. Due to these discoveries a more in depth design and engineering phase was required for the renovation of the existing building. The entire mechanical system was replaced as well as the electrical service and subsequent main and distribution panels. These discoveries added scope to the renovation caused the schedule to move out to accommodate the additional work required both in design and construction. Page 2 of 2 New Downtown Network Building: Sept. 3, 2015 Design and Engineering process began for new building October 2015 Apply for Road Vacation with City of Spokane June 2016 100% Drawing set due for new building design September 2016 Road vacation between lots complete September 2016 Downtown Network building construction begins May 2017 Downtown Network building construction complete To maximize the land purchase and the layout options for the Downtown Network building the design required the vacation of a road between two Avista properties. This milestone needs to be resolved before we can begin construction of the Downtown Network building. Therefore the construction start date was pushed out to allow for the road vacation to be completed thru the city. This data response will be updated as the milestones and schedule has significant changes. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/19/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Karen Schuh REQUESTER: UTC Staff - Huang RESPONDER: Karen Schuh TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff – 062 TELEPHONE: (509) 495-2293 EMAIL: karen.schuh@avistacorp.com REQUEST: ER 7139: Network Building Purchase and Renovation Referring to Karen Schuh’s Exhibit No.___(KKS-5), Section 2, page 16, this is a memorandum dated 2/15/16 from Mike Faulkenberry, Director of Natural Gas. Referring to the memorandum, paragraph 3, please explain the Mirabeau lease and Steam Plant lease and their relationship with the ER 7139: Network Building Purchase and Renovation. RESPONSE: The purchase of the Network Building serves several purposes. The first purpose is noted in Exhibit No.___(KKS-5), Section 2, page 16 in the second paragraph: The Downtown Network facilities will enable the consolidation of the downtown network crews and equipment onto one site rather than several sites that are scattered around downtown. This will improve the efficiency of the operations of the downtown network crews. Additionally, the new facility will provide new equipment such as overhead cranes and welding bays, which supports the operation of the downtown network. In addition to the added benefits of the network crews and equipment, the Network Building has capacity for additional space to house special project teams that were previously housed at the Mirabeau location. With several larger projects on Avista’s forefront, such as the Advanced Metering Infrastructure project (AMI) and Avista Facilities Maintenance (AFM) this additional capacity allows Avista to release the lease previously held out at the Mirabeau location. Avista also has additional swing space held at the Steam Plant Square location for when construction occurs at the main campus that displaces employees. Due to the additional space available through the Network Building, Avista has released approximately 2/3 of the leased space at the Steam Plant Square location and alleviated additional costs for several years to come. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/19/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Karen Schuh REQUESTER: UTC Staff - Huang RESPONDER: Karen Schuh TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff – 062 TELEPHONE: (509) 495-2293 EMAIL: karen.schuh@avistacorp.com REQUEST: ER 7139: Network Building Purchase and Renovation Referring to Karen Schuh’s Exhibit No.___(KKS-5), Section 2, page 16, this is a memorandum dated 2/15/16 from Mike Faulkenberry, Director of Natural Gas. Referring to the memorandum, paragraph 3, please explain the Mirabeau lease and Steam Plant lease and their relationship with the ER 7139: Network Building Purchase and Renovation. RESPONSE: The purchase of the Network Building serves several purposes. The first purpose is noted in Exhibit No.___(KKS-5), Section 2, page 16 in the second paragraph: The Downtown Network facilities will enable the consolidation of the downtown network crews and equipment onto one site rather than several sites that are scattered around downtown. This will improve the efficiency of the operations of the downtown network crews. Additionally, the new facility will provide new equipment such as overhead cranes and welding bays, which supports the operation of the downtown network. In addition to the added benefits of the network crews and equipment, the Network Building has capacity for additional space to house special project teams that were previously housed at the Mirabeau location. With several larger projects on Avista’s forefront, such as the Advanced Metering Infrastructure project (AMI) and Avista Facilities Maintenance (AFM) this additional capacity allows Avista to release the lease previously held out at the Mirabeau location. Avista also has additional swing space held at the Steam Plant Square location for when construction occurs at the main campus that displaces employees. Due to the additional space available through the Network Building, Avista has released approximately 2/3 of the leased space at the Steam Plant Square location and alleviated additional costs for several years to come. UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 __________________________________________________________________________________________ Form 10-K (Mark One) x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED December 31, 2015 OR ¨TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM TO Commission file number 1-3701 __________________________________________________________________________________________ AVISTA CORPORATION (Exact name of Registrant as specified in its charter) Washington 91-0462470 (State or other jurisdiction of incorporation or organization) (I.R.S. Employer Identification No.) 1411 East Mission Avenue, Spokane, Washington 99202-2600 (Address of principal executive offices) (Zip Code) Registrant’s telephone number, including area code: 509-489-0500 Web site: http://www.avistacorp.com Securities registered pursuant to Section 12(b) of the Act: Title of Class Name of Each Exchange on Which Registered Common Stock, no par value New York Stock Exchange Securities registered pursuant to Section 12(g) of the Act: Title of Class Preferred Stock, Cumulative, Without Par Value __________________________________________________________________________________________ Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes x No ¨ Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. Yes ¨ No x Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days: Yes x No ¨ Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨ Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of Registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨ Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one): Large accelerated filer x Accelerated filer ¨ Non-accelerated filer ¨ (Do not check if a smaller reporting company)Smaller reporting company ¨ Staff_DR_063 Attachment A Page 1 of 180 Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act): Yes ¨ No x The aggregate market value of the Registrant’s outstanding Common Stock, no par value (the only class of voting stock), held by non-affiliates is $1,909,309,138 based on the last reported sale price thereof on the consolidated tape on June 30, 2015. As of January 31, 2016, 62,494,881 shares of Registrant’s Common Stock, no par value (the only class of common stock), were outstanding. __________________________________________________________________________________________ Documents Incorporated By Reference Document Part of Form 10-K into Which Document is Incorporated Proxy Statement to be filed in connection with the annual meeting of shareholders to be held on May 12, 2016. Prior to such filing, the Proxy Statement filed in connection with the annual meeting of shareholders held on May 7, 2015. Part III, Items 10, 11, 12, 13 and 14 Staff_DR_063 Attachment A Page 2 of 180 Table of Contents AVISTA CORPORATION INDEX Item No. Page No. Acronyms and Terms iii Forward-Looking Statements 1 Available Information 4 Part I 1 Business 4 Company Overview 4 Avista Utilities 4 General 4 Electric Operations 4 Electric Requirements 5 Electric Resources 5 Hydroelectric Licenses 8 Future Resource Needs 8 Natural Gas Operations 9 Regulatory Issues 11 Federal Laws Related to Wholesale Competition 12 Regional Transmission Organizations 12 Regional Transmission Planning 12 Regional Energy Markets 12 Reliability Standards 12 Avista Utilities Operating Statistics 14 Alaska Electric Light and Power Company 17 Other Businesses 18 1A. Risk Factors 19 1B. Unresolved Staff Comments 25 2 Properties 26 Utility Properties 26 3 Legal Proceedings 28 4 Mine Safety Disclosures 28 * Part II 5 Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 28 6 Selected Financial Data 30 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations 31 Business Segments 31 Executive Level Summary 31 Regulatory Matters 34 Results of Operations - Overall 40 Results of Operations - Avista Utilities 41 Results of Operations - Alaska Electric Light and Power Company 53 Results of Operations - Ecova - Discontinued Operations 55 Results of Operations - Other Businesses 55 Accounting Standards to Be Adopted in 2016 56 Critical Accounting Policies and Estimates 56 Liquidity and Capital Resources 58 Overall Liquidity 58 Review of Consolidated Cash Flow Statement 59 Capital Resources 62 Capital Expenditures 63 Off-Balance Sheet Arrangements 64 Pension Plan 64 Credit Ratings 64 Staff_DR_063 Attachment A Page 3 of 180 Dividends 65 Contractual Obligations 65 Competition 66 Economic Conditions and Utility Load Growth 67 i Staff_DR_063 Attachment A Page 4 of 180 Table of Contents AVISTA CORPORATION Environmental Issues and Other Contingencies 68 Enterprise Risk Management 72 7A. Quantitative and Qualitative Disclosures about Market Risk 79 8. Financial Statements and Supplementary Data 79 Report of Independent Registered Public Accounting Firm 80 Financial Statements 81 Consolidated Statements of Income 81 Consolidated Statements of Comprehensive Income 83 Consolidated Balance Sheets 84 Consolidated Statements of Cash Flows 86 Consolidated Statements of Equity and Redeemable Noncontrolling Interests 88 Notes to Consolidated Financial Statements 90 Note 1. Summary of Significant Accounting Policies 90 Note 2. New Accounting Standards 99 Note 3. Variable Interest Entities 100 Note 4. Business Acquisitions 101 Note 5. Discontinued Operations 103 Note 6. Derivatives and Risk Management 105 Note 7. Jointly Owned Electric Facilities 109 Note 8. Property, Plant and Equipment 110 Note 9. Asset Retirement Obligations 110 Note 10. Pension Plans and Other Postretirement Benefit Plans 111 Note 11. Accounting for Income Taxes 117 Note 12. Energy Purchase Contracts 119 Note 13. Committed Lines of Credit 119 Note 14. Long-Term Debt and Capital Leases 121 Note 15. Long-Term Debt to Affiliated Trusts 123 Note 16. Fair Value 124 Note 17. Common Stock 128 Note 18. Earnings per Common Share Attributable to Avista Corporation Shareholders 130 Note 19. Commitments and Contingencies 130 Note 20. Regulatory Matters 134 Note 21. Information by Business Segments 136 Note 22. Selected Quarterly Financial Data (Unaudited)138 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 139 * 9A. Controls and Procedures 139 9B. Other Information 142 Part III 10. Directors, Executive Officers and Corporate Governance 142 11. Executive Compensation 143 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 143 13. Certain Relationships and Related Transactions, and Director Independence 144 14. Principal Accounting Fees and Services 144 Part IV 15. Exhibits, Financial Statement Schedules 145 Signatures 146 Exhibit Index 148 * = not an applicable item in the 2015 calendar year for Avista Corp. ii Staff_DR_063 Attachment A Page 5 of 180 Table of Contents AVISTA CORPORATION ACRONYMS AND TERMS (The following acronyms and terms are found in multiple locations within the document) Acronym/Term Meaning aMW -Average Megawatt - a measure of the average rate at which a particular generating source produces energy over a period of time AEL&P -Alaska Electric Light and Power Company, the primary operating subsidiary of AERC, which provides electric services in Juneau, Alaska AERC -Alaska Energy and Resources Company, the Company's wholly-owned subsidiary based in Juneau, Alaska AFUDC -Allowance for Funds Used During Construction; represents the cost of both the debt and equity funds used to finance utility plant additions during the construction period AM&D -Advanced Manufacturing and Development, does business as METALfx ASC -Accounting Standards Codification ASU -Accounting Standards Update Avista Capital -Parent company to the Company’s non-utility businesses Avista Corp.-Avista Corporation, the Company Avista Energy -Avista Energy, Inc., an inactive electricity and natural gas marketing, trading and resource management business, subsidiary of Avista Capital Avista Utilities -Operating division of Avista Corp. (not a subsidiary) comprising the regulated utility operations in the Pacific Northwest BPA -Bonneville Power Administration Capacity -The rate at which a particular generating source is capable of producing energy, measured in KW or MW Cabinet Gorge -The Cabinet Gorge Hydroelectric Generating Project, located on the Clark Fork River in Idaho Colstrip -The coal-fired Colstrip Generating Plant in southeastern Montana Coyote Springs 2 -The natural gas-fired combined-cycle Coyote Springs 2 Generating Plant located near Boardman, Oregon CT -Combustion turbine Deadband or ERM deadband -The first $4.0 million in annual power supply costs above or below the amount included in base retail rates in Washington under the ERM in the state of Washington Dekatherm -Unit of measurement for natural gas; a dekatherm is equal to approximately one thousand cubic feet (volume) or 1,000,000 BTUs (energy) Ecology -The state of Washington’s Department of Ecology Ecova - Ecova, Inc., a provider of facility information and cost management services for multi-site customers and energy efficiency program management for commercial enterprises and utilities throughout North America, subsidiary of Avista Capital. Ecova was sold on June 30, 2014. EIM -Energy Imbalance Market Energy -The amount of electricity produced or consumed over a period of time, measured in KWh or MWh. Also, refers to natural gas consumed and is measured in dekatherms. EPA -Environmental Protection Agency ERM -The Energy Recovery Mechanism, a mechanism for accounting and rate recovery of certain power supply costs accepted by the utility commission in the state of Washington FASB -Financial Accounting Standards Board FERC -Federal Energy Regulatory Commission GAAP -Generally Accepted Accounting Principles GHG -Greenhouse gas GS -Generating station IPUC -Idaho Public Utilities Commission IRP -Integrated Resource Plan iii Staff_DR_063 Attachment A Page 6 of 180 Table of Contents AVISTA CORPORATION Jackson Prairie -Jackson Prairie Natural Gas Storage Project, an underground natural gas storage field located near Chehalis, Washington Juneau -The City and Borough of Juneau, Alaska kV -Kilovolt (1000 volts): a measure of capacity on transmission lines KW, KWh -Kilowatt (1000 watts): a measure of generating output or capability. Kilowatt-hour (1000 watt hours): a measure of energy produced Lancaster Plant -A natural gas-fired combined cycle combustion turbine plant located in Idaho MPSC -Public Service Commission of the State of Montana MW, MWh -Megawatt: 1000 KW. Megawatt-hour: 1000 KWh NERC -North American Electricity Reliability Corporation Noxon Rapids -The Noxon Rapids Hydroelectric Generating Project, located on the Clark Fork River in Montana OPUC -The Public Utility Commission of Oregon PCA -The Power Cost Adjustment mechanism, a procedure for accounting and rate recovery of certain power supply costs accepted by the utility commission in the state of Idaho PGA -Purchased Gas Adjustment PLP -Potentially liable party PUD -Public Utility District PURPA -The Public Utility Regulatory Policies Act of 1978, as amended RCA -The Regulatory Commission of Alaska REC -Renewable energy credit RTO -Regional Transmission Organization Salix -Salix, Inc., a subsidiary of Avista Capital, launched in 2014 to explore markets that could be served with liquefied natural gas (LNG), primarily in western North America. Spokane Energy -Spokane Energy, LLC (dissolved in the third quarter of 2015), a special purpose limited liability company and all of its membership capital was owned by Avista Corp. Therm -Unit of measurement for natural gas; a therm is equal to approximately one hundred cubic feet (volume) or 100,000 BTUs (energy) UTC -Washington Utilities and Transportation Commission Watt -Unit of measurement for electricity; a watt is equal to the rate of work represented by a current of one ampere under a pressure of one volt iv Staff_DR_063 Attachment A Page 7 of 180 Table of Contents AVISTA CORPORATION Forward-Looking Statements From time to time, we make forward-looking statements such as statements regarding projected or future: •financial performance; •cash flows; •capital expenditures; •dividends; •capital structure; •other financial items; •strategic goals and objectives; •business environment; and •plans for operations. These statements are based upon underlying assumptions (many of which are based, in turn, upon further assumptions). Such statements are made both in our reports filed under the Securities Exchange Act of 1934, as amended (including this Annual Report on Form 10-K), and elsewhere. Forward-looking statements are all statements except those of historical fact including, without limitation, those that are identified by the use of words that include “will,” “may,” “could,” “should,” “intends,” “plans,” “seeks,” “anticipates,” “estimates,” “expects,” “forecasts,” “projects,” “predicts,” and similar expressions. Forward-looking statements (including those made in this Annual Report on Form 10-K) are subject to a variety of risks and uncertainties and other factors. Most of these factors are beyond our control and may have a significant effect on our operations, results of operations, financial condition or cash flows, which could cause actual results to differ materially from those anticipated in our statements. Such risks, uncertainties and other factors include, among others: Financial Risk •weather conditions (temperatures, precipitation levels and wind patterns) which affect both energy demand and electric generating capability, including the effect of precipitation and temperature on hydroelectric resources, the effect of wind patterns on wind-generated power, weather- sensitive customer demand, and similar effects on supply and demand in the wholesale energy markets; •our ability to obtain financing through the issuance of debt and/or equity securities, which can be affected by various factors including our credit ratings, interest rates and other capital market conditions and the global economy; •changes in interest rates that affect borrowing costs, our ability to effectively hedge interest rates for anticipated debt issuances, variable interest rate borrowing and the extent we recover interest costs through utility operations; •changes in actuarial assumptions, interest rates and the actual return on plan assets for our pension and other postretirement benefit plans, which can affect future funding obligations, pension and other postretirement benefit expense and the related liabilities; •external pressure to meet financial goals that can lead to short-term or expedient decisions that reduce the likelihood of long-term objectives being met; •deterioration in the creditworthiness of our customers; •the outcome of pending legal proceedings arising out of the “western energy crisis” of 2000 and 2001, specifically related to the Pacific Northwest refund proceedings; •the outcome of legal proceedings and other contingencies; •economic conditions in our service areas, including the economy's effects on customer demand for utility services; •declining energy demand related to customer energy efficiency and/or conservation measures; •changes in the long-term global and our utilities' service area climates, which can affect, among other things, customer demand patterns and the volume and timing of streamflows to our hydroelectric resources; •changes in industrial, commercial and residential growth and demographic patterns in our service territory or changes in demand by significant customers; 1 Staff_DR_063 Attachment A Page 8 of 180 Table of Contents AVISTA CORPORATION Utility Regulatory Risk •state and federal regulatory decisions that affect our ability to recover costs and earn a reasonable return including, but not limited to, disallowance or delay in the recovery of capital investments, operating costs and commodity costs and discretion over allowed return on investment; •possibility that our integrated resource plans for electric and natural gas will not be acknowledged by the state commissions; Energy Commodity Risk •volatility and illiquidity in wholesale energy markets, including the availability of willing buyers and sellers, changes in wholesale energy prices that can affect operating income, cash requirements to purchase electricity and natural gas, value received for wholesale sales, collateral required of us by counterparties in wholesale energy transactions and credit risk to us from such transactions, and the market value of derivative assets and liabilities; •default or nonperformance on the part of any parties from whom we purchase and/or sell capacity or energy; •potential obsolescence of our power supply resources; Operational Risk •severe weather or natural disasters, including, but not limited to, avalanches, wind storms, wildfires, snow and ice storms, that can disrupt energy generation, transmission and distribution, as well as the availability and costs of materials, equipment, supplies and support services; •explosions, fires, accidents, mechanical breakdowns or other incidents that may impair assets and may disrupt operations of any of our generation facilities, transmission and distribution systems or other operations and may require us to purchase replacement power; •public injuries or damage arising from or allegedly arising from our operations; •blackouts or disruptions of interconnected transmission systems (the regional power grid); •terrorist attacks, cyber attacks or other malicious acts that may disrupt or cause damage to our utility assets or to the national economy in general, including any effects of terrorism, cyber attacks or vandalism that damage or disrupt information technology systems; •work force issues, including changes in collective bargaining unit agreements, strikes, work stoppages, the loss of key executives, availability of workers in a variety of skill areas, and our ability to recruit and retain employees; •increasing costs of insurance, more restrictive coverage terms and our ability to obtain insurance; •delays or changes in construction costs, and/or our ability to obtain required permits and materials for present or prospective facilities; •third party construction of buildings, billboard signs or towers within our rights of way, or placement of fuel receptacles within close proximity to our transformers or other equipment, including overbuild atop natural gas distribution lines; •the loss of key suppliers for materials or services or disruptions to the supply chain; •increasing health care costs and the resulting effect on employee injury costs and health insurance provided to our employees and retirees; •adverse impacts to our Alaska operations that could result from an extended outage of its hydroelectric generating resources or its inability to deliver energy, due to its lack of interconnectivity to any other electrical grids and the extensive cost of replacement power (diesel); Compliance Risk •compliance with extensive federal, state and local legislation and regulation, including numerous environmental, health, safety, infrastructure protection, reliability and other laws and regulations that affect our operations and costs; •the ability to comply with the terms of the licenses and permits for our hydroelectric or thermal generating facilities at cost-effective levels; 2 Staff_DR_063 Attachment A Page 9 of 180 Table of Contents AVISTA CORPORATION Technology Risk •cyber attacks on us or our vendors or other potential lapses that result in unauthorized disclosure of private information, which could result in liabilities against us, costs to investigate, remediate and defend, and damage to our reputation; •disruption to or breakdowns of information systems, automated controls and other technologies that we rely on for our operations, communications and customer service; •changes in the costs to operate and maintain current production technology or to implement new information technology systems that impede our ability to complete such projects timely and effectively; •changes in technologies, possibly making some of the current technology we utilize obsolete or the introduction of new technology that may create new cyber security related risk; •insufficient technology skills, which could lead to the inability to develop, modify or maintain our information systems; Strategic Risk •growth or decline of our customer base and the extent to which new uses for our services may materialize or existing uses may decline, including, but not limited to, the effect of the trend toward distributed generation at customer sites; •potential difficulties in integrating acquired operations and in realizing expected opportunities, diversions of management resources and losses of key employees, challenges with respect to operating new businesses and other unanticipated risks and liabilities; •the potential effects of negative publicity regarding business practices, whether true or not, which could result in litigation or a decline in our common stock price; •changes in our strategic business plans, which may be affected by any or all of the foregoing, including the entry into new businesses and/or the exit from existing businesses and the extent of our business development efforts where potential future business is uncertain; External Mandates Risk •changes in environmental laws, regulations, decisions and policies, including present and potential environmental remediation costs and our compliance with these matters; •the potential effects of legislation or administrative rulemaking at the federal, state or local levels, including possible effects on our generating resources of restrictions on greenhouse gas emissions to mitigate concerns over global climate changes; •political pressures or regulatory practices that could constrain or place additional cost burdens on our energy supply sources, such as campaigns to halt coal-fired power generation and opposition to other thermal generation, wind turbines or hydroelectric facilities; •wholesale and retail competition including alternative energy sources, growth in customer-owned power resource technologies that displace utility- supplied energy or that may be sold back to the utility, and alternative energy suppliers and delivery arrangements; •failure by us to identify changes in legislation, taxation and regulatory issues which are detrimental or beneficial to our overall business; and •the risk of municipalization in any of our service territories. Our expectations, beliefs and projections are expressed in good faith. We believe they are reasonably based on, without limitation, an examination of historical operating trends, our records and other information available from third parties. However, there can be no assurance that our expectations, beliefs or projections will be achieved or accomplished. Furthermore, any forward-looking statement speaks only as of the date on which such statement is made. We undertake no obligation to update any forward-looking statement or statements to reflect events or circumstances that occur after the date on which such statement is made or to reflect the occurrence of unanticipated events. New risks, uncertainties and other factors emerge from time to time, and it is not possible for us to predict all such factors, nor can we assess the effect of each such factor on our business or the extent that any such factor or combination of factors may cause actual results to differ materially from those contained in any forward-looking statement. 3 Staff_DR_063 Attachment A Page 10 of 180 Table of Contents AVISTA CORPORATION Available Information Our Web site address is www.avistacorp.com. We make annual, quarterly and current reports available on our Web site as soon as practicable after electronically filing these reports with the U.S. Securities and Exchange Commission (SEC). Information contained on our Web site is not part of this report. PART I ITEM 1. BUSINESS COMPANY OVERVIEW Avista Corporation, incorporated in the territory of Washington in 1889, is primarily an electric and natural gas utility with certain other business ventures. As of December 31, 2015, we employed 1,711 people in our Pacific Northwest utility operations (Avista Utilities) and 227 people in our subsidiary businesses (including our Juneau, Alaska utility operations). Our corporate headquarters are in Spokane, Washington, the second-largest city in Washington. Spokane serves as the business, transportation, medical, industrial and cultural hub of the Inland Northwest region (eastern Washington and northern Idaho). Regional services include government and higher education, medical services, retail trade and finance. Through our subsidiary AEL&P, we also provide electric utility services in the City and Borough of Juneau (Juneau), Alaska. As of December 31, 2015, we have two reportable business segments as follows: •Avista Utilities – an operating division of Avista Corp. (not a subsidiary) that comprises our regulated utility operations in the Pacific Northwest. Avista Utilities generates, transmits and distributes electricity and distributes natural gas, serving electric and natural gas customers in eastern Washington and northern Idaho and natural gas customers in parts of Oregon. We also supply electricity to a small number of customers in Montana, most of whom are our employees who operate our Noxon Rapids generating facility. Avista Utilities also engages in wholesale purchases and sales of electricity and natural gas as an integral part of energy resource management and our load-serving obligation. •AEL&P - a utility providing electric services in Juneau, Alaska and the primary operating subsidiary of AERC. We acquired AERC on July 1, 2014, and as of that date, AERC became a wholly-owned subsidiary of Avista Corp. See "Note 4 of the Notes to Consolidated Financial Statements" for further discussion regarding this acquisition. We have other businesses, including sheet metal fabrication, venture fund investments, real estate investments, a company that explores markets that could be served with LNG, as well as certain other investments of Avista Capital, which is a direct, wholly owned subsidiary of Avista Corp. These activities do not represent a reportable business segment and are conducted by various direct and indirect subsidiaries of Avista Corp., including AM&D, doing business as METALfx. Total Avista Corp. shareholders’ equity was $1,528.6 million as of December 31, 2015, of which $57.4 million represented our investment in Avista Capital and $95.4 million represented our investment in AERC. See “Item 6. Selected Financial Data” and “Note 21 of the Notes to Consolidated Financial Statements” for information with respect to the operating performance of each business segment (and other subsidiaries). AVISTA UTILITIES General At the end of 2015, we supplied retail electric service to 375,000 customers and retail natural gas service to 335,000 customers across Avista Utilities' service territory. Avista Utilities' service territory covers 30,000 square miles with a population of 1.6 million. See “Item 2. Properties” for further information on our utility assets. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Economic Conditions and Utility Load Growth” for information on economic conditions in our service territory. Electric Operations General Avista Utilities generates, transmits and distributes electricity, serving electric customers in eastern Washington, northern Idaho and a small number of customers in Montana. Avista Utilities generates electricity from facilities that we own and purchases capacity, energy and fuel for generation under long-term and short-term contracts to meet customer load obligations. We also sell electric capacity and energy, as well as surplus fuel in the wholesale market in connection with our resource optimization activities as described below. 4 Staff_DR_063 Attachment A Page 11 of 180 Table of Contents AVISTA CORPORATION As part of Avista Utilities' resource procurement and management operations in the electric business, we engage in an ongoing process of resource optimization, which involves the economic selection from available energy resources to serve our load obligations and then capture additional economic value through market transactions. We engage in transactions in the wholesale markets by selling and purchasing electric capacity and energy, fuel for electric generation, and derivative instruments related to capacity, energy, transport and fuel. Such transactions are part of the process of matching available resources with load obligations and hedging the related financial risks. These transactions range from terms of intra-hour up to multiple years. We make continuing projections of: •electric loads at various points in time (ranging from intra-hour to multiple years) based on, among other things, estimates of customer usage and weather, historical data and contract terms, and •resource availability at these points in time based on, among other things, fuel choices and fuel markets, estimates of streamflows, availability of generating units, historic and forward market information, contract terms, and experience. On the basis of these projections, we make purchases and sales of electric capacity and energy, fuel for electric generation, and related derivative instruments to match expected resources to expected electric load requirements and reduce our exposure to electricity (or fuel) market price changes. Resource optimization involves scheduling and dispatching available resources as well as the following: •purchasing fuel for generation, •when economical, selling fuel and substituting wholesale electric purchases, and •other wholesale transactions to capture the value of generating resources, transmission contract rights and fuel delivery (transport) capacity contracts. This optimization process includes entering into hedging transactions to manage risks. Transactions include both physical energy contracts and related derivative instruments. Avista Utilities' generation assets are interconnected through the regional transmission system and are operated on a coordinated basis to enhance load- serving capability and reliability. Avista acquires both long term and short term transmission capacity to facilitate all of our energy and capacity transactions. We provide transmission and ancillary services in eastern Washington, northern Idaho and western Montana. Electric Requirements Avista Utilities' peak electric native load requirement for 2015 occurred on August 12, 2015, at which time our peak electric native load was 1,638 MW. In 2014 and 2013, our peak electric native load requirements were 1,715 and 1,669 MW, respectively, both of which occurred during the winter. Electric Resources Avista Utilities has a diverse electric resource mix of Company-owned and contracted hydroelectric projects, thermal generating facilities, wind generation facilities, and power purchases and exchanges. At the end of 2015, our Company-owned facilities had a total net capability of 1,841 MW, of which 55 percent was hydroelectric and 45 percent was thermal. See “Item 2. Properties” for detailed information on generating facilities. Hydroelectric Resources Avista Utilities owns and operates six hydroelectric projects on the Spokane River and two hydroelectric projects on the Clark Fork River. Hydroelectric generation is typically our lowest cost source per MWh of electricity and the availability of hydroelectric generation has a significant effect on total power supply costs. Under normal streamflow and operating conditions, we estimate that we would be able to meet approximately one-half of our total average electric requirements (both retail and long-term wholesale) with the combination of our hydroelectric generation and long-term hydroelectric purchase contracts with certain PUDs in the state of Washington. Our estimate of normal annual hydroelectric generation for 2016 (including resources purchased under long-term hydroelectric contracts with certain PUDs) is 533 aMW (or 4.6 million MWhs). 5 Staff_DR_063 Attachment A Page 12 of 180 Table of Contents AVISTA CORPORATION The following graph shows Avista Utilities' hydroelectric generation (in thousands of MWhs) during the year ended December 31: (1)Normal hydroelectric generation is determined by applying an upstream regulation calculation to median natural water flow information. Natural water flow is the flow of the rivers without the influence of dams, whereas regulated water flow takes into account any water flow changes from upstream dams due to releasing or holding back water. The calculation of normal varies annually due to the timing of upstream dam regulation throughout the year. Thermal Resources Avista Utilities owns the following thermal resources: •the combined cycle CT natural gas-fired Coyote Springs 2 located near Boardman, Oregon, •a 15 percent interest in a twin-unit, coal-fired boiler generating facility, Colstrip 3 & 4, located in southeastern Montana, •a wood waste-fired boiler generating facility known as the Kettle Falls Generating Station (Kettle Falls GS) in northeastern Washington, •a two-unit natural gas-fired CT generating facility, located in northeastern Spokane (Northeast CT), •a two-unit natural gas-fired CT generating facility in northern Idaho (Rathdrum CT), and •two small natural gas-fired generating facilities (Boulder Park and Kettle Falls CT). Coyote Springs 2, which is operated by Portland General Electric Company, is supplied with natural gas under both term contracts and spot market purchases, including transportation agreements with bilateral renewal rights. Colstrip, which is operated by Talen Energy LLC, is supplied with fuel from adjacent coal reserves under coal supply and transportation agreements in effect through 2019. The primary fuel for the Kettle Falls GS is wood waste generated as a by-product and delivered by trucks from forest industry operations within 100 miles of the plant. A combination of long-term contracts and spot purchases has provided, and is expected to meet, fuel requirements for the Kettle Falls GS. 6 Staff_DR_063 Attachment A Page 13 of 180 Table of Contents AVISTA CORPORATION The Northeast CT, Rathdrum CT, Boulder Park and Kettle Falls CT generating units are primarily used to meet peaking electric requirements. We also operate these facilities when marginal costs are below prevailing wholesale electric prices. These generating facilities have access to natural gas supplies that are adequate to meet their respective operating needs. See "Item 2. Properties - Avista Utilities - Generation Properties" for the nameplate rating and present generating capabilities of the above thermal resources. Lancaster Plant We have the exclusive rights to capacity of the Lancaster Plant, a 270 MW natural gas-fired combined cycle combustion turbine plant located in northern Idaho, owned by an unrelated third-party. All of the output from the Lancaster Plant is contracted to us through 2026 under a power purchase agreement (PPA). Under the terms of the PPA, we make the dispatch decisions, provide all natural gas fuel and receive all of the electric energy output from the Lancaster Plant; therefore, we consider this plant in our baseload resources. See "Note 3 of the Notes to Consolidated Financial Statements" for further discussion of this PPA. The following graph shows Avista Utilities' thermal generation (in thousands of MWhs) during the year ended December 31: Wind Resources Palouse Wind is a wind generation project developed by Palouse Wind, LLC, and located in Whitman County, Washington. We have a 30- year PPA (expires in 2042) to acquire all of the power and renewable attributes produced by the project at a fixed price per MWh with a fixed escalation of the price over the term of the agreement. The project has a nameplate capacity of approximately 105 MW. Generation from Palouse Wind was 293,563 MWhs in 2015, 335,291 MWhs in 2014 and 297,027 MWhs in 2013. We have an annual option to purchase the wind project following the 10th anniversary of its December 2012 commercial operation date. The purchase price per the PPA is a fixed price per KW of in-service capacity with a fixed decline in the price per KW over the remaining 20 year term of the agreement. Other Purchases, Exchanges and Sales In addition to the resources described above, we purchase and sell power under various long-term contracts and we also enter into short-term purchases and sales. Further, pursuant to the PURPA, as amended, we are required to purchase generation from qualifying facilities. This includes, among other resources, hydroelectric projects, cogeneration projects and wind generation projects at rates approved by the UTC and the IPUC. See “Avista Utilities Operating Statistics – Electric Operations – Electric Energy Resources” for annual quantities of purchased power, wholesale power sales and power from exchanges in 2015, 2014 and 2013. See “Electric Operations” for additional information with respect to the use of wholesale purchases and sales as part of our resource optimization process and also see "Future Resource Needs" for the magnitude of these power purchase and sales contracts in future periods. 7 Staff_DR_063 Attachment A Page 14 of 180 Table of Contents AVISTA CORPORATION Hydroelectric Licenses Avista Corp. is a licensee under the Federal Power Act (FPA) as administered by the FERC, which includes regulation of hydroelectric generation resources. Excluding the Little Falls Hydroelectric Generating Project, our other seven hydroelectric plants are regulated by the FERC through two project licenses. The licensed projects are subject to the provisions of Part I of the FPA. These provisions include payment for headwater benefits, condemnation of licensed projects upon payment of just compensation, and take-over of such projects after the expiration of the license upon payment of the lesser of “net investment” or “fair value” of the project, in either case, plus severance damages. Cabinet Gorge and Noxon Rapids are under one 45-year FERC license issued in March 2001. See “Cabinet Gorge Total Dissolved Gas Abatement Plan” in “Note 19 of the Notes to Consolidated Financial Statements” for discussion of dissolved atmospheric gas levels that exceed state of Idaho and federal numeric water quality standards downstream of Cabinet Gorge during periods when we must divert excess river flows over the spillway as well as of our mitigation plans and efforts. Five of our six hydroelectric projects on the Spokane River (Long Lake, Nine Mile, Upper Falls, Monroe Street and Post Falls) are under one 50-year FERC license issued in June 2009 and are referred to collectively as the Spokane River Project. The sixth, Little Falls, is operated under separate Congressional authority and is not licensed by the FERC. Future Resource Needs Avista Utilities has operational strategies to provide sufficient resources to meet our energy requirements under a range of operating conditions. These operational strategies consider the amount of energy needed, which varies widely because of the factors that influence demand over intra-hour, hourly, daily, monthly and annual durations. Our average hourly load was 1,047 aMW in 2015, 1,062 aMW in 2014 and 1,086 aMW in 2013. The following is a forecast of our average annual energy requirements and resources for 2016 through 2019: (1)The contracts for power sales decrease due to certain contracts expiring in each of these years. We are evaluating the future plan for the additional resources made available due to the expiration of these contracts. (2)The forecast assumes near normal hydroelectric generation. (3)Includes the Lancaster Plant PPA. Excludes Boulder Park GS, Kettle Falls CT, Northeast CT and Rathdrum CT, as these are considered peaking facilities and are generally not used to meet our base load requirements. (4)The combined maximum capacity of Boulder Park GS, Kettle Falls CT, Northeast CT and Rathdrum CT is 278 MW, with estimated available energy production as indicated for each year. 8 Staff_DR_063 Attachment A Page 15 of 180 Table of Contents AVISTA CORPORATION In August 2015, we filed our 2015 Electric IRP with the UTC and the IPUC. The UTC and IPUC review the IRPs and give the public the opportunity to comment. The UTC and IPUC do not approve or disapprove of the content in the IRPs; rather they only acknowledge that the IRPs were prepared in accordance with applicable standards if that is the case. The IRP details projected growth in demand for energy and the new resources needed to serve customers over the next 20 years. We regard the IRP as a tool for resource evaluation, rather than an acquisition plan for a particular project. Highlights of the 2015 IRP include: •We have adequate resources between our owned and contractually controlled generation, combined with conservation and market purchases, to meet customer needs through 2020. •565 MW of additional generation capacity is required for the period 2020 through 2034. •We expect to meet or exceed the renewable energy requirements of the Washington state Energy Independence Act through the 20-year IRP time frame with a combination of qualifying hydroelectric upgrades, the 30-year PPA with Palouse Wind, the Kettle Falls GS and selective REC purchases. •Load growth is expected to be approximately 0.6 percent, a decline from the growth of 1.0 percent forecasted in 2013. This delays the need for a new natural gas-fired resource by one year. The decrease in expected load growth is primarily due to energy efficiency programs (using less energy to perform activities) over the next 20 years and the load impacts of increased prices. See "Item 7. Management Discussion and Analysis of Financial Condition and Results of Operations – Forecasted Customer and Load Growth and Economic Conditions and Utility Load Growth" for further discussion regarding utility customer growth, load growth, and the general economic conditions in our service territory. The estimates of future load growth in the IRP and at "Item 7. Management Discussion and Analysis of Financial Condition and Results of Operations – Forecasted Customer and Load Growth and Economic Conditions and Utility Load Growth" differ slightly due to the timing of when the two estimates were prepared and due to the time period that each estimate is focused on. •Colstrip remains a cost effective and reliable source of power to meet future customer needs. •Energy efficiency offsets more than half of projected load growth through the 20-year IRP time frame. •Demand response (temporarily reducing the demand for energy) was eliminated from the Preferred Resource Strategy due to higher estimated costs. We are required to file an IRP every two years, with the next IRP expected to be filed during the third quarter of 2017. Our resource strategy may change from the 2015 IRP based on market, legislative and regulatory developments. We are subject to the Washington state Energy Independence Act, which requires us to obtain a portion of our electricity from qualifying renewable resources or through purchase of RECs and acquiring all cost effective conservation measures. Future generation resource decisions will be impacted by legislation for restrictions on GHG emissions and renewable energy requirements. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Environmental Issues and Contingencies” for information related to existing laws, as well as potential legislation that could influence our future electric resource mix. Natural Gas Operations General Avista Utilities provides natural gas distribution services to retail customers in parts of eastern Washington, northern Idaho, and northeastern and southwestern Oregon. Market prices for natural gas, like other commodities, can be volatile. Our natural gas procurement strategy is to provide reliable supply to our customers with some level of price certainty. We procure natural gas from various supply basins and over varying time periods. The resulting portfolio is a diversified mix of spot market purchases and forward fixed price purchases, utilizing physical and financial derivative instruments. We also use natural gas storage to support high demand periods and to procure natural gas when prices may be lower. Securing prices throughout the year and even into subsequent years provides a level of price certainty and can mitigate price volatility to customers between years. Weather is a key component of our natural gas customer load. This load is highly variable and daily natural gas loads can differ significantly from the monthly forecasted load projections. We make continuing projections of our natural gas loads and assess available natural gas resources. On the basis of these projections, we plan and execute a series of transactions to hedge a portion 9 Staff_DR_063 Attachment A Page 16 of 180 Table of Contents AVISTA CORPORATION of our customers' projected natural gas requirements through forward market transactions and derivative instruments. These transactions may extend for multiple years into the future with the highest volumes hedged for the current and most immediate upcoming natural gas operating year (November through October). We also leave a portion of our natural gas supply requirements unhedged for purchase in the short-term spot markets. Our purchase of natural gas supply is governed by our procurement plan, which is reviewed and approved annually by the Risk Management Committee (RMC), which is comprised of certain officers and other management personnel. Once approval is received, the plan is implemented and monitored by our gas supply and risk management groups. The plan’s progress is also presented to the UTC and IPUC staff in semi-annual meetings, and updates are given to the OPUC staff quarterly. Other stakeholders (Public Counsel Unit of the Office of the Attorney General, Citizen Utility Board) are invited to participate. The RMC is provided with an update on plan results and changes in their monthly meetings. These activities provide transparency for the natural gas supply procurement plan. Any material changes to the plan are documented and communicated to RMC members. As part of the process of balancing natural gas retail load requirements with resources, we engage in the wholesale purchase and sale of natural gas. We plan for sufficient natural gas delivery capacity to serve our retail customers for a theoretical peak day event. As such, we generally have more pipeline and storage capacity than what is needed during periods other than a peak day. We optimize our natural gas resources by using market opportunities to generate economic value that helps mitigate fixed costs. Wholesale sales are delivered through wholesale market facilities outside of our natural gas distribution system. Natural gas resource optimization activities include, but are not limited to: •wholesale market sales of surplus natural gas supplies, •purchases and sales of natural gas to optimize use of pipeline and storage capacity, and •participation in the transportation capacity release market. We also provide distribution transportation service to qualified, large commercial and industrial natural gas customers who purchase natural gas through third-party marketers. For these customers, we receive their purchased natural gas from such third-party marketers into our distribution system and redeliver it to the customers’ premise. Optimization transactions that we engage in throughout the year are included in our annual purchased gas cost adjustment filings with the various commissions and they are subject to review for prudency during this process. Natural Gas Supply Avista Utilities purchases all of its natural gas in wholesale markets. We are connected to multiple supply basins in the western United States and Canada through firm capacity transportation rights on six different pipeline networks. Access to this diverse portfolio of natural gas resources allows us to make natural gas procurement decisions that benefit our natural gas customers. These interstate pipeline transportation rights provide the capacity to serve approximately 25 percent of peak natural gas customer demands from domestic sources and 75 percent from Canadian sourced supply. Natural gas prices in the Pacific Northwest are affected by global energy markets, as well as supply and demand factors in other regions of the United States and Canada. Future prices and delivery constraints may cause our resource mix to vary. Natural Gas Storage Avista Utilities owns a one-third interest in Jackson Prairie, an underground aquifer natural gas storage field located near Chehalis, Washington. Jackson Prairie has a total peak day deliverability of 12 million therms, with a total working natural gas capacity of 256 million therms. As an owner, our share is one-third of the peak day deliverability and total working capacity. We also contract for additional storage capacity and delivery at Jackson Prairie from Northwest Pipeline for a portion of their one-third share of the storage project. We optimize our natural gas storage capacity by purchasing and storing natural gas when prices are traditionally lower, typically in the summer, and withdraw during higher priced months, typically during the winter. However, if market conditions and prices indicate that we should buy or sell natural gas during other times in the year, we engage in optimization transactions to capture value in the marketplace. Jackson Prairie is also used as a variable peaking resource and to protect from extreme daily price volatility during cold weather or other events affecting the market. Future Resource Needs In August 2014, we filed our 2014 Natural Gas IRP with the UTC, IPUC and the OPUC. The natural gas IRPs are similar in nature to the electric IRPs and the process for preparation and review by the state commissions of both the electric and natural gas IRPs is similar. The IRP details projected growth in demand for energy and the new resources needed to serve customers over the next 20 years. We regard the IRP as a tool for resource evaluation, rather than an acquisition plan for a particular project. 10 Staff_DR_063 Attachment A Page 17 of 180 Table of Contents AVISTA CORPORATION Highlights of the 2014 IRP include: •We have sufficient natural gas transportation resources well into the future with resource needs not occurring during the 20 year planning horizon in Washington, Idaho, or Oregon. •Natural gas commodity prices continue to be relatively stable due to robust North American supplies led by shale gas development; and •As forecasted demand is relatively flat, we will monitor actual demand for signs of increased growth which could accelerate resource needs. We are required to file an IRP every two years, with the next IRP expected to be filed during the third quarter of 2016. Our resource strategy may change from the 2014 IRP based on market, legislative and regulatory developments. Regulatory Issues General As a public utility, Avista Corp. is subject to regulation by state utility commissions for prices, accounting, the issuance of securities and other matters. The retail electric and natural gas operations are subject to the jurisdiction of the UTC, the IPUC, the OPUC and the MPSC. Approval of the issuance of securities is not required from the MPSC. We are also subject to the jurisdiction of the FERC for licensing of hydroelectric generation resources, and for electric transmission services and wholesale sales. Since Avista Corp. is a “holding company,” we are also subject to the jurisdiction of the FERC under the Public Utility Holding Company Act of 2005, which imposes certain reporting and other requirements. We, and all of our subsidiaries (whether or not engaged in any energy related business), are required to maintain books, accounts and other records in accordance with the FERC regulations and to make them available to the FERC and the state utility commissions. In addition, upon the request of any state utility commission, or of Avista Corp., the FERC would have the authority to review assignment of costs of non-power goods and administrative services among us and our subsidiaries. The FERC has the authority generally to require that rates subject to its jurisdiction be just and reasonable and in this context would continue to be able to, among other things, review transactions of any affiliated company. Our rates for retail electric and natural gas services (other than specially negotiated retail rates for industrial or large commercial customers, which are subject to regulatory review and approval) are generally determined on a “cost of service” basis. Rates are designed to provide an opportunity for us to recover allowable operating expenses and earn a return of and a reasonable return on “rate base.” Rate base is generally determined by reference to the original cost (net of accumulated depreciation) of utility plant in service, subject to various adjustments for deferred income taxes and other items. Over time, rate base is increased by additions to utility plant in service and reduced by depreciation and retirement of utility plant and write-offs as authorized by the utility commissions. Our operating expenses and rate base are allocated or directly assigned among five regulatory jurisdictions: electric in Washington and Idaho, and natural gas in Washington, Idaho and Oregon. In general, requests for new retail rates are made on the basis of net investment, operating expenses and revenues for a test year that ended prior to the date of the request, plus certain adjustments, which differ among the various jurisdictions, designed to reflect the expected revenues, expenses and net investment during the period new retail rates will be in effect. The retail rates approved by the state commissions in a rate proceeding may not provide sufficient revenues to provide recovery of costs and a reasonable return on investment for a number of reasons, including but not limited to, unexpected changes in revenues, expenses and investment following the time new retail rates are requested in the rate proceeding, and exclusion of certain costs and investment by the commission from the rate making process. Our rates for wholesale electric and natural gas transmission services are based on either “cost of service” principles or market-based rates as set forth by the FERC. See “Notes 1 and 20 of the Notes to Consolidated Financial Statements” for additional information about regulation, depreciation and deferred income taxes. General Rate Cases Avista Utilities regularly reviews the need for electric and natural gas rate changes in each state in which we provide service. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Regulatory Matters – General Rate Cases” for information on general rate case activity. Power Cost Deferrals Avista Utilities defers the recognition in the income statement of certain power supply costs that vary from the level currently recovered from our retail customers as authorized by the UTC and the IPUC. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Regulatory Matters – Power Cost Deferrals and Recovery Mechanisms” and “Note 20 of the Notes to Consolidated Financial Statements” for information on power cost deferrals and recovery mechanisms in Washington and Idaho. 11 Staff_DR_063 Attachment A Page 18 of 180 Table of Contents AVISTA CORPORATION Purchased Gas Adjustment (PGA) Under established regulatory practices in each state, Avista Utilities defers the recognition in the income statement of the natural gas costs that vary from the level currently recovered from our retail customers as authorized by each of our jurisdictions. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Regulatory Matters – Purchased Gas Adjustments” and “Note 20 of the Notes to Consolidated Financial Statements” for information on natural gas cost deferrals and recovery mechanisms in Washington, Idaho and Oregon. Federal Laws Related to Wholesale Competition Federal law promotes practices that open the electric wholesale energy market to competition. The FERC requires electric utilities to transmit power and energy to or for wholesale purchasers and sellers, and requires electric utilities to enhance or construct transmission facilities to create additional transmission capacity for the purpose of providing these services. Public utilities (through subsidiaries or affiliates) and other entities may participate in the development of independent electric generating plants for sales to wholesale customers. Public utilities operating under the FPA are required to provide open and non-discriminatory access to their transmission systems to third parties and establish an Open Access Same-Time Information System to provide an electronic means by which transmission customers can obtain information about available transmission capacity and purchase transmission access. The FERC also requires each public utility subject to the rules to operate its transmission and wholesale power merchant operating functions separately and to comply with standards of conduct designed to ensure that all wholesale users, including the public utility’s power merchant operations, have equal access to the public utility’s transmission system. Our compliance with these standards has not had any substantive impact on the operation, maintenance and marketing of our transmission system or our ability to provide service to customers. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Competition” for further information. Regional Transmission Organizations Beginning with FERC Order No. 888 and continuing with subsequent rulemakings and policies, the FERC has encouraged better coordination and operational consistency aimed to capture efficiencies that might otherwise be gained through the formation of a Regional Transmission Organization (RTO) or an independent system operator (ISO). Regional Transmission Planning Avista Utilities meets its FERC requirements to coordinate transmission planning activities with other regional entities through ColumbiaGrid. ColumbiaGrid is a Washington nonprofit membership corporation with an independent board formed to improve the operational efficiency, reliability, and planned expansion of the transmission grid in the Pacific Northwest. We became a member of ColumbiaGrid in 2006 during its formation. ColumbiaGrid is not an ISO, but performs those functions that its members request, as set forth in specific agreements. Currently, ColumbiaGrid fills the role of facilitating our regional transmission planning as required in FERC Order No. 1000 and other clarifying FERC Orders. ColumbiaGrid and its members also work with other western organizations to address transmission planning, including WestConnect and the Northern Tier Transmission Group (NTTG). In 2011, we became a registered Planning Participant of the NTTG. We will continue to assess the benefits of entering into other functional agreements with ColumbiaGrid and/or participating in other forums to attain operational efficiencies and to meet FERC policy objectives. Regional Energy Markets The California Independent System Operator (CAISO) recently implemented an EIM in the western United States. Several Pacific Norhwest utilities are either participants in the CAISO EIM or plan to integrate into the market in the next few years, which could reduce bilateral market liquidity and transaction opportunities in the Pacific Northwest. Avista Utilities is monitoring the CAISO EIM implementation but currently does not plan to join as a participating member. We will continue to monitor the CAISO EIM expansion and the associated impacts. As market fundamentals and our business needs evolve, we will weigh the advantages and disadvantages of joining the CAISO EIM or other organized energy markets in the future. Reliability Standards Among its other provisions, the U.S. Energy Policy Act provides for the implementation of mandatory reliability standards and authorizes the FERC to assess penalties for non-compliance with these standards and other FERC regulations. The FERC certified the NERC as the single Electric Reliability Organization authorized to establish and enforce reliability standards and delegate authority to regional entities for the purpose of establishing and enforcing reliability standards. The 12 Staff_DR_063 Attachment A Page 19 of 180 Table of Contents AVISTA CORPORATION FERC approved the NERC Reliability Standards, including western region standards, making up the set of legally enforceable standards for the United States bulk electric system. The first of these reliability standards became effective in June 2007. We are required to self-certify our compliance with these standards on an annual basis and undergo regularly scheduled periodic reviews by the NERC and its regional entity, the Western Electricity Coordinating Council (WECC). Our failure to comply with these standards could result in financial penalties of up to $1 million per day per violation. Annual self-certification and audit processes to date have demonstrated our substantial compliance with these standards. Requirements relating to cyber security are continually evolving. Our compliance with version 5 of the NERC's Critical Infrastructure Protection standard is driving several physical and electronic security initiatives in our control centers, generating stations and substations. We do not expect the costs of the physical and electronic securities initiatives to have a material impact to our financial results. 13 Staff_DR_063 Attachment A Page 20 of 180 Table of Contents AVISTA CORPORATION AVISTA UTILITIES ELECTRIC OPERATING STATISTICS Years Ended December 31, 2015 2014 2013 ELECTRIC OPERATIONS OPERATING REVENUES (Dollars in Thousands): Residential $335,552 $338,697 $331,867 Commercial 308,210 300,109 289,604 Industrial 111,770 110,775 113,632 Public street and highway lighting 7,277 7,549 7,267 Total retail 762,809 757,130 742,370 Wholesale 127,253 138,162 127,556 Sales of fuel 82,853 83,732 126,657 Other 25,839 27,467 36,071 Decoupling 4,740 — — Provision for earnings sharing (5,621) (7,503) (2,048) Total electric operating revenues $997,873 $998,988 $1,030,606 ENERGY SALES (Thousands of MWhs): Residential 3,571 3,694 3,745 Commercial 3,197 3,189 3,147 Industrial 1,812 1,868 1,979 Public street and highway lighting 23 25 26 Total retail 8,603 8,776 8,897 Wholesale 3,145 3,686 3,874 Total electric energy sales 11,748 12,462 12,771 ENERGY RESOURCES (Thousands of MWhs): Hydro generation (from Company facilities)3,434 4,143 3,646 Thermal generation (from Company facilities)3,983 3,252 3,383 Purchased power 4,899 5,615 6,375 Power exchanges (2) (25) (20) Total power resources 12,314 12,985 13,384 Energy losses and Company use (566) (523) (613) Total energy resources (net of losses)11,748 12,462 12,771 NUMBER OF RETAIL CUSTOMERS (Average for Period): Residential 327,057 324,188 321,098 Commercial 41,296 40,988 40,202 Industrial 1,353 1,385 1,386 Public street and highway lighting 529 531 527 Total electric retail customers 370,235 367,092 363,213 RESIDENTIAL SERVICE AVERAGES: Annual use per customer (KWh)10,827 11,394 11,664 Revenue per KWh (in cents)9.40 9.17 8.86 Annual revenue per customer $1,017.21 $1,044.76 $1,033.54 AVERAGE HOURLY LOAD (aMW)1,047 1,062 1,086 14 Staff_DR_063 Attachment A Page 21 of 180 Table of Contents AVISTA CORPORATION AVISTA UTILITIES ELECTRIC OPERATING STATISTICS Years Ended December 31, 2015 2014 2013 RETAIL NATIVE LOAD at time of system peak (MW): Winter 1,529 1,715 1,669 Summer 1,638 1,606 1,577 COOLING DEGREE DAYS: (1) Spokane, WA Actual 805 631 709 Historical average 334 394 394 % of average 241% 160% 180% HEATING DEGREE DAYS: (2) Spokane, WA Actual 5,614 6,215 6,683 Historical average 6,491 6,820 6,780 % of average 86% 91% 99% (1)Cooling degree days are the measure of the warmness of weather experienced, based on the extent to which the average of high and low temperatures for a day exceeds 65 degrees Fahrenheit (annual degree days above historic indicate warmer than average temperatures). In 2015, we switched to a rolling 20-year average for calculating cooling degree days, whereas in prior years we used a 30-year rolling average. (2)Heating degree days are the measure of the coldness of weather experienced, based on the extent to which the average of high and low temperatures for a day falls below 65 degrees Fahrenheit (annual degree days below historic indicate warmer than average temperatures). In 2015, we switched to a rolling 20-year average for calculating heating degree days, whereas in prior years we used a 30-year rolling average. 15 Staff_DR_063 Attachment A Page 22 of 180 Table of Contents AVISTA CORPORATION AVISTA UTILITIES NATURAL GAS OPERATING STATISTICS Years Ended December 31, 2015 2014 2013 NATURAL GAS OPERATIONS OPERATING REVENUES (Dollars in Thousands): Residential $193,825 $203,373 $206,330 Commercial 96,751 103,179 102,225 Interruptible 2,782 2,792 2,681 Industrial 3,792 4,158 3,599 Total retail 297,150 313,502 314,835 Wholesale 204,289 228,187 194,717 Transportation 7,988 7,735 7,576 Other 5,578 7,461 8,573 Decoupling 6,004 — — Provision for earnings sharing — (221) (442) Total natural gas operating revenues $521,009 $556,664 $525,259 THERMS DELIVERED (Thousands of Therms): Residential 176,613 190,171 204,711 Commercial 107,894 116,748 122,245 Interruptible 4,708 5,033 5,694 Industrial 5,070 5,648 5,181 Total retail 294,285 317,600 337,831 Wholesale 809,132 545,620 524,818 Transportation 164,679 162,311 159,976 Interdepartmental and Company use 335 411 418 Total therms delivered 1,268,431 1,025,942 1,023,043 NUMBER OF RETAIL CUSTOMERS (Average for Period): Residential 296,005 291,928 288,708 Commercial 34,229 34,047 33,932 Interruptible 35 37 38 Industrial 261 264 259 Total natural gas retail customers 330,530 326,276 322,937 RESIDENTIAL SERVICE AVERAGES: Annual use per customer (therms)593 651 709 Revenue per therm (in dollars)$1.10 $1.07 $1.01 Annual revenue per customer $650.83 $696.66 $714.67 HEATING DEGREE DAYS: (1) Spokane, WA Actual 5,614 6,215 6,683 Historical average (2)6,491 6,820 6,780 % of average 86% 91% 99% Medford, OR Actual 3,534 3,382 4,576 Historical average (2)4,150 4,539 4,539 % of average 85% 75% 101% (1)Heating degree days are the measure of the coldness of weather experienced, based on the extent to which the average of high and low temperatures for a day falls below 65 degrees Fahrenheit (annual degree days below historic indicate warmer than average temperatures). (2)In 2015, we switched to a rolling 20-year average for calculating heating degree days, whereas in prior years we used a 30-year rolling average. 16 Staff_DR_063 Attachment A Page 23 of 180 Table of Contents AVISTA CORPORATION ALASKA ELECTRIC LIGHT AND POWER COMPANY AEL&P is the primary operating subsidiary of AERC. AEL&P is the sole utility providing electrical energy in Juneau, Alaska. Juneau is a geographically isolated community with no electric interconnections with the transmission facilities of other utilities and no pipeline access to natural gas or other fuels. Juneau’s economy is primarily driven by government activities, tourism, commercial fishing, and mining, as well as activities as the commercial hub of southeast Alaska. AEL&P owns and operates electric generation, transmission and distribution facilities located in Juneau. AEL&P operates five hydroelectric generation facilities with 102.7 MW of hydroelectric generation capacity as of December 31, 2015. AEL&P owns four of these generation facilities (totaling 24.7 MW of capacity) and has a PPA for the output of the Snettisham hydroelectric project (totaling 78 MW of capacity). The Snettisham hydroelectric project is owned by the Alaska Industrial Development and Export Authority (AIDEA), a public corporation of the State of Alaska. AEL&P has a PPA and operating and maintenance agreement with the AIDEA to operate and maintain the facility. This PPA is a take-or-pay obligation expiring in December 2038, to purchase all of the output of the project. For accounting purposes, this PPA is treated as a capital lease and as of December 31, 2015, the capital lease obligation was $64.5 million. Snettisham Electric Company, a non-operating subsidiary of AERC, has the option to purchase the Snettisham project at any time for the principal amount of the bonds outstanding at that time. See "Note 14 of the Notes to Consolidated Financial Statements" for further discussion of the Snettisham capital lease obligation. As of December 31, 2015, AEL&P also had 93.9 MW of diesel generating capacity from three facilities to provide back-up service to firm customers when necessary. The following graph shows AEL&P's hydroelectric generation (in thousands of MWhs) during the time periods indicated below: Only the hydroelectric generation for the second half of 2014 in the graph above was included in Avista Corp.'s overall results for 2014. The full 12 months of 2014 in the graph above is presented for information purposes only. As of December 31, 2015, AEL&P served approximately 17,000 customers. Its primary customers include city, state and federal governmental entities located in Juneau, as well as a mine located in the Juneau area. Most of AEL&P’s customers are served on a firm basis while certain of its customers, including its largest customer, are served on an interruptible sales basis. AEL&P maintains separate rate tariffs for each of its customer classes, as well as seasonal rates. 17 Staff_DR_063 Attachment A Page 24 of 180 Table of Contents AVISTA CORPORATION AEL&P’s operations are subject to regulation by the RCA with respect to rates, standard of service, facilities, accounting and certain other matters, but not with respect to the issuance of securities. Rate adjustments for AEL&P’s customers require approval by the RCA pursuant to RCA regulations. AEL&P's last general rate case was filed in 2010 and approved by the RCA in 2011. The RCA approved a capital structure including 53.8 percent equity and an authorized return on equity of 12.875 percent. We expect that AEL&P will maintain a similar capital structure going forward. AEL&P is also subject to the jurisdiction of the FERC concerning the permits and licenses necessary to operate certain of its hydroelectric facilities. One of these licenses (for the Salmon Creek and Annex Creek hydroelectric projects) expires in 2018. Since AEL&P has no electric interconnection with other utilities and makes no wholesale sales, it is not subject to general FERC jurisdiction. The Snettisham hydroelectric project is subject to regulation by the State of Alaska with respect to dam safety and certain aspects of its operations. In addition, AEL&P is subject to regulation with respect to air and water quality, land use and other environmental matters under both federal and state laws. OTHER BUSINESSES The following graph shows our assets related to our other businesses as of December 31 (dollars in thousands): Spokane Energy was a special purpose limited liability company and all of its membership capital was owned by Avista Corp. Spokane Energy was formed in December 1998, to assume ownership of a fixed rate electric capacity contract between Avista Corp. and Portland General Electric Company. The fixed rate electric capacity contract, which expires in December 2016, was transferred from Spokane Energy to Avista Corp. during the second quarter of 2015. Spokane Energy was then dissolved during the third quarter of 2015. The fixed rate electric capacity contract has a value of $14.7 million as of December 31, 2015, compared to $28.2 million as of December 31, 2014. AM&D doing business as METALfx performs custom sheet metal fabrication of electronic enclosures, parts and systems for the computer, construction, telecom, renewable energy and medical industries. Steam Plant and Courtyard Office Center consist of real estate investments (primarily mixed use commercial and retail office space). AJT Mining is a wholly-owned subsidiary of AERC and is an inactive mining company holding certain properties. The assets at Avista Capital - standalone as of December 31, 2014 primarily consisted of the escrow receivables related to the sale of Ecova on June 30, 2014. The escrow receivables were settled and we received the proceeds during the fourth quarter of 2015. See "Note 5 of the Notes to Consolidated Financial Statements" for further detail regarding this transaction. 18 Staff_DR_063 Attachment A Page 25 of 180 Table of Contents AVISTA CORPORATION Our other investments and operations include emerging technology venture capital funds. Over time as opportunities arise, we dispose of investments and phase out operations that do not fit with our overall corporate strategy. However, we may invest incremental funds to protect our existing investments and invest in new businesses that we believe fit with our overall corporate strategy. We continue to evaluate the opportunity to bring natural gas to Juneau, Alaska. If we pursue this project, we estimate that the total investment for our local distribution company (LDC) project would be about $130 million over 10 years, with about half being invested during the first five years. Lower oil prices have made it more difficult for customers to justify converting to natural gas. In addition, we have yet to secure a mechanism to provide funds that are needed to help customers with the conversion costs, thus challenging the economics of the project. In addition, the state of Alaska has not yet adopted legislation that would enable the state to provide customer assistance for conversions. We will continue our due diligence and we will be ready to proceed if and when the economics prove favorable for customers and our Company. Salix was notified by AIDEA in December 2015 that its proposal to build an LNG liquefaction plant to serve the Interior Energy Project, specifically to serve the Fairbanks, Alaska area, was selected as one of the two finalists. A decision by the AIDEA board is expected in early 2016. ITEM 1A. RISK FACTORS RISK FACTORS The following factors could have a significant impact on our operations, results of operations, financial condition or cash flows. These factors could cause future results or outcomes to differ materially from those discussed in our reports filed with the SEC (including this Annual Report on Form 10-K), and elsewhere. Please also see “Forward-Looking Statements” for additional factors which could have a significant impact on our operations, results of operations, financial condition or cash flows and could cause actual results to differ materially from those anticipated in such statements. Financial Risk Factors Weather (temperatures, precipitation levels, wind patterns and storms) has a significant effect on our results of operations, financial condition and cash flows. Weather impacts are described in the following subtopics: •certain retail electricity and natural gas sales, •the cost of natural gas supply, and •the cost of power supply. Certain retail electricity and natural gas sales volumes vary directly with changes in temperatures. We normally have our highest retail (electric and natural gas) energy sales during the winter heating season in the first and fourth quarters of the year. We also have high electricity demand for air conditioning during the summer (third quarter) in the Pacific Northwest. In general, warmer weather in the heating season and cooler weather in the cooling season will reduce our customers’ energy demand and retail operating revenues. The cost of natural gas supply tends to increase with higher demand during periods of cold weather. Increased costs adversely affect cash flows when we purchase natural gas for retail supply at prices above the amount then allowed for recovery in retail rates. We defer differences between actual natural gas supply costs and the amount currently recovered in retail rates and we are generally allowed to recover substantially all of these differences after regulatory review. However, these deferred costs require cash outflows from the time of natural gas purchases until the costs are later recovered through retail sales. Inter-regional natural gas pipelines and competition for supply can allow demand-driven price volatility in other regions of North America to affect prices in our region, even though there may be less extreme weather conditions in our area. The cost of power supply can be significantly affected by weather. Precipitation (consisting of snowpack, its water content and melting pattern plus rainfall) and other streamflow conditions (such as regional water storage operations) significantly affect hydroelectric generation capability. Variations in hydroelectric generation inversely affect our reliance on market purchases and thermal generation. To the extent that hydroelectric generation is less than normal, significantly more costly power supply resources must be acquired and the ability to realize net benefits from surplus hydroelectric wholesale sales 19 Staff_DR_063 Attachment A Page 26 of 180 Table of Contents AVISTA CORPORATION is reduced. Wholesale prices also vary based on wind patterns as wind generation capacity is material in our region but its contribution to supply is inconsistent. The price of power in the wholesale energy markets tends to be higher during periods of high regional demand, such as occurs with temperature extremes. We may need to purchase power in the wholesale market during peak price periods. The price of natural gas as fuel for natural gas-fired electric generation also tends to increase during periods of high demand which are often related to temperature extremes. We may need to purchase natural gas fuel in these periods of high prices to meet electric demands. The cost of power supply during peak usage periods may be higher than the retail sales price or the amount allowed in retail rates by our regulators. To the extent that power supply costs are above the amount allowed currently in retail rates, the difference is partially absorbed by the Company in current expense and it is partially deferred or shared with customers through regulatory mechanisms. The price of power tends to be lower during periods with excess supply, such as the spring when hydroelectric conditions are usually at their maximum and various facilities are required to operate to meet environmental mandates. Oversupply can be exacerbated when intermittent resources such as wind generation are producing output that may be supported by price subsidies. In extreme situations, we may be required to sell excess energy at negative prices. As a result of these combined factors, our net cost of power supply – the difference between our costs of generation and market purchases, reduced by our revenue from wholesale sales – varies significantly because of weather. We rely on regular access to financial markets but we cannot assure favorable or reasonable financing terms will be available when we need them. Access to capital markets is critical to our operations and our capital structure. We have significant capital requirements that we expect to fund, in part, by accessing capital markets. As such, the state of financial markets and credit availability in the global, United States and regional economies impacts our financial condition. We could experience increased borrowing costs or limited access to capital on reasonable terms. We access long-term capital markets to finance capital expenditures, repay maturing long-term debt and obtain additional working capital from time to time. Our ability to access capital on reasonable terms is subject to numerous factors and market conditions, many of which are beyond our control. If we are unable to obtain capital on reasonable terms, it may limit or prohibit our ability to finance capital expenditures and repay maturing long-term debt. Our liquidity needs could exceed our short-term credit availability and lead to defaults on various financing arrangements. We would also likely be prohibited from paying dividends on our common stock. Performance of the financial markets could also result in significant declines in the market values of assets held by our pension plan and/or a significant increase in the pension liability (which impacts the funded status of the plan) and could increase future funding obligations and pension expense. We rely on credit from financial institutions for short-term borrowings. We need adequate levels of credit with financial institutions for short- term liquidity. We have a $400.0 million committed line of credit that expires in April 2019. Our subsidiary AEL&P has a committed line of credit in the amount of $25.0 million that expires in November 2019. There is no assurance that we will have access to credit beyond these expiration dates. The committed line of credit agreements contain customary covenants and default provisions. In the event of default, it would be difficult for us to obtain financing on reasonable terms to pay creditors or fund operations. We would also likely be prohibited from paying dividends on our common stock. We hedge a portion of our interest rate risk with financial derivative instruments, which may include interest rate swaps and U.S. Treasury lock agreements. If market interest rates decrease below the interest rates we have locked in, this will result in a liability related to our interest rate swap agreements, which can be significant. As of December 31, 2015, we had a net interest rate derivative liability of $84.0 million, reflecting a decline in interest rates since the time we entered the agreements. We did not have any U.S. Treasury lock agreements outstanding as of December 31, 2015. We may be required to post cash or letters of credit as collateral depending on fluctuations in the fair value of the derivative instruments. Settlement of interest rate derivative instruments in a liability position could require a significant amount of cash, which could negatively impact our liquidity and short-term credit availability and increase interest expense over the term of the associated debt. Downgrades in our credit ratings could impede our ability to obtain financing, adversely affect the terms of financing and impact our ability to transact for or hedge energy resources. If we do not maintain our investment grade credit rating with the major credit rating agencies, we could expect increased debt service costs, limitations on our ability to access capital markets or obtain other financing on reasonable terms, and requirements to provide collateral (in the form of cash 20 Staff_DR_063 Attachment A Page 27 of 180 Table of Contents AVISTA CORPORATION or letters of credit) to lenders and counterparties. In addition, credit rating downgrades could reduce the number of counterparties willing to do business with us or result in the termination of outstanding regulatory authorizations for certain financing activities. Credit risk may be affected by industry concentration and geographic concentration. We have concentrations of suppliers and customers in the electric and natural gas industries including: •electric and natural gas utilities, •electric generators and transmission providers, •oil and natural gas producers and pipelines, •financial institutions including commodity clearing exchanges and related parties, and •energy marketing and trading companies. We have concentrations of credit risk related to our geographic location in the western United States and western Canada energy markets. These concentrations of counterparties and concentrations of geographic location may affect our overall exposure to credit risk because the counterparties may be similarly affected by changes in conditions. Utility Regulatory Risk Factors Regulators may not grant rates that provide timely or sufficient recovery of our costs or allow a reasonable rate of return for our shareholders. We have experienced higher expenses and capital costs for utility operations in the last several years. We have also made significant capital investments into utility plant assets. Our ability to recover these expenses and capital costs depends on the amount and timeliness of retail rate changes allowed by regulatory agencies. We expect to periodically file for rate increases with regulatory agencies to recover our expenses and capital costs and provide an opportunity to earn a reasonable rate of return for shareholders. If regulators grant substantially lower rate increases than our requests in the future or if recovery of deferred expenses is disallowed, it could have a negative effect on our operating revenues, net income and cash flows. In the future, we may no longer meet the criteria for continued application of regulatory accounting practices for all or a portion of our regulated operations. If we could no longer apply regulatory accounting, we could be: •required to write off our regulatory assets, and •precluded from the future deferral of costs or decoupled revenues not recovered through rates at the time such amounts are incurred, even if we are expected to recover these amounts from customers in the future. See further discussion at "Note 1 of the Notes to Consolidated Financial Statements – Regulatory Deferred Charges and Credits." Energy Commodity Risk Factors Energy commodity price changes affect our cash flows and results of operations. Energy commodity prices can be volatile. A combination of factors exposes our operations to commodity price risks. We rely on energy markets and other counterparties for energy supply, surplus and optimization transactions and commodity price hedging. These factors include: •our obligation to serve our retail customers at rates set through the regulatory process - we cannot change retail rates to reflect current energy prices unless and until we receive regulatory approval, •customer demand, which is beyond our control because of weather, customer choices, prevailing economic conditions and other factors, •some of our energy supply cost is fixed by the nature of the energy-producing assets or through contractual arrangements - however, a significant portion of our energy resource costs are not fixed, and •the potential non-performance by commodity counterparties, which could lead to replacement of the scheduled energy or natural gas at higher prices. 21 Staff_DR_063 Attachment A Page 28 of 180 Table of Contents AVISTA CORPORATION Because we must supply the amount of energy demanded by our customers and we must sell it at fixed rates and only a portion of our energy supply costs are fixed, we are subject to the risk of buying energy at higher prices in wholesale energy markets (and the risk of selling energy at lower prices if we are in a surplus position). Electricity and natural gas in wholesale markets are commodities with historically high price volatility. Changes in wholesale energy prices affect, among other things, the cash requirements to purchase electricity and natural gas for retail customers or wholesale obligations and the market value of derivative assets and liabilities. When we enter into fixed price energy commodity transactions for future delivery, we are subject to credit terms that may require us to provide collateral to wholesale counterparties related to the difference between current prices and the agreed upon fixed prices. These collateral requirements can place significant demands on our cash flows or borrowing arrangements. Price volatility can cause collateral requirements to change quickly and significantly. Cash flow deferrals related to energy commodities can be significant. We are permitted to collect from customers only amounts approved by regulatory commissions. However, our costs to provide energy service can be much higher or lower than the amounts currently billed to customers. We are permitted to defer most of this difference for review by the regulatory commissions who have discretion as to the extent and timing of future recovery or refund to customers. Power and natural gas costs higher than those recovered in retail rates reduce cash flows. Amounts that are not allowed for deferral or which are not approved to become part of customer rates affect our results of operations. We defer income statement recognition and recovery from customers of certain power and natural gas costs that are higher or lower than what are currently authorized in retail rates by regulators. These power and natural gas costs are recorded as deferred charges with the opportunity for future recovery through retail rates. These deferred costs are subject to review for prudence and potential disallowance by regulators. Despite the opportunity to recover deferred power and natural gas costs, our operating cash flows can be negatively affected until these costs are recovered from customers. Our energy resource risk management processes can cause volatility in our cash flows and results of operations. We engage in active hedging and resource optimization practices to reduce energy cost volatility and economic exposure related to commodity price fluctuations. We routinely enter into contracts to hedge a portion of our purchase and sale commitments for electricity and natural gas, as well as forecasted excess or deficit energy positions and inventories of natural gas. We use physical energy contracts and derivative instruments, such as forwards, futures, swaps and options traded in the over-the- counter markets or on exchanges. We cannot and do not attempt to fully hedge our energy resource assets or our forecasted net positions for various time horizons. To the extent we have positions that are not hedged, or if hedging positions do not fully match the corresponding purchase or sale, fluctuating commodity prices could have a material effect on our operating revenues, resource costs, derivative assets and liabilities, and operating cash flows. In addition, actual loads and resources typically vary from forecasts, sometimes to a significant degree, which require additional transactions or dispatch decisions that impact cash flows. The hedges we enter into are reviewed for prudence by the various regulators and any deferred costs (including those as a result of our hedging transactions) are subject to review for prudence and potential disallowance by regulators. Generation plants may become obsolete. We rely on a variety of generation and energy commodity market sources to fulfill our obligation to serve customers and meet the demands of our counterparty agreements. There is the potential that some of our generation sources, such as coal, may become obsolete. This could result in higher commodity costs to customers to replace the lost generation, as well as higher costs to retire the generation source before the end of its expected life. Operational Risk Factors We are subject to various operational and event risks. Our operations are subject to operational and event risks that include: •severe weather or natural disasters, including, but not limited to, avalanches, wind storms, wildfires, snow and ice storms, that can disrupt energy generation, transmission and distribution, as well as the availability and costs of materials, equipment, supplies and support services; •blackouts or disruptions of interconnected transmission systems (the regional power grid); •unplanned outages at generating plants, 22 Staff_DR_063 Attachment A Page 29 of 180 Table of Contents AVISTA CORPORATION •fuel cost and availability, including delivery constraints, •explosions, fires, accidents, or mechanical breakdowns that may occur while operating and maintaining our generation, transmission and distribution systems, •damage or injuries to third parties caused by our generation, transmission and distribution systems, •natural disasters that can disrupt energy generation, transmission and distribution and general business operations, and •terrorist attacks or other malicious acts that may disrupt or cause damage to our utility assets or the vendors we utilize. Disasters may affect the general economy, financial and capital markets, specific industries, or our ability to conduct business. As protection against operational and event risks, we maintain business continuity and disaster recovery plans, maintain insurance coverage against some, but not all, potential losses and we seek to negotiate indemnification arrangements with contractors for certain event risks. However, insurance or indemnification agreements may not be adequate to protect us against liability, extra expenses and operating disruptions from all of the operational and event risks described above. In addition, we are subject to the risk that insurers and/or other parties will dispute or be unable to perform on their obligations to us. Damage to facilities may be caused by severe weather, such as snow, ice, wind storms or avalanches. The cost to implement rapid or any repair to such facilities can be significant. Overhead electric lines are most susceptible to damage caused by severe weather. Adverse impacts may occur at our Alaska operations that could result from an extended outage of their hydroelectric generating resources or its inability to deliver energy, due to their lack of interconnectivity to any other electrical grids and the extensive cost of replacement power (diesel); AEL&P operates several hydroelectric power generation facilities and has diesel generating capacity from multiple facilities to provide backup service to firm customers when necessary; however, a single hydroelectric power generation facility, the Snettisham hydroelectric project, provides approximately two- thirds of AEL&P’s hydroelectric power generation. Any issues that negatively affect AEL&P's ability to generate or transmit power or any decrease in the demand for the power generated by AEL&P could negatively affect our results of operations, financial condition and cash flows. Compliance Risk Factors There have been numerous changes in legislation, related administrative rulemakings, and Executive Orders, including periodic audits of compliance with such rules, which may adversely affect our operational and financial performance. We expect to continue to be affected by legislation at the national, state and local level, as well as by administrative rules and requirements published by government agencies, including but not limited to the FERC, the EPA and state regulators. We are also subject to NERC and WECC reliability standards. The FERC, the NERC and the WECC perform periodic audits of the Company. Failure to comply with the FERC, the NERC, or the WECC requirements can result in financial penalties of up to $1 million per day per violation. Future legislation or administrative rules could have a material adverse effect on our operations, results of operations, financial condition and cash flows. Actions or limitations to address concerns over the long-term global and our utilities' service area climate changes may affect our operations and financial performance. Legislative developments and advocacy at the state, national and international levels concerning climate change and other environmental issues could have significant impacts on our operations. The electric utility industry is one of the largest and most immediate industries to be more heavily regulated in some proposals. For example, various legislative proposals have been made to limit or place further restrictions on byproducts of combustion, including sulfur dioxide, nitrogen oxide, carbon dioxide, and other greenhouse gases and mercury emissions. Such proposals, if adopted, could restrict the operation and raise the cost of our power generation resources. We expect continuing activity in the future and we are evaluating the extent to which potential changes to environmental laws and regulations may: •increase the operating costs of generating plants, •increase the lead time and capital costs for the construction of new generating plants, •require modification of our existing generating plants, 23 Staff_DR_063 Attachment A Page 30 of 180 Table of Contents AVISTA CORPORATION •require existing generating plant operations to be curtailed or shut down, •reduce the amount of energy available from our generating plants, •restrict the types of generating plants that can be built or contracted with, and •require construction of specific types of generation plants at higher cost. We have contingent liabilities, including certain matters related to potential environmental liabilities, and cannot predict the outcome of these matters. In the normal course of our business, we have matters that are the subject of ongoing litigation, mediation, investigation and/or negotiation. We cannot predict the ultimate outcome or potential impact of any particular issue, including the extent, if any, of insurance coverage or that amounts payable by us may be recoverable through the ratemaking process. We are subject to environmental regulation by federal, state and local authorities related to our past, present and future operations. See “Note 19 of the Notes to Consolidated Financial Statements” for further details of these matters. Technology Risk Factors Cyber attacks, terrorism or other malicious acts could disrupt our businesses and have a negative impact on our results of operations and cash flows. In the course of our operations, we rely on interconnected technology systems for operation of our generating plants, electric transmission and distribution systems, natural gas distribution systems, customer billing and customer service, accounting and other administrative processes and compliance with various regulations. There are various risks associated with technology systems such as hardware or software failure, communications failure, data distortion or destruction, unauthorized access to data, misuse of proprietary or confidential data, unauthorized control through electronic means, programming mistakes and other deliberate or inadvertent human errors. In particular, cyber attacks, terrorism or other malicious acts could damage, destroy or disrupt these systems. Additionally, the facilities and systems of clients, suppliers and third party service providers could be vulnerable to these same risks and, to the extent of interconnection to our technology, may impact us. Any failure, unexpected, or unauthorized unavailability of technology systems could result in a loss of operating revenues, an increase in operating expenses and costs to repair or replace damaged assets. Any of the above could also result in the loss or release of confidential customer information or other proprietary data that could adversely affect our reputation, competitiveness, and result in costly litigation and impact on our results of operations. As these potential cyber attacks become more common and sophisticated, we could be required to incur costs to strengthen our systems and respond to emerging concerns. Terrorist attacks could also be directed at physical electric and natural gas facilities, as well as technology systems. We may be adversely affected by our inability to successfully implement certain technology projects. We are currently investigating whether to replace all of our electric meter infrastructure in Washington State with advanced metering infrastructure (AMI). If we were to proceed with this AMI project, there is the potential that the costs associated with retiring our current meters could be disallowed by regulators. There is also the risk that regulators will not allow the full recovery of new AMI if we proceed with the project. In addition, there are inherent risks associated with replacing and changing these types of systems, such as incorrect or nonfunctioning metering and/or delayed or inaccurate customer bills or unplanned outages, which could have a material adverse effect on our results of operations, financial condition and cash flows. Strategic Risk Factors Changes in our strategic business plans, which may be affected by any or all of the foregoing, including the entry into new businesses and/or the exit from existing businesses and the extent of our business development efforts where potential future business is uncertain. Our strategic business plans could be affected by or result in any of the following: •disruptive innovations in the marketplace may outpace our ability to compete or manage our risk, •potential difficulties in integrating acquired operations and in realizing expected opportunities, diversions of management resources and losses of key employees, challenges with respect to operating new businesses and other unanticipated risks and liabilities, and 24 Staff_DR_063 Attachment A Page 31 of 180 Table of Contents AVISTA CORPORATION •potential reputational risk arising from repeated general rate case filings, degradation in the quality of service, or from failed strategic investments and opportunities, which could erode shareholder, customer and community satisfaction with our Company. Our acquisition of AERC may not achieve its intended results. On July 1, 2014, we acquired AERC, and its subsidiary, AEL&P, the sole provider of electric services in Juneau, Alaska. Achieving the anticipated earnings contribution from AERC is subject to numerous uncertainties, including market conditions and risks related to AERC's business. This transaction could result in increased costs, decreases in the expected revenues from AERC, the impairment of goodwill or other assets, and diversion of management time and resources, which could have a material adverse effect on our results of operations, financial condition and cash flows. External Mandates Risk Factors External mandate risk involves forces outside the Company, which may include significant changes in customer expectations, disruptive technologies that result in obsolescence of our business model and government action that could impact our Company. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Environmental Issues and Contingencies" and "Forward-Looking Statements" for discussion of or reference to external mandates which could have a material adverse effect on our results of operations, financial condition and cash flows. ITEM 1B. UNRESOLVED STAFF COMMENTS As of the filing date of this Annual Report on Form 10-K, we have no unresolved comments from the staff of the SEC. 25 Staff_DR_063 Attachment A Page 32 of 180 Table of Contents AVISTA CORPORATION ITEM 2. PROPERTIES AVISTA UTILITIES Substantially all of Avista Utilities' properties are subject to the lien of Avista Corp.'s mortgage indenture. Our utility electric properties, located in the states of Washington, Idaho, Montana and Oregon, include the following: Generation Properties No. of Units Nameplate Rating (MW) (1) Present Capability (MW) (2) Hydroelectric Generating Stations (River) Washington: Long Lake (Spokane)4 70.0 88.0 Little Falls (Spokane)4 32.0 35.6 Nine Mile (Spokane) (3)4 26.4 19.5 Upper Falls (Spokane)1 10.0 10.2 Monroe Street (Spokane)1 14.8 15.0 Idaho: Cabinet Gorge (Clark Fork) (4)4 265.0 273.0 Post Falls (Spokane)6 14.8 15.4 Montana: Noxon Rapids (Clark Fork)5 487.8 562.4 Total Hydroelectric 920.8 1,019.1 Thermal Generating Stations (cycle, fuel source) Washington: Kettle Falls GS (combined-cycle, wood waste) (5)1 50.7 53.5 Kettle Falls CT (combined-cycle, natural gas) (5)1 7.2 6.9 Northeast CT (simple-cycle, natural gas)2 61.8 64.8 Boulder Park GS (simple-cycle, natural gas)6 24.6 24.0 Idaho: Rathdrum CT (simple-cycle, natural gas)2 166.5 166.5 Montana: Colstrip Units 3 and 4 (simple-cycle, coal) (6)2 233.4 222.0 Oregon: Coyote Springs 2 (combined-cycle, natural gas)1 287.0 284.4 Total Thermal 831.2 822.1 Total Generation Properties 1,752.0 1,841.2 (1)Nameplate Rating, also referred to as “installed capacity,” is the manufacturer’s assigned power capability under specified conditions. (2)Present capability is the maximum capacity of the plant under standard test conditions without exceeding specified limits of temperature, stress and environmental conditions. Information is provided as of December 31, 2015. (3)There are four units at the Nine Mile plant; however, Units 1 and 2 are not operating due to a mechanical failure. A project is underway to replace these units and restore capability. The present capability disclosed above represents the capability of the two operating units, which have a nameplate rating of 18 MW combined. (4)For Cabinet Gorge, we have water rights permitting generation up to 265 MW. However, if natural stream flows will allow for generation above our water rights, we are able to generate above our water rights. If natural stream flows only allow for generation at or below 265 MW, we are limited to generation of 265 MW. The present capability disclosed above represents the capability based on maximum stream flow conditions when we are allowed to generate above our water rights. (5)These generating stations can operate as separate single-cycle plants or combined-cycle with the natural gas plant providing exhaust heat to the wood boiler to increase efficiency. 26 Staff_DR_063 Attachment A Page 33 of 180 Table of Contents AVISTA CORPORATION (6)Jointly owned; data refers to our 15 percent interest. Electric Distribution and Transmission Plant Avista Utilities owns and operates approximately 19,000 miles of primary and secondary electric distribution lines providing service to retail customers. We have an electric transmission system of 685 miles of 230 kV line and 1,565 miles of 115 kV line. We also own an 11 percent interest in approximately 500 miles of a 500 kV line between Colstrip, Montana and Townsend, Montana. Our transmission and distribution systems also include numerous substations with transformers, switches, monitoring and metering devices, and other equipment. The 230 kV lines are the backbone of our transmission grid and are used to transmit power from generation resources, including Noxon Rapids, Cabinet Gorge and the Mid-Columbia hydroelectric projects, to the major load centers in our service area, as well as to transfer power between points of interconnection with adjoining electric transmission systems. These lines interconnect at various locations with the BPA, Grant County PUD, PacifiCorp, NorthWestern Energy and Idaho Power Company and serve as points of delivery for power from generating facilities outside of our service area, including Colstrip, Coyote Springs 2 and the Lancaster Plant. These lines also provide a means for us to optimize resources by entering into short-term purchases and sales of power with entities within and outside of the Pacific Northwest. The 115 kV lines provide for transmission of energy and the integration of smaller generation facilities with our service-area load centers, including the Spokane River hydroelectric projects, the Kettle Falls projects, Rathdrum CT, Boulder Park and the Northeast CT. These lines interconnect with the BPA, Chelan County PUD, the Grand Coulee Project Hydroelectric Authority, Grant County PUD, NorthWestern Energy, PacifiCorp and Pend Oreille County PUD. Both the 115 kV and 230 kV interconnections with the BPA are used to transfer energy to facilitate service to each other’s customers that are connected through the other’s transmission system. We hold a long-term transmission agreement with the BPA that allows us to serve our native load customers that are connected through the BPA’s transmission system. Natural Gas Plant Avista Utilities has natural gas distribution mains of approximately 3,400 miles in Washington, 2,000 miles in Idaho and 2,300 miles in Oregon. We have natural gas transmission mains of approximately 75 miles in Washington and 50 miles in Oregon. Our natural gas system includes numerous regulator stations, service distribution lines, monitoring and metering devices, and other equipment. We own a one-third interest in Jackson Prairie, an underground natural gas storage field located near Chehalis, Washington. See "Part 1 – Item 1. Business – Avista Utilities – Natural Gas Operations" for further discussion of Jackson Prairie. 27 Staff_DR_063 Attachment A Page 34 of 180 Table of Contents AVISTA CORPORATION ALASKA ELECTRIC LIGHT AND POWER COMPANY Substantially all of AEL&P's utility properties are subject to the lien of the AEL&P mortgage indenture. AEL&P's utility electric properties, located in Alaska include the following: Generation Properties and Transmission and Distribution Lines No. of Units Nameplate Rating (MW) (1) Present Capability (MW) (2) Hydroelectric Generating Stations Snettisham (3)3 78.2 78.2 Lake Dorothy 1 14.3 14.3 Salmon Creek 1 8.4 5.0 Annex Creek 2 4.1 3.6 Gold Creek 3 1.6 1.6 Total Hydroelectric 106.6 102.7 Diesel Generating Stations Lemon Creek 11 61.4 57.5 Auke Bay 3 36.2 28.3 Gold Creek 5 8.2 8.1 Total Diesel 105.8 93.9 Total Generation Properties 212.4 196.6 (1)Nameplate Rating, also referred to as “installed capacity,” is the manufacturer’s assigned power capability under specified conditions. (2)Present capability is the maximum capacity of the plant under standard test conditions without exceeding specified limits of temperature, stress and environmental conditions. Information is provided as of December 31, 2015. (3)AEL&P does not own this generating facility but has a PPA under which it has the right to purchase, and the obligation to pay for (whether or not energy is received), all of the capacity and energy of this facility. See further information at "Part 1. Item 1. Business – Alaska Electric Light and Power Company." In addition to the generation properties above, AEL&P owns approximately 61 miles of transmission lines, which is primarily comprised of 69 kV line, and approximately 184 miles of distribution lines. ITEM 3. LEGAL PROCEEDINGS See “Note 19 of Notes to Consolidated Financial Statements” for information with respect to legal proceedings. ITEM 4. MINE SAFETY DISCLOSURES Not applicable. PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES Avista Corp. Market Information and Dividend Policy Avista Corp.'s common stock is listed on the New York Stock Exchange under the ticker symbol “AVA.” As of January 31, 2016, there were 8,753 registered shareholders of our common stock. Avista Corp.'s Board of Directors considers the level of dividends on our common stock on a regular basis, taking into account numerous factors including, without limitation: •our results of operations, cash flows and financial condition, •the success of our business strategies, and •general economic and competitive conditions. Avista Corp.'s net income available for dividends is generally derived from our regulated utility operations (Avista Utilities and AEL&P). 28 Staff_DR_063 Attachment A Page 35 of 180 Table of Contents AVISTA CORPORATION The payment of dividends on common stock could be limited by: •certain covenants applicable to the Company's outstanding long-term debt and committed line of credit agreements (see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Executive Level Summary and Capital Resources" for compliance with these covenants), •the hydroelectric licensing requirements of section 10(d) of the FPA (see “Note 1 of Notes to Consolidated Financial Statements”), •certain requirements under the OPUC approval of the AERC acquisition. The OPUC does not permit one-time or special dividends from AERC to Avista Corp. and does not permit Avista Utilities' total equity to total capitalization to be less than 40 percent, without approval from the OPUC. However, the OPUC approval does allow for regular distributions of AERC earnings to Avista Corp. as long as AERC remains sufficiently capitalized and insured, and •certain covenants applicable to preferred stock (when outstanding) contained in the Company’s Restated Articles of Incorporation, as amended (currently there are no preferred shares outstanding). On February 5, 2016, Avista Corp.’s Board of Directors declared a quarterly dividend of $0.3425 per share on the Company’s common stock. This was an increase of $0.0125 per share, or 3.8 percent from the previous quarterly dividend of $0.33 per share. For additional information, see “Notes 1, 17 and 18 of Notes to Consolidated Financial Statements.” The following table presents quarterly high and low stock prices as reported on the consolidated reporting system, as well as dividend information: Three Months Ended March 31 June 30 September 30 December 31 2015 Dividends paid per common share $0.33 $0.33 $0.33 $0.33 Trading price range per common share: High $38.30 $34.25 $33.99 $36.06 Low $32.22 $30.41 $29.93 $32.86 2014 Dividends paid per common share $0.3175 $0.3175 $0.3175 $0.3175 Trading price range per common share: High $30.83 $33.58 $33.60 $37.37 Low $27.71 $30.02 $30.35 $30.55 For information with respect to securities authorized for issuance under equity compensation plans, see “Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.” 29 Staff_DR_063 Attachment A Page 36 of 180 Table of Contents AVISTA CORPORATION ITEM 6. SELECTED FINANCIAL DATA (in thousands, except per share data and ratios)Years Ended December 31, 2015 2014 2013 2012 2011 Operating Revenues: Avista Utilities $1,411,863 $1,413,499 $1,403,995 $1,354,185 $1,443,322 AEL&P 44,778 21,644 — — — Other 28,685 39,219 39,549 38,953 40,410 Intersegment eliminations (550) (1,800) (1,800) (1,800) (1,800) Total $1,484,776 $1,472,562 $1,441,744 $1,391,338 $1,481,932 Income (Loss) from Operations (pre-tax): Avista Utilities $241,228 $239,976 $232,572 $188,778 $202,373 AEL&P 14,072 6,221 — — — Other (2,086) 6,391 (1,483) (1,680) 4,714 Total $253,214 $252,588 $231,089 $187,098 $207,087 Net income from continuing operations $118,170 $119,866 $104,333 $76,803 $90,658 Net income from discontinued operations 5,147 72,411 7,961 1,997 12,881 Net income $123,317 $192,277 $112,294 $78,800 $103,539 Net income attributable to noncontrolling interests $(90) $(236) $(1,217) $(590) $(3,315) Net Income (Loss) attributable to Avista Corporation shareholders: Avista Utilities $113,360 $113,263 $108,598 $81,704 $90,902 AEL&P 6,641 3,152 — — — Ecova - Discontinued operations 5,147 72,390 7,129 1,825 9,671 Other (1,921) 3,236 (4,650) (5,319) (349) Net income attributable to Avista Corp. shareholders $123,227 $192,041 $111,077 $78,210 $100,224 Average common shares outstanding, basic 62,301 61,632 59,960 59,028 57,872 Average common shares outstanding, diluted 62,708 61,887 59,997 59,201 58,092 Common shares outstanding at year-end 62,313 62,243 60,077 59,813 58,423 Earnings per common share attributable to Avista Corp. shareholders, basic: Earnings per common share from continuing operations $1.90 $1.94 $1.74 $1.30 $1.56 Earnings per common share from discontinued operations 0.08 1.18 0.11 0.02 0.17 Total earnings per common share attributable to Avista Corp. shareholders, basic $1.98 $3.12 $1.85 $1.32 $1.73 Earnings per common share attributable to Avista Corp. shareholders, diluted: Earnings per common share from continuing operations $1.89 $1.93 $1.74 $1.30 $1.56 Earnings per common share from discontinued operations 0.08 1.17 0.11 0.02 0.16 Total earnings per common share attributable to Avista Corp. shareholders, diluted $1.97 $3.10 $1.85 $1.32 $1.72 30 Staff_DR_063 Attachment A Page 37 of 180 Table of Contents AVISTA CORPORATION (in thousands, except per share data and ratios)Years Ended December 31, 2015 2014 2013 2012 2011 Dividends declared per common share $1.32 $1.27 $1.22 $1.16 $1.10 Book value per common share $24.53 $23.84 $21.61 $21.06 $20.30 Total Assets at Year-End: Avista Utilities $4,601,708 $4,357,760 $3,930,251 $3,883,602 $3,797,160 AEL&P 265,735 263,070 — — — Other 39,206 80,141 81,282 95,638 112,145 Total (1) (2)$4,906,649 $4,700,971 $4,011,533 $3,979,240 $3,909,305 Long-Term Debt and Capital Leases (including current portion) (2)$1,573,278 $1,487,126 $1,262,036 $1,217,520 $1,165,014 Nonrecourse Long-Term Debt of Spokane Energy (including current portion)$— $1,431 $17,838 $32,803 $46,471 Long-Term Debt to Affiliated Trusts $51,547 $51,547 $51,547 $51,547 $51,547 Total Avista Corp. Shareholders’ Equity $1,528,626 $1,483,671 $1,298,266 $1,259,477 $1,185,701 Ratio of Earnings to Fixed Charges (3)3.13 3.39 3.02 2.48 2.81 (1)The total assets at year-end for the years 2013 to 2011 exclude the total assets associated with Ecova of $339.6 million, $322.7 million and $292.9 million, respectively. (2)The total assets and total long-term debt and capital leases for 2014 through 2011 were adjusted due to the adoption of ASU No. 2015-03, "Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs." See "Note 2 of the Notes to Consolidated Financial Statements" for further discussion of the adoption of this ASU. (3)See Exhibit 12 for computations. ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Business Segments As of December 31, 2015, we have two reportable business segments, Avista Utilities and AEL&P. We also have other businesses which do not represent a reportable business segment and are conducted by various direct and indirect subsidiaries of Avista Corp. See "Part I, Item 1. Business – Company Overview" for further discussion of our business segments. The following table presents net income (loss) attributable to Avista Corp. shareholders for each of our business segments (and the other businesses) for the year ended December 31 (dollars in thousands): 2015 2014 2013 Avista Utilities $113,360 $113,263 $108,598 AEL&P 6,641 3,152 — Ecova - Discontinued operations (1)5,147 72,390 7,129 Other (1,921) 3,236 (4,650) Net income attributable to Avista Corporation shareholders $123,227 $192,041 $111,077 (1)The results for the year ended December 31, 2014 include the net gain on sale of Ecova of $69.7 million. Executive Level Summary Overall Results Net income attributable to Avista Corp. shareholders was $123.2 million for 2015, a decrease from $192.0 million for 2014. The decrease was primarily due to the disposition of Ecova during 2014, which resulted in the recognition of a $74.8 million net gain, with $69.7 million being recognized in 2014 and the remainder being recognized in 2015. Avista Utilities' earnings increased slightly primarily due to the implementation of a general rate increase in Washington, lower net power supply costs, a decrease in the provision for earnings sharing in Idaho and increased cooling loads during the summer. This was mostly offset by weather that was significantly warmer than normal and warmer than the prior year in the first quarter, which reduced heating loads, which was partially offset by the new decoupling mechanism in Washington (implemented January 1, 2015). Also, we 31 Staff_DR_063 Attachment A Page 38 of 180 Table of Contents AVISTA CORPORATION experienced expected increases in other operating expenses, depreciation and amortization, taxes other than income taxes, and interest expense. Results for 2015 also include earnings at AEL&P for the full period, whereas 2014 results only include AEL&P for the third and fourth quarters. Results for 2014 include a $9.8 million net gain at Avista Energy related to the settlement of the California power markets litigation. The net gain from the litigation settlement was partially offset by a pre-tax contribution of $6.4 million of the proceeds to the Avista Foundation, a charitable organization funded by Avista Corp. Both of these transactions are reflected in the results of the other businesses. Avista Utilities Avista Utilities is our most significant business segment. Our utility financial performance is dependent upon, among other things: •weather conditions (temperatures, precipitation levels and wind patterns) which affect energy demand and electric generation, including the effect of precipitation and temperature on hydroelectric resources, the effect of wind patterns on wind-generated power, weather-sensitive customer demand, and similar impacts on supply and demand in the wholesale energy markets, •regulatory decisions, allowing our utility to recover costs, including purchased power and fuel costs, on a timely basis, and to earn a reasonable return on investment, •the price of natural gas in the wholesale market, including the effect on the price of fuel for generation, and •the price of electricity in the wholesale market, including the effects of weather conditions, natural gas prices and other factors affecting supply and demand. Forecasted Customer and Load Growth Based on our forecast for 2016 through 2019 for Avista Utilities' service area, we expect annual electric customer growth to average 1.0 percent, within a forecast range of 0.6 percent to 1.4 percent. We expect annual natural gas customer growth to average 1.1 percent, within a forecast range of 0.6 percent to 1.6 percent. We anticipate retail electric load growth to average 0.7 percent, within a forecast range of 0.4 percent and 1.0 percent. We expect natural gas load growth to average 1.1 percent, within a forecast range of 0.6 percent and 1.6 percent. The forecast ranges reflect (1) the inherent uncertainty associated with the economic assumptions on which forecasts are based and (2) the historic variability of natural gas customer and load growth. In AEL&P's service area, we expect annual residential customer growth to be in a narrow range around 0.4 percent for 2016 through 2019. We expect no significant growth in commercial and government customers over the same period. We anticipate that average annual total load growth will be in a narrow range around 0.6 percent, with residential load growth averaging 0.6 percent; commercial 0.8 percent; and government 0 percent (no load growth). For further discussion regarding utility customer growth, load growth, and the general economic conditions in our service territory, see "Economic Conditions and Utility Load Growth." See also "Competition" for a discussion of competitive factors that could affect our results of operations in the future. Capital Expenditures We are making significant capital investments in generation, transmission and distribution systems to preserve and enhance service reliability for our customers and replace aging infrastructure. The following table summarizes our actual and expected capital expenditures as of and for the year ended December 31, 2015 (in thousands): Avista Utilities AEL&P 2015 Actual capital expenditures Capital expenditures (per the Consolidated Statement of Cash Flows)381,174 12,251 Expected total annual capital expenditures (by year) 2016 375,000 17,000 2017 405,000 13,000 2018 405,000 18,000 32 Staff_DR_063 Attachment A Page 39 of 180 Table of Contents AVISTA CORPORATION Avista Utilities' 2015 calendar year capital costs, including capital costs of approximately $35.2 million that was unpaid for and accrued in accounts payable as of December 31, 2015, were $415.9 million. These estimates of capital expenditures are subject to continuing review and adjustment. Alaska Energy and Resources Company Acquisition On July 1, 2014, we acquired AERC, based in Juneau, Alaska. The completion of this transaction makes the financial results for 2015 and 2014 incomparable since the first half of 2014 does not contain any financial results from AERC. This transaction resulted in the recording of $52.4 million in goodwill. For additional information regarding the AERC transaction, including pro forma financial comparisons, see “Note 4 of the Notes to Consolidated Financial Statements.” Ecova Disposition On June 30, 2014, Avista Capital completed the sale of its interest in Ecova to Cofely USA Inc., an indirect subsidiary of GDF SUEZ, a French multinational utility company, for a sales price of $335.0 million in cash, less the payment of debt and other customary closing adjustments. The sale of Ecova provided total cash proceeds to Avista Corp., net of debt, payment to option and minority holders, income taxes and transaction expenses, of $143.7 million and resulted in a net gain of $74.8 million. Almost all of the net gain was recognized in 2014 with some minor true-ups during 2015. The completion of this transaction makes the financial results for 2015 and 2014 incomparable since the first half of 2014 contains the financial results of Ecova (in discontinued operations) and 2015 does not have any material results from Ecova. For additional information regarding the Ecova disposition, see “Note 5 of the Notes to Consolidated Financial Statements.” Stock Repurchase Programs During 2014, Avista Corp. repurchased 2,529,615 shares of our outstanding common stock at a total cost of $79.9 million and an average cost of $31.57 per share through our 2014 stock repurchase program. We did not make any repurchases under this program subsequent to October 2014 and the program expired on December 31, 2014. In the first quarter of 2015, Avista Corp. repurchased 89,400 shares of our outstanding common stock at a total cost of $2.9 million and an average cost of $32.66 per share under a second stock repurchase program that expired on March 31, 2015. All repurchased shares reverted to the status of authorized but unissued shares. Wind Storm On November 17, 2015, a historic wind storm occurred in our service territory. The storm had wind speeds exceeding 70 miles per hour which knocked down numerous trees and power poles and caused severe damage to our electrical system. Most of the damage occurred in Spokane County. The storm resulted in significant customer power outages and at the height of the storm approximately 180,000 customers (about 48 percent of our total retail electric customers) were without power, causing the most significant damage and the highest number of customer outages Avista Utilities has ever experienced. It took Avista Utilities crews from throughout the region, along with contract and mutual aid crews, approximately 10 days to fully restore power to all affected customers. Most of the storm-related costs incurred were capital costs (labor and materials) to repair the electrical system, but there were also operating and maintenance costs. The capital repair costs for power restoration were $22.9 million and $2.9 million for incremental utility operating and maintenance costs. In addition, there was approximately $0.4 million of incremental nonutility operating and maintenance costs. The damage and restoration costs were primarily incurred in Washington state and we plan to include the incremental operating and maintenance costs in the calculations for earnings sharing (see "Regulatory Matters – Decoupling and Earnings Sharing Mechanisms" for further discussion of the earnings sharing mechanisms). Liquidity and Capital Resources Avista Corp. has a $400.0 million committed line of credit with various financial institutions that expires in April 2019. We have an option to request an extension for an additional one or two years beyond April 2019, provided, 1) that no event of default has occurred and is continuing prior to the requested extension and 2) the remaining term of agreement, including the requested extension period, does not exceed five years. As of December 31, 2015, there were $105.0 million of cash borrowings and $44.6 million in letters of credit outstanding, leaving $250.4 million of available liquidity under this line of credit. The Avista Corp. facility contains customary covenants and default provisions, including a covenant which does not permit our ratio of “consolidated total debt” to “consolidated total capitalization” to be greater than 65 percent at any time. As of December 31, 2015, we were in compliance with this covenant with a ratio of 53.1 percent. AEL&P has a $25.0 million committed line of credit which expires in November 2019. As of December 31, 2015, there were no borrowings or letters of credit outstanding under this committed line of credit. 33 Staff_DR_063 Attachment A Page 40 of 180 Table of Contents AVISTA CORPORATION The AEL&P committed line of credit agreement contains customary covenants and default provisions including a covenant which does not permit the ratio of “consolidated total debt at AEL&P” to “consolidated total capitalization at AEL&P,” (including the impact of the Snettisham obligation) to be greater than 67.5 percent at any time. As of December 31, 2015, AEL&P was in compliance with this covenant with a ratio of 57.2 percent. In December 2015, we issued $100.0 million of first mortgage bonds to five institutional investors in a private placement transaction. The first mortgage bonds bear an interest rate of 4.37 percent and mature in 2045. In connection with this pricing, we cash-settled five interest rate swap contracts (notional aggregate amount of $75.0 million) and paid a total of $9.3 million. Upon settlement of interest rate swaps, the regulatory asset or liability (included as part of long-term debt) is amortized as a component of interest expense over the term of the associated debt. In 2015, we issued $1.6 million (net of issuance costs) of common stock under the employee plans. For 2016, we expect to issue approximately $155.0 million of long-term debt and $55.0 million of common stock in order to maintain an appropriate capital structure and to fund planned capital expenditures. After considering the expected issuances of long-term debt and common stock during 2016, we expect net cash flows from operating activities, together with cash available under our committed line of credit agreements, to provide adequate resources to fund capital expenditures, dividends, and other contractual commitments. Regulatory Matters General Rate Cases We regularly review the need for electric and natural gas rate changes in each state in which we provide service. We will continue to file for rate adjustments to: •seek recovery of operating costs and capital investments, and •seek the opportunity to earn reasonable returns as allowed by regulators. With regards to the timing and plans for future filings, the assessment of our need for rate relief and the development of rate case plans takes into consideration short-term and long-term needs, as well as specific factors that can affect the timing of rate filings. Such factors include, but are not limited to, in-service dates of major capital investments and the timing of changes in major revenue and expense items. Washington General Rate Cases 2012 General Rate Cases In December 2012, the UTC approved a settlement agreement in Avista Utilities' electric and natural gas general rate cases filed in April 2012. The settlement, effective January 1, 2013 provided that base rates for our Washington electric customers increase by an overall 3.0 percent (designed to increase annual revenues by $13.6 million), and base rates for our Washington natural gas customers increased by an overall 3.6 percent (designed to increase annual revenues by $5.3 million). The approved settlement also provided that, effective January 1, 2014, base rates increase for our Washington electric customers by an overall 3.0 percent (designed to increase annual revenues by $14.0 million), and increase for our Washington natural gas customers by an overall 0.9 percent (designed to increase annual revenues by $1.4 million). The settlement agreement provided for an authorized return on equity (ROE) of 9.8 percent and an equity ratio of 47 percent, resulting in an overall rate of return on rate base (ROR) of 7.64 percent. 2014 General Rate Cases In November 2014, the UTC approved an all-party settlement agreement related to Avista Utilities' electric and natural gas general rate cases filed in February 2014 and new rates became effective on January 1, 2015. The settlement was designed to increase annual electric base revenues by $12.3 million, or 2.5 percent, inclusive of a $5.3 million power supply update as required in the settlement agreement (explained below). The settlement was designed to increase annual natural gas base revenues by $8.5 million, or 5.6 percent. The settlement agreement also included the implementation of decoupling mechanisms for electric and natural gas and a related after-the-fact earnings test. See "Decoupling and Earnings Sharing Mechanisms" below for further discussion of these mechanisms. Specific capital structure ratios and the cost of capital components were not agreed to in the settlement agreement. The revenue increases in the settlement were not tied to the 7.32 percent ROR used in conjunction with the after-the fact earnings test discussed under "Decoupling and Earnings Sharing Mechanisms" below. The electric and natural gas revenue increases were negotiated numbers, with each party using its own set of assumptions underlying its agreement to the revenue increases. The parties agreed that the 7.32 percent ROR will be used to calculate the AFUDC and other purposes. 34 Staff_DR_063 Attachment A Page 41 of 180 Table of Contents AVISTA CORPORATION 2015 General Rate Cases In January 2016, we received an order that concluded our electric and natural gas general rate cases that were originally filed with the UTC in February 2015. New electric and natural gas rates were effective on January 11, 2016. The UTC approved rates designed to provide a 1.6 percent, or $8.1 million decrease in electric base revenue, and a 7.4 percent, or $10.8 million increase in natural gas base revenue. The UTC also approved an ROR on rate base of 7.29 percent, with a common equity ratio of 48.5 percent and a 9.5 percent ROE. Throughout the rate case process, certain circumstances and costs changed, causing us to revise our overall proposed rate requests downward, especially for our electric operations. Our need for electric rate relief was reduced primarily due to the following: •a decrease in power supply costs of approximately $24.0 million caused by the continuing decline in the price of natural gas used to run our natural gas-fired generation and lower contract costs associated with a new PPA from Chelan PUD, •updated information related to federal tax adjustments and state allocations, •the delay in the expected completion date of the Nine Mile hydroelectric generation project upgrade from late 2015 to late 2016, and •a delay of the start date to begin amortization of existing electric meters from 2016 to a future year, associated with our proposed AMI project. The natural gas revenue increase approved by the UTC is related to our ownership and operating costs to run the natural gas business. Changes in the commodity costs of natural gas for natural gas customers are reflected in our annual PGA, which is generally effective November 1st each year. On November 1, 2015 natural gas customers’ bills were reduced approximately 15 percent related to the decline in the market price of natural gas. In responsive testimony filed by the UTC Staff in July 2015 in our electric and natural gas general rate cases, they recommended a disallowance of $12.7 million (Washington's share) of the costs associated with the replacement of our customer information and work management systems (Project Compass) primarily related to the delay in the completion of the project. In the January 6, 2016 UTC order, they approved the full recovery of Washington's portion of Project Compass costs. UTC issues Order denying Industrial Customers of Northwest Utilities / Public Counsel Joint Motion for Clarification, UTC Staff Motion to Reconsider and UTC Staff Motion to Reopen Record On February 19, 2016, the UTC issued an order denying the Motions summarized below and affirmed their original January 2016 order of an $8.1 million decrease in electric base revenue, thus finalizing our 2015 electric and natural gas general rate cases. On January 19, 2016, the Industrial Customers of Northwest Utilities (ICNU) and the Public Counsel Unit of the Washington State Office of the Attorney General (PC) filed a Joint Motion for Clarification with the UTC. In its Motion for Clarification, ICNU and PC requested that the UTC clarify the calculation of the electric attrition adjustment and the end-result revenue decrease of $8.1 million. ICNU and PC provided their own calculations in their Motion, and suggested that the revenue decrease should have been $19.8 million based on their reading of the UTC’s Order. On January 19, 2016, the UTC Staff, which is a separate party in the general rate case proceedings from the UTC Advisory Staff that supports the Commissioners, filed a Motion to Reconsider with the UTC. In its Motion to Reconsider, the Staff provided calculations and explanations that suggested that the electric revenue decrease should have been a revenue decrease of $27.4 million instead of $8.1 million, based on its reading of the UTC's Order. Further, on February 4, 2016, the UTC Staff filed a Motion to Reopen Record for the Limited Purpose of Receiving into Evidence Instruction on Use and Application of Staff’s Attrition Model, and sought to supplement the record “to incorporate all aspects of the Company’ Power Cost Update.” Within this Motion, UTC Staff updated its suggested electric revenue decrease to $19.6 million. None of the parties in their Motions raised issues with the UTC’s decision on the natural gas revenue increase of $10.8 million. 35 Staff_DR_063 Attachment A Page 42 of 180 Table of Contents AVISTA CORPORATION Petition for an Accounting Order to Defer Existing Washington Electric Meters In January 2016, we filed a Petition with the UTC for an Accounting Order to defer and include in a regulatory asset the undepreciated value of our existing Washington electric meters for later recovery. This requested accounting treatment is related to our plans to replace approximately 253,000 of our existing electric meters with new two-way digital meters through our Advanced Metering Infrastructure (AMI) project in Washington state. The petition requests that the UTC allow the deferral, with prudence of the overall AMI project and ultimate recovery, to be addressed in a future regulatory proceeding. The undepreciated value estimated for this deferred accounting treatment is approximately $18.6 million. We have requested recovery of this regulatory asset, with a full rate of return, over fifteen years starting in January 2017, within our February 19, 2016 general rate case filing. 2016 General Rate Cases On February 19, 2016, we filed electric and natural gas general rates cases with the UTC. Our proposal includes an 18-month rate plan, with new rates taking effect on January 1, 2017 and January 1, 2018. Under this plan, we would not file a future rate case for new rates to be effective prior to July 1, 2018. The 2017 increase, if approved, would increase overall base electric rates 7.8 percent (designed to increase annual electric revenues by $38.6 million) and overall base natural gas rates 5.0 percent (designed to increase annual natural gas revenues by $4.4 million). In addition, we have requested a second step increase effective January 1, 2018, which would increase overall base electric rates by 3.9 percent (designed to increase annual electric revenues by $10.3 million) and overall base natural gas rates by 1.8 percent (designed to increase annual natural gas revenues by $0.9 million). We have proposed to offset the electric increase, for the period January through June 2018, with available ERM dollars. As a result, customers would not see an electric general rate case bill increase in 2018 prior to July 1, 2018. Our requests are based on a proposed ROR on rate base of 7.64 percent with a common equity ratio of 48.5 percent and a 9.9 percent ROE. The UTC has up to 11 months to review the filings and issue a decision. Idaho General Rate Cases 2012 General Rate Cases In March 2013, the IPUC approved a settlement agreement in Avista Utilities' electric and natural gas general rate cases filed in October 2012. As agreed to in the settlement, new rates were implemented in two phases: April 1, 2013 and October 1, 2013. Effective April 1, 2013, base rates increased for our Idaho natural gas customers by an overall 4.9 percent (designed to increase annual revenues by $3.1 million). There was no change in base electric rates on April 1, 2013. The settlement also provided that, effective October 1, 2013, base rates increased for our Idaho natural gas customers by an overall 2.0 percent (designed to increase annual revenues by $1.3 million). Further, the settlement provided that, effective October 1, 2013, base rates increased for our Idaho electric customers by an overall 3.1 percent (designed to increase annual revenues by $7.8 million). The settlement agreement provided for an authorized ROE of 9.8 percent and an equity ratio of 50.0 percent. 2014 Rate Plan Extension Avista Utilities did not file new general rate cases in Idaho in 2014; instead, we developed an extension to the 2013 and 2014 rate plan and reached a settlement agreement with all interested parties. In September 2014, the IPUC approved the settlement, which reflected agreement among all interested parties, for a one-year extension to our current rate plan, which was set to expire on December 31, 2014. Under the approved extension, base retail rates remained unchanged through December 31, 2015. The settlement provided an estimated $3.7 million increase in pre-tax income by reducing planned expenses in 2015 for our Idaho operations. 36 Staff_DR_063 Attachment A Page 43 of 180 Table of Contents AVISTA CORPORATION 2015 General Rate Cases In December 2015, the IPUC approved a settlement agreement between Avista Utilities and all interested parties related to our electric and natural gas general rate cases, which were originally filed with the IPUC on June 1, 2015. New rates were effective on January 1, 2016. The settlement agreement is designed to increase annual electric base revenues by $1.7 million or 0.7 percent and annual natural gas base revenues by $2.5 million or 3.5 percent. The settlement is based on a ROR of 7.42 percent with a common equity ratio of 50 percent and a 9.5 percent ROE. The settlement agreement also reflects the following: •the discontinuation of the after-the-fact earnings test (provision for earnings sharing) that was originally agreed to as part of the settlement of our 2012 electric and natural gas general rate cases, and •the implementation of electric and natural gas Fixed Cost Adjustment mechanisms, as discussed below. 2016 General Rate Cases We expect to file electric and natural gas general rate cases in Idaho during the first half of 2016. Oregon General Rate Cases 2013 General Rate Case In January 2014, the OPUC approved a settlement agreement in Avista Utilities' natural gas general rate case (originally filed in August 2013). As agreed to in the settlement, new rates were implemented in two phases: February 1, 2014 and November 1, 2014. Effective February 1, 2014, rates increased for Oregon natural gas customers on a billed basis by an overall 4.4 percent (designed to increase annual revenues by $3.8 million). Effective November 1, 2014, rates for Oregon natural gas customers were to increase on a billed basis by an overall 1.6 percent (designed to increase annual revenues by $1.4 million). The billed rate increase on November 1, 2014 was dependent upon the completion of Project Compass and the actual costs incurred through September 30, 2014, and the actual costs incurred through June 30, 2014 related to the Company's Aldyl A distribution pipeline replacement program. Project Compass was completed in February 2015. The November 1, 2014 rate increase was reduced from $1.4 million to $0.3 million due to the delay of Project Compass. The approved settlement agreement provides for an overall authorized ROR of 7.47 percent, with a common equity ratio of 48 percent and a 9.65 percent ROE. 2014 General Rate Case In January 2015, Avista Utilities filed an all-party settlement agreement with the OPUC related to our natural gas general rate case, which was originally filed in September 2014. On February 23, 2015, the OPUC issued an order rejecting the all-party settlement agreement. The OPUC expressed concerns related to, among other things, various rate design issues. In March 2015, Avista Utilities filed an amended all-party settlement agreement with the OPUC which addressed the OPUC's concerns regarding the initial settlement agreement. The amended settlement agreement was designed to increase base natural gas revenues by $5.3 million. Included in this base rate increase is $0.3 million in base revenues that we are already receiving from customers through a separate rate adjustment. Therefore, the net increase in base revenues was $5.0 million, or 4.9 percent on a billed basis. The parties requested that new retail rates become effective on April 16, 2015. On April 9, 2015, the OPUC issued an Order approving the amended settlement agreement as filed. This settlement agreement provided for an overall authorized ROR of 7.516 percent with a common equity ratio of 51 percent and a 9.5 percent ROE. 2015 General Rate Case On May 1, 2015, we filed a natural gas general rate case with the OPUC. We have requested an overall increase in base natural gas rates of 8 percent (designed to increase annual natural gas revenues by $8.6 million). Our request is based on a proposed ROR on rate base of 7.72 percent with a common equity ratio of 50 percent and a 9.9 percent ROE. Avista Corp. and all parties to our natural gas general rate case reached agreement on certain issues, and a partial settlement agreement was filed with the OPUC in November 2015. The partial settlement agreement reduced our requested natural gas revenue increase from $8.6 million to $6.7 million or 6.3 percent. The partial settlement, if approved by the OPUC, would resolve a number of issues including the calculation of state income taxes for rate-making purposes, wages and salaries, the revenue forecast for the rate period, and working capital. The agreement does not resolve other issues including the appropriate ROE and capital structure, the appropriate level of additions to rate base, and medical and pension expenses. In January 2016, 37 Staff_DR_063 Attachment A Page 44 of 180 Table of Contents AVISTA CORPORATION we entered into an additional all-party partial settlement to further reduce our revenue increase request to $6.1 million, related to updated information related to deferred taxes and its effect on rate base. The agreement includes a provision for the implementation of a decoupling mechanism, similar to the Washington and Idaho mechanisms described above. In addition to the partial settlement agreements above, the OPUC staff filed testimony which included a recommendation to disallow $1.2 million (Oregon's share) of Project Compass costs primarily related to the delay in the full completion of the project. In January 2016, following the January 6, 2016 UTC order approving the full recovery of Washington's portion of Project Compass costs, the OPUC staff withdrew its proposal for a disallowance, with the exception of an inconsequential amount which is still open for discussion. The procedural schedule includes an expected decision from the OPUC by February 29, 2016. Alaska General Rate Case AEL&P's last general rate case was filed in 2010 and approved by the RCA in 2011. We are evaluating the need to file an electric general rate case with the RCA in 2016. Purchased Gas Adjustments PGAs are designed to pass through changes in natural gas costs to Avista Utilities' customers with no change in gross margin (operating revenues less resource costs) or net income. In Oregon, we absorb (cost or benefit) 10 percent of the difference between actual and projected natural gas costs included in retail rates for supply that is not hedged. Total net deferred natural gas costs among all jurisdictions were a liability of $17.9 million as of December 31, 2015 and a liability of $3.9 million as of December 31, 2014. The following PGAs went into effect in our various jurisdictions during 2013, 2014 and 2015: Jurisdiction PGA Effective Date Percentage Increase / (Decrease) in Billed Rates Washington November 1, 2013 9.2% November 1, 2014 1.2% November 1, 2015 (15.0)% Idaho October 1, 2013 7.5% November 1, 2014 (2.1)% November 1, 2015 (14.5)% Oregon November 1, 2013 (7.9)% November 1, 2014 8.3% November 1, 2015 (14.1)% Power Cost Deferrals and Recovery Mechanisms The ERM is an accounting method used to track certain differences between Avista Utilities' actual power supply costs, net of wholesale sales and sales of fuel, and the amount included in base retail rates for our Washington customers. Total net deferred power costs under the ERM were a liability of $18.0 million as of December 31, 2015 compared to a liability $14.2 million as of December 31, 2014, and these deferred power cost balances represent amounts due to customers. The difference in net power supply costs under the ERM primarily results from changes in: •short-term wholesale market prices and sales and purchase volumes, •the level and availability of hydroelectric generation, •the level and availability of thermal generation (including changes in fuel prices), and •retail loads. Under the ERM, Avista Utilities absorbs the cost or receives the benefit from the initial amount of power supply costs in excess of or below the level in retail rates, which is referred to as the deadband. The annual (calendar year) deadband amount is $4.0 million. 38 Staff_DR_063 Attachment A Page 45 of 180 Table of Contents AVISTA CORPORATION The following is a summary of the ERM: Annual Power Supply Cost Variability Deferred for Future Surcharge or Rebate to Customers Expense or Benefit to the Company within +/- $0 to $4 million (deadband) 0% 100% higher by $4 million to $10 million 50% 50% lower by $4 million to $10 million 75% 25% higher or lower by over $10 million 90% 10% Under the ERM, Avista Utilities makes an annual filing on or before April 1 of each year to provide the opportunity for the UTC staff and other interested parties to review the prudence of and audit the ERM deferred power cost transactions for the prior calendar year. We made our annual filing on March 31, 2015. The ERM provides for a 90-day review period for the filing; however, the period may be extended by agreement of the parties or by UTC order. The 2014 ERM deferred power costs transactions were approved by an order from the UTC. Avista Utilities has a PCA mechanism in Idaho that allows us to modify electric rates on October 1 of each year with IPUC approval. Under the PCA mechanism, we defer 90 percent of the difference between certain actual net power supply expenses and the amount included in base retail rates for our Idaho customers. The October 1 rate adjustments recover or rebate power supply costs deferred during the preceding July-June twelve-month period. Total net power supply costs deferred under the PCA mechanism were an asset of $0.2 million as of December 31, 2015 compared to an asset of $8.3 million as of December 31, 2014. Decoupling and Earnings Sharing Mechanisms Decoupling is a mechanism designed to sever the link between a utility's revenues and consumers' energy usage. Our actual revenue, based on kilowatt hour and therm sales will vary, up or down, from the level included in a general rate case, which could be caused by changes in weather, energy conservation or the economy. Generally, our electric and natural gas revenues will be adjusted each month to be based on the number of customers, rather than kilowatt hour and therm sales. The difference between revenues based on sales and revenues based on the number of customers will be deferred and either surcharged or rebated to customers beginning in the following year. Washington Decoupling and Earnings Sharing In Washington, the UTC approved our decoupling mechanisms for electric and natural gas for a five-year period that commenced January 1, 2015. Electric and natural gas decoupling surcharge rate adjustments to customers are limited to 3 percent on an annual basis, with any remaining surcharge balance carried forward for recovery in a future period. There is no limit on the level of rebate rate adjustments. The decoupling mechanisms each include an after-the-fact earnings test. At the end of each calendar year, separate electric and natural gas earnings calculations will be made for the prior calendar year. These earnings tests will reflect actual decoupled revenues, normalized power supply costs and other normalizing adjustments. •If we have a decoupling rebate balance for the prior year and earn in excess of a 7.32 percent ROR, the rebate to customers would be increased by 50 percent of the earnings in excess of the 7.32 percent ROR. •If we have a decoupling rebate balance for the prior year and earn a 7.32 percent ROR or less, only the base amount of the rebate to customers would be made. •If we have a decoupling surcharge balance for the prior year and earn in excess of a 7.32 percent ROR, the surcharge to customers would be reduced by 50 percent of the earnings in excess of the 7.32 percent ROR (or eliminated). If 50 percent of the earnings in excess of the 7.32 percent ROR exceeds the decoupling surcharge balance, the dollar amount that exceeds the surcharge balance would create a rebate balance for customers. •If we have a decoupling surcharge balance for the prior year and earn a 7.32 percent ROR or less, the base amount of the surcharge to customers would be made. As of December 31, 2015, we had a total net decoupling surcharge (asset) of $10.9 million for Washington electric and natural gas customers and a liability (rebate to customers) for earnings sharing of $3.4 million for Washington electric customers. Idaho Fixed Cost Adjustment (FCA) and Earnings Sharing Mechanisms In Idaho, the IPUC approved the implementation of FCAs for electric and natural gas (similar in operation and effect to the Washington decoupling mechanisms) for an initial term of three years, commencing on January 1, 2016. 39 Staff_DR_063 Attachment A Page 46 of 180 Table of Contents AVISTA CORPORATION For the period 2013 through 2015, we had an after-the-fact earnings test, such that if Avista Corp., on a consolidated basis for electric and natural gas operations in Idaho, earned more than a 9.8 percent ROE, we were required to share with customers 50 percent of any earnings above the 9.8 percent. There was no provision for a surcharge to customers if our ROE was less than 9.8 percent. This after-the-fact earnings test was discontinued as part of the settlement of our 2015 Idaho electric and natural gas general rates cases (discussed in further detail above). As of December 31, 2015 and December 31, 2014, we had total cumulative earnings sharing liabilities (rebates to customers) of $8.8 million and $10.1 million, respectively for electric and natural gas customers. Of the total rebate balance as of December 31, 2015, approximately $5.8 million will be returned to customers during January 1, 2016 through December 31, 2017 and the remainder of the balance will be addressed at a future date. See "Results of Operations - Avista Utilities'" for further discussion of the amounts recorded to operating revenues in 2013 through 2015 related to the decoupling and earnings sharing mechanisms. Results of Operations - Overall The following provides an overview of changes in our Consolidated Statements of Income. More detailed explanations are provided, particularly for operating revenues and operating expenses, in the business segment discussions (Avista Utilities, AEL&P, Ecova - Discontinued Operations and the other businesses) that follow this section. As discussed in "Executive Level Summary," Ecova was disposed of as of June 30, 2014. As a result, in accordance with GAAP, all of Ecova's operating results were removed from each line item on the Consolidated Statements of Income and reclassified into discontinued operations for all periods presented. The discussion of continuing operations below does not include any Ecova amounts. For our discussion of discontinued operations and Ecova, see "Ecova - Discontinued Operations." The balances included below for utility operations reconcile to the Consolidated Statements of Income. Beginning on July 1, 2014, AEL&P is included in the overall utility results. 2015 compared to 2014 Utility revenues increased $22.7 million, after elimination of intracompany revenues (within Avista Utilities) of $107.0 million for 2015 and $142.2 million for 2014. Avista Utilities' portion of utility revenues increased $1.6 million and AEL&P's revenues increased $23.1 million due to a full year of AEL&P results in 2015 as compared to six months in 2014. Including intracompany revenues, Avista Utilities' electric revenues decreased $1.1 million and natural gas revenues decreased $35.7 million. Other non-utility revenues decreased $10.5 million primarily due to the long-term fixed rate electric capacity contract that was previously held by Spokane Energy being transferred to Avista Corp. during the second quarter of 2015. The capacity revenue from this contract was included in non-utility revenues when it was held by Spokane Energy. Utility resource costs decreased $21.3 million, after elimination of intracompany resource costs of $107.0 million for 2015 and $142.2 million for 2014. Avista Utilities' portion of resource costs decreased $27.4 million and AEL&P's resource costs increased $6.1 million due to a full year of AEL&P results in 2015 as compared to six months in 2014. Including intracompany resource costs, Avista Utilities' electric resource costs decreased $17.6 million and natural gas resource costs decreased $44.9 million. Utility other operating expenses increased $16.4 million. Avista Utilities' portion of other operating expenses increased $11.1 million and AEL&P's other operating expenses increased $5.3 million due to a full year of AEL&P results in 2015 as compared to six months in 2014. Avista Utilities incurred increased generation, transmission and distribution operating expenses of $5.7 million, increased administrative and general wages of $9.8 million and increased pension and other post-retirement benefit expenses of $10.0 million. In addition, Avista Utilities incurred incremental storm restoration costs associated with the November 2015 wind storm of approximately $2.9 million. These increases were partially offset by decreases in outside services and generation maintenance of $7.8 million and decreases in other various accounts. Utility depreciation and amortization increased $13.9 million driven by additions to utility plant and the inclusion of a full year of AEL&P depreciation as compared to only six months of AEL&P in 2014. Income taxes decreased $4.8 million and our effective tax rate was 36.3 percent for 2015 compared to 37.6 percent for 2014. The decrease in expense was primarily due to a decrease in income before income taxes. There were not material changes in any other account balances on the Consolidated Statement of Income for the year ended December 31, 2015 as compared to the year ended December 31, 2014. 2014 compared to 2013 Utility revenues increased $31.1 million, after elimination of intracompany revenues (within Avista Utilities) of $142.2 million for 2014 and $151.9 million for 2013. Avista Utilities' portion of utility revenues increased $9.5 million and AEL&P had 40 Staff_DR_063 Attachment A Page 47 of 180 Table of Contents AVISTA CORPORATION electric revenues of $21.6 million, representing its revenues for the six months ended December 31, 2014. Including intracompany revenues, Avista Utilities' electric revenues decreased $31.6 million and natural gas revenues increased $31.4 million. Utility resource costs decreased $11.3 million, after elimination of intracompany resource costs of $142.2 million for 2014 and $151.9 million for 2013. Avista Utilities' portion of resource costs decreased $17.2 million and this was offset by utility resource costs at AEL&P of $5.9 million, representing its resource costs for the six months ended December 31, 2014. Including intracompany resource costs, Avista Utilities' electric resource costs decreased $57.7 million and natural gas resource costs increased $30.7 million. Utility other operating expenses increased $10.6 million and was partially the result of AEL&P being included for the six months ended December 31, 2014, which added $5.9 million to other operating expenses. Avista Utilities incurred increased generation, transmission and distribution operating and maintenance expenses and increased outside services. There were also transaction fees associated with the AERC acquisition of $1.3 million in 2014 compared to $1.6 million in 2013. These were partially offset by a decrease in pension and other post-retirement benefits expense. The remainder of the change resulted from various smaller changes in other accounts. Utility depreciation and amortization increased $12.4 million driven by additions to utility plant and the inclusion of $2.6 million related to AEL&P for the second half of the year. Other non-utility operating expenses decreased $8.2 million primarily due to the receipt of $15.0 million related to the settlement of the California power markets litigation (which was recorded as a reduction to operating expenses), partially offset by a $6.4 million contribution to the Avista Foundation. Income taxes increased $14.2 million and our effective tax rate was 37.6 percent for 2014 compared to 35.7 percent for 2013. The increase in expense was primarily due to an increase in income before income taxes. The increase in the effective tax rate was primarily the result of the Section 199 Domestic Manufacturing Deduction not being available to the Company due to limitations on taxable qualified production activities income. There were not material changes in any other account balances on the Consolidated Statement of Income for the year ended December 31, 2014 as compared to the year ended December 31, 2013. Results of Operations - Avista Utilities Non-GAAP Financial Measures The following discussion for Avista Utilities includes two financial measures that are considered “non-GAAP financial measures,” electric gross margin and natural gas gross margin. In the AEL&P section, we include a discussion of electric gross margin. Generally, a non-GAAP financial measure is a numerical measure of a company's financial performance, financial position or cash flows that excludes (or includes) amounts that are included (excluded) in the most directly comparable measure calculated and presented in accordance with GAAP. The presentation of electric gross margin and natural gas gross margin for Avista Utilities and electric gross margin for AEL&P is intended to supplement an understanding of Avista Utilities' and AEL&P's operating performance. We use these measures to determine whether the appropriate amount of energy costs are being collected from our customers to allow for recovery of operating costs, as well as to analyze how changes in loads (due to weather, economic or other conditions), rates, supply costs and other factors impact our results of operations. These measures are not intended to replace income from operations as determined in accordance with GAAP as an indicator of operating performance. The calculations of electric and natural gas gross margins are presented below. 41 Staff_DR_063 Attachment A Page 48 of 180 Table of Contents AVISTA CORPORATION 2015 compared to 2014 The following graphs presents Avista Utilities' operating revenues, resource costs and resulting gross margin for the year ended December 31 (dollars in millions): Total results of operations for electric and natural gas in the graphs above include intracompany revenues and resource costs of $107.0 million and $142.2 million for the years ended December 31, 2015 and December 31, 2014, respectively. Staff_DR_063 Attachment A Page 49 of 180 The gross margin on electric sales increased $16.5 million and the gross margin on natural gas sales increased $9.2 million. The increase in electric gross margin was primarily due to a general rate increase in Washington, lower net power supply costs and a $1.9 million decrease in the provision for earnings sharing (which is an offset to revenue). We experienced weather that was significantly warmer than normal and warmer than the prior year, which decreased heating loads in the first quarter and increased cooling loads in the second quarter. Loads in the third quarter were slightly higher than the prior year. Loads for the fourth quarter were lower than the prior year, particularly for residential and industrial customers. For 2015, the decoupling mechanism in Washington had a positive effect on each of electric revenues and gross margin as did the decrease in the overall provision for earnings sharing (see the details by jurisdiction in the table below). For 2015, we recognized a pre-tax benefit of 42 Staff_DR_063 Attachment A Page 50 of 180 Table of Contents AVISTA CORPORATION $6.3 million under the ERM in Washington compared to a benefit of $5.4 million for 2014. This change represents a decrease in net power supply costs primarily due to lower natural gas fuel and purchased power prices in 2015, partially offset by lower hydroelectric generation (due to warm and dry conditions in the second and third quarters). The increase in natural gas gross margin was primarily due to a decrease in natural gas resources costs and a decrease in the provision for earnings sharing, partially offset by a decrease in natural gas revenues. The decrease in natural gas revenues resulted from lower heating loads from significantly warmer weather that was partially offset by general rate increases. The earnings impact of the decrease in heating loads was partially offset by the decoupling mechanism in Washington, which had a positive effect on natural gas revenues and gross margin (see the details by jurisdiction in the table below). Intracompany revenues and resource costs represent purchases and sales of natural gas between our natural gas distribution operations and our electric generation operations (as fuel for our generation plants). These transactions are eliminated in the presentation of total results for Avista Utilities and in the consolidated financial statements but are reflected in the presentation of the separate results for electric and natural gas below. The following graphs present Avista Utilities' electric operating revenues and megawatt-hour (MWh) sales for the year ended December 31 (dollars in millions and MWhs in thousands): 43 Staff_DR_063 Attachment A Page 51 of 180 Table of Contents AVISTA CORPORATION The following table presents Avista Utilities' decoupling and customer earnings sharing mechanisms by jurisdiction that are included in utility electric operating revenues for the year ended December 31 (dollars in thousands): Electric Operating Revenues 2015 2014 Washington Decoupling $4,740 $— Provision for earnings sharing (3,423) — Total 1,317 — Idaho Decoupling — — Provision for earnings sharing (2,198) (7,503) Total $(2,198) $(7,503) Total electric revenues decreased $1.1 million for 2015 as compared to 2014 due to the following: •a $5.7 million increase in retail electric revenues due to an increase in revenue per MWh (increased revenues $21.0 million), partially offset by a decrease in total MWhs sold (decreased revenues $15.3 million). The increase in revenue per MWh was primarily due to a general rate increase in Washington. The decrease in total MWhs sold was primarily the result of weather that was significantly warmer than normal and warmer than the prior year, which decreased the electric heating load in the first quarter. Compared to 2014, residential electric use per customer decreased 5 percent and commercial use per customer decreased 2 percent. Heating degree days in Spokane were 14 percent below normal and 10 percent below 2014. The impact from reduced heating loads was partially offset by increased cooling loads in the summer. Year-to-date cooling degree days were 141 percent above normal and 28 percent above the prior year. •a $10.9 million decrease in wholesale electric revenues due to a decrease in sales volumes (decreased revenues $21.9 million), partially offset by an increase in sales prices (increased revenues $11.0 million). The fluctuation in volumes and prices was primarily the result of our optimization activities. •a $0.9 million decrease in sales of fuel due to a decrease in sales of natural gas fuel as part of thermal generation resource optimization activities. For 2015, $50.0 million of these sales were made to our natural gas operations and are included as intracompany revenues and resource costs. For 2014, $67.4 million of these sales were made to our natural gas operations. •a $4.7 million increase in electric revenue due to decoupling, which reflected decreased heating loads in the first and fourth quarters, partially offset by increased cooling loads in the second and third quarters. 44 Staff_DR_063 Attachment A Page 52 of 180 Table of Contents AVISTA CORPORATION •a $1.9 million decrease in the provision for earnings sharing, primarily due to a decrease of $5.3 million for our Idaho electric operations, partially offset by an increase of $3.4 million for our Washington electric operations. In 2014, we recorded a provision for earnings sharing of $7.5 million for Idaho electric customers with $5.6 million representing our estimate for 2014 and $1.9 million representing an adjustment of our 2013 estimate. The following graphs present Avista Utilities' natural gas operating revenues and therms delivered for the year ended December 31 (dollars in millions and therms in thousands): 45 Staff_DR_063 Attachment A Page 53 of 180 Table of Contents AVISTA CORPORATION The following table presents Avista Utilities' decoupling and customer earnings sharing mechanisms by jurisdiction that are included in utility natural gas operating revenues for the year ended December 31 (dollars in thousands): Natural Gas Operating Revenues 2015 2014 Washington Decoupling $6,004 $— Provision for earnings sharing — — Total 6,004 — Idaho Decoupling — — Provision for earnings sharing — (221) Total $— $(221) Total natural gas revenues decreased $35.7 million for 2015 as compared to 2014 due to the following: •a $16.4 million decrease in retail natural gas revenues due to a decrease in volumes (decreased revenues $23.6 million), partially offset by higher retail rates (increased revenues $7.2 million). Higher retail rates were due to PGAs implemented in November 2014, which passed through higher costs of natural gas, and general rate cases. This was partially offset by PGA rate decreases implemented in November 2015, which passed through lower costs. We sold less retail natural gas in 2015 as compared to 2014 primarily due to weather that was warmer than normal and warmer than the prior year. Compared to 2014, residential use per customer decreased 9 percent and commercial use per customer decreased 9 percent. Heating degree days in Spokane were 14 percent below historical average for 2015, and 10 percent below 2014. Heating degree days in Medford were 15 percent below historical average for 2015, and 4 percent above 2014. •a $23.9 million decrease in wholesale natural gas revenues due to a decrease in prices (decreased revenues $90.4 million), partially offset by an increase in volumes (increased revenues $66.5 million). In 2015, $57.0 million of these sales were made to our electric generation operations and are included as intracompany revenues and resource costs. In 2014, $74.7 million of these sales were made to our electric generation operations. Differences between revenues and costs from sales of resources in excess of retail load requirements and from resource optimization are accounted for through the PGA mechanisms. •a $6.0 million increase for natural gas decoupling revenues due primarily to significantly warmer than normal weather and the impact on heating loads. The following table presents Avista Utilities' average number of electric and natural gas retail customers for the year ended December 31: Electric Customers Natural Gas Customers 2015 2014 2015 2014 Residential 327,057 324,188 296,005 291,928 Commercial 41,296 40,988 34,229 34,047 Interruptible — — 35 37 Industrial 1,353 1,385 261 264 Public street and highway lighting 529 531 — — Total retail customers 370,235 367,092 330,530 326,276 46 Staff_DR_063 Attachment A Page 54 of 180 Table of Contents AVISTA CORPORATION The following graphs present Avista Utilities' resource costs for the year ended December 31 (dollars in millions): Total resource costs in the graphs above include intracompany resource costs of $107.0 million and $142.2 million for the years ended December 31, 2015 and December 31, 2014, respectively. Total resource costs decreased $27.4 million for 2015 as compared to 2014 primarily due to the following: •a $18.3 million decrease in power purchased due to a decrease in the volume of power purchases (decreased costs $23.6 million), partially offset by an increase in wholesale prices (increased costs $5.3 million). The fluctuation in volumes and prices was primarily the result of our overall optimization activities. •a $14.2 million increase from amortizations and deferrals of power costs due to the following. •increases to expense in 2015: •a $5.8 million surcharge to customers of previously deferred power costs in Idaho through the PCA. •an $11.3 million deferral in Washington and a $2.0 million deferral in Idaho for probable future benefit to customers due to actual power supply costs being below the amount included in base retail rates. 47 Staff_DR_063 Attachment A Page 55 of 180 Table of Contents AVISTA CORPORATION •a $2.0 million deferral in Washington of RECs for probable future benefit to customers. •decreases to expense in 2015: •an $8.0 million refund to Washington customers through an ERM rebate. •a $5.4 million refund to Washington customers through a REC rebate. •a $4.4 million increase in fuel for generation primarily due to an increase in thermal generation (due in part to decreased hydroelectric generation), partially offset by a decrease in natural gas fuel prices. •a $10.0 million decrease in other fuel costs. This represents fuel and the related derivative instruments that were purchased for generation but were later sold when conditions indicated that it was more economical to sell the fuel as part of the resource optimization process. When the fuel or related derivative instruments are sold, that revenue is included in sales of fuel. •a $7.7 million decrease in other electric resource costs primarily due to the benefit from a capacity contract of Spokane Energy, which was mostly deferred for probable future benefit to customers through the ERM and PCA. •a $66.1 million decrease in natural gas purchased due to a decrease in the price of natural gas (decreased costs $138.3 million), partially offset by an increase in total therms purchased (increased costs $72.2 million). Total therms purchased increased due to an increase in wholesale sales, partially offset by a decrease in retail sales. •a $21.8 million increase from amortizations and deferrals of natural gas costs. This reflects lower natural gas prices and the deferral of lower costs for future rebate to customers. •a $35.1 million decrease in intracompany resource costs (which has the effect of increasing overall net resource costs). 2014 compared to 2013 The following graphs present Avista Utilities' operating revenues, resource costs and resulting gross margin for the year ended December 31 (dollars in millions): Staff_DR_063 Attachment A Page 56 of 180 Total results of operations for electric and natural gas in the graphs above include intracompany revenues and resource costs of $142.2 million and $151.9 million for the years ended December 31, 2014 and December 31, 2013, respectively. 48 Staff_DR_063 Attachment A Page 57 of 180 Table of Contents AVISTA CORPORATION The gross margin on electric sales increased $26.0 million and the gross margin on natural gas sales increased $0.7 million. Electric gross margin for 2014 included a pre-tax benefit of $5.4 million under the ERM in Washington compared to a pre-tax expense of $4.7 million for 2013. This change represents a decrease in net power supply costs due to the Colstrip outage in 2013 and increased hydroelectric generation in 2014. Electric gross margin for 2013 included the net benefit from the settlement with the BPA of $5.1 million. The following graphs present Avista Utilities' electric operating revenues and megawatt-hour (MWh) sales for the year ended December 31 (dollars in millions and MWhs in thousands): 49 Staff_DR_063 Attachment A Page 58 of 180 Table of Contents AVISTA CORPORATION Total electric revenues decreased $31.6 million for 2014 as compared to 2013 due to the following: •a $14.8 million increase in retail electric revenue primarily due to general rate increases and a change in revenue mix (which increased revenue by $25.2 million), partially offset by a decrease in volumes (which decreased revenue by $10.4 million). The decrease in residential volumes was primarily due to warmer weather in the fourth quarter, partially offset by customer growth. The decrease in total MWhs sold to industrial customers was primarily due to the expiration and replacement of a contract with one of our largest industrial customers in Idaho, effective July 1, 2013. The change resulting from this new contract did not impact gross margin because any change in revenues and expenses was tracked through the PCA in Idaho at 100 percent until such time as the contract was included in the Company’s base rates, •a $10.6 million increase in wholesale electric revenues due to an increase in sales prices (increased revenues $17.6 million), partially offset by a decrease in sales volumes (decreased revenues $7.0 million). The fluctuation in volumes and prices was primarily the result of our optimization activities during the period, •a decrease of $42.9 million in sales of natural gas fuel as part of thermal generation resource optimization activities. For 2014, $67.4 million of these sales were made to our natural gas operations and are included as intracompany revenues and resource costs. For 2013, $102.4 million of these sales were made to our natural gas operations, •an $8.6 million decrease in other electric revenues primarily due to the receipt of $11.7 million of revenue from the Bonneville Power Administration in 2013 for past use of our electric transmission system, and •a $5.5 million increase in the provision for earnings sharing for Idaho electric customers primarily due to the 2014 provision for earnings sharing including a $1.9 million adjustment of our 2013 estimate. 50 Staff_DR_063 Attachment A Page 59 of 180 Table of Contents AVISTA CORPORATION The following graphs present Avista Utilities' natural gas operating revenues and therms delivered for the year ended December 31 (dollars in millions and therms in thousands): Natural gas revenues increased $31.4 million for 2014 as compared to 2013 due to the following: •a $1.3 million decrease in retail natural gas revenues due to a decrease in volumes (decreased revenues by $20.0 million), partially offset by general rate increases and higher PGA rates, which passed through costs of natural gas (increased revenues by $18.7 million). We had decreased volumes primarily due to weather that was warmer than normal and warmer than the prior year during the fourth quarter, •an increase of $33.5 million in wholesale natural gas revenues due to an increase in prices (increased revenues by $24.8 million) and an increase in volumes (increased revenues by $8.7 million). In 2014, $74.7 million of wholesale sales were made to our electric generation operations and are included as intracompany revenues and resource costs. In 2013, $49.5 million of these sales were made to our electric generation operations, and •a $0.2 million reduction to revenue in 2014 for the provision for earnings sharing for Idaho natural gas customers, compared to a reduction to revenue of $0.4 million in 2013. 51 Staff_DR_063 Attachment A Page 60 of 180 Table of Contents AVISTA CORPORATION The following table presents Avista Utilities' average number of electric and natural gas retail customers for the year ended December 31: Electric Customers Natural Gas Customers 2014 2013 2014 2013 Residential 324,188 321,098 291,928 288,708 Commercial 40,988 40,202 34,047 33,932 Interruptible — — 37 38 Industrial 1,385 1,386 264 259 Public street and highway lighting 531 527 — — Total retail customers 367,092 363,213 326,276 322,937 The following graphs present Avista Utilities' resource costs for the year ended December 31 (dollars in millions): 52 Staff_DR_063 Attachment A Page 61 of 180 Table of Contents AVISTA CORPORATION Total resource costs in the graphs above include intracompany resource costs of $142.2 million and $151.9 million for the years ended December 31, 2014 and December 31, 2013, respectively. Total resource costs decreased $31.4 million for 2014 as compared to 2013 primarily due to the following: •a decrease of $5.0 million in power purchased due to a decrease in the volume of power purchases, partially offset by an increase in wholesale prices. The fluctuation in volumes and prices was primarily the result of our overall optimization activities during the year. The decrease in volumes purchased was also due to increased hydroelectric generation, •a decrease to 2014 electric resource costs of $6.5 million for amortizations and deferrals of power costs, compared to a decrease of $14.2 million for 2013. •increases to expense in 2014: •a $1.6 million deferral in Idaho and a $4.2 million deferral in Washington for probable future benefit to customers due to actual power supply costs being below the amount included in retail rates. •decreases to expense in 2014: •a $2.3 million refund to Idaho customers of previously deferred power costs through the PCA rebate. •an $8.5 million refund to Washington customers through an ERM rebate. •a $1.6 million deferral of RECs for probable future benefit to Washington customers. •a decrease of $17.2 million for fuel for generation primarily due to a decrease in natural gas generation, •a decrease of $39.6 million in other fuel costs due to the resource optimization process, and •an increase of $44.6 million in natural gas purchased due to an increase in the price of natural gas and a slight increase in total therms purchased. Total therms purchased increased due to an increase in wholesale sales as part of the natural gas procurement and resource optimization process, mostly offset by a decrease in retail sales. Results of Operations - Alaska Electric Light and Power Company AEL&P was acquired on July 1, 2014 and only the results for the second half of 2014 are included in the actual overall results of Avista Corp. The discussion below is only for AEL&P's earnings that were included in Avista Corp.'s overall earnings. 53 Staff_DR_063 Attachment A Page 62 of 180 Table of Contents AVISTA CORPORATION 2015 compared to 2014 Net income for AEL&P was $6.6 million for the year ended December 31, 2015, compared to $3.2 million for the second half of 2014. The following table presents AEL&P's operating revenues, resource costs and resulting gross margin for the year ended December 31, 2015 and the second half of 2014 (dollars in thousands): Second half of 2015 2014 Operating revenues $44,778 $21,644 Resource costs 11,973 5,900 Gross margin $32,805 $15,744 The following table presents AEL&P's electric operating revenues and megawatt-hour (MWh) sales for the year ended December 31, 2015 and the second half of 2014 (dollars and MWhs in thousands): Electric Operating Revenues Electric Energy MWh sales 2015 Second half of 2014 2015 Second half of 2014 Residential $18,017 $8,283 139 63 Commercial and government 26,049 12,948 258 125 Public street and highway lighting 215 150 1 1 Total retail 44,281 21,381 398 189 Other 497 263 — — Total $44,778 $21,644 398 189 AEL&P has a relatively stable load profile as it does not have a large population of customers in its service territory with electric heating and cooling requirements; therefore, their revenues are not as sensitive to weather fluctuations as Avista Utilities. However, AEL&P does have higher winter rates for its customers during the peak period of November through May of each year, which drives higher revenues during those periods. Government sales are similar to commercial sales in that they are primarily firm customers, but are government entities. Commercial and government revenues from interruptible or non-firm customers were $8.3 million for 2015, including $7.2 million from AEL&P's largest customer. These revenues from non-firm customers are deferred and passed on for the benefit of firm customers in future periods either through base rates or a cost of power adjustment. As noted at "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Economic Conditions," one of AEL&P's largest commercial customers (a retailer), which accounts for approximately 1 percent of AEL&P's annual firm revenues, is permanently closing in early 2016. It is unknown whether a new business will occupy the building that was occupied by this retailer. The following table presents AEL&P's average number of electric retail customers for the year ended December 31, 2015 and the second half of 2014: Electric Customers 2015 Second half of 2014 Residential 14,285 14,121 Commercial and government 2,179 2,148 Public street and highway lighting 210 213 Total retail customers 16,674 16,482 54 Staff_DR_063 Attachment A Page 63 of 180 Table of Contents AVISTA CORPORATION The following table presents AEL&P's resource costs for the year ended December 31, 2015 and the second half of 2014 (dollars in thousands): Resource Costs 2015 Second half of 2014 Snettisham power expenses $10,377 $5,196 Cost of power adjustment, net 1,501 646 Fuel for generation 95 58 Total electric resource costs $11,973 $5,900 Snettisham power expenses represent costs associated with operating the Snettisham hydroelectric project, including amounts paid under the take-or-pay PPA for the full capacity of this plant. This agreement is recorded as a capital lease on AEL&P's balance sheet, but reflected as an operating lease in the income statement. See "Note 14 of the Notes to Consolidated Financial Statements" for further information regarding this capital lease obligation. Cost of power adjustments are primarily derived from certain revenues from interruptible or non-firm customers that are deferred and passed on for the benefit of firm customers in future periods. For instance, revenues from electric sales to cruise ships are passed back to firm customers at 100 percent. The amortization of these deferred balances flows through this account along with the original deferral. Results of Operations - Ecova - Discontinued Operations Ecova was disposed of as of June 30, 2014. As a result, in accordance with GAAP, all of Ecova's operating results were removed from each line item on the Consolidated Statements of Income and reclassified into discontinued operations for all periods presented. In addition, since Ecova was a subsidiary of Avista Capital, the net gain recognized on the sale of Ecova was attributable to our other businesses. However, in accordance with GAAP, this gain is included in discontinued operations; therefore, we included the analysis of the gain in the Ecova discontinued operations section rather than in the other businesses section. 2015 compared to 2014 Ecova's net income was $5.1 million for 2015, compared to net income of $72.4 million for 2014. The net income for 2015 was primarily related to a tax benefit during 2015 that resulted from the reversal of a valuation allowance against net operating losses at Ecova because the net operating losses were deemed realizable under the current tax code. Additionally, there were some minor true-ups to the gain recognized on the sale due to the settlement of the working capital and indemnification escrow accounts during 2015. The results for 2014 included $69.7 million of the net gain recognized on the sale of Ecova. 2014 compared to 2013 Ecova's net income was $72.4 million for 2014 compared to net income of $7.1 million for 2013. The increase was primarily attributable to the net gain recognized on the sale of Ecova of $69.7 million. Excluding the net gain, net income from Ecova's regular operations through the date of the sale were flat compared to the same period in 2013 and were the result of a decrease in depreciation and amortization expense and an increase in operating revenues, offset by an increase in operating expenses. Results of Operations - Other Businesses 2015 compared to 2014 The net loss from these operations was $1.9 million for 2015 compared to net income of $3.2 million for 2014. The decrease in net income compared to 2014 was primarily due to the settlement of the California power markets litigation in 2014, which is described in further detail below. In addition, the net loss for 2015 was primarily related to: •$2.3 million (net of tax) of corporate costs, including costs associated with exploring strategic opportunities, compared to $2.4 million in 2014, •net losses on investments (net of tax) of $0.4 million for 2015, compared to net gains of $0.2 million for 2014, •net income at METALfx of $1.5 million for 2015, compared to net income of $0.9 million for 2014. 2014 compared to 2013 The net income from these operations was $3.2 million for 2014 compared to a net loss of $4.7 million for 2013. The net income for 2014 was primarily the result of the settlement of the California power markets litigation, where Avista Energy received settlement proceeds from a litigation with various California parties related to the prices paid for power in the 55 Staff_DR_063 Attachment A Page 64 of 180 Table of Contents AVISTA CORPORATION California spot markets during the years 2000 and 2001. This settlement resulted in an increase in pre-tax earnings of approximately $15.0 million. This was partially offset by a pre-tax contribution of $6.4 million of the proceeds to the Avista Foundation. METALfx had net income of $0.9 million for 2014, compared to net income of $1.2 million for 2013. In 2014, we also incurred $2.4 million (net of tax) of corporate costs, including costs associated with exploring strategic opportunities. Accounting Standards to be Adopted in 2016 At this time, we are not expecting the adoption of accounting standards to have a material impact on our financial condition, results of operations and cash flows in 2016. For information on accounting standards adopted in 2015 and earlier periods, see “Note 2 of the Notes to Consolidated Financial Statements.” Critical Accounting Policies and Estimates The preparation of our consolidated financial statements in conformity with GAAP requires us to make estimates and assumptions that affect amounts reported in the consolidated financial statements. Changes in these estimates and assumptions are considered reasonably possible and may have a material effect on our consolidated financial statements and thus actual results could differ from the amounts reported and disclosed herein. The following accounting policies represent those that our management believes are particularly important to the consolidated financial statements and require the use of estimates and assumptions: •Regulatory accounting, which requires that certain costs and/or obligations be reflected as deferred charges on our Consolidated Balance Sheets and are not reflected in our Consolidated Statements of Income until the period during which matching revenues are recognized. We also have decoupling revenue deferrals. As opposed to cost deferrals which are not recognized in the Consolidated Statements of Income until they are included in rates, decoupling revenue is recognized in the Consolidated Statements of Income during the period in which it occurs (i.e. during the period of revenue shortfall or excess due to fluctuations in customer usage), subject to certain limitations, and a regulatory asset/liability is established which will be surcharged or rebated to customers in future periods. GAAP requires that for any alternative regulatory revenue program, like decoupling, the revenue must be collected from customers within 24 months of the deferral to qualify for recognition in the current period Consolidated Statement of Income. Any amounts included in the Company's decoupling program that won't be collected from customers within 24 months are not recorded in the financial statements until the period in which revenue recognition criteria are met. This could ultimately result in more decoupling revenue being collected from customers over the life of the decoupling program than what is deferred and recognized in the current period financial statements. We make estimates regarding the amount of revenue that will be collected with 24 months of deferral. We also make the assumption that there are regulatory precedents for many of our regulatory items and that we will be allowed recovery of these costs via retail rates in future periods. If we were no longer allowed to apply regulatory accounting or no longer allowed recovery of these costs, we could be required to recognize significant write-offs of regulatory assets and liabilities in the Consolidated Statements of Income. See "Notes 1 and 20 of the Notes to Consolidated Financial Statements" for further discussion of our regulatory accounting policy. •Utility energy commodity derivative asset and liability accounting, where we estimate the fair value of outstanding commodity derivatives and we offset energy commodity derivative assets or liabilities with a regulatory asset or liability. This accounting treatment is intended to defer the recognition of mark-to-market gains and losses on energy commodity transactions until the period of delivery. This accounting treatment is supported by accounting orders issued by the UTC and IPUC. If we were no longer allowed to apply regulatory accounting or no longer allowed recovery of these costs, we could be required to recognize significant changes in fair value of these energy commodity derivatives on a regular basis in the Consolidated Statements of Income, which could lead to significant fluctuations in net income. See "Notes 1 and 6 of the Notes to Consolidated Financial Statements" for further discussion of our energy derivative accounting policy. •Interest rate derivative asset and liability accounting, where we estimate the fair value of outstanding interest rate swaps, and U.S. Treasury lock agreements and offset the derivative asset or liability with a regulatory asset or liability. This is similar to the treatment of energy commodity derivatives described above. Upon settlement of interest rate swaps, the regulatory asset or liability (included as part of long-term debt) is amortized as a component of interest expense over the term of the associated debt. If we no longer applied regulatory accounting or were no longer allowed recovery of these costs, we could be required to recognize significant changes in fair value of these interest rate 56 Staff_DR_063 Attachment A Page 65 of 180 Table of Contents AVISTA CORPORATION derivatives on a regular basis in the Consolidated Statements of Income, which could lead to significant fluctuations in net income. •Pension Plans and Other Postretirement Benefit Plans, discussed in further detail below. •Contingencies, related to unresolved regulatory, legal and tax issues for which there is inherent uncertainty for the ultimate outcome of the respective matter. We accrue a loss contingency if it is probable that an asset is impaired or a liability has been incurred and the amount of the loss or impairment can be reasonably estimated. We also disclose losses that do not meet these conditions for accrual, if there is a reasonable possibility that a potential loss may be incurred. For all material contingencies, we have made a judgment as to the probability of a loss occurring and as to whether or not the amount of the loss can be reasonably estimated. If the loss recognition criteria are met, liabilities are accrued or assets are reduced. However, no assurance can be given to the ultimate outcome of any particular contingency. See "Notes 1 and 19 of the Notes to Consolidated Financial Statements" for further discussion of our commitments and contingencies. •Discontinued operations, related to the accounting and financial statement presentation for Ecova following its disposition in 2014. In accordance with GAAP, this transaction caused Ecova to be accounted for as a discontinued operation. Ecova's revenues and expenses are included in the Consolidated Statements of Income in discontinued operations (as a single line item, net of tax). The gain, net of tax, recognized on the sale of Ecova is also included in discontinued operations. All tables throughout the Notes to Consolidated Financial Statements that present Consolidated Statements of Income information were revised to only include amounts from continuing operations. In addition, we are presenting earnings per share calculations for continuing and discontinued operations. Pension Plans and Other Postretirement Benefit Plans - Avista Utilities We have a defined benefit pension plan covering substantially all regular full-time employees at Avista Utilities that were hired prior to January 1, 2014. For substantially all regular non-union full-time employees at Avista Utilities that were hired on or after January 1, 2014, a defined contribution 401(k) plan replaced the defined benefit pension plan. The Finance Committee of the Board of Directors approves investment policies, objectives and strategies that seek an appropriate return for the pension plan and it reviews and approves changes to the investment and funding policies. We have contracted with an independent investment consultant who is responsible for managing/monitoring the individual investment managers. The investment managers’ performance and related individual fund performance is reviewed at least quarterly by an internal benefits committee and by the Finance Committee to monitor compliance with our established investment policy objectives and strategies. Our pension plan assets are invested in debt securities and mutual funds, trusts and partnerships that hold marketable debt and equity securities, real estate and absolute return funds. In seeking to obtain the desired return to fund the pension plan, the investment consultant recommends allocation percentages by asset classes. These recommendations are reviewed by the internal benefits committee, which then recommends their adoption by the Finance Committee. The Finance Committee has established target investment allocation percentages by asset classes and also investment ranges for each asset class. The target investment allocation percentages are typically the midpoint of the established range and are disclosed in “Note 10 of the Notes to Consolidated Financial Statements.” We also have a Supplemental Executive Retirement Plan (SERP) that provides additional pension benefits to our executive officers and others whose benefits under the pension plan are reduced due to the application of Section 415 of the Internal Revenue Code of 1986 and the deferral of salary under deferred compensation plans. Pension costs (including the SERP) were $27.1 million for 2015, $14.6 million for 2014 and $28.8 million for 2013. Of our pension costs, approximately 60 percent are expensed and 40 percent are capitalized consistent with labor charges. The costs related to the SERP are expensed. Our costs for the pension plan are determined in part by actuarial formulas that are dependent upon numerous factors resulting from actual plan experience and assumptions of future experience. Pension costs are affected by among other things: •employee demographics (including age, compensation and length of service by employees), •the amount of cash contributions we make to the pension plan, and •the actual return on pension plan assets, •expected return on pension plan assets, 57 Staff_DR_063 Attachment A Page 66 of 180 Table of Contents AVISTA CORPORATION •discount rate used in determining the projected benefit obligation and pension costs, •assumed rate of increase in employee compensation, •life expectancy of participants and other beneficiaries, and •expected method of payment (lump sum or annuity) of pension benefits. Any changes in pension plan obligations associated with these factors may not be immediately recognized as pension costs in our Consolidated Statement of Income, but we generally recognize the change in future years over the remaining average service period of pension plan participants. As such, our costs recorded in any period may not reflect the actual level of cash benefits provided to pension plan participants. We revise the key assumption of the discount rate each year. In selecting a discount rate, we consider yield rates at the end of the year for highly rated corporate bond portfolios with cash flows from interest and maturities similar to that of the expected payout of pension benefits. In 2015, the pension plan discount rate (exclusive of the SERP) was 4.58 percent compared to 4.21 percent in 2014 and 5.10 percent in 2013. These changes in the discount rate decreased the projected benefit obligation (exclusive of the SERP) by approximately $31.0 million in 2015 and increased the obligation by $66.3 million in 2014. The expected long-term rate of return on plan assets is reset or confirmed annually based on past performance and economic forecasts for the types of investments held by our plan. We used an expected long-term rate of return of 5.30 percent in 2015, 6.60 percent in 2014 and 6.60 percent in 2013. This change increased pension costs by approximately $6.9 million in 2015. The actual return on plan assets, net of fees, was a loss of $4.3 million (or 0.8 percent) for 2015, a gain of $56.0 million (or 11.6 percent) for 2014 and a gain of $52.5 million (or 12.5 percent) for 2013. The following chart reflects the sensitivities associated with a change in certain actuarial assumptions by the indicated percentage (dollars in thousands): Actuarial Assumption Change in Assumption Effect on Projected Benefit Obligation Effect on Pension Cost Expected long-term return on plan assets (0.5)% $—* $2,670 Expected long-term return on plan assets 0.5 % —* (2,670) Discount rate (0.5)% 42,561 4,226 Discount rate 0.5 % (37,969) (3,768) *Changes in the expected return on plan assets would not affect our projected benefit obligation. We provide certain health care and life insurance benefits for substantially all of our retired employees. We accrue the estimated cost of postretirement benefit obligations during the years that employees provide service. Assumed health care cost trend rates have a significant effect on the amounts reported for our postretirement plans. A one-percentage-point increase in the assumed health care cost trend rate for each year would increase our accumulated postretirement benefit obligation as of December 31, 2015 by $9.7 million and the service and interest cost by $0.5 million. A one-percentage-point decrease in the assumed health care cost trend rate for each year would decrease our accumulated postretirement benefit obligation as of December 31, 2015 by $7.5 million and the service and interest cost by $0.4 million. As of December 31, 2015, for the estimated retiree medical plan liability and costs, which are included as part of other post-retirement benefits, our actuaries adopted an updated method of calculation. For the updated method, the assumed average per-capita claim costs for pre-65 participants and post-65 participants were age-adjusted into 5-year bands as prescribed by the Actuarial Standards of Practice. This change in method resulted in an increase to the accumulated post-retirement benefit obligation of approximately $4.6 million in 2015. Liquidity and Capital Resources Overall Liquidity Avista Corp.'s consolidated operating cash flows are primarily derived from the operations of Avista Utilities. The primary source of operating cash flows for Avista Utilities is revenues from sales of electricity and natural gas. Significant uses of cash flows from Avista Utilities include the purchase of power, fuel and natural gas, and payment of other operating expenses, taxes and interest, with any excess being available for other corporate uses such as capital expenditures and dividends. 58 Staff_DR_063 Attachment A Page 67 of 180 Table of Contents AVISTA CORPORATION We design operating and capital budgets to control operating costs and to direct capital expenditures to choices that support immediate and long-term strategies, particularly for our regulated utility operations. In addition to operating expenses, we have continuing commitments for capital expenditures for construction and improvement of utility facilities. Our annual net cash flows from operating activities usually do not fully support the amount required for annual utility capital expenditures. As such, from time to time, we need to access long-term capital markets in order to fund these needs as well as fund maturing debt. See further discussion at “Capital Resources.” We periodically file for rate adjustments for recovery of operating costs and capital investments and to seek the opportunity to earn reasonable returns as allowed by regulators. See further details in the section “Regulatory Matters.” For Avista Utilities, when power and natural gas costs exceed the levels currently recovered from retail customers, net cash flows are negatively affected. Factors that could cause purchased power and natural gas costs to exceed the levels currently recovered from our customers include, but are not limited to, higher prices in wholesale markets when we buy energy or an increased need to purchase power in the wholesale markets. Factors beyond our control that could result in an increased need to purchase power in the wholesale markets include, but are not limited to: •increases in demand (due to either weather or customer growth), •low availability of streamflows for hydroelectric generation, •unplanned outages at generating facilities, and •failure of third parties to deliver on energy or capacity contracts. Avista Utilities has regulatory mechanisms in place that provide for the deferral and recovery of the majority of power and natural gas supply costs. However, if prices rise above the level currently allowed in retail rates in periods when we are buying energy, deferral balances would increase, negatively affecting our cash flow and liquidity until such time as these costs, with interest, are recovered from customers. In addition to the above, Avista Utilities enters into derivative instruments to hedge our exposure to certain risks, including fluctuations in commodity market prices, foreign exchange rates and interest rates (for purposes of issuing long-term debt in the future). These derivative instruments often require collateral (in the form of cash or letters of credit) or other credit enhancements, or reductions or terminations of a portion of the contract through cash settlement, in the event of a downgrade in the Company's credit ratings or changes in market prices. In periods of price volatility, the level of exposure can change significantly. As a result, sudden and significant demands may be made against the Company's credit facilities and cash. See “Enterprise Risk Management – Demands for Collateral” below. We monitor the potential liquidity impacts of changes to energy commodity prices and other increased operating costs for our utility operations. We believe that we have adequate liquidity to meet such potential needs through our committed lines of credit. As of December 31, 2015, we had $250.4 million of available liquidity under the Avista Corp. committed line of credit and $25.0 million under the AEL&P committed line of credit. With our $400.0 million credit facility that expires in April 2019 and AEL&P's $25.0 million credit facility that expires in November 2019, we believe that we have adequate liquidity to meet our needs for the next 12 months. Review of Consolidated Cash Flow Statement Overall During 2015, cash flows from operating activities were $375.6 million, proceeds from the issuance of long-term debt were $100.0 million and we received $13.9 million from the settlement of the Ecova escrow receivable. Cash requirements included utility capital expenditures of $393.4 million, the redemption of long-term debt of $2.9 million, defined benefit pension plan contributions of $12.0 million, dividends of $82.4 million and the repurchase of common stock of $2.9 million. 2015 compared to 2014 Consolidated Operating Activities Net cash provided by operating activities was $375.6 million for 2015 compared to $267.3 million for 2014. Net cash used by the changes in certain current assets and liabilities components was $4.1 million for 2015, compared to net cash used of $50.0 million for 2014. The net cash used during 2015 primarily reflects cash outflows from changes in accounts payable, collateral posted for derivative instruments and accounts receivable. This was partially offset by inflows from changes in natural gas stored and income taxes receivable. 59 Staff_DR_063 Attachment A Page 68 of 180 Table of Contents AVISTA CORPORATION The gross gain on the sale of Ecova of $0.8 million for 2015 is deducted in reconciling net income to net cash provided by operating activities. The cash proceeds from the sale (which includes the gross gain) is included in investing activities. This is compared to the gross gain recognized in 2014 of $160.6 million. Net amortizations of power and natural gas costs were $21.4 million for 2015 compared to net deferrals of $14.8 million for 2014. The provision for deferred income taxes was $51.8 million for 2015 compared to $144.3 million for 2014. The decrease in 2015 was primarily due to the combination of implementation by the Company of updated federal tax tangible property regulations and increased deductions related to bonus depreciation in 2014. Contributions to our defined benefit pension plan were $12.0 million for 2015 compared to $32.0 million in 2014. Net cash received for income taxes was $10.0 million for 2015 compared to net cash paid of $45.4 million for 2014. Consolidated Investing Activities Net cash used in investing activities was $387.8 million for 2015, an increase compared to $103.7 million for 2014. During 2015, we received cash proceeds (related to the settlement of the escrow accounts) of $13.9 million for the sale of Ecova. We received the majority of the proceeds ($229.9 million) from the sale of Ecova during 2014. The proceeds received in 2014 were used to pay off the balance of Ecova's long-term borrowings and make payments to option holders and noncontrolling interests (included in financing activities). We also used a portion of these proceeds to pay our $74.8 million tax liability associated with the gain on sale and to fund common stock repurchases. Utility property capital expenditures increased by $67.9 million for 2015 as compared to 2014. During 2014, we received $15.0 million in cash (net of cash paid) related to the acquisition of AERC. Consolidated Financing Activities Net cash provided by financing activities was $0.5 million for 2015 compared to net cash used of $224.0 million for 2014. In 2015 we had the following significant transactions: •issuance and sale of $100.0 million of Avista Corp. first mortgage bonds in December 2015, •cash settlement of interest rate swaps in conjunction with the execution of the purchase agreement for the Avista Corp. first mortgage bonds which resulted in the payment of $9.3 million, •payment of $2.9 million for the redemption and maturity of long-term debt, •cash dividends paid increased to $82.4 million (or $1.32 per share) for 2015 from $78.3 million (or $1.27 per share) for 2014, •issuance of $1.6 million of common stock (net of issuance costs), and •repurchase of $2.9 million of our common stock. In 2014, we had the following significant transactions: •issuance of $150.0 million of long-term debt ($60.0 million of Avista Corp. first mortgage bonds, $75.0 million of AEL&P first mortgage bonds and a $15.0 million AERC unsecured note representing a term loan), •a decrease of $66.0 million in short-term borrowings on Avista Corp.’s committed line of credit, •a decrease of $46.0 million on Ecova's committed line of credit with $6.0 million in payments throughout the year and $40.0 million related to the close of the Ecova sale, •payment of $40.0 million for the redemption and maturity of long-term debt (primarily related to AEL&P paying off its existing debt), •cash payments of $54.2 million to noncontrolling interests and $20.9 million to stock option holders and redeemable noncontrolling interests of Ecova related to the Ecova sale in 2014, •issuance of $4.1 million of common stock (net of issuance costs) excluding issuances related to the acquisition of AERC. We issued $150.1 million of common stock to AERC shareholders, and this is reflected as a non-cash financing activity, •repurchase of $79.9 million of our common stock during 2014 using the proceeds from our sale of Ecova, and •a $16.2 million increase in cash related to the fluctuation in the balance of customer fund obligations at Ecova. 60 Staff_DR_063 Attachment A Page 69 of 180 Table of Contents AVISTA CORPORATION 2014 compared to 2013 Consolidated Operating Activities Net cash provided by operating activities was $267.3 million for 2014 compared to $242.6 million for 2013. Net cash used by the changes in certain current assets and liabilities components was $50.0 million for 2014, compared to net cash used of $48.2 million for 2013. The net cash used during 2014 primarily reflects cash outflows from changes in accounts payable, natural gas stored and income taxes receivable. These were partially offset by cash inflows from changes in other current liabilities (primarily related to accrued taxes and interest) and accounts receivable. The net cash used during 2013 primarily reflects cash outflows from changes in accounts receivable, accounts payable and other current assets (primarily related to miscellaneous current assets and income taxes receivable). These were partially offset by cash inflows from other current liabilities (primarily related to accrued taxes and interest). The gross gain on the sale of Ecova of $160.6 million for 2014 is deducted in reconciling net income to net cash provided by operating activities. The cash proceeds from the sale (which includes the gross gain) is included in investing activities. Net amortizations of power and natural gas costs were $14.8 million for 2014 compared to $9.4 million for 2013. The provision for deferred income taxes was $144.3 million for 2014 compared to $23.5 million for 2013. The increase for 2014 was primarily due to the combination of implementation by the Company of updated federal tax tangible property regulations and increased deductions related to bonus depreciation. Contributions to our defined benefit pension plan were $32.0 million for 2014 compared to $44.3 million in 2013. Collateral posted for derivative instruments increased by $23.3 million in 2014 compared to an increase of $16.1 million in 2013. We had cash collateral posted of $49.4 million as of December 31, 2014 and $26.1 million as of December 31, 2013. Net cash paid for income taxes was $45.4 million for 2014 compared to $44.8 million for 2013. Cash paid for interest was $73.5 million for 2014 compared to $75.4 million for 2013. Consolidated Investing Activities Net cash used in investing activities was $103.7 million for 2014, a decrease compared to $312.2 million for 2013. During 2014, we received cash proceeds (net of cash sold and escrow amounts) of $229.9 million related to the sale of Ecova. A portion of the proceeds from the Ecova sale was used to pay off the balance of Ecova's long-term borrowings and make payments to option holders and noncontrolling interests (included in financing activities). We also used a portion of these proceeds to pay our $74.8 million tax liability associated with the gain on sale. Utility property capital expenditures increased by $31.2 million for 2014 as compared to 2013. A significant portion of Ecova's funds held for clients were held as securities available for sale with purchases of $12.3 million and sales and maturities of $14.6 million in 2014. For 2013, Ecova had purchases of $35.9 million and sales and maturities of $23.0 million. The fluctuation in the balance of funds held for customers resulted in a decrease to cash of $18.9 million for 2014 as compared to an increase to cash of $1.8 million for 2013. We received $15.0 million in cash (net of cash paid) related to the acquisition of AERC during 2014. Consolidated Financing Activities Net cash used in financing activities was $224.0 million for 2014 compared to net cash provided of $76.8 million for 2013. During 2014, short-term borrowings on Avista Corp.’s committed line of credit decreased $66.0 million. Net borrowings on Ecova's committed line of credit decreased $46.0 million during the period with $6.0 million in payments throughout the year and $40.0 million related to the close of the Ecova sale. In September 2014, AEL&P issued $75.0 million of first mortgage bonds. In December 2014, Avista Corp. issued $60.0 million of first mortgage bonds and AERC issued a $15.0 million unsecured note representing a term loan. We cash settled interest rate swaps in conjunction with the pricing of the $60.0 million of Avista Corp. first mortgage bonds and received $5.4 million. The majority of the $40.0 million of retirements of long-term debt in 2014 relates to AEL&P paying off its existing debt. In connection with the closing of the Ecova sale, we made cash payments of $54.2 million to noncontrolling interests and $20.9 million to stock option holders and redeemable noncontrolling interests of Ecova. Cash dividends paid increased to $78.3 million (or $1.27 per share) for 2014 from $73.3 million (or $1.22 per share) for 2013. Excluding issuances related to the acquisition of AERC, we issued $4.1 million of common stock during 2014. We issued $150.1 million of common stock to AERC shareholders, and this is reflected as a non-cash financing activity. The fluctuation in 61 Staff_DR_063 Attachment A Page 70 of 180 Table of Contents AVISTA CORPORATION the balance of customer fund obligations at Ecova increased cash by $16.2 million. During 2014, we repurchased $79.9 million of common stock. Cash inflows during 2013 were from a $119.0 million increase in short-term borrowings on Avista Corp.’s committed line of credit, the issuance of $90.0 million of long-term debt and the issuance of $4.6 million of common stock. We also cash settled interest rate swap agreements for $2.9 million related to the pricing of the $90.0 million of long-term debt. Cash outflows during 2013 were from the maturity of long-term debt of $50.5 million and a net decrease in borrowings on Ecova's committed line of credit of $8.0 million (borrowings of $3.0 million and repayments of $11.0 million). Capital Resources Our consolidated capital structure, including the current portion of long-term debt and short-term borrowings, and excluding noncontrolling interests, consisted of the following as of December 31, 2015 and 2014 (dollars in thousands): December 31, 2015 December 31, 2014 Amount Percent of total Amount Percent of total Current portion of long-term debt and capital leases $93,167 2.9% $6,424 0.2% Current portion of nonrecourse long-term debt (Spokane Energy)— —% 1,431 0.1% Short-term borrowings 105,000 3.2% 105,000 3.4% Long-term debt to affiliated trusts 51,547 1.6% 51,547 1.6% Long-term debt and capital leases 1,480,111 45.4% 1,480,702 47.3% Total debt 1,729,825 53.1% 1,645,104 52.6% Total Avista Corporation shareholders’ equity 1,528,626 46.9% 1,483,671 47.4% Total $3,258,451 100.0% $3,128,775 100.0% Our shareholders’ equity increased $45.0 million during 2015 primarily due to net income, partially offset by the repurchase of common stock and dividends. We need to finance capital expenditures and acquire additional funds for operations from time to time. The cash requirements needed to service our indebtedness, both short-term and long-term, reduce the amount of cash flow available to fund capital expenditures, purchased power, fuel and natural gas costs, dividends and other requirements. See "Executive Level Summary" for a detailed discussion of the liquidity and capital resource transactions which occurred during 2015 and our anticipated needs for 2016. Balances outstanding and interest rates of borrowings (excluding letters of credit) under Avista Corp.'s committed line of credit were as follows as of and for the year ended December 31 (dollars in thousands): 2015 2014 2013 Balance outstanding at end of year $105,000 $105,000 $171,000 Letters of credit outstanding at end of year $44,595 $32,579 $27,434 Maximum balance outstanding during the year $180,000 $171,000 $171,000 Average balance outstanding during the year $95,573 $62,088 $27,580 Average interest rate during the year 0.98% 1.01% 1.14% Average interest rate at end of year 1.18% 0.93% 1.02% Any default on the line of credit or other financing arrangements of Avista Corp. or any of our “significant subsidiaries,” if any, could result in cross-defaults to other agreements of such entity, and/or to the line of credit or other financing arrangements of any other of such entities. Any defaults could also induce vendors and other counterparties to demand collateral. In the event of any such default, it would be difficult for us to obtain financing on reasonable terms to pay creditors or fund operations. We would also likely be prohibited from paying dividends on our common stock. Avista Corp. does not guarantee the indebtedness of any of its subsidiaries. As of December 31, 2015, Avista Corp. and its subsidiaries were in compliance with all of the covenants of their financing agreements, and none of Avista Corp.'s subsidiaries constituted a “significant subsidiary” as defined in Avista Corp.'s committed line of credit. We are restricted under our Restated Articles of Incorporation, as amended, as to the additional preferred stock we can issue. As of December 31, 2015, we could issue $1.3 billion of additional preferred stock at an assumed dividend rate of 6.3 percent. We are not planning to issue preferred stock. 62 Staff_DR_063 Attachment A Page 71 of 180 Table of Contents AVISTA CORPORATION Under the Avista Corp. and the AEL&P Mortgages and Deeds of Trust securing Avista Corp.'s and AEL&P's first mortgage bonds (including Secured Medium-Term Notes), respectively, each entity may issue additional first mortgage bonds in an aggregate principal amount equal to the sum of: •66-2/3 percent of the cost or fair value (whichever is lower) of property additions at each entity which have not previously been made the basis of any application under the Mortgages, or •an equal principal amount of retired first mortgage bonds at each entity which have not previously been made the basis of any application under the Mortgages, or •deposit of cash. However, Avista Corp. and AEL&P may not individually issue any additional first mortgage bonds (with certain exceptions in the case of bonds issued on the basis of retired bonds) unless the particular entity issuing the bonds has “net earnings” (as defined in the Mortgages) for any period of 12 consecutive calendar months out of the preceding 18 calendar months that were at least twice the annual interest requirements on all mortgage securities at the time outstanding, including the first mortgage bonds to be issued, and on all indebtedness of prior rank. As of December 31, 2015, property additions and retired bonds would have allowed, and the net earnings test would not have prohibited, the issuance of $1.1 billion in aggregate principal amount of additional first mortgage bonds at Avista Corp. and $5.0 million at AEL&P. We believe that we have adequate capacity to issue first mortgage bonds to meet our financing needs over the next several years. Capital Expenditures Utility cash-basis capital expenditures were $1,013.3 million for the years 2013 through 2015 including $13.8 million at AEL&P for 2014 and 2015. The following table summarizes our expected future capital expenditures by year (in thousands): Avista Utilities AEL&P Expected total annual capital expenditures (by year) 2016 375,000 17,000 2017 405,000 13,000 2018 405,000 18,000 Most of the capital expenditures at Avista Utilities are for upgrading our existing facilities and technology, and not for construction of new facilities. A significant portion of the capital expenditures at AEL&P are for the construction of an additional back-up generation plant planned to be completed in 2016 and a new hydroelectric generation project in 2017 and 2018. 63 Staff_DR_063 Attachment A Page 72 of 180 Table of Contents AVISTA CORPORATION The following graph shows the Avista Utilities' capital budget for 2016: These estimates of capital expenditures are subject to continuing review and adjustment. Actual capital expenditures may vary from our estimates due to factors such as changes in business conditions, construction schedules and environmental requirements. Off-Balance Sheet Arrangements As of December 31, 2015, we had $44.6 million in letters of credit outstanding under our $400.0 million committed line of credit, compared to $32.6 million as of December 31, 2014. Pension Plan We contributed $12.0 million to the pension plan in 2015. We expect to contribute a total of $60.0 million to the pension plan in the period 2016 through 2020, with an annual contribution of $12.0 million over that period. The final determination of pension plan contributions for future periods is subject to multiple variables, most of which are beyond our control, including changes to the fair value of pension plan assets, changes in actuarial assumptions (in particular the discount rate used in determining the benefit obligation), or changes in federal legislation. We may change our pension plan contributions in the future depending on changes to any variables, including those listed above. See "Note 10 of the Notes to Consolidated Financial Statements" for additional information regarding the pension plan. Credit Ratings Our access to capital markets and our cost of capital are directly affected by our credit ratings. In addition, many of our contracts for the purchase and sale of energy commodities contain terms dependent upon our credit ratings. See “Enterprise Risk Management – Demands for Collateral” and “Note 6 of the Notes to Consolidated Financial Statements.” The following table summarizes our credit ratings as of February 23, 2016: Standard & Poor’s (1) Moody’s (2) Corporate/Issuer rating BBB Baa1 Senior secured debt A- A2 Senior unsecured debt BBB Baa1 (1)Standard & Poor’s lowest “investment grade” credit rating is BBB-. (2)Moody’s lowest “investment grade” credit rating is Baa3. 64 Staff_DR_063 Attachment A Page 73 of 180 Table of Contents AVISTA CORPORATION A security rating is not a recommendation to buy, sell or hold securities. Each security rating is subject to revision or withdrawal at any time by the assigning rating organization. Each security rating agency has its own methodology for assigning ratings, and, accordingly, each rating should be considered in the context of the applicable methodology, independent of all other ratings. The rating agencies provide ratings at the request of Avista Corp. and charge fees for their services. Dividends On February 5, 2016, Avista Corp.’s Board of Directors declared a quarterly dividend of $0.3425 per share on the Company’s common stock. This was an increase of $0.0125 per share, or 3.8 percent from the previous quarterly dividend of $0.3300 per share. See "Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities" for a detailed discussion of our dividend policy and the factors which could limit the payment of dividends. Contractual Obligations The following table provides a summary of our future contractual obligations as of December 31, 2015 (dollars in millions): 2016 2017 2018 2019 2020 Thereafter Avista Utilities: Long-term debt maturities $90 $— $273 $90 $52 $949 Long-term debt to affiliated trusts — — — — — 52 Interest payments on long-term debt (1)74 73 64 56 52 697 Short-term borrowings 105 — — — — — Energy purchase contracts (2)341 233 215 202 150 1,266 Operating lease obligations (3)2 1 1 — — 3 Other obligations (4)34 31 26 31 32 192 Information technology contracts (5)2 2 — — — — Pension plan funding (6)12 12 12 12 12 — AERC (consolidated) total contractual commitments (7)15 15 15 30 15 307 Avista Capital (consolidated) total contractual commitments (8)2 1 1 1 1 — Total contractual obligations $677 $368 $607 $422 $314 $3,466 (1)Represents our estimate of interest payments on long-term debt, which is calculated based on the assumption that all debt is outstanding until maturity. Interest on variable rate debt is calculated using the rate in effect at December 31, 2015. (2)Energy purchase contracts were entered into as part of the obligation to serve our retail electric and natural gas customers’ energy requirements. As a result, costs are generally recovered either through base retail rates or adjustments to retail rates as part of the power and natural gas cost adjustment mechanisms. (3)Includes the interest component of the lease obligation. (4)Represents operational agreements, settlements and other contractual obligations for our generation, transmission and distribution facilities. These costs are generally recovered through base retail rates. (5)Includes information service contracts which are recorded to other operating expenses in the Consolidated Statements of Income. On March 30, 2015, Avista Corp. provided a cancellation notice, effective May 31, 2015, to one of its information technology service providers. New contracts were entered into to replace the cancelled contract. The replacement contracts result in similar amount of expense each year; however, this resulted in a significant decrease in future information technology contractual commitments because the new contracts do not have minimum committed spending in them and are primarily time and materials contracts. (6)Represents our estimated cash contributions to pension plans and other postretirement benefit plans through 2020. We cannot reasonably estimate pension plan contributions beyond 2020 at this time and have excluded them from the table above. (7)Primarily relates to long-term debt and capital lease maturities and the related interest. AERC contractual commitments also include contractually required capital project funding and operating and maintenance costs associated with the Snettisham hydroelectric project. These costs are generally recovered through base retail rates. 65 Staff_DR_063 Attachment A Page 74 of 180 Table of Contents AVISTA CORPORATION (8)Primarily relates to operating lease commitments and a commitment to fund a limited liability company in exchange for equity ownership, made by a subsidiary of Avista Capital. The above contractual obligations do not include income tax payments. Also, asset retirement obligations are not included above and payments associated with these have historically been less than $1 million per year. There are approximately $16.0 million remaining asset retirement obligations as of December 31, 2015. In addition to the contractual obligations disclosed above, we will incur additional operating costs and capital expenditures in future periods for which we are not contractually obligated as part of our normal business operations. Competition Our utility electric and natural gas distribution business has historically been recognized as a natural monopoly. In each regulatory jurisdiction, our rates for retail electric and natural gas services (other than specially negotiated retail rates for industrial or large commercial customers, which are subject to regulatory review and approval) are generally determined on a “cost of service” basis. Rates are designed to provide, after recovery of allowable operating expenses and capital investments, an opportunity for us to earn a reasonable return on investment as allowed by our regulators. In retail markets, we compete with various rural electric cooperatives and public utility districts in and adjacent to our service territories in the provision of service to new electric customers. Alternative energy technologies, including customer-sited solar, wind or geothermal generation, may also compete with us for sales to existing customers. While the risk is currently small in our service territory given the small numbers of customers utilizing these technologies, advances in power generation, energy efficiency and other alternative energy technologies could lead to more wide-spread usage of these technologies, thereby reducing customer demand for the energy supplied by us. This reduction in usage and demand would reduce our revenue and negatively impact our financial condition including possibly leading to our inability to fully recover our investments in generation, transmission and distribution assets. Similarly, our natural gas distribution operations compete with other energy sources including heating oil, propane and other fuels. Certain natural gas customers could bypass our natural gas system, reducing both revenues and recovery of fixed costs. To reduce the potential for such bypass, we price natural gas services, including transportation contracts, competitively and have varying degrees of flexibility to price transportation and delivery rates by means of individual contracts. These individual contracts are subject to state regulatory review and approval. We have long-term transportation contracts with several of our largest industrial customers under which the customer acquires its own commodity while using our infrastructure for delivery. Such contracts reduce the risk of these customers bypassing our system in the foreseeable future and minimizes the impact on our earnings. Also, non-utility businesses are developing new technologies and services to help energy consumers manage energy in new ways that may improve productivity and could alter demand for the energy we sell. In wholesale markets, competition for available electric supply is influenced by the: •localized and system-wide demand for energy, •type, capacity, location and availability of generation resources, and •variety and circumstances of market participants. These wholesale markets are regulated by the FERC, which requires electric utilities to: •transmit power and energy to or for wholesale purchasers and sellers, •enlarge or construct additional transmission capacity for the purpose of providing these services, and •transparently price and offer transmission services without favor to any party, including the merchant functions of the utility. Participants in the wholesale energy markets include: •other utilities, •federal power marketing agencies, •energy marketing and trading companies, •independent power producers, •financial institutions, and 66 Staff_DR_063 Attachment A Page 75 of 180 Table of Contents AVISTA CORPORATION •commodity brokers. Economic Conditions and Utility Load Growth The general economic data, on both national and local levels, contained in this section is based, in part, on independent government and industry publications, reports by market research firms or other independent sources. While we believe that these publications and other sources are reliable, we have not independently verified such data and can make no representation as to its accuracy. We track multiple economic indicators affecting three distinct metropolitan statistical areas in our Avista Utilities service area: Spokane, Washington, Coeur d'Alene, Idaho, and Medford, Oregon. Several key indicators are employment change, unemployment rates and foreclosure rates. On a year-over-year basis, December 2015 showed positive job growth, and lower unemployment rates in all three metropolitan areas. However, the unemployment rates in Spokane and Medford are still above the national average. Except for Medford, foreclosure rates are in line with or below the U.S rate in all areas, and key leading indicators, initial unemployment claims and residential building permits, continue to signal modest growth over the next 12 months. Therefore, in 2016, we expect economic growth in our service area to be somewhat stronger than the U.S. as a whole. Nonfarm employment (non-seasonally adjusted) in our eastern Washington, northern Idaho, and southwestern Oregon metropolitan service areas exhibited moderate growth between December 2014 and December 2015. In Spokane, Washington employment growth was 2.5 percent with gains in all major sectors except leisure and hospitality. Employment increased by 4.4 percent in Coeur d'Alene, Idaho, reflecting gains in all major sectors except information and leisure and hospitality. In Medford, Oregon, employment growth was 3.3 percent, with gains in all major sectors except construction. U.S. nonfarm sector jobs grew by 1.9 percent in the same 12-month period. Seasonally adjusted unemployment rates went down in December 2015 from the year earlier in Spokane, Coeur d'Alene, and Medford. In Spokane the rate was 7.7 percent in December 2014 and declined to 6.3 percent in December 2015; in Coeur d'Alene the rate went from 5.1 percent to 4.7 percent; and in Medford the rate declined from 8.2 percent to 6.5 percent. The U.S. rate declined from 5.6 percent to 5.0 percent in the same period. Except for the Medford area, the housing market in our Avista Utilities service area continues to experience foreclosure rates in line with the national average. The December 2015 national rate was 0.08 percent, compared to 0.08 percent in Spokane County, Washington; 0.04 percent in Kootenai County (Coeur d'Alene), Idaho; and 0.1 percent in Jackson County (Medford), Oregon. Our AEL&P service area is centered in Juneau. Although Juneau is Alaska’s state capital, it is not a metropolitan statistical area. This means breadth and frequency of economic data is more limited. Therefore, the dates of Juneau's economic data may significantly lag the period of this filing. The Quarterly Census of Employment and Wages for Juneau shows employment increased 0.5 percent between second quarter 2014 and second quarter 2015. The modest growth in employment was largely due to gains in construction; manufacturing; trade, transportation, and utilities; information; professional and business services; and leisure and hospitality, mostly offset by a contraction in government employment, which is Juneau's largest single sector. Government (including active duty military personnel) accounts for approximately 37 percent of total employment. Employment declines also occurred in natural resources and mining; financial activities; education and health services; and other services. Between December 2014 and December 2015 the non- seasonally adjusted unemployment rate decreased from 5.0 percent to 4.7 percent. The Juneau foreclosure rate is below the U.S. rate. The December 2015 rate was 0.02 percent compared to 0.08 percent for the U.S. Based on our forecast for 2016 through 2019 for Avista Utilities' service area, we expect annual electric customer growth to average 1.0 percent, within a forecast range of 0.6 percent to 1.4 percent. We expect annual natural gas customer growth to average 1.1 percent, within a forecast range of 0.6 percent to 1.6 percent. We anticipate retail electric load growth to average 0.7 percent, within a forecast range of 0.4 percent and 1.0 percent. We expect natural gas load growth to average 1.1 percent, within a forecast range of 0.6 percent and 1.6 percent. The forecast ranges reflect (1) the inherent uncertainty associated with the economic assumptions on which forecasts are based and (2) natural gas customer and load growth has been historically volatile. In AEL&P's service area, we expect annual residential customer growth to be in a narrow range around 0.4 percent for 2016 through 2019. We expect no significant growth in commercial and government customers over the same period. We anticipate that average annual total load growth will be in a narrow range around 0.6 percent, with residential load growth averaging 0.6 percent; commercial 0.8 percent; and government 0 percent (no load growth). 67 Staff_DR_063 Attachment A Page 76 of 180 Table of Contents AVISTA CORPORATION The forward-looking statements set forth above regarding retail load growth are based, in part, upon purchased economic forecasts and publicly available population and demographic studies. The expectations regarding retail load growth are also based upon various assumptions, including: •assumptions relating to weather and economic and competitive conditions, •internal analysis of company-specific data, such as energy consumption patterns, •internal business plans, •an assumption that we will incur no material loss of retail customers due to self-generation or retail wheeling, and •an assumption that demand for electricity and natural gas as a fuel for mobility will for now be immaterial. Changes in actual experience can vary significantly from our projections. Environmental Issues and Contingencies We are subject to environmental regulation by federal, state and local authorities. The generation, transmission, distribution, service and storage facilities in which we have ownership interests are designed and operated in compliance with applicable environmental laws. Furthermore, we conduct periodic reviews and audits of pertinent facilities and operations to ensure compliance and to respond to or anticipate emerging environmental issues. The Company's Board of Directors has established a committee to oversee environmental issues. We monitor legislative and regulatory developments at all levels of government for environmental issues, particularly those with the potential to impact the operation and productivity of our generating plants and other assets. Environmental laws and regulations may: •increase the operating costs of generating plants; •increase the lead time and capital costs for the construction of new generating plants; •require modification of our existing generating plants; •require existing generating plant operations to be curtailed or shut down; •reduce the amount of energy available from our generating plants; •restrict the types of generating plants that can be built or contracted with; and •require construction of specific types of generation plants at higher cost. Compliance with environmental laws and regulations could result in increases to capital expenditures and operating expenses. We intend to seek recovery of any such costs through the ratemaking process. Clean Air Act We must comply with the requirements under the Clean Air Act (CAA) in operating our thermal generating plants. The CAA currently requires a Title V operating permit for Colstrip (expires in 2017), Coyote Springs 2 (expires in 2018), the Kettle Falls GS (application has been made for a new permit), and the Rathdrum CT (application has been made for a new permit). Boulder Park GS, Northeast CT, and other activities only require minor source operating or registration permits based on their limited operation and emissions. The Title V operating permits are renewed every five years and updated to include newly applicable CAA requirements. We actively monitor legislative, regulatory and program developments within the CAA that may impact our facilities. On March 6, 2013, the Sierra Club and Montana Environmental Information Center, filed a Complaint (Complaint) in the United States District Court for the District of Montana, Billings Division, against the owners of Colstrip. The Complaint alleges certain violations of the CAA. See “Sierra Club and Montana Environmental Information Center Complaint Against the Owners of Colstrip” in “Note 19 of the Notes to Consolidated Financial Statements” for further information on this matter. Hazardous Air Pollutants (HAPs) The EPA regulates hazardous air pollutants from a published list of industrial sources referred to as "source categories" which must meet control technology requirements if they emit one or more of the pollutants in significant quantities. In 2012, the EPA finalized the Mercury Air Toxic Standards (MATS) for the coal and oil-fired source category. At the time of issuance in 2012, we examined the existing emission control systems of Colstrip Units 3 & 4, the only units in which we are a minority owner, and concluded that the existing emission control systems should be sufficient to meet mercury limits. 68 Staff_DR_063 Attachment A Page 77 of 180 Table of Contents AVISTA CORPORATION For the remaining portion of the rule that utilized Particulate Matter as a surrogate for air toxics (including metals and acid gases), the Colstrip owners reviewed recent stack testing data and expected that no additional emission control systems would be needed for Units 3 & 4 MATS compliance. On June 29, 2015, the Supreme Court held that the EPA's interpretation of MATS was unreasonable when it deemed cost irrelevant for MATS regulation. The EPA's interpretation of MATS has been reversed and remanded. Regional Haze Program The EPA set a national goal of eliminating man-made visibility degradation in Class I areas by the year 2064. States are expected to take actions to make “reasonable progress” through 10-year plans, including application of Best Available Retrofit Technology (BART) requirements. BART is a retrofit program applied to large emission sources, including electric generating units built between 1962 and 1977. In the case where a State opts out of implementing the Regional Haze program, the EPA may act directly. On September 18, 2012, the EPA finalized the Regional Haze federal implementation plan (FIP) for Montana. The FIP includes both emission limitations and pollution controls for Colstrip Units 1 & 2. Colstrip Units 3 & 4, the only units of which we are a minority owner, are not currently affected, but will be evaluated for Reasonable Progress at the next review period in September 2017. We do not anticipate any material impacts on Units 3 & 4 at this time. Coal Ash Management/Disposal On April 17, 2015, the EPA published a final rule regarding coal combustion residuals (CCRs), also termed coal combustion byproducts or coal ash in the Federal Register, and this rule became effective on October 15, 2015. Colstrip, of which we are a 15 percent owner of Units 3 and 4, produces this byproduct. The rule establishes technical requirements for CCR landfills and surface impoundments under Subtitle D of the Resource Conservation and Recovery Act, the nation's primary law for regulating solid waste. We, in conjunction with the other owners, are developing a multi-year compliance plan to strategically address the new CCR requirements and existing state obligations while maintaining operational stability. During the second quarter of 2015, the operator of Colstrip provided an initial cost estimate of the expected retirement costs associated with complying with the new CCR rule and this estimate was subsequently updated during the fourth quarter of 2015. Based on the initial assessments, Avista Corp. recorded an increase to its asset retirement obligations of $12.5 million with a corresponding increase in the cost basis of the utility plant. In addition to an increase to our ARO, there are expected to be significant compliance costs at Colstrip in the future, both operating and capital costs, due to a series of incremental infrastructure improvements which are separate from any retirement obligations. Due to the preliminary nature of available data, we cannot reasonably estimate the future compliance costs; however, we will update our ARO and compliance cost estimates when data becomes available. The actual asset retirement costs and future compliance costs related to the CCR Rule requirements may vary substantially from the estimates used to record the increased obligation due to uncertainty about the compliance strategies that will be used and the preliminary nature of available data used to estimate costs, such as the quantity of coal ash present at certain sites and the volume of fill that will be needed to cap and cover certain impoundments. We will coordinate with the plant operators and continue to gather additional data in future periods to make decisions about compliance strategies and the timing of closure activities. As additional information becomes available, we will update the ARO and future nonretirement compliance costs for these changes in estimates, which could be material. We expect to seek recovery of any increased costs related to complying with the new rule through customer rates. Climate Change Concerns about long-term global climate changes could have a significant effect on our business. Our operations could also be affected by changes in laws and regulations intended to mitigate the risk of or alter global climate changes, including restrictions on the operation of our power generation resources and obligations imposed on the sale of natural gas. Changing temperatures and precipitation, including snowpack conditions, affect the availability and timing of streamflows, which impact hydroelectric generation. Extreme weather events could increase service interruptions, outages and maintenance costs. Changing temperatures could also increase or decrease customer demand. Our Climate Policy Council (an interdisciplinary team of management and other employees): •facilitates internal and external communications regarding climate change issues, •analyzes policy effects, anticipates opportunities and evaluates strategies for Avista Corp., and •develops recommendations on climate related policy positions and action plans. 69 Staff_DR_063 Attachment A Page 78 of 180 Table of Contents AVISTA CORPORATION Climate Change - Federal Regulatory Actions The EPA released the final rules for the Clean Power Plan (Final CPP) and the Carbon Pollution Standards (Final CPS) on August 3, 2015. The Final CPP and the Final CPS are both intended to reduce the carbon dioxide (CO2) emissions from certain coal-fired and natural gas electric generating units (EGUs). These rules were published in the Federal Register on October 23, 2015 and were immediately challenged via lawsuits by other parties. The Final CPP was promulgated pursuant to Section 111(d) of the CAA and applies to CO2 emissions from existing EGUs. The Final CPP is intended to reduce national CO2 emissions by approximately 32 percent below 2005 levels by 2030. The Final CPS rule was issued pursuant to Section 111(b) of the CAA and applies to the emissions of new, modified and reconstructed EGUs. The two rules are the first rules ever adopted by the U.S. federal government to comprehensively control and reduce CO2 emissions from the power sector. The EPA also issued a proposed Federal Implementation Plan (Proposed FIP) for the Final CPP. The Final FIP that the EPA adopts could be imposed on states by the EPA, should a state decide not to develop its own plan. The Final CPP establishes individual state emission reduction goals based upon the assumed potential for (1) heat rate improvements at coal-fired units, (2) increased utilization of natural gas-fired combined cycle plants, and (3) increased utilization of low or zero carbon emitting generation resources. As expressed in the final rule, states have until September 2016 to submit state compliance plans, with a potential for two-year extensions. Avista Corp. owns two EGUs that are subject to the Final CPP: its portion (15 percent of Units 3 & 4) of Colstrip in Montana and Coyote Springs 2 in Oregon. States may adopt rate-based or mass-based plans, and may choose to focus compliance on specific EGUs or adopt broader measures to reduce carbon emissions from this sector. The states in which Avista Utilities generates or delivers electricity, Washington, Idaho, Montana and Oregon, are all evaluating options for developing state plans, which will define compliance approaches and obligations. Alaska was exempted in the Final CPP. The EPA may consider rulemaking for Alaska and Hawaii, both states which lack regional grid connections, in the future. In a separate but related rulemaking, the EPA finalized CO2 new source performance standards (NSPS) for new, modified and reconstructed fossil fuel- fired EGUs under CAA section 111(b). These EGUs fall into the same two categories of sources regulated by the Final CPP: steam generating units (also known as “utility boilers and IGCC units”), which primarily burn coal, and stationary combustion turbines, which primarily burn natural gas. GHG emission standards could result in significant compliance costs. Such standards could also preclude us from developing, operating or contracting with certain types of generating plants. Additionally, the Climate Action Plan requirements related to preparing the U.S. for the impacts of climate change could affect us and others in the industry as transmission system modifications to improve resiliency may be needed in order to meet those requirements. The promulgated and proposed GHG rulemakings mentioned above have been legally challenged in multiple venues. On February 9, 2016, the U.S. Supreme Court granted a request for stay, halting implementation of the CPP. Given this development and the ongoing legal challenges, we cannot fully predict the outcome or estimate the extent to which our facilities may be impacted by these regulations at this time. We intend to seek recovery of any costs related to compliance with these requirements through the ratemaking process. Climate Change - State Legislation and State Regulatory Activities The states of Washington and Oregon have adopted non-binding targets to reduce GHG emissions. Both states enacted their targets with an expectation of reaching the targets through a combination of renewable energy standards, and assorted “complementary policies,” but no specific reductions are mandated. Washington and Oregon apply a GHG emissions performance standard (EPS) to electric generation facilities used to serve retail loads in their jurisdictions. The EPS prevents utilities from constructing or purchasing generation facilities, or entering into power purchase agreements of five years or longer duration, to purchase energy produced by plants that have emission levels higher than 1,100 pounds of GHG per MWh. The Washington State Department of Commerce (Commerce) initiated a process to adopt a lower emissions performance standard in 2012, any new standard will be applicable until at least 2017. Commerce published a supplemental notice of proposed rulemaking on January 16, 2013 with a new EPS of 970 pounds of GHG per MWh. We will engage in the next process to revise the EPS, which should occur in 2017. The Energy Independence Act (EIA) in Washington requires electric utilities with over 25,000 customers to acquire qualified renewable energy resources and/or renewable energy credits equal to 15 percent of the utility's total retail load in 2020. I-937 also requires these utilities to meet biennial energy conservation targets beginning in 2012. The renewable energy standard increases from three percent in 2012 to nine percent in 2016. Failure to comply with renewable energy and efficiency standards could result in penalties of $50 per MWh or greater assessed against a utility for each MWh it is deficient in meeting a standard. We have met, and will continue to meet, the requirements of EIA through a variety of 70 Staff_DR_063 Attachment A Page 79 of 180 Table of Contents AVISTA CORPORATION renewable energy generating means, including, but not limited to, some combination of hydro upgrades, wind and biomass. In 2012, EIA was amended in such a way that our Kettle Falls GS and certain other biomass energy facilities, which commenced operation before March 31, 1999, are considered resources that may be used to meet the renewable energy standards beginning in 2016. The Washington State Department of Ecology (Ecology) has commenced rulemaking, using its existing authorities, to cap and reduce carbon emissions across the State of Washington in pursuit of the State’s carbon goals, which were enacted in 2008 by the Washington State Legislature (Legislature). The rule applies to sources of annual greenhouse emissions in excess of 100,000 tons for the first compliance period of 2017 through 2019; this threshold incrementally decreases to 70,000 metric tons beginning in 2035. The rule affects stationary sources and transportation fuel suppliers, as well as natural gas distribution companies. Ecology has identified approximately 30 entities responsible for 60 percent of the state’s emission sources that would be regulated under the proposed rule. The proposed rule would only apply to Avista Corp. as a natural gas distribution company, for the emissions associated with the use of the gas we provide our customers. The Governor of Washington ordered Ecology to finalize the rule by June 2016. An Initiative to the Legislature (I-732), which would impose a carbon tax on fossil-fueled generation and natural gas distribution, as well as on transportation fuels, has qualified for submittal to the Legislature. The Legislature may enact the measure into law, pass an alternative, in which case the original initiative and the alternative will be referred to the voters in November, or allow the measure to go onto the ballot in its original form. In addition, a coalition of environmental and labor groups in Washington announced its intent to file an initiative at the start of 2016 that would apply cap and trade regulation to sources of greenhouse gas emissions, with proceeds from the State's sale of compliance instruments (allowances) dedicated to clean-energy investments and other government programs. If filed and if it gains sufficient signatures, this initiative would go on the general ballot in 2016. While we cannot predict the eventual outcome of actions arising out of initiatives, proposed legislation and regulatory actions at this time nor estimate the effect thereof, we will continue to seek recovery, through the ratemaking process, of all operating and capitalized costs related to our utility operations. On February 6, 2014, the UTC issued a letter finding that Puget Sound Energy’s (PSE’s) 2013 Electric Integrated Resource Plan meets the requirements of the Revised Code of Washington and the Washington Administrative Code. In its letter, however, the UTC expressed concern regarding the continued operation of the Colstrip plant as a resource to serve retail customers. Although the UTC recognized that the results of the analyses presented by PSE “differed significantly between [Colstrip] Units 1 and 2 and Units 3 and 4,” the UTC did not limit its concerns solely to Colstrip Units 1 and 2. The UTC recommended that PSE “consult with UTC staff to consider a Colstrip Proceeding to determine the prudency of any new investment in Colstrip before it is made or, in the alternative, a closure or partial-closure plan.” As a 15 percent owner of Colstrip Units 3 and 4, we cannot estimate the effect of such proceeding, should it occur, on the future ownership and operation of our share of Colstrip Units 3 and 4. Our remaining investment in Colstrip Units 3 and 4 as of December 31, 2015 was $118.8 million. In Oregon, legislation has been introduced which would require Portland General Electric and Pacificorp to remove coal-fired generation from their rate- base by 2030. Because these two utilities, along with Avista Utilities, hold minority interests in Colstrip, the legislation could indirectly impact Avista Utilities, though specific impacts cannot be identified at this time. While the legislation requires the two utilities to eliminate Colstrip from their rates, they would be permitted to sell the output of their shares of Colstrip into the wholesale market or, as is the case with Pacificorp, reallocate the plant to other states. We cannot predict the eventual outcome of actions arising from this legislation at this time or estimate the effect thereof; however, we will continue to seek recovery, through the ratemaking process, of all operating and capitalized costs related to our generation assets. Threatened and Endangered Species and Wildlife A number of species of fish in the Northwest are listed as threatened or endangered under the Federal Endangered Species Act (ESA). Efforts to protect these and other species have not significantly impacted generation levels at any of our hydroelectric facilities. We are implementing fish protection measures at our hydroelectric project on the Clark Fork River under a 45-year FERC operating license for Cabinet Gorge and Noxon Rapids (issued March 2001) that incorporates a comprehensive settlement agreement. The restoration of native salmonid fish, including bull trout, is a key part of the agreement. The result is a collaborative native salmonid restoration program with the U.S. Fish and Wildlife Service, Native American tribes and the states of Idaho and Montana on the lower Clark Fork River, consistent with requirements of the FERC license. The U.S. Fish & Wildlife Service issued an updated Critical Habitat Designation for bull trout in 2010 that includes the lower Clark Fork River, as well as portions of the Coeur d'Alene basin within our Spokane River Project area, and issued a final Bull Trout Recovery Plan under the ESA. Issues related to these activities are expected to be resolved through the ongoing collaborative effort of our 71 Staff_DR_063 Attachment A Page 80 of 180 Table of Contents AVISTA CORPORATION Clark Fork and Spokane River FERC licenses. See “Fish Passage at Cabinet Gorge and Noxon Rapids” in “Note 19 of the Notes to Consolidated Financial Statements” for further information. Various statutory authorities, including the Migratory Bird Treaty Act, have established penalties for the unauthorized take of migratory birds. Because we operate facilities that can pose risks to a variety of such birds, we have developed and follow an avian protection plan. Other For other environmental issues and other contingencies see “Note 19 of the Notes to Consolidated Financial Statements.” Enterprise Risk Management The material risks to our businesses are discussed in "Item 1A. Risk Factors," "Forward-Looking Statements," as well as "Environmental Issues and Contingencies." The following discussion focuses on our mitigation processes and procedures to address these risks. We consider the management of these risks an integral part of managing our core businesses and a key element of our approach to corporate governance. Risk management includes identifying and measuring various forms of risk that may affect the Company. We have an enterprise risk management process for managing risks throughout our organization. Our Board of Directors and its Committees take an active role in the oversight of risk affecting the Company. Our risk management department facilitates the collection of risk information across the Company, providing senior management with a consolidated view of the Company’s major risks and risk mitigation measures. Each area identifies risks and implements the related mitigation measures. The enterprise risk process supports management in identifying, assessing, quantifying, managing and mitigating the risks. Despite all risk mitigation measures, however, risks are not eliminated. Our primary identified categories of risk exposure are: • Financial • Compliance • Utility regulatory • Technology • Energy commodity • Strategic • Operational • External Mandates Financial Risk Financial risk is any risk that could have a direct material impact on the financial performance or financial viability of the Company. Broadly, financial risks involve variation of earnings and liquidity. Underlying risks include, but are not limited to, those described in "Item 1A. Risk Factors." We mitigate financial risk in a variety of ways including through oversight from the Finance Committee of our Board of Directors and from senior management. Our Regulatory department is also critical in risk mitigation as they have regular communications with state commission regulators and staff and they monitor and develop rate strategies for the Company. Rate strategies, such as decoupling, help mitigate the impacts of revenue fluctuations due to weather, conservation or the economy. We also have a Treasury department that monitors our daily cash position and future cash flow needs, as well as monitoring market conditions to determine the appropriate course of action for capital financing and/or hedging strategies. Weather Risk To partially mitigate the risk of financial underperformance due to weather-related factors, we developed decoupling rate mechanisms that were approved by the Washington and Idaho commissions. Decoupling mechanisms are designed to break the link between a utility's revenues and consumers' energy usage and instead provide revenue based on the number of customers, thus mitigating a large portion of the risk associated with lower customer loads. See "Regulatory Matters" for further discussion of our decoupling mechanisms. Access to Capital Markets Our capital requirements rely to a significant degree on regular access to capital markets. We actively engage with rating agencies, banks, investors and state public utility commissions to understand and address the factors that support access to capital markets on reasonable terms. We manage our capital structure to maintain a financial risk profile that these parties will deem prudent. We forecast cash requirements to determine liquidity needs, including sources and variability of cash flows that may arise from our spending plans or from external forces, such as changes in energy prices or interest rates. Our financial and 72 Staff_DR_063 Attachment A Page 81 of 180 Table of Contents AVISTA CORPORATION operating forecasts consider various metrics that affect credit ratings. Our regulatory strategies include working with state public utility commissions and filing for rate changes as appropriate to meet financial performance expectations. Interest Rate Risk Uncertainty about future interest rates causes risk related to a portion of our existing debt, our future borrowing requirements, and our pension and other post- retirement benefit obligations. We manage debt interest rate exposure by limiting our variable rate debt to a percentage of total capitalization of the Company. We hedge a portion of our interest rate risk on forecasted debt issuances with financial derivative instruments, which may include interest rate swaps and U.S. Treasury lock agreements. The Finance Committee of our Board of Directors periodically reviews and discusses interest rate risk management processes and the steps management has undertaken to control interest rate risk. Our Risk Management Committee, which is comprised of certain officers and other management personnel, also reviews our interest rate risk management plan. Additionally, interest rate risk is managed by monitoring market conditions when timing the issuance of long-term debt and optional debt redemptions and establishing fixed rate long-term debt with varying maturities. Our interest rate swap agreements are considered economic hedges against fluctuations in future cash flows associated with anticipated debt issuances. Interest rates on our long-term debt are generally set based on underlying U.S. Treasury rates plus credit spreads, which are based on our credit ratings and prevailing market prices for debt. The swap agreements hedge against changes in the U.S. Treasury rates but do not hedge the credit spread. Even though we work to manage our exposure to interest rate risk by locking in certain long-term interest rates through interest rate swap agreements, if market interest rates decrease below the interest rates we have locked in, this will result in a liability related to our interest rate swap agreements, which can be significant. However, through our regulatory accounting practices similar to our energy commodity derivatives, any interim mark-to-market gains or losses are offset by regulatory assets and liabilities. Upon settlement of interest rate swaps, the regulatory asset or liability (included as part of long-term debt) is amortized as a component of interest expense over the term of the associated debt. The following table summarizes our interest rate swap agreements outstanding as of December 31, 2015 and December 31, 2014 (dollars in thousands): December 31, December 31, 2015 2014 Number of agreements 23 22 Notional amount $455,000 $420,000 Mandatory cash settlement dates 2016 to 2022 2015 to 2018 Short-term derivative assets (1)$— $460 Long-term derivative assets (1)23 — Short-term derivative liability (1)(19,264) (7,325) Long-term derivative liability (1) (2)(30,679) (40,857) (1)There are offsetting regulatory assets and liabilities for these items on the Consolidated Balance Sheets in accordance with regulatory accounting practices. (2)The balance as of December 31, 2015 and December 31, 2014 reflects the offsetting of $34.0 million and $28.9 million, respectively of cash collateral against the net derivative positions where a legal right of offset exists. In anticipation of issuing long-term debt in future years, we entered into three interest rate swap agreements in January 2016, hedging an aggregate notional amount of $30.0 million with mandatory cash settlement dates in 2018 and 2022. The following table shows our outstanding interest rate swaps as of February 23, 2016 (dollars in thousands): As of Date Number of Contracts Notional Amount Mandatory Cash Settlement Date February 23, 2016 6 115,000 2016 4 55,000 2017 13 265,000 2018 3 40,000 2019 4 50,000 2022 73 Staff_DR_063 Attachment A Page 82 of 180 Table of Contents AVISTA CORPORATION We estimate that a 10-basis-point increase in forward LIBOR interest rates as of December 31, 2015 would decrease the interest rate swap derivative net liability by $9.8 million, while a 10-basis-point decrease would increase the interest rate swap net liability by $10.1 million. We estimated that a 10-basis-point increase in forward LIBOR interest rates as of December 31, 2014 would have decreased the interest rate swap derivative net liability by $9.0 million, while a 10-basis-point decrease would increase the interest rate swap net liability by $9.3 million. The interest rate on $51.5 million of long-term debt to affiliated trusts is adjusted quarterly, reflecting current market rates. Amounts borrowed under our committed line of credit agreements have variable interest rates. Historically, during years where we have long-term debt that is maturing, we have to issue long-term debt to replace the maturing debt. To hedge our interest rate risk associated with these expected long-term debt issuances, we enter into interest rate swap agreements (discussed above). The following table shows our long-term debt (including current portion) and related weighted average interest rates, by expected maturity dates as of December 31, 2015 (dollars in thousands): 2016 2017 2018 2019 2020 Thereafter Total Fair Value Fixed rate long-term debt (1)$90,000 $— $272,500 $105,000 $52,000 $1,023,500 $1,543,000 $1,650,815 Weighted average interest rate 0.84% — 6.07% 5.22% 3.89% 5.15% 5.02% Variable rate long-term debt to affiliated trusts — — — — — $51,547 $51,547 $36,083 Weighted average interest rate — — — — — 1.29% 1.29% (1)These balances include the fixed rate long-term debt of Avista Corp., AEL&P and AERC. Our pension plan is exposed to interest rate risk because the value of pension obligations and other post-retirement obligations vary directly with changes in the discount rates, which are derived from end-of-year market interest rates. In addition, the value of pension investments and potential income on pension investments is partially affected by interest rates because a significant portion of pension investments are in fixed income securities. The Finance Committee of the Board of Directors approves investment policies, objectives and strategies that seek an appropriate return for the pension plan and it reviews and approves changes to the investment and funding policies. We manage interest rate risk associated with our pension and other post-retirement benefit plans by investing a targeted amount of pension plan assets in fixed income investments that have maturities with similar profiles to future projected benefit obligations. We have implemented a liability-driven investment process for the pension plan with the objective of enhancing the match between changes in pension investments and changes in pension obligations and reducing volatility of annual pension expense arising from changes in interest rates. Credit Risk Counterparty non-performance risk relates to potential losses that we would incur as a result of non-performance of contractual obligations by counterparties to deliver energy or make financial settlements. Changes in market prices may dramatically alter the size of credit risk with counterparties, even when we establish conservative credit limits. Should a counterparty fail to perform, we may be required to honor the underlying commitment or to replace existing contracts with contracts at then-current market prices. We enter into bilateral transactions with various counterparties. We also trade energy and related derivative instruments through clearinghouse exchanges. We seek to mitigate credit risk by: •transacting through clearinghouse exchanges, •entering into bilateral contracts that specify credit terms and protections against default, •applying credit limits and duration criteria to existing and prospective counterparties, •actively monitoring current credit exposures, 74 Staff_DR_063 Attachment A Page 83 of 180 Table of Contents AVISTA CORPORATION •asserting our collateral rights with counterparties, and •carrying out transaction settlements timely and effectively. The extent of transactions conducted through exchanges has increased as many market participants have shown a preference toward exchange trading and have reduced bilateral transactions. We actively monitor the collateral required by such exchanges to effectively manage our capital requirements. To address the impact on our operations of energy market price volatility, our hedging practices for electricity (including fuel for generation) and natural gas extend beyond the current operating year. Executing this extended hedging program may increase credit risk and demands for collateral. Our credit risk management process is designed to mitigate such credit risks through limit setting, contract protections and counterparty diversification, among other practices. Credit risk affects demands on our capital. We are subject to limits and credit terms that counterparties may assert to allow us to enter into transactions with them and maintain acceptable credit exposures. Many of our counterparties allow unsecured credit at limits prescribed by agreements or their discretion. Capital requirements for certain transaction types involve a combination of initial margin and market value margins without any unsecured credit threshold. Counterparties may seek assurances of performance from us in the form of letters of credit, prepayment or cash deposits. Credit exposure can change significantly in periods of commodity price and interest rate volatility. As a result, sudden and significant demands may be made against our credit facilities and cash. We actively monitor the exposure to possible collateral calls and take steps to minimize capital requirements. Counterparties’ credit exposure to us is dynamic in normal markets and may change significantly in more volatile markets. The amount of potential default risk to us from each counterparty depends on the extent of forward contracts, unsettled transactions, interest rates and market prices. There is a risk that we do not obtain sufficient additional collateral from counterparties that are unable or unwilling to provide it. As of December 31, 2015, we had cash deposited as collateral of $28.7 million and letters of credit of $28.2 million outstanding related to our energy derivative contracts. Price movements and/or a downgrade in our credit ratings could impact further the amount of collateral required. See “Credit Ratings” for further information. For example, in addition to limiting our ability to conduct transactions, if our credit ratings were lowered to below “investment grade” based on our positions outstanding at December 31, 2015, we would potentially be required to post additional collateral of up to $9.0 million. This amount is different from the amount disclosed in “Note 6 of the Notes to Consolidated Financial Statements” because, while this analysis includes contracts that are not considered derivatives in addition to the contracts considered in Note 6, this analysis also takes into account contractual threshold limits that are not considered in Note 6. Without contractual threshold limits, we would potentially be required to post additional collateral of $18.4 million. Under the terms of interest rate swap agreements that we enter into periodically, we may be required to post cash or letters of credit as collateral depending on fluctuations in the fair value of the instrument. As of December 31, 2015, we had interest rate swap agreements outstanding with a notional amount totaling $455.0 million and we had deposited cash in the amount of $34.0 million and letters of credit of $9.6 million as collateral for these interest rate swap derivative contracts. If our credit ratings were lowered to below “investment grade” based on our interest rate swap agreements outstanding at December 31, 2015, we would have to post $18.8 million of additional collateral. Foreign Currency Risk A significant portion of our utility natural gas supply (including fuel for electric generation) is obtained from Canadian sources. Most of those transactions are executed in U.S. dollars, which avoids foreign currency risk. A portion of our short-term natural gas transactions and long-term Canadian transportation contracts are committed based on Canadian currency prices. The short-term natural gas transactions are typically settled within sixty days with U.S. dollars. We economically hedge a portion of the foreign currency risk by purchasing Canadian currency exchange contracts when such commodity transactions are initiated. This risk has not had a material effect on our financial condition, results of operations or cash flows and these differences in cost related to currency fluctuations are included with natural gas supply costs for ratemaking. Further information for derivatives and fair values is disclosed at “Note 6 of the Notes to Consolidated Financial Statements” and “Note 16 of the Notes to Consolidated Financial Statements.” 75 Staff_DR_063 Attachment A Page 84 of 180 Table of Contents AVISTA CORPORATION Utility Regulatory Risk Because we are primarily a regulated utility, we face the risk that regulators may not grant rates that provide timely or sufficient recovery of our costs or allow a reasonable rate of return for our shareholders. This includes costs associated with our investment in rate base, as well as commodity costs and other operating and financing expenses. We mitigate regulatory risk through oversight from our Board of Directors and from senior management. We have a separate regulatory group which communicates with commission regulators and staff regarding the Company’s business plans and concerns. The regulatory group also considers the regulator’s priorities and rate policies and makes recommendations to senior management on regulatory strategy for the Company. See “Regulatory Matters” for further discussion of regulatory matters affecting our Company. Energy Commodity Risk Energy commodity risks are associated with fulfilling our obligation to serve customers, managing variability of energy facilities, rights and obligations and fulfilling the terms of our energy commodity agreements with counterparties. These risks include, among other things, those described in "Item 1A. Risk Factors." We mitigate energy commodity risk primarily through our energy resources risk policy, which includes oversight from the Risk Management Committee, which is comprised of certain officers and other management and oversight from the Audit Committee and the Environmental, Technology and Operations Committee of our Board of Directors. In conjunction with the oversight committees, our management team develops hedging strategies, detailed resource procurement plans, resource optimization strategies and long-term integrated resource planning to mitigate some of the risk associated with energy commodities. The various plans and strategies are monitored daily and developed with quantitative methods. Our energy resources risk policy, which includes our wholesale energy markets credit policy and control procedures to manage energy commodity price and credit risks. Nonetheless, adverse changes in commodity prices, generating capacity, customer loads, regulation and other factors may result in losses of earnings, cash flows and/or fair values. We measure the volume of monthly, quarterly and annual energy imbalances between projected power loads and resources. The measurement process is based on expected loads at fixed prices (including those subject to retail rates) and expected resources to the extent that costs are essentially fixed by virtue of known fuel supply costs or projected hydroelectric conditions. To the extent that expected costs are not fixed, either because of volume mismatches between loads and resources or because fuel cost is not locked in through fixed price contracts or derivative instruments, our risk policy guides the process to manage this open forward position over a period of time. Normal operations result in seasonal mismatches between power loads and available resources. We are able to vary the operation of generating resources to match parts of intra-hour, hourly, daily and weekly load fluctuations. We use the wholesale power markets, including the natural gas market as it relates to power generation fuel, to sell projected resource surpluses and obtain resources when deficits are projected. We buy and sell fuel for thermal generation facilities based on comparative power market prices and marginal costs of fueling and operating available generating facilities and the relative economics of substitute market purchases for generating plant operation. To address the impact on our operations of energy market price volatility, our hedging practices for electricity (including fuel for generation) and natural gas extend beyond the current operating year. Executing this extended hedging program may increase our credit risks. Our credit risk management process is designed to mitigate such credit risks through limit setting, contract protections and counterparty diversification, among other practices. Our projected retail natural gas loads and resources are regularly reviewed by operating management and the Risk Management Committee. To manage the impacts of volatile natural gas prices, we seek to procure natural gas through a diversified mix of spot market purchases and forward fixed price purchases from various supply basins and time periods. We have an active hedging program that extends several years into the future with the goal of reducing price volatility in our natural gas supply costs. We use natural gas storage capacity to support high demand periods and to procure natural gas when prices are likely to be seasonally lower. Securing prices throughout the year and even into subsequent years mitigates potential adverse impacts of significant purchase requirements in a volatile price environment. 76 Staff_DR_063 Attachment A Page 85 of 180 Table of Contents AVISTA CORPORATION The following table presents energy commodity derivative fair values as a net asset or (liability) as of December 31, 2015 that are expected to settle in each respective year (dollars in thousands): Purchases Sales Electric Derivatives Gas Derivatives Electric Derivatives Gas Derivatives Year Physical (1) Financial (1) Physical (1) Financial (1) Physical (1) Financial (1) Physical (1) Financial (1) 2016 $(6,928) $(14,988) $(5,895) $(41,006) $82 $28,857 $173 $22,445 2017 (6,403) 36 (1,050) (9,473) (23) 3,971 (1,125) 313 2018 (5,614) — — (3,554) (50) — (1,172) (162) 2019 (3,072) — (22) (1,964) (44) — (1,220) — 2020 — — 35 (18) — — (1,130) — Thereafter — — — — — — (679) — The following table presents energy commodity derivative fair values as a net asset or (liability) as of December 31, 2014 that are expected to settle in each respective year (dollars in thousands): Purchases Sales Electric Derivatives Gas Derivatives Electric Derivatives Gas Derivatives Year Physical (1) Financial (1) Physical (1) Financial (1) Physical (1) Financial (1) Physical (1) Financial (1) 2015 $(6,053) $(27,664) $(10,607) $(50,852) $17 $32,629 $1,228 $31,661 2016 (5,978) (5,124) (2,970) (19,381) (80) 13,126 (853) 10,170 2017 (4,657) — (355) (2,428) (117) 1,151 — 119 2018 (4,173) — — (389) (120) — — — 2019 (2,191) — — (147) (85) — — — Thereafter — — — — — — — — (1)Physical transactions represent commodity transactions where we will take delivery of either electricity or natural gas and financial transactions represent derivative instruments with no physical delivery, such as futures, swaps, options, or forward contracts. The above electric and natural gas derivative contracts will be included in either power supply costs or natural gas supply costs during the period they are delivered and will be included in the various recovery mechanisms (ERM, PCA, and PGAs), or in the general rate case process, and are expected to eventually be collected through retail rates from customers. See "Item 1. Business – Electric Operations," "Item 1. Business – Natural Gas Operations," and "Item 1A. Risk Factors" for additional discussion of the risks associated with Energy Commodities. Operational Risk Operational risk involves potential disruption, losses, or excess costs arising from external events or inadequate or failed internal processes, people and systems. Our operations are subject to operational and event risks that include, but are not limited to, those described in "Item 1A. Risk Factors." To manage operational and event risks, we maintain emergency operating plans, business continuity and disaster recovery plans, maintain insurance coverage against some, but not all, potential losses and seek to negotiate indemnification arrangements with contractors for certain event risks. In addition, we design and follow detailed vegetation management and asset management inspection plans, which help mitigate wildfire and storm event risks, as well as identify utility assets which may be failing and in need of repair or replacement. We also have an Emergency Operating Center, which is a team of employees that plan for and train to deal with potential emergencies or unplanned outages at our facilities, resulting from natural disasters or other events. To prevent unauthorized access to our facilities, we have both physical and cyber security in place. To address the risk related to fuel cost, availability and delivery restraints, we have an energy resources risk policy, which includes our wholesale energy markets credit policy and control procedures to manage energy commodity price and credit risks. Development of the energy resources risk policy includes planning for sufficient capacity to meet our customer and wholesale energy delivery obligations. See further discussion of the energy resources risk policy above. Oversight of the operational risk management process is performed by the Environmental, Technology and Operations Committee of our Board of Directors and from senior management with input from each operating department. 77 Staff_DR_063 Attachment A Page 86 of 180 Table of Contents AVISTA CORPORATION Compliance Risk Compliance risk is the potential consequences of legal or regulatory sanctions or penalties arising from the failure of the Company to comply with requirements of applicable laws, rules and regulations. We have extensive compliance obligations. Our primary compliance risks and obligations include, among others, those described in "Item 1A. Risk Factors." We mitigate compliance risk through oversight from the Environmental, Technology and Operations Committee and the Audit Committee of our Board of Directors and from senior management. We also have separate Regulatory and Environmental Compliance departments that monitor legislation, regulatory orders and actions to determine the overall potential impact to our Company and develop strategies for complying with the various rules and regulations. We also engage outside attorneys, and consultants, when necessary, to help ensure compliance with laws and regulations. See "Item 1. Business, Regulatory Issues" through "Item 1. Business, Reliability Standards" and “Environmental Issues and Contingencies” for further discussion of compliance issues that impact our Company. Technology Risk Our primary technology risks are described in "Item 1A. Risk Factors." We mitigate technology risk through trainings and exercises at all levels of the Company. The Environmental, Technology and Operations Committee of our Board of Directors along with senior management are regularly briefed on security policy, programs and incidents. Annual cyber and physical training and testing of employees are included in our enterprise security program as is business continuity testing and a data breach response exercises. Technology governance is led by senior management, which includes new technology strategy, risk planning and major project planning and approval. The technology project management office and enterprise capital planning group provide project cost, timeline and schedule oversight. In addition, there are independent third party audits of our critical infrastructure security program and our business risk security controls. We have a Technology department dedicated to securing, maintaining, evaluating and developing our information technology systems. There is regular training of the technology and security team. This group also evaluates the Company's technology for obsolescence and makes recommendations for upgrading or replacing systems as necessary. This group also monitors for intrusion and security events that may include a data breach. Strategic Risk Strategic risk relates to the potential impacts resulting from incorrect assumptions about external and internal factors, inappropriate business plans, ineffective business strategy execution, or the failure to respond in a timely manner to changes in the regulatory, macroeconomic or competitive environments. Our primary strategic risks include, among others, those described in "Item 1A. Risk Factors." We mitigate strategic risk through detailed oversight from the Board of Directors and from senior management. We also have a Chief Strategy Officer that heads a Strategic Initiatives department, to search for and evaluate opportunities for the Company and makes recommendations to senior management. The Strategic Initiatives department not only focuses on whether opportunities are financially viable, but also considers whether these opportunities fall within our core policies and our core business strategies. We mitigate our reputational risk primarily through a focus on adherence to our core policies, including our Code of Conduct, maintaining an appropriate Company culture and tone at the top, and through communication and engagement of our external stakeholders. External Mandates Risk External mandate risk involves forces outside the Company, which may include significant changes in customer expectations, disruptive technologies that result in obsolescence of our business model and government action that could impact the Company. See "Environmental Issues and Contingencies" and "Forward-Looking Statements" for a discussion of or reference to our external mandates risks. We mitigate external mandate risk through detailed oversight from the Environmental, Technology and Operations Committee of our Board of Directors and from senior management. We have a Climate Council which meets internally to assess the potential impacts of climate policy to our business and to identify strategies to plan for change. We also have employees dedicated to actively engage and monitor federal, state and local government positions and legislative actions that may affect us or our customers. 78 Staff_DR_063 Attachment A Page 87 of 180 Table of Contents AVISTA CORPORATION To prevent the threat of municipalization, we work to build strong relationships with the communities we serve through, among other things: •communication and involvement with local business leaders and community organizations, •providing customers with a multitude of limited income initiatives, including energy fairs, senior outreach and low income workshops, mobile outreach strategy and a Low Income Rate Assistance Plan, •tailoring our internal company initiatives to focus on choices for our customers, to increase their overall satisfaction with the Company, and •engaging in the legislative process in a manner that fosters the interests of our customers and the communities we serve. ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK The information required by this item is set forth in the Enterprise Risk Management section of "Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations" and is incorporated herein by reference. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA The Report of Independent Registered Public Accounting Firm and Financial Statements begin on the next page. 79 Staff_DR_063 Attachment A Page 88 of 180 Table of Contents REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors and Shareholders of Avista Corporation Spokane, Washington We have audited the accompanying consolidated balance sheets of Avista Corporation and subsidiaries (the “Company”) as of December 31, 2015 and 2014, and the related consolidated statements of income, comprehensive income, equity and redeemable noncontrolling interests, and cash flows for each of the three years in the period ended December 31, 2015. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Avista Corporation and subsidiaries at December 31, 2015 and 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015, in conformity with accounting principles generally accepted in the United States of America. We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2015, based on the criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report, dated February 23, 2016 expressed an unqualified opinion on the Company’s internal control over financial reporting. /s/ Deloitte & Touche LLP Seattle, Washington February 23, 2016 80 Staff_DR_063 Attachment A Page 89 of 180 Table of Contents CONSOLIDATED STATEMENTS OF INCOME Avista Corporation For the Years Ended December 31 Dollars in thousands, except per share amounts 2015 2014 2013 Operating Revenues: Utility revenues $1,456,091 $1,433,343 $1,402,195 Non-utility revenues 28,685 39,219 39,549 Total operating revenues 1,484,776 1,472,562 1,441,744 Operating Expenses: Utility operating expenses: Resource costs 656,964 678,244 689,586 Other operating expenses 303,221 286,832 276,228 Depreciation and amortization 143,499 129,570 117,174 Taxes other than income taxes 97,657 94,300 88,435 Non-utility operating expenses: Other operating expenses 29,526 30,418 38,651 Depreciation and amortization 695 610 581 Total operating expenses 1,231,562 1,219,974 1,210,655 Income from operations 253,214 252,588 231,089 Interest expense 79,968 75,302 77,118 Interest expense to affiliated trusts 473 450 467 Capitalized interest (3,546) (3,924) (3,676) Other income-net (9,300) (11,346) (5,167) Income from continuing operations before income taxes 185,619 192,106 162,347 Income tax expense 67,449 72,240 58,014 Net income from continuing operations 118,170 119,866 104,333 Net income from discontinued operations (Note 5)5,147 72,411 7,961 Net income 123,317 192,277 112,294 Net income attributable to noncontrolling interests (90) (236) (1,217) Net income attributable to Avista Corp. shareholders $123,227 $192,041 $111,077 The Accompanying Notes are an Integral Part of These Statements. 81 Staff_DR_063 Attachment A Page 90 of 180 Table of Contents CONSOLIDATED STATEMENTS OF INCOME (continued) Avista Corporation For the Years Ended December 31 Dollars in thousands, except per share amounts 2015 2014 2013 Amounts attributable to Avista Corp. shareholders: Net income from continuing operations $118,080 $119,817 $104,273 Net income from discontinued operations 5,147 72,224 6,804 Net income attributable to Avista Corp. shareholders $123,227 $192,041 $111,077 Weighted-average common shares outstanding (thousands), basic 62,301 61,632 59,960 Weighted-average common shares outstanding (thousands), diluted 62,708 61,887 59,997 Earnings per common share attributable to Avista Corp. shareholders, basic: Earnings per common share from continuing operations $1.90 $1.94 $1.74 Earnings per common share from discontinued operations 0.08 1.18 0.11 Total earnings per common share attributable to Avista Corp. shareholders, basic $1.98 $3.12 $1.85 Earnings per common share attributable to Avista Corp. shareholders, diluted: Earnings per common share from continuing operations $1.89 $1.93 $1.74 Earnings per common share from discontinued operations 0.08 1.17 0.11 Total earnings per common share attributable to Avista Corp. shareholders, diluted $1.97 $3.10 $1.85 The Accompanying Notes are an Integral Part of These Statements. 82 Staff_DR_063 Attachment A Page 91 of 180 Table of Contents CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME Avista Corporation For the Years Ended December 31 Dollars in thousands 2015 2014 2013 Net income $123,317 $192,277 $112,294 Other Comprehensive Income (Loss): Unrealized investment gains/(losses) - net of taxes of $0, $664 and $(1,026), respectively — 1,126 (1,741) Reclassification adjustment for realized gains on investment securities included in net income - net of taxes of $0, $(1) and $(7), respectively — (2) (12) Reclassification adjustment for realized losses on investment securities included in net income from discontinued operations - net of taxes of $0, $273 and $0, respectively — 462 — Change in unfunded benefit obligation for pension and other postretirement benefit plans - net of taxes of $667, $(1,967) and $1,418, respectively 1,238 (3,655) 2,634 Total other comprehensive income (loss)1,238 (2,069) 881 Comprehensive income 124,555 190,208 113,175 Comprehensive income attributable to noncontrolling interests (90) (236) (1,217) Comprehensive income attributable to Avista Corporation shareholders $124,465 $189,972 $111,958 The Accompanying Notes are an Integral Part of These Statements. 83 Staff_DR_063 Attachment A Page 92 of 180 Table of Contents CONSOLIDATED BALANCE SHEETS Avista Corporation As of December 31 Dollars in thousands 2015 2014 Assets: Current Assets: Cash and cash equivalents $10,484 $22,143 Accounts and notes receivable-less allowances of $4,530 and $4,888, respectively 169,413 171,925 Utility energy commodity derivative assets 683 1,525 Regulatory asset for utility derivatives 17,260 29,640 Materials and supplies, fuel stock and stored natural gas 54,148 66,356 Deferred income taxes — 14,794 Income taxes receivable 24,121 43,893 Other current assets 29,937 45,071 Total current assets 306,046 395,347 Net Utility Property: Utility plant in service 5,129,192 4,718,062 Construction work in progress 202,683 227,758 Total 5,331,875 4,945,820 Less: Accumulated depreciation and amortization 1,433,286 1,325,858 Total net utility property 3,898,589 3,619,962 Other Non-current Assets: Investment in exchange power-net 8,983 11,433 Investment in affiliated trusts 11,547 11,547 Goodwill 57,672 57,976 Long-term energy contract receivable 14,694 28,202 Other property and investments-net 50,750 42,016 Total other non-current assets 143,646 151,174 Deferred Charges: Regulatory assets for deferred income tax 101,240 100,412 Regulatory assets for pensions and other postretirement benefits 235,009 235,758 Other regulatory assets 99,798 91,920 Regulatory asset for unsettled interest rate swaps 83,973 77,063 Non-current regulatory asset for utility derivatives 32,420 24,483 Other deferred charges 5,928 4,852 Total deferred charges 558,368 534,488 Total assets $4,906,649 $4,700,971 The Accompanying Notes are an Integral Part of These Statements. 84 Staff_DR_063 Attachment A Page 93 of 180 Table of Contents CONSOLIDATED BALANCE SHEETS (continued) Avista Corporation As of December 31 Dollars in thousands 2015 2014 Liabilities and Equity: Current Liabilities: Accounts payable $114,349 $112,974 Current portion of long-term debt and capital leases 93,167 6,424 Current portion of nonrecourse long-term debt of Spokane Energy — 1,431 Short-term borrowings 105,000 105,000 Utility energy commodity derivative liabilities 14,268 18,045 Other current liabilities 147,896 141,395 Total current liabilities 474,680 385,269 Long-term debt and capital leases 1,480,111 1,480,702 Long-term debt to affiliated trusts 51,547 51,547 Regulatory liability for utility plant retirement costs 261,594 254,140 Pensions and other postretirement benefits 201,453 189,489 Deferred income taxes 747,477 710,342 Other non-current liabilities and deferred credits 161,500 146,240 Total liabilities 3,378,362 3,217,729 Commitments and Contingencies (See Notes to Consolidated Financial Statements) Equity: Avista Corporation Shareholders’ Equity: Common stock, no par value; 200,000,000 shares authorized; 62,312,651 and 62,243,374 shares issued and outstanding as of December 31, 2015 and December 31, 2014, respectively 1,004,336 999,960 Accumulated other comprehensive loss (6,650) (7,888) Retained earnings 530,940 491,599 Total Avista Corporation shareholders’ equity 1,528,626 1,483,671 Noncontrolling Interests (339) (429) Total equity 1,528,287 1,483,242 Total liabilities and equity $4,906,649 $4,700,971 The Accompanying Notes are an Integral Part of These Statements. 85 Staff_DR_063 Attachment A Page 94 of 180 Table of Contents CONSOLIDATED STATEMENTS OF CASH FLOWS Avista Corporation For the Years Ended December 31 Dollars in thousands 2015 2014 2013 Operating Activities: Net income $123,317 $192,277 $112,294 Non-cash items included in net income: Depreciation and amortization 147,835 138,337 133,189 Provision for deferred income taxes 51,801 144,269 23,532 Power and natural gas cost amortizations (deferrals), net 21,358 (14,821) (9,408) Amortization of debt expense 3,526 3,692 3,813 Amortization of investment in exchange power 2,450 2,450 2,450 Stock-based compensation expense 6,914 8,114 6,218 Equity-related AFUDC (8,331) (8,808) (6,066) Pension and other postretirement benefit expense 37,050 22,943 42,067 Amortization of Spokane Energy contract 13,508 12,417 11,414 Write-off of wind generation capitalized costs — — 2,534 Gain on sale of Ecova (777) (160,612) — Other (6,881) 9,009 12,982 Contributions to defined benefit pension plan (12,000) (32,000) (44,263) Changes in certain current assets and liabilities: Accounts and notes receivable (10,538) 16,425 (32,675) Materials and supplies, fuel stock and stored natural gas 12,208 (19,394) 2,509 Increase in collateral posted for derivative instruments (13,301) (23,301) (16,073) Income taxes receivable 19,772 (36,110) (5,006) Other current assets 2,338 (7,117) 2,608 Accounts payable (8,138) (12,562) (8,389) Other current liabilities (6,471) 32,060 8,827 Net cash provided by operating activities 375,640 267,268 242,557 Investing Activities: Utility property capital expenditures (excluding equity-related AFUDC)(393,425) (325,516) (294,363) Other capital expenditures (885) (6,427) (8,750) Federal and state grant payments received 2,730 2,530 3,409 Cash received (paid) in acquisition, net (95) 15,007 — Decrease (increase) in funds held for clients — (18,931) 1,815 Purchase of securities available for sale — (12,267) (35,949) Sale and maturity of securities available for sale — 14,612 22,960 Proceeds from sale of Ecova, net of cash sold 13,856 229,903 — Other (10,008) (2,647) (1,339) Net cash used in investing activities $(387,827) $(103,736) $(312,217) The Accompanying Notes are an Integral Part of These Statements. 86 Staff_DR_063 Attachment A Page 95 of 180 Table of Contents CONSOLIDATED STATEMENTS OF CASH FLOWS (continued) Avista Corporation For the Years Ended December 31 Dollars in thousands 2015 2014 2013 Financing Activities: Net increase (decrease) in short-term borrowings $— $(66,000) $119,000 Borrowings from Ecova line of credit — — 3,000 Repayment of borrowings from Ecova line of credit — (46,000) (11,000) Proceeds from issuance of long-term debt 100,000 150,000 90,000 Redemption and maturity of long-term debt and capital leases (2,905) (39,971) (50,462) Maturity of nonrecourse long-term debt of Spokane Energy (1,431) (16,407) (14,965) Cash received (paid) for settlement of interest rate swap agreements (9,326) 5,429 2,901 Issuance of common stock, net of issuance costs 1,560 4,060 4,609 Repurchase of common stock (2,920) (79,856) — Cash dividends paid (82,397) (78,314) (73,276) Increase in client fund obligations — 16,216 11,278 Payment to noncontrolling interests for sale of Ecova — (54,179) — Payment to option holders and redeemable noncontrolling interests for sale of Ecova — (20,871) — Other (2,053) 1,930 (4,315) Net cash provided by (used in) financing activities 528 (223,963) 76,770 Net increase (decrease) in cash and cash equivalents (11,659) (60,431) 7,110 Cash and cash equivalents at beginning of year 22,143 82,574 75,464 Cash and cash equivalents at end of year $10,484 $22,143 $82,574 Supplemental Cash Flow Information: Cash paid (received) during the year: Interest $79,673 $73,526 $75,411 Income taxes (net of total refunds of $37,200, $35,573 and $123, respectively)(9,961) 45,416 44,772 Non-cash financing and investing activities: Accounts payable for capital expenditures 35,248 26,959 12,723 Valuation adjustment for redeemable noncontrolling interests — (15,873) 10,704 Receivable for escrow amounts associated with the sale of Ecova — 13,079 — Non-cash stock issuance for acquisition of AERC — 150,119 — The Accompanying Notes are an Integral Part of These Statements. 87 Staff_DR_063 Attachment A Page 96 of 180 Table of Contents CONSOLIDATED STATEMENTS OF EQUITY AND REDEEMABLE NONCONTROLLING INTERESTS Avista Corporation For the Years Ended December 31 Dollars in thousands 2015 2014 2013 Common Stock, Shares: Shares outstanding at beginning of year 62,243,374 60,076,752 59,812,796 Shares issued through equity compensation plans 125,620 51,127 58,002 Shares issued through Employee Investment Plan (401-K)33,057 33,168 42,073 Shares issued through Dividend Reinvestment Plan — 110,501 163,881 Shares issued for acquisition — 4,501,441 — Shares repurchased (89,400) (2,529,615) — Shares outstanding at end of year 62,312,651 62,243,374 60,076,752 Common Stock, Amount: Balance at beginning of year $999,960 $896,993 $889,237 Equity compensation expense 6,035 7,676 6,002 Issuance of common stock through equity compensation plans 462 108 (1,342) Issuance of common stock through Employee Investment Plan (401-K)1,099 1,005 1,127 Issuance of common stock through Dividend Reinvestment Plan — 3,441 4,360 Issuance of common stock for acquisition, net of issuance costs — 149,625 — Payment of minimum tax withholdings for share-based payment awards (1,832) — — Repurchase of common stock (1,431) (40,486) — Equity transactions of consolidated subsidiaries — (1,062) (3,007) Payment to option holders and redeemable noncontrolling interests for sale of Ecova — (20,871) — Excess tax benefits 43 3,531 616 Balance at end of year 1,004,336 999,960 896,993 Accumulated Other Comprehensive Loss: Balance at beginning of year (7,888) (5,819) (6,700) Other comprehensive income (loss)1,238 (2,069) 881 Balance at end of year (6,650) (7,888) (5,819) Retained Earnings: Balance at beginning of year 491,599 407,092 376,940 Net income attributable to Avista Corporation shareholders 123,227 192,041 111,077 Cash dividends paid (common stock)(82,397) (78,314) (73,276) Repurchase of common stock (1,489) (39,370) — Valuation adjustments and other noncontrolling interests activity — 10,150 (7,649) Balance at end of year 530,940 491,599 407,092 Total Avista Corporation shareholders’ equity $1,528,626 $1,483,671 $1,298,266 The Accompanying Notes are an Integral Part of These Statements. 88 Staff_DR_063 Attachment A Page 97 of 180 Table of Contents CONSOLIDATED STATEMENTS OF EQUITY AND REDEEMABLE NONCONTROLLING INTERESTS (continued) Avista Corporation For the Years Ended December 31 Dollars in thousands 2015 2014 2013 Noncontrolling Interests: Balance at beginning of year $(429) $20,001 $17,658 Net income attributable to noncontrolling interests 90 240 1,066 Issuance of subsidiary noncontrolling interests — — 480 Purchase of subsidiary noncontrolling interests — — (4,182) Deconsolidation of noncontrolling interests related to sale of Ecova — (23,612) — Other — 2,942 4,979 Balance at end of year (339) (429) 20,001 Total equity $1,528,287 $1,483,242 $1,318,267 Redeemable Noncontrolling Interests: Balance at beginning of year $— $15,889 $4,938 Net income attributable to noncontrolling interests — (4) 151 Purchase of subsidiary noncontrolling interests — (12) (405) Valuation adjustments and other noncontrolling interests activity — (15,873) 11,205 Balance at end of year $— $— $15,889 The Accompanying Notes are an Integral Part of These Statements. 89 Staff_DR_063 Attachment A Page 98 of 180 Table of Contents AVISTA CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Nature of Business Avista Corp. is primarily an electric and natural gas utility with certain other business ventures. Avista Utilities is an operating division of Avista Corp., comprising the regulated utility operations in the Pacific Northwest. Avista Utilities provides electric distribution and transmission, and natural gas distribution services in parts of eastern Washington and northern Idaho. Avista Utilities also provides natural gas distribution service in parts of northeastern and southwestern Oregon. Avista Utilities has electric generating facilities in Washington, Idaho, Oregon and Montana. Avista Utilities also supplies electricity to a small number of customers in Montana, most of whom are employees who operate Avista Utilities' Noxon Rapids generating facility. On July 1, 2014, Avista Corp. acquired AERC, and as of that date, AERC became a wholly-owned subsidiary of Avista Corp. The primary subsidiary of AERC is AEL&P, comprising regulated electric utility operations in Juneau, Alaska. There are no AERC earnings included in the overall results of Avista Corp. prior to July 1, 2014. See Note 4 for information regarding the acquisition of AERC. Avista Capital, a wholly owned subsidiary of Avista Corp., is the parent company of all of the subsidiary companies in the non-utility businesses. During the first half of 2014 and prior, Avista Capital’s subsidiaries included Ecova, which was an 80.2 percent owned subsidiary prior to its disposition on June 30, 2014. Ecova was a provider of energy efficiency and other facility information and cost management programs and services for multi-site customers and utilities throughout North America. See Note 5 for information regarding the disposition of Ecova and Note 21 for business segment information. Basis of Reporting The consolidated financial statements include the assets, liabilities, revenues and expenses of the Company and its subsidiaries and other majority owned subsidiaries and variable interest entities for which the Company or its subsidiaries are the primary beneficiaries. Ecova's revenues and expenses are included in the Consolidated Statements of Income in discontinued operations; however, as of June 30, 2014 and for all subsequent reporting periods there are no balance sheet amounts included for Ecova. All tables throughout the Notes to Consolidated Financial Statements that present Consolidated Statements of Income information were revised to include only the amounts from continuing operations. Intercompany balances were eliminated in consolidation. The accompanying consolidated financial statements include the Company’s proportionate share of utility plant and related operations resulting from its interests in jointly owned plants (see Note 7). Use of Estimates The preparation of the consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported for assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Significant estimates include: •determining the market value of energy commodity derivative assets and liabilities, •pension and other postretirement benefit plan obligations, •contingent liabilities, •goodwill impairment testing, •recoverability of regulatory assets, and •unbilled revenues. Changes in these estimates and assumptions are considered reasonably possible and may have a material effect on the consolidated financial statements and thus actual results could differ from the amounts reported and disclosed herein. System of Accounts The accounting records of the Company’s utility operations are maintained in accordance with the uniform system of accounts prescribed by the FERC and adopted by the state regulatory commissions in Washington, Idaho, Montana, Oregon and Alaska. 90 Staff_DR_063 Attachment A Page 99 of 180 Table of Contents AVISTA CORPORATION Regulation The Company is subject to state regulation in Washington, Idaho, Montana, Oregon and Alaska. The Company is also subject to federal regulation primarily by the FERC, as well as various other federal agencies with regulatory oversight of particular aspects of its operations. Utility Revenues Utility revenues related to the sale of energy are recorded when service is rendered or energy is delivered to customers. Revenues and resource costs from Avista Utilities’ settled energy contracts that are “booked out” (not physically delivered) are reported on a net basis as part of utility revenues. AEL&P does not have booked out transactions. The determination of the energy sales to individual customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each calendar month, the amount of energy delivered to customers since the date of the last meter reading is estimated and the corresponding unbilled revenue is estimated and recorded. Our estimate of unbilled revenue is based on: •the number of customers, •current rates, •meter reading dates, •actual native load for electricity, •actual throughput for natural gas, and •electric line losses and natural gas system losses. Any difference between actual and estimated revenue is automatically corrected in the following month when the actual meter reading and customer billing occurs. Accounts receivable includes unbilled energy revenues of the following amounts as of December 31 (dollars in thousands): 2015 2014 Unbilled accounts receivable $62,003 $80,718 Other Non-Utility Revenues Revenues from the other businesses are primarily derived from the operations of AM&D, doing business as METALfx, and are recognized when the risk of loss transfers to the customer, which occurs when products are shipped. In addition, prior to Spokane Energy's dissolution in 2015, there were revenues at Spokane Energy related to a long-term fixed rate electric capacity contract. This contract was transferred to Avista Corp. during the second quarter of 2015 and the revenues from this contract are now included in utility revenues. Depreciation For utility operations, depreciation expense is estimated by a method of depreciation accounting utilizing composite rates for utility plant. Such rates are designed to provide for retirements of properties at the expiration of their service lives. For utility operations, the ratio of depreciation provisions to average depreciable property was as follows for the years ended December 31: 2015 2014 2013 Avista Utilities Ratio of depreciation to average depreciable property 3.09% 2.97% 2.90% Alaska Electric Light and Power Company Ratio of depreciation to average depreciable property 2.42% 2.43% N/A 91 Staff_DR_063 Attachment A Page 100 of 180 Table of Contents AVISTA CORPORATION The average service lives for the following broad categories of utility plant in service are (in years): Avista Utilities Alaska Electric Light and Power Company Electric thermal/other production 40 36 Hydroelectric production 79 45 Electric transmission 57 39 Electric distribution 36 38 Natural gas distribution property 45 N/A Taxes Other Than Income Taxes Taxes other than income taxes include state excise taxes, city occupational and franchise taxes, real and personal property taxes and certain other taxes not based on net income. These taxes are generally based on revenues or the value of property. Utility related taxes collected from customers (primarily state excise taxes and city utility taxes) are recorded as operating revenue and expense and totaled the following amounts for the years ended December 31 (dollars in thousands): 2015 2014 2013 Utility taxes $59,173 $58,250 $55,565 Allowance for Funds Used During Construction The AFUDC represents the cost of both the debt and equity funds used to finance utility plant additions during the construction period. As prescribed by regulatory authorities, AFUDC is capitalized as a part of the cost of utility plant and the debt component is credited against total interest expense in the Consolidated Statements of Income in the line item “capitalized interest.” The equity component of AFUDC is included in the Consolidated Statement of Income in the line item “other income-net.” The Company is permitted, under established regulatory rate practices, to recover the capitalized AFUDC, and a reasonable return thereon, through its inclusion in rate base and the provision for depreciation after the related utility plant is placed in service. Cash inflow related to AFUDC does not occur until the related utility plant is placed in service and included in rate base. The effective AFUDC rate was the following for the years ended December 31: 2015 2014 2013 Avista Utilities Effective AFUDC rate 7.32% 7.64% 7.64% Alaska Electric Light and Power Company Effective AFUDC rate 9.31% 10.37% N/A Income Taxes A deferred income tax asset or liability is determined based on the enacted tax rates that will be in effect when the differences between the financial statement carrying amounts and tax basis of existing assets and liabilities are expected to be reported in the Company’s consolidated income tax returns. The deferred income tax expense for the period is equal to the net change in the deferred income tax asset and liability accounts from the beginning to the end of the period. The effect on deferred income taxes from a change in tax rates is recognized in income in the period that includes the enactment date. Deferred income tax liabilities and regulatory assets are established for income tax benefits flowed through to customers. The Company recognizes the effect of state tax credits, which are generated from utility plant, as they are utilized. The Company did not incur any penalties on income tax positions in 2015, 2014 or 2013. The Company would recognize interest accrued related to income tax positions as interest expense and any penalties incurred as other operating expense. Stock-Based Compensation The Company currently issues three types of stock-based compensation awards - restricted shares, market-based awards and performance-based awards. Historically, these stock compensation awards have not been material to the Company's overall financial results. Compensation cost relating to share-based payment transactions is recognized in the Company’s financial statements based on the fair value of the equity or liability instruments issued and recorded over the requisite service period. 92 Staff_DR_063 Attachment A Page 101 of 180 Table of Contents AVISTA CORPORATION The Company recorded stock-based compensation expense (included in other operating expenses) and income tax benefits in the Consolidated Statements of Income of the following amounts for the years ended December 31 (dollars in thousands): 2015 2014 2013 Stock-based compensation expense $6,914 $6,007 $5,037 Income tax benefits 2,420 2,102 1,763 Restricted share awards vest in equal thirds each year over a three-year period and are payable in Avista Corp. common stock at the end of each year if the service condition is met. In addition to the service condition, the Company must meet a return on equity target in order for the CEO’s restricted shares to vest. Restricted stock is valued at the close of market of the Company’s common stock on the grant date. Total Shareholder Return (TSR) awards are market-based awards and Cumulative Earnings Per Share (CEPS) awards are performance awards. CEPS awards were first granted in 2014. Both types of awards vest after a period of three years and are payable in cash or Avista Corp. common stock at the end of the three-year period. The method of settlement is at the discretion of the Company and historically the Company has settled these awards through issuance of Avista Corp. common stock and intends to continue this practice. Both types of awards entitle the recipients to dividend equivalent rights, are subject to forfeiture under certain circumstances, and are subject to meeting specific market or performance conditions. Based on the level of attainment of the market or performance conditions, the amount of cash paid or common stock issued will range from 0 to 200 percent of the initial awards granted. Dividend equivalent rights are accumulated and paid out only on shares that eventually vest and have met the market and performance conditions. For both the TSR awards and the CEPS awards, the Company accounts for them as equity awards and compensation cost for these awards is recognized over the requisite service period, provided that the requisite service period is rendered. For TSR awards, if the market-condition is not met at the end of the three- year service period, there will be no change in the cumulative amount of compensation cost recognized, since the awards are still considered vested even though the market metric was not met. For CEPS awards, at the end of the three-year service period, if the internal performance metric of cumulative earnings per share is not met, all compensation cost for these awards is reversed as these awards are not considered vested. The fair value of each TSR award is estimated on the date of grant using a statistical model that incorporates the probability of meeting the market targets based on historical returns relative to a peer group. The estimated fair value of the equity component of CEPS awards was estimated on the date of grant as the share price of Avista Corp. common stock on the date of grant, less the net present value of the estimated dividends over the three-year period. The following table summarizes the number of grants, vested and unvested shares, earned shares (based on market metrics), and other pertinent information related to the Company's stock compensation awards for the years ended December 31: 2015 2014 2013 Restricted Shares Shares granted during the year 58,302 62,075 44,556 Shares vested during the year (60,379) (52,899) (55,456) Unvested shares at end of year 106,091 112,042 104,416 Unrecognized compensation expense at end of year (in thousands)$1,705 $1,349 $1,199 TSR Awards TSR shares granted during the year 116,435 117,550 175,000 TSR shares vested during the year (171,334) (167,584) (176,718) TSR shares earned based on market metrics 222,734 97,199 — Unvested TSR shares at end of year 223,697 287,834 344,684 Unrecognized compensation expense (in thousands)$3,219 $2,833 $3,651 CEPS Awards CEPS shares granted during the year 58,259 59,025 — Unvested CEPS shares at end of year 111,887 58,017 — Unrecognized compensation expense (in thousands)$1,840 $1,577 $— Outstanding TSR and CEPS share awards include a dividend component that is paid in cash. This component of the share grants is accounted for as a liability award. These liability awards are revalued on a quarterly basis taking into account the number of awards outstanding, historical dividend rate, the change in the value of the Company’s common stock relative to an external benchmark (TSR awards only) and the amount of CEPS earned to-date compared to estimated CEPS over the 93 Staff_DR_063 Attachment A Page 102 of 180 Table of Contents AVISTA CORPORATION performance period (CEPS awards only). Over the life of these awards, the cumulative amount of compensation expense recognized will match the actual cash paid. As of December 31, 2015 and 2014, the Company had recognized cumulative compensation expense and a liability of $1.5 million and $1.3 million, respectively, related to the dividend component on the outstanding and unvested share grants. Other Income - Net Other Income - net consisted of the following items for the years ended December 31 (dollars in thousands): 2015 2014 2013 Interest income $653 $987 $754 Interest on regulatory deferrals 48 220 126 Equity-related AFUDC 8,331 8,808 6,066 Net gain (loss) on investments (637) 276 (3,378) Other income 905 1,055 1,599 Total $9,300 $11,346 $5,167 Earnings per Common Share Attributable to Avista Corporation Shareholders Basic earnings per common share attributable to Avista Corp. shareholders is computed by dividing net income attributable to Avista Corp. shareholders by the weighted average number of common shares outstanding for the period. Diluted earnings per common share attributable to Avista Corp. shareholders is calculated by dividing net income attributable to Avista Corp. shareholders (adjusted for the effect of potentially dilutive securities issued to noncontrolling interests by the Company's subsidiaries) by diluted weighted average common shares outstanding during the period, including common stock equivalent shares outstanding using the treasury stock method, unless such shares are anti-dilutive. Common stock equivalent shares include shares issuable upon exercise of stock options and contingent stock awards. See Note 18 for earnings per common share calculations. Cash and Cash Equivalents For the purposes of the Consolidated Statements of Cash Flows, the Company considers all temporary investments with a maturity of three months or less when purchased to be cash equivalents. Allowance for Doubtful Accounts The Company maintains an allowance for doubtful accounts to provide for estimated and potential losses on accounts receivable. The Company determines the allowance for utility and other customer accounts receivable based on historical write-offs as compared to accounts receivable and operating revenues. Additionally, the Company establishes specific allowances for certain individual accounts. The following table presents the activity in the allowance for doubtful accounts during the years ended December 31 (dollars in thousands): 2015 2014 2013 Allowance as of the beginning of the year $4,888 $44,309 $44,155 Additions expensed during the year 5,802 5,296 5,099 Net deductions (1)(6,160) (44,717) (4,945) Allowance as of the end of the year $4,530 $4,888 $44,309 (1)During the second quarter of 2014, the Company received $15.0 million in gross proceeds related to the settlement of its California wholesale power markets litigation. The gross proceeds effectively settled all outstanding receivables and payables at Avista Energy (which had been fully reserved against since 2001). As a result of the settlement, the Company reversed $15.0 million of the allowance, which was recorded as a reduction to non-utility other operating expenses on the Consolidated Statements of Income, and the remainder of the receivables, payables and allowance of $24.5 million were removed from the Consolidated Balance Sheets (and had no effect on net income). 94 Staff_DR_063 Attachment A Page 103 of 180 Table of Contents AVISTA CORPORATION Materials and Supplies, Fuel Stock and Stored Natural Gas Inventories of materials and supplies, fuel stock and stored natural gas are recorded at average cost for our regulated operations and the lower of cost or market for our non-regulated operations and consisted of the following as of December 31 (dollars in thousands): 2015 2014 Materials and supplies $37,101 $32,483 Fuel stock 4,273 5,142 Stored natural gas 12,774 28,731 Total $54,148 $66,356 Utility Plant in Service The cost of additions to utility plant in service, including an allowance for funds used during construction and replacements of units of property and improvements, is capitalized. The cost of depreciable units of property retired plus the cost of removal less salvage is charged to accumulated depreciation. Asset Retirement Obligations The Company records the fair value of a liability for an asset retirement obligation (ARO) in the period in which it is incurred. When the liability is initially recorded, the associated costs of the ARO are capitalized as part of the carrying amount of the related long-lived asset. The liability is accreted to its present value each period and the related capitalized costs are depreciated over the useful life of the related asset. In addition, if there are changes in the estimated timing or estimated costs of the AROs, adjustments are recorded during the period new information becomes available as an increase or decrease to the liability, with the offset recorded to the related long-lived asset. Upon retirement of the asset, the Company either settles the ARO for its recorded amount or incurs a gain or loss. The Company records regulatory assets and liabilities for the difference between asset retirement costs currently recovered in rates and AROs recorded since asset retirement costs are recovered through rates charged to customers (see Note 9 for further discussion of the Company's asset retirement obligations). The Company recovers certain asset retirement costs through rates charged to customers as a portion of its depreciation expense for which the Company has not recorded asset retirement obligations. The Company has recorded the amount of estimated retirement costs collected from customers (that do not represent legal or contractual obligations) and included them as a regulatory liability on the Consolidated Balance Sheets in the following amounts as of December 31 (dollars in thousands): 2015 2014 Regulatory liability for utility plant retirement costs $261,594 $254,140 Goodwill Goodwill arising from acquisitions represents the excess of the purchase price over the estimated fair value of net assets acquired. The Company evaluates goodwill for impairment using a combination of discounted cash flow models and a market approach on at least an annual basis or more frequently if impairment indicators arise. The Company completed its annual evaluation of goodwill for potential impairment as of November 30, 2015 and determined that goodwill was not impaired at that time. The changes in the carrying amount of goodwill are as follows (dollars in thousands): Ecova AEL&P Other Accumulated Impairment Losses Total Balance as of January 1, 2014 $71,011 $— $12,979 $(7,733) $76,257 Adjustments 112 — — — 112 Goodwill sold during the year (71,123) — — — (71,123) Goodwill acquired during the year — 52,730 — — 52,730 Balance as of the December 31, 2014 — 52,730 12,979 (7,733) 57,976 Adjustments — (304) — — (304) Balance as of the December 31, 2015 $— $52,426 $12,979 $(7,733) $57,672 Accumulated impairment losses are attributable to the other businesses. The goodwill sold during 2014 relates to the Ecova disposition, which occurred on June 30, 2014. See Note 5 for information regarding this sales transaction. The goodwill 95 Staff_DR_063 Attachment A Page 104 of 180 Table of Contents AVISTA CORPORATION acquired during 2014 relates to the acquisition of AERC and the goodwill associated with this acquisition is not deductible for tax purposes. See Note 4 for information regarding this business acquisition and Note 21 regarding the Company's reportable segments. Derivative Assets and Liabilities Derivatives are recorded as either assets or liabilities on the Consolidated Balance Sheets measured at estimated fair value. In certain defined conditions, a derivative may be specifically designated as a hedge for a particular exposure. The accounting for a derivative depends on the intended use of such derivative and the resulting designation. The UTC and the IPUC issued accounting orders authorizing Avista Utilities to offset energy commodity derivative assets or liabilities with a regulatory asset or liability. This accounting treatment is intended to defer the recognition of mark-to-market gains and losses on energy commodity transactions until the period of delivery. The orders provide for Avista Utilities to not recognize the unrealized gain or loss on utility derivative commodity instruments in the Consolidated Statements of Income. Realized gains or losses are recognized in the periods of delivery, subject to approval for recovery through retail rates. Realized gains and losses, subject to regulatory approval, result in adjustments to retail rates through purchased gas cost adjustments, the ERM in Washington, the PCA mechanism in Idaho, and periodic general rates cases. Regulatory assets are assessed regularly and are probable for recovery through future rates. Substantially all forward contracts to purchase or sell power and natural gas are recorded as derivative assets or liabilities at estimated fair value with an offsetting regulatory asset or liability. Contracts that are not considered derivatives are accounted for on the accrual basis until they are settled or realized, unless there is a decline in the fair value of the contract that is determined to be other-than-temporary. For interest rate swap agreements, each period Avista Utilities records all mark-to-market gains and losses as assets and liabilities and records offsetting regulatory assets and liabilities, such that there is no income statement impact. Upon settlement of interest rate swaps, the regulatory asset or liability (included as part of long-term debt) is amortized as a component of interest expense over the term of the associated debt. While the Company has not received any formal accounting orders from the various state commissions allowing for the offset of interest rate swap assets and liabilities with regulatory assets and liabilities, the Company has deemed this accounting treatment appropriate and future recovery probable due to the regulatory precedents set in prior general rate cases and the fact that the state commissions view interest rate swap derivatives as risk management tools similar to energy commodity derivatives. As of December 31, 2015, the Company has multiple master netting agreements with a variety of entities that allow for cross-commodity netting of derivative agreements with the same counterparty (i.e. power derivatives can be netted with natural gas derivatives) under ASC 815-10-45. The Company does not have any agreements which allow for cross-affiliate netting among multiple affiliated legal entities. The Company nets all derivative instruments when allowed by the agreement for presentation in the Consolidated Balance Sheets. Fair Value Measurements Fair value represents the price that would be received when selling an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. Energy commodity derivative assets and liabilities, deferred compensation assets, as well as derivatives related to interest rate swap agreements and foreign currency exchange contracts, are reported at estimated fair value on the Consolidated Balance Sheets. See Note 16 for the Company’s fair value disclosures. Regulatory Deferred Charges and Credits The Company prepares its consolidated financial statements in accordance with regulatory accounting practices because: •rates for regulated services are established by or subject to approval by independent third-party regulators, •the regulated rates are designed to recover the cost of providing the regulated services, and •in view of demand for the regulated services and the level of competition, it is reasonable to assume that rates can be charged to and collected from customers at levels that will recover costs. Regulatory accounting practices require that certain costs and/or obligations (such as incurred power and natural gas costs not currently included in rates, but expected to be recovered or refunded in the future), are reflected as deferred charges or credits on the Consolidated Balance Sheets. These costs and/or obligations are not reflected in the Consolidated Statements of Income until the period during which matching revenues are recognized. The Company also has decoupling revenue deferrals. As opposed to cost deferrals which are not recognized in the Consolidated Statements of Income until they are included in rates, 96 Staff_DR_063 Attachment A Page 105 of 180 Table of Contents AVISTA CORPORATION decoupling revenue is recognized in the Consolidated Statements of Income during the period it occurs (i.e. during the period of revenue shortfall or excess due to fluctuations in customer usage), subject to certain limitations, and a regulatory asset/liability is established which will be surcharged or rebated to customers in future periods. GAAP requires that for any alternative regulatory revenue program, like decoupling, the revenue must be collected from customers within 24 months of the deferral to qualify for recognition in the current period Consolidated Statement of Income. Any amounts included in the Company's decoupling program that won't be collected from customers within 24 months are not recorded in the financial statements until the period in which revenue recognition criteria are met. This could ultimately result in more decoupling revenue being collected from customers over the life of the decoupling program than what is deferred and recognized in the current period financial statements. If at some point in the future the Company determines that it no longer meets the criteria for continued application of regulatory accounting practices for all or a portion of its regulated operations, the Company could be: •required to write off its regulatory assets, and •precluded from the future deferral of costs or decoupled revenues not recovered through rates at the time such amounts are incurred, even if the Company expected to recover these amounts from customers in the future. See Note 20 for further details of regulatory assets and liabilities. Investment in Exchange Power-Net The investment in exchange power represents the Company’s previous investment in Washington Public Power Supply System Project 3 (WNP-3), a nuclear project that was terminated prior to completion. Under a settlement agreement with the Bonneville Power Administration in 1985, Avista Utilities began receiving power in 1987, for a 32.5-year period, related to its investment in WNP-3. Through a settlement agreement with the UTC in the Washington jurisdiction, Avista Utilities is amortizing the recoverable portion of its investment in WNP-3 (recorded as investment in exchange power) over a 32.5-year period that began in 1987. For the Idaho jurisdiction, Avista Utilities fully amortized the recoverable portion of its investment in exchange power. Unamortized Debt Expense Unamortized debt expense includes debt issuance costs that are amortized over the life of the related debt. See further discussion related to the Consolidated Balance Sheet classification of these costs below under reclassifications. Unamortized Debt Repurchase Costs For the Company’s Washington regulatory jurisdiction and for any debt repurchases beginning in 2007 in all jurisdictions, premiums paid to repurchase debt are amortized over the remaining life of the original debt that was repurchased or, if new debt is issued in connection with the repurchase, these costs are amortized over the life of the new debt. In the Company’s other regulatory jurisdictions, premiums paid to repurchase debt prior to 2007 are being amortized over the average remaining maturity of outstanding debt when no new debt was issued in connection with the debt repurchase. These costs are recovered through retail rates as a component of interest expense. Accumulated Other Comprehensive Loss Accumulated other comprehensive loss, net of tax, consisted of the following as of December 31 (dollars in thousands): 2015 2014 Unfunded benefit obligation for pensions and other postretirement benefit plans - net of taxes of $3,580 and $4,247, respectively $6,650 $7,888 97 Staff_DR_063 Attachment A Page 106 of 180 Table of Contents AVISTA CORPORATION The following table details the reclassifications out of accumulated other comprehensive loss by component for the years ended December 31 (dollars in thousands): Amounts Reclassified from Accumulated Other Comprehensive Loss Details about Accumulated Other Comprehensive Loss Components 2015 2014 Affected Line Item in Statement of Income Realized gains on investment securities $— $3 (a) Realized losses on investment securities — (735) (a) — (732) Total before tax — 272 Tax benefit (a) $— $(460) Net of tax Amortization of defined benefit pension items Amortization of net prior service cost $(31) $1,094 (b) Amortization of net loss (2,623) 83,301 (b) Adjustment due to effects of regulation 749 (78,773) (b) (1,905) 5,622 Total before tax 667 (1,967) Tax expense (benefit) $(1,238) $3,655 Net of tax (a)These amounts were included as part of net income from discontinued operations for all periods presented (see Note 5 for additional details). (b)These accumulated other comprehensive loss components are included in the computation of net periodic pension cost (see Note 10 for additional details). Appropriated Retained Earnings In accordance with the hydroelectric licensing requirements of section 10(d) of the Federal Power Act (FPA), the Company maintains an appropriated retained earnings account for any earnings in excess of the specified rate of return on the Company's investment in the licenses for its various hydroelectric projects. Per section 10(d) of the FPA, the Company must maintain these excess earnings in an appropriated retained earnings account until the termination of the licensing agreements or apply them to reduce the net investment in the licenses of the hydroelectric projects at the discretion of the FERC. The Company typically calculates the earnings in excess of the specified rate of return on an annual basis, usually during the second quarter. In addition to the hydroelectric project licenses identified above for Avista Utilities, the requirements of section 10(d) of the FPA also apply to the AEL&P licenses for Lake Dorothy and Annex Creek/Salmon Creek (combined). The appropriated retained earnings amounts included in retained earnings were as follows as of December 31 (dollars in thousands): 2015 2014 Appropriated retained earnings $21,030 $14,270 Operating Leases The Company has multiple lease arrangements involving various assets, with minimum terms ranging from 1 to 45 years. Future minimum lease payments required under operating leases having initial or remaining noncancelable lease terms in excess of one year were not material as of December 31, 2015. Contingencies The Company has unresolved regulatory, legal and tax issues which have inherently uncertain outcomes. The Company accrues a loss contingency if it is probable that a liability has been incurred and the amount of the loss or impairment can be reasonably estimated. The Company also discloses losses that do not meet these conditions for accrual, if there is a reasonable possibility that a material loss may be incurred. As of December 31, 2015, the Company has not recorded any significant amounts related to unresolved contingencies. See Note 19 for further discussion of the Company's commitments and contingencies. Reclassifications Certain prior year amounts on the Company's Consolidated Balance Sheets were reclassified to conform to the current year 98 Staff_DR_063 Attachment A Page 107 of 180 Table of Contents AVISTA CORPORATION presentation. The reclassifications related the presentation of debt issuance costs due to the retrospective adoption of FASB ASU No. 2015-03, "Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs" as of December 31, 2015. This resulted in a decrease to Other Deferred Charges and a decrease to Long-Term Debt and Capital Leases of $11.4 million as of December 31, 2014. There was no other impact on the Company's financial statements or results of operations. Also, the Company adopted FASB ASU 2015-17 “Income Taxes (Topic 740) - Balance Sheet Classification of Deferred Taxes,” as of December 31, 2015 on a prospective basis, which resulted in all 2015 deferred income taxes being classified as noncurrent liabilities on the Consolidated Balance Sheet, compared to 2014 under the previous guidance, which required entities to separately present Deferred Tax Assets (DTAs) and Deferred Tax Liabilities (DTLs) as current and noncurrent in a classified balance sheet. This makes the 2015 presentation of deferred income taxes incomparable to the 2014 presentation of deferred income taxes. See Note 2 of the Notes to Consolidated Financial Statements for further discussion of the adoption of both of these ASUs. NOTE 2. NEW ACCOUNTING STANDARDS In April 2014, the FASB issued ASU No. 2014-08, "Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity." This ASU amends the definition of a discontinued operation and requires entities to provide additional disclosures about discontinued operations as well as disposal transactions that do not meet the discontinued- operations criteria. ASU 2014-08 makes it more difficult for a disposal transaction to qualify as a discontinued operation. In addition, the ASU requires entities to reclassify assets and liabilities of a discontinued operation for all comparative periods presented in the Balance Sheet rather than just the current period, and it requires additional disclosures on the face of the Statement of Cash Flows regarding discontinued operations. This ASU became effective for periods beginning on or after December 15, 2014; however, early adoption was permitted. The Company evaluated this standard and determined that it would not early adopt this standard. Since the disposition of Ecova occurred before the effective date of this standard, and the Company did not early adopt this standard, there is no impact on the Company's financial condition, results of operations and cash flows in the current year. In May 2014, the FASB issued ASU No. 2014-09, "Revenue from Contracts with Customers (Topic 606)," which outlines a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. The core principle of the revenue model is that an entity identifies the various performance obligations in a contract, allocates the transaction price among the performance obligations and recognizes revenue as the entity satisfies the performance obligations. This ASU was originally effective for periods beginning after December 15, 2016 and early adoption is not permitted. In August 2015, the FASB issued ASU 2015-14 Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date," which deferred the effective date of ASU 2014-09 for one year, with adoption as of the original date permitted. However, while this ASU is not effective until 2018, it will require retroactive application to all periods presented in the financial statements. As such, at adoption in 2018, amounts in 2016 and 2017 may have to be revised or a cumulative adjustment to opening retained earnings may have to be recorded. The Company is evaluating this standard and cannot, at this time, estimate the potential impact on its future financial condition, results of operations and cash flows. In February 2015, the FASB issued ASU No. 2015-02, "Consolidation (Topic 810): Amendments to the Consolidation Analysis." This ASU significantly changes the consolidation analysis required under GAAP, including the identification of variable interest entities (VIE). The ASU also removes the deferral of the VIE analysis related to investments in certain investment funds, which will result in a different consolidation evaluation for these types of investments. This ASU is effective for periods beginning on or after December 15, 2015; however, early adoption is permitted. The Company evaluated this standard and determined that it will not early adopt this standard. The Company is evaluating this standard and cannot, at this time, estimate the potential impact on its future financial condition, results of operations and cash flows. In April 2015, the FASB issued ASU No. 2015-03, "Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs." This ASU amends the presentation of debt issuance costs in the financial statements such that an entity presents such costs in the balance sheet as a direct deduction from the related debt liability rather than as a deferred asset. Amortization of the costs will continue to be reported as interest expense. ASU No. 2015-03 is effective for periods beginning on or after December 15, 2015; however, early adoption is permitted. Upon adoption, entities will apply the new guidance retrospectively to all comparable prior periods presented in the financial statements. The Company evaluated this standard and determined that it will early adopt this standard as of December 31, 2015. As such, the Company revised its presentation of debt issuance costs for long-term debt in the Consolidated Balance Sheets for both periods presented. See Note 1 of the Notes to Consolidated Financial Statements - Reclassifications for the quantification of the impact on the prior year Consolidated Balance Sheet. 99 Staff_DR_063 Attachment A Page 108 of 180 Table of Contents AVISTA CORPORATION ASU No. 2015-03 did not address the presentation of debt issuance costs associated with line of credit arrangements. Accordingly, in August 2015, the FASB issued ASU No. 2015-15, "Interest - Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements." This ASU incorporates guidance from the Securities and Exchange Commission which states that it would not object to an entity deferring and presenting debt issuance costs as an asset and subsequently amortizing the deferred debt issuance costs ratably over the term of the line of credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. This ASU was effective upon issuance. The presentation outlined in ASU No. 2015-15 is consistent with the Company's historical presentation of line of credit issuance costs; therefore, there is no impact on the Company's financial statements as a result of adopting this accounting standard in 2015. In April 2015, the FASB issued ASU No. 2015-05, "Intangibles - Goodwill and Other - Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Fees Paid in a Cloud Computing Arrangement." This ASU provides guidance on how organizations should account for fees paid in a cloud computing arrangement, including helping organizations understand whether their arrangement includes a software license. If the arrangement includes a software license, the software license would be accounted for in a manner consistent with internal-use software. If a cloud-computing arrangement does not include a software license, the customer is required to account for the arrangement as a service contract. This ASU is effective for periods beginning on or after December 15, 2015; however, early adoption is permitted. The Company evaluated this standard and determined that it will not early adopt this standard. Upon adoption, an entity can elect to apply this ASU prospectively or retroactively and disclose the method selected. The Company is evaluating this standard and cannot, at this time, estimate the potential impact on its future financial condition, results of operations and cash flows. In May 2015, the FASB issued ASU No. 2015-07, "Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent)." This ASU removes, from the fair value hierarchy, investments for which the practical expedient is used to measure fair value at net asset value (NAV). Instead, an entity is required to include those investments as a reconciling line item so that the total fair value amount of investments in the disclosure is consistent with the amount on the balance sheet. Further, entities must provide certain disclosures for investments for which they elect to use the NAV practical expedient to determine fair value. This ASU is effective for periods beginning on or after December 15, 2015 and early adoption is permitted. The Company evaluated this standard and determined that it will early adopt this standard as of December 31, 2015. As required, this ASU is being applied retrospectively to all periods presented. The adoption of this standard did not affect the Company's future financial condition, results of operations and cash flows; however, it did affect the Company's disclosures. See Note 10 and 16 for the expanded disclosures surrounding the adoption of this ASU. In November 2015, the FASB issued ASU 2015-17 “Income Taxes (Topic 740) - Balance Sheet Classification of Deferred Taxes,” which requires entities to present DTAs and DTLs as noncurrent in a classified balance sheet. The ASU simplifies the current guidance, which requires entities to separately present DTAs and DTLs as current and noncurrent in a classified balance sheet. This ASU is effective for annual periods beginning after December 15, 2016, and interim periods within those years and early adoption is permitted. In addition, upon adoption, entities are permitted to apply the amendments either prospectively or retrospectively. The Company has evaluated this standard and determined that it will early adopt this standard as of December 31, 2015 and it will apply this ASU on a prospective basis. As such, the Consolidated Balance Sheet as of December 31, 2014 was not adjusted to reflect the new ASU. The Company early adopted this ASU to ease the burden of preparing its financial statements and eliminate the need to evaluate deferred taxes for current and noncurrent presentation. NOTE 3. VARIABLE INTEREST ENTITIES Lancaster Power Purchase Agreement The Company has a PPA for the purchase of all the output of the Lancaster Plant, a 270 MW natural gas-fired combined cycle combustion turbine plant located in Kootenai County, Idaho, owned by an unrelated third-party (Rathdrum Power LLC), through 2026. Avista Corp. has a variable interest in the PPA. Accordingly, Avista Corp. made an evaluation of which interest holders have the power to direct the activities that most significantly impact the economic performance of the entity and which interest holders have the obligation to absorb losses or receive benefits that could be significant to the entity. Avista Corp. pays a fixed capacity and operations and maintenance payment and certain monthly variable costs under the PPA. Under the terms of the PPA, Avista Corp. makes the dispatch decisions, provides all natural gas fuel and receives all of the electric energy output from the Lancaster Plant. However, Rathdrum Power LLC (the owner) controls the daily operation of the Lancaster Plant and makes operating and maintenance decisions. Rathdrum Power LLC controls all of the rights and obligations of the Lancaster Plant after the expiration of the PPA in 2026. It is estimated that the plant will have 15 to 25 years of useful life after that time. Rathdrum Power LLC bears the maintenance risk of the plant and will receive the residual value of the Lancaster Plant. Avista 100 Staff_DR_063 Attachment A Page 109 of 180 Table of Contents AVISTA CORPORATION Corp. has no debt or equity investments in the Lancaster Plant and does not provide financial support through liquidity arrangements or other commitments (other than the PPA). Based on its analysis, Avista Corp. does not consider itself to be the primary beneficiary of the Lancaster Plant. Accordingly, neither the Lancaster Plant nor Rathdrum Power LLC is included in Avista Corp.’s consolidated financial statements. The Company has a future contractual obligation of approximately $296.5 million under the PPA (representing the fixed capacity and operations and maintenance payments through 2026) and believes this would be its maximum exposure to loss. However, the Company believes that such costs will be recovered through retail rates. NOTE 4. BUSINESS ACQUISITIONS Alaska Energy and Resources Company On July 1, 2014, the Company acquired AERC, based in Juneau, Alaska, and as of that date, AERC became a wholly-owned subsidiary of Avista Corp. The primary subsidiary of AERC is AEL&P, a regulated utility which provides electric services to approximately 17,000 customers in the City and Borough of Juneau (Juneau), Alaska as of December 31, 2015. In addition to the regulated utility, AERC owns AJT Mining, which is an inactive mining company holding certain properties. The purpose of the acquisition was to expand and diversify Avista Corp.'s energy assets and deliver long-term value to its customers, communities and investors. In connection with the closing, on July 1, 2014 Avista Corp. issued 4,500,014 new shares of common stock to the shareholders of AERC based on a contractual formula that resulted in a price of $32.46 per share, reflecting a purchase price of $170.0 million, plus acquired cash, less outstanding debt and other closing adjustments. The $32.46 price per share of Avista Corp. common stock was determined based on the average closing stock price of Avista Corp. common stock for the 10 consecutive trading days immediately preceding, but not including, the trading day prior to July 1, 2014. This value was used solely for determining the number of shares to issue based on the adjusted contract closing price (see reconciliation below). The fair value of the consideration transferred at the closing date was based on the closing stock price of Avista Corp. common stock on July 1, 2014, which was $33.35 per share. On October 1, 2014, a working capital adjustment was made in accordance with the agreement and plan of merger which resulted in Avista Corp. issuing an additional 1,427 shares of common stock to the shareholders of AERC. The number of shares issued on October 1, 2014 was based on the same contractual formula described above. The fair value of the new shares issued in October was $30.71 per share, which was the closing stock price of Avista Corp. common stock on that date. The contract acquisition price and the fair value of consideration transferred for AERC were as follows (in thousands, except "per share" and number of shares data): Contract acquisition price (using the calculated $32.46 per share common stock price) Gross contract price $170,000 Acquired cash 19,704 Acquired debt (excluding capital lease obligation)(38,832) Other closing adjustments (including the working capital adjustment)37 Total adjusted contract price $150,909 Fair value of consideration transferred Avista Corp. common stock (4,500,014 shares at $33.35 per share)$150,075 Avista Corp. common stock (1,427 shares at $30.71 per share)44 Cash 4,792 Fair value of total consideration transferred $154,911 101 Staff_DR_063 Attachment A Page 110 of 180 Table of Contents AVISTA CORPORATION The fair value of assets acquired and liabilities assumed as of July 1, 2014 (after consideration of the working capital adjustment and the income tax true-ups during the second quarter of 2015) were as follows (in thousands): July 1, 2014 Assets acquired: Current Assets: Cash $19,704 Accounts receivable - gross totals $3,928 3,851 Materials and supplies 2,017 Other current assets 999 Total current assets 26,571 Utility Property: Utility plant in service 113,964 Utility property under long-term capital lease 71,007 Construction work in progress 3,440 Total utility property 188,411 Other Non-current Assets: Non-utility property 6,660 Electric plant held for future use 3,711 Goodwill (1)52,426 Other deferred charges and non-current assets 5,368 Total other non-current assets 68,165 Total assets $283,147 Liabilities Assumed: Current Liabilities: Accounts payable $700 Current portion of long-term debt and capital lease obligations 3,773 Other current liabilities (1)2,807 Total current liabilities 7,280 Long-term debt 37,227 Capital lease obligations 68,840 Other non-current liabilities and deferred credits (1)14,889 Total liabilities $128,236 Total net assets acquired $154,911 (1)During the second quarter of 2015, the Company recorded a reduction to goodwill of approximately $0.3 million due to income tax related adjustments. After consideration of the goodwill adjustment in the second quarter of 2015, the transaction resulted in a total amount of goodwill of $52.4 million. The goodwill associated with this acquisition is not deductible for tax purposes. The majority of AERC’s operations are subject to the rate-setting authority of the RCA and are accounted for pursuant to GAAP, including the accounting guidance for regulated operations. The rate-setting and cost recovery provisions currently in place for AERC’s regulated operations provide revenues derived from costs, including a return on investment, of assets and liabilities included in rate base. Due to this regulation, the fair values of AERC’s assets and liabilities subject to these rate-setting provisions are assumed to approximate their carrying values. There were not any identifiable intangible assets associated with this acquisition. The excess of the purchase consideration over the estimated fair values of the assets acquired and liabilities assumed was recognized as goodwill at the acquisition date. The goodwill reflects the value paid for the expected continued growth of a rate-regulated business located in a defined service area with a constructive regulatory environment, the 102 Staff_DR_063 Attachment A Page 111 of 180 Table of Contents AVISTA CORPORATION attractiveness of stable, growing cash flows, as well as providing a platform for potential future growth outside of the rate-regulated electric utility in Alaska and potential additional utility investment. The following table summarizes the supplemental pro forma information for the years ended December 31 related to the acquisition of AERC as if the acquisition had occurred on January 1, 2013 (dollars in thousands - unaudited): 2015 2014 2013 Actual Avista Corp. revenues from continuing operations (excluding AERC)$1,439,807 $1,450,918 $1,441,744 Supplemental pro forma AERC revenues (1)44,969 46,467 41,594 Total pro forma revenues 1,484,776 1,497,385 1,483,338 Actual AERC revenues included in Avista Corp. revenues (1)44,969 21,644 — Actual Avista Corp. net income from continuing operations attributable to Avista Corp. shareholders (excluding AERC)111,772 116,665 104,273 Actual Avista Corp. net income from discontinued operations attributable to Avista Corp. shareholders 5,147 72,224 6,804 Adjustment to Avista Corp.'s net income for acquisition costs (net of tax) (2)22 870 (892) Supplemental pro forma AERC net income (1)6,308 8,806 9,328 Total pro forma net income 123,249 198,565 119,513 Actual AERC net income included in Avista Corp. net income (1)$6,308 $3,152 $— (1)AERC was acquired on July 1, 2014; therefore, all the revenues and net income for the second half of 2014 and all of 2015 are actual amounts that are included in Avista Corp.'s overall results. All revenue and net income amounts prior to July 1, 2014 are supplemental pro forma amounts and are excluded from Avista Corp.'s overall results. (2)This adjustment is to treat all transaction costs as if they occurred on January 1, 2013 and to remove them from the periods in which they actually occurred. The transaction costs were expensed and presented in the Consolidated Statements of Income in other operating expenses within utility operating expenses. Since the start of the transaction through December 31, 2015, Avista Corp. has expensed $3.0 million (pre-tax) in total transaction fees. In addition to the amounts expensed, through December 31, 2015, Avista Corp. has included $0.4 million in fees associated with the issuance of common stock for the transaction as a reduction to common stock. These fees do not impact the supplemental pro forma information above. NOTE 5. DISCONTINUED OPERATIONS On June 30, 2014, Avista Capital, completed the sale of its interest in Ecova to Cofely USA Inc., an indirect subsidiary of GDF SUEZ, a French multinational utility company, and an unrelated party to Avista Corp. The sales price was $335.0 million in cash, less the payment of debt and other customary closing adjustments. At the closing of the transaction on June 30, 2014, Ecova became a wholly-owned subsidiary of Cofely USA Inc. and the Company has not had and will not have any further involvement with Ecova after such date. The purchase price of $335.0 million, as adjusted, was divided among the security holders of Ecova, including minority shareholders, option holders and a warrant holder, pro rata based on ownership. Approximately $16.8 million (5 percent of the purchase price) was held in escrow for 15 months from the closing of the transaction to satisfy certain indemnification obligations under the merger agreement (Escrow). An additional $1.0 million was held in escrow pending resolution of adjustments to working capital. The indemnification escrow and the working capital adjustment escrow amounts above represent the full amounts to be divided among all security holders pro rata based on ownership. As expected, no claims were made against the Escrow as of September 30, 2015 (the end of the claims period) and accordingly, all Escrow amounts were released in October 2015 and the Company received its full portion of the Escrow proceeds together with the remainder of the working capital adjustment escrow for a total amount of $13.8 million. After consideration of the escrow amounts received, the sales transaction provided cash proceeds to Avista Corp., net of debt, payment to option and minority holders, income taxes and transaction expenses, of $143.7 million and resulted in a net gain of $74.8 million. Almost all of the net gain was recognized in 2014 with some true-ups during 2015. 103 Staff_DR_063 Attachment A Page 112 of 180 Table of Contents AVISTA CORPORATION The summary of cash proceeds associated with the sales transaction are as follows (in thousands): Reconciliation to Statement of Cash Flows Contract price $335,000 Closing adjustments 4,103 Litigation settlement at Ecova 588 Gross proceeds from sale (1)339,691 Cash sold in the transaction (95,932) Gross proceeds from sale of Ecova, net of cash sold (per Statement of Cash Flows) (2)$243,759 Reconciliation of total net proceeds Gross proceeds from sale (1)$339,691 Repayment of long-term borrowings under committed line of credit (40,000) Payment to option holders and redeemable noncontrolling interests (20,871) Payment to noncontrolling interests (54,179) Transaction expenses withheld from proceeds (5,461) Net proceeds to Avista Capital (prior to tax payments) (2)219,180 Tax payments made in 2014 (74,842) Tax payments made in 2015 (590) Total net proceeds related to sales transaction $143,748 (1)Of this total amount, approximately $16.8 million was held in escrow for 15 months from the transaction closing date for any indemnity claims and an additional $1.0 million was held in escrow pending resolution of adjustments to working capital. Both of these escrow accounts were resolved during 2015. (2)Of the total gross proceeds and total net proceeds received, approximately $229.9 million and $205.4 million was received in 2014, respectively, with the remainder being received in 2015. Prior to the completion of the sales transaction, Ecova was a reportable business segment. The major classes of assets and liabilities and their carrying amounts immediately prior to the completion of the sales transaction were as follows: June 30, 2014 Assets: Current Assets: Cash and cash equivalents $95,932 Accounts and notes receivable-less allowances of $410 32,070 Investments and funds held for clients 114,598 Income taxes receivable 2,548 Other current assets 8,908 Total current assets 254,056 Other Non-current Assets: Goodwill 71,123 Intangible assets-net of accumulated amortization of $42,266 37,185 Other property and investments-net 4,656 Total other non-current assets 112,964 Total assets $367,020 104 Staff_DR_063 Attachment A Page 113 of 180 Table of Contents AVISTA CORPORATION June 30, 2014 Liabilities: Current Liabilities: Accounts payable $72,453 Client fund obligations 115,333 Current portion of long-term debt 67 Other current liabilities 35,329 Total current liabilities 223,182 Long-term borrowings under committed line of credit 40,000 Other non-current liabilities 2,117 Total liabilities $265,299 Amounts reported in discontinued operations for 2013 through 2015 relate solely to the Ecova business segment. The following table presents amounts that were included in discontinued operations for the years ended December 31 (dollars in thousands): 2015 2014 2013 Revenues $— $87,534 $176,761 Gain on sale of Ecova (1)777 160,612 — Transaction expenses and accelerated employee benefits (2)71 9,062 — Gain on sale of Ecova, net of transaction expenses 706 151,550 — Income before income taxes 706 156,025 13,177 Income tax expense (benefit) (3)(4,441) 83,614 5,216 Net income from discontinued operations 5,147 72,411 7,961 Net income attributable to noncontrolling interests — (187) (1,157) Net income from discontinued operations attributable to Avista Corp. shareholders $5,147 $72,224 $6,804 (1)This represents the gross gain recorded to discontinued operations. The total gain net of taxes and transactions expenses is $74.8 million, of which $69.7 million was recognized during 2014. (2)Avista Corp.'s portion of the total transaction expenses was $9.1 million (including amounts which were withheld from the transaction net proceeds) and this was recognized during the second and third quarters of 2014 and the third and fourth quarters of 2015. All transaction expenses paid on the Ecova sale (including Avista Corp.'s portion and the portion attributable to the minority interest holders of Ecova) were $11.1 million, of which $5.5 million was withheld from the net proceeds and the remainder was paid during the second and third quarters of 2014. The transaction expenses were for legal, accounting and other consulting fees, and the accelerated employee benefits related to employee stock options which were settled in accordance with the Ecova equity plan. (3)The tax benefit during 2015 primarily resulted from the reversal of a valuation allowance against net operating losses at Ecova because the net operating losses were deemed realizable under the current tax code. NOTE 6. DERIVATIVES AND RISK MANAGEMENT The disclosures below in Note 6 apply only to Avista Corp. and Avista Utilities; AERC and its primary subsidiary AEL&P do not enter into derivative instruments. Energy Commodity Derivatives Avista Utilities is exposed to market risks relating to changes in electricity and natural gas commodity prices and certain other fuel prices. Market risk is, in general, the risk of fluctuation in the market price of the commodity being traded and is influenced primarily by supply and demand. Market risk includes the fluctuation in the market price of associated derivative commodity instruments. Avista Utilities utilizes derivative instruments, such as forwards, futures, swaps and options in order to manage the various risks relating to these commodity price exposures. The Company has an energy resources risk policy and control procedures to manage these risks. 105 Staff_DR_063 Attachment A Page 114 of 180 Table of Contents AVISTA CORPORATION As part of the Company's resource procurement and management operations in the electric business, the Company engages in an ongoing process of resource optimization, which involves the economic selection from available energy resources to serve the Company's load obligations and the use of these resources to capture available economic value. The Company transacts in wholesale markets by selling and purchasing electric capacity and energy, fuel for electric generation, and derivative contracts related to capacity, energy and fuel. Such transactions are part of the process of matching resources with load obligations and hedging the related financial risks. These transactions range from terms of intra-hour up to multiple years. As part of its resource procurement and management of its natural gas business, Avista Utilities makes continuing projections of its natural gas loads and assesses available natural gas resources including natural gas storage availability. Natural gas resource planning typically includes peak requirements, low and average monthly requirements and delivery constraints from natural gas supply locations to Avista Utilities’ distribution system. However, daily variations in natural gas demand can be significantly different than monthly demand projections. On the basis of these projections, Avista Utilities plans and executes a series of transactions to hedge a portion of its projected natural gas requirements through forward market transactions and derivative instruments. These transactions may extend as much as four natural gas operating years (November through October) into the future. Avista Utilities also leaves a significant portion of its natural gas supply requirements unhedged for purchase in short-term and spot markets. The following table presents the underlying energy commodity derivative volumes as of December 31, 2015 that are expected to be settled in each respective year (in thousands of MWhs and mmBTUs): Purchases Sales Electric Derivatives Gas Derivatives Electric Derivatives Gas Derivatives Year Physical (1) MWh Financial (1) MWh Physical (1) mmBTUs Financial (1) mmBTUs Physical (1) MWh Financial (1) MWh Physical (1) mmBTUs Financial (1) mmBTUs 2016 407 1,954 17,252 142,693 280 2,656 3,182 112,233 2017 397 97 675 49,200 255 483 1,360 26,965 2018 397 — — 15,118 286 — 1,360 2,738 2019 235 — 305 6,935 158 — 1,345 — 2020 — — 455 905 — — 1,430 — Thereafter — — — — — — 1,060 — (1)Physical transactions represent commodity transactions in which Avista Utilities will take or make delivery of either electricity or natural gas; financial transactions represent derivative instruments with delivery of cash in the amount of gain or loss but with no physical delivery of the commodity, such as futures, swaps, options, or forward contracts. The electric and natural gas derivative contracts above will be included in either power supply costs or natural gas supply costs during the period they are settled and will be included in the various recovery mechanisms (ERM, PCA, and PGAs), or in the general rate case process, and are expected to be collected through retail rates from customers. Foreign Currency Exchange Contracts A significant portion of Avista Utilities’ natural gas supply (including fuel for power generation) is obtained from Canadian sources. Most of those transactions are executed in U.S. dollars, which avoids foreign currency risk. A portion of Avista Utilities’ short-term natural gas transactions and long-term Canadian transportation contracts are committed based on Canadian currency prices and settled within 60 days with U.S. dollars. Avista Utilities hedges a portion of the foreign currency risk by purchasing Canadian currency exchange contracts when such commodity transactions are initiated. This risk has not had a material effect on the Company’s financial condition, results of operations or cash flows and these differences in cost related to currency fluctuations were included with natural gas supply costs for ratemaking. The following table summarizes the foreign currency hedges that the Company has entered into as of December 31 (dollars in thousands): 2015 2014 Number of contracts 24 18 Notional amount (in United States dollars)$1,463 $5,474 Notional amount (in Canadian dollars)2,002 6,198 Interest Rate Swap Agreements Avista Corp. is affected by fluctuating interest rates related to a portion of its existing debt, and future borrowing requirements. The Company hedges a portion of its interest rate risk with financial derivative instruments, which may include interest rate 106 Staff_DR_063 Attachment A Page 115 of 180 Table of Contents AVISTA CORPORATION swaps and U.S. Treasury lock agreements. These interest rate swaps and U.S. Treasury lock agreements are considered economic hedges against fluctuations in future cash flows associated with anticipated debt issuances. The following table summarizes the interest rate swaps that the Company has outstanding as of the balance sheet date indicated below (dollars in thousands): Balance Sheet Date Number of Contracts Notional Amount Mandatory Cash Settlement Date December 31, 2015 6 115,000 2016 3 45,000 2017 11 245,000 2018 2 30,000 2019 1 20,000 2022 December 31, 2014 5 75,000 2015 5 95,000 2016 3 45,000 2017 9 205,000 2018 During the third quarter 2015, in connection with the execution of a purchase agreement for bonds that the Company issued in December 2015, the Company cash-settled five interest rate swap contracts (notional aggregate amount of $75.0 million) and paid a total of $9.3 million. The interest rate swap contracts were settled in connection with the pricing of $100.0 million of Avista Corp. first mortgage bonds that were issued in December 2015 (see Note 14). Upon settlement of interest rate swaps, the regulatory asset or liability (included as part of long-term debt) is amortized as a component of interest expense over the term of the associated debt. The fair value of outstanding interest rate swaps can vary significantly from period to period depending on the total notional amount of swaps outstanding and fluctuations in market interest rates compared to the interest rates fixed by the swaps. The Company would be required to make cash payments to settle the interest rate swaps if the fixed rates are higher than prevailing market rates at the date of settlement. Conversely, the Company receives cash to settle its interest rate swaps when prevailing market rates at the time of settlement exceed the fixed swap rates. Summary of Outstanding Derivative Instruments The amounts recorded on the Consolidated Balance Sheet as of December 31, 2015 and December 31, 2014 reflect the offsetting of derivative assets and liabilities where a legal right of offset exists. The following table presents the fair values and locations of derivative instruments recorded on the Consolidated Balance Sheet as of December 31, 2015 (in thousands): Fair Value Derivative Balance Sheet Location Gross Asset Gross Liability Collateral Netting Net Asset (Liability) in Balance Sheet Foreign currency contracts Other current liabilities $2 $(19) $— $(17) Interest rate contracts Other property and investments-net 23 — — 23 Interest rate contracts Other current liabilities 118 (23,262) 3,880 (19,264) Interest rate contracts Other non-current liabilities and deferred credits 1,407 (62,236) 30,150 (30,679) Commodity contracts Current utility energy commodity derivative assets 1,236 (553) — 683 Commodity contracts Current utility energy commodity derivative liabilities 67,466 (85,409) 3,675 (14,268) Commodity contracts Other non-current liabilities and deferred credits 6,613 (39,033) 10,851 (21,569) Total derivative instruments recorded on the balance sheet $76,865 $(210,512) $48,556 $(85,091) 107 Staff_DR_063 Attachment A Page 116 of 180 Table of Contents AVISTA CORPORATION The following table presents the fair values and locations of derivative instruments recorded on the Consolidated Balance Sheet as of December 31, 2014 (in thousands): Fair Value Derivative Balance Sheet Location Gross Asset Gross Liability Collateral Netting Net Asset (Liability) in Balance Sheet Foreign currency contracts Other current liabilities $1 $(21) $— $(20) Interest rate contracts Other current assets 966 (506) — 460 Interest rate contracts Other current liabilities — (7,325) — (7,325) Interest rate contracts Other non-current liabilities and deferred credits — (69,737) 28,880 (40,857) Commodity contracts Current utility energy commodity derivative assets 2,063 (538) — 1,525 Commodity contracts Current utility energy commodity derivative liabilities 66,421 (97,586) 13,120 (18,045) Commodity contracts Other non-current liabilities and deferred credits 29,594 (54,077) 2,390 (22,093) Total derivative instruments recorded on the balance sheet $99,045 $(229,790) $44,390 $(86,355) Exposure to Demands for Collateral The Company's derivative contracts often require collateral (in the form of cash or letters of credit) or other credit enhancements, or reductions or terminations of a portion of the contract through cash settlement, in the event of a downgrade in the Company's credit ratings or changes in market prices. In periods of price volatility, the level of exposure can change significantly. As a result, sudden and significant demands may be made against the Company's credit facilities and cash. The Company actively monitors the exposure to possible collateral calls and takes steps to mitigate capital requirements. The following table presents the Company's collateral outstanding related to its derivative instruments as of as of December 31 (in thousands): 2015 2014 Energy commodity derivatives Cash collateral posted $28,716 $20,565 Letters of credit outstanding 28,200 14,500 Balance sheet offsetting (cash collateral against net derivative positions)14,526 15,510 Interest rate swaps Cash collateral posted 34,030 28,880 Letters of credit outstanding 9,600 10,900 Balance sheet offsetting (cash collateral against net derivative positions)34,030 28,880 Certain of the Company’s derivative instruments contain provisions that require the Company to maintain an "investment grade" credit rating from the major credit rating agencies. If the Company’s credit ratings were to fall below “investment grade,” it would be in violation of these provisions, and the counterparties to the derivative instruments could request immediate payment or demand immediate and ongoing collateralization on derivative instruments in net liability positions. 108 Staff_DR_063 Attachment A Page 117 of 180 Table of Contents AVISTA CORPORATION The following table presents the aggregate fair value of all derivative instruments with credit-risk-related contingent features that are in a liability position and the amount of additional collateral the Company could be required to post as of December 31 (in thousands): 2015 2014 Energy commodity derivatives Liabilities with credit-risk-related contingent features $7,090 $12,911 Additional collateral to post 6,980 16,227 Interest rate swaps Liabilities with credit-risk-related contingent features 85,498 77,568 Additional collateral to post 18,750 19,404 Credit Risk Credit risk relates to the potential losses that the Company would incur as a result of non-performance by counterparties of their contractual obligations to deliver energy or make financial settlements. The Company often extends credit to counterparties and customers and is exposed to the risk that it may not be able to collect amounts owed to the Company. Credit risk includes potential counterparty default due to circumstances: •relating directly to it, •caused by market price changes, and •relating to other market participants that have a direct or indirect relationship with such counterparty. Changes in market prices may dramatically alter the size of credit risk with counterparties, even when conservative credit limits are established. Should a counterparty fail to perform, the Company may be required to honor the underlying commitment or to replace existing contracts with contracts at then- current market prices. The Company enters into bilateral transactions with various counterparties. The Company also transacts in energy and related derivative instruments through clearinghouse exchanges. In addition, the Company has concentrations of credit risk related to geographic location as it operates in the western United States and western Canada. These concentrations of counterparties and concentrations of geographic location may impact the Company’s overall exposure to credit risk because the counterparties may be similarly affected by changes in conditions. The Company maintains credit support agreements with certain counterparties and margin calls are periodically made and/or received. Margin calls are triggered when exposures exceed contractual limits or when there are changes in a counterparty’s creditworthiness. Price movements in electricity and natural gas can generate exposure levels in excess of these contractual limits. Negotiating for collateral in the form of cash, letters of credit, or performance guarantees is common industry practice. NOTE 7. JOINTLY OWNED ELECTRIC FACILITIES The Company has a 15 percent ownership interest in a twin-unit coal-fired generating facility, Colstrip, located in southeastern Montana, and provides financing for its ownership interest in the project. The Company’s share of related fuel costs as well as operating expenses for plant in service are included in the corresponding accounts in the Consolidated Statements of Income. The Company’s share of utility plant in service for Colstrip and accumulated depreciation were as follows as of December 31 (dollars in thousands): 2015 2014 Utility plant in service $362,199 $350,518 Accumulated depreciation (243,363) (239,845) 109 Staff_DR_063 Attachment A Page 118 of 180 Table of Contents AVISTA CORPORATION NOTE 8. PROPERTY, PLANT AND EQUIPMENT The balances of the major classifications of property, plant and equipment are detailed in the following table as of December 31 (dollars in thousands): 2015 2014 Avista Utilities: Electric production $1,217,179 $1,171,002 Electric transmission 640,586 603,909 Electric distribution 1,468,157 1,360,185 Electric construction work-in-progress (CWIP) and other 358,846 311,807 Electric total 3,684,768 3,446,903 Natural gas underground storage 43,080 41,963 Natural gas distribution 878,982 810,487 Natural gas CWIP and other 62,024 57,088 Natural gas total 984,086 909,538 Common plant (including CWIP)456,796 394,027 Total Avista Utilities 5,125,650 4,750,468 AEL&P: Electric production 72,292 71,969 Electric transmission 18,817 18,392 Electric distribution 19,005 17,936 Electric production held under long-term capital lease 71,007 71,007 Electric CWIP and other 16,971 7,893 Electric total 198,092 187,197 Common plant 8,133 8,155 Total AEL&P 206,225 195,352 Other (1)25,709 25,803 Total $5,357,584 $4,971,623 (1)Included in other property and investments-net on the Consolidated Balance Sheets. Accumulated depreciation was $10.6 million as of December 31, 2015 and $10.8 million as of December 31, 2014 for the other businesses. The decrease in accumulated depreciation for the other businesses was due to the sale of certain assets which were nearing the end of their useful lives. NOTE 9. ASSET RETIREMENT OBLIGATIONS See Note 1 for a discussion of the Company's accounting policy associated with AROs. Specifically, the Company has recorded liabilities for future AROs to: •restore coal ash containment ponds at Colstrip, •cap a landfill at the Kettle Falls Plant, •remove plant and restore the land at the Coyote Springs 2 site at the termination of the land lease, and •dispose of PCBs in certain transformers. Due to an inability to estimate a range of settlement dates, the Company cannot estimate a liability for the: •removal and disposal of certain transmission and distribution assets, and •abandonment and decommissioning of certain hydroelectric generation and natural gas storage facilities. On April 17, 2015, the EPA published a final rule regarding CCRs, also termed coal combustion byproducts or coal ash in the Federal Register and this rule became effective on October 15, 2015. Colstrip, of which Avista Corp. is a 15 percent owner of units 3 and 4, produces this byproduct. The rule establishes technical requirements for CCR landfills and surface impoundments under Subtitle D of the Resource Conservation and Recovery Act, the nation's primary law for regulating solid waste. The 110 Staff_DR_063 Attachment A Page 119 of 180 Table of Contents AVISTA CORPORATION Company, in conjunction with the other Colstrip owners, is developing a multi-year compliance plan to strategically address the new CCR requirements and existing State obligations while maintaining operational stability. During the second quarter of 2015, the operator of Colstrip provided an initial cost estimate of the expected retirement costs associated with complying with the new CCR rule and this estimate was subsequently updated during the fourth quarter of 2015. Based on the initial assessments, Avista Corp. recorded an increase to its ARO of $12.5 million during 2015 with a corresponding increase in the cost basis of the utility plant. The actual asset retirement costs related to the new CCR rule requirements may vary substantially from the estimates used to record the increased obligation due to uncertainty about the compliance strategies that will be used and the preliminary nature of available data used to estimate costs, such as the quantity of coal ash present at certain sites and the volume of fill that will be needed to cap and cover certain impoundments. Avista Corp. will coordinate with the plant operator and continue to gather additional data in future periods to make decisions about compliance strategies and the timing of closure activities. As additional information becomes available, Avista Corp. will update the ARO for these changes in estimates, which could be material. The Company expects to seek recovery of any increased costs related to complying with the new rule through customer rates. The following table documents the changes in the Company’s asset retirement obligation during the years ended December 31 (dollars in thousands): 2015 2014 2013 Asset retirement obligation at beginning of year $3,028 $2,859 $3,168 Liabilities incurred 12,539 — — Liabilities settled (29) (41) (263) Accretion expense (income)459 210 (46) Asset retirement obligation at end of year $15,997 $3,028 $2,859 NOTE 10. PENSION PLANS AND OTHER POSTRETIREMENT BENEFIT PLANS The pension and other postretirement benefit plans described below only relate to Avista Utilities. AEL&P (not discussed below) participates in a defined contribution multiemployer plan for its union workers and a defined contribution money purchase pension plan for its nonunion workers. METALfx (not discussed below) has a defined contribution 401(k) savings plan. None of the subsidiary retirement plans, individually or in the aggregate, are significant to Avista Corp. Avista Utilities The Company has a defined benefit pension plan covering the majority of all regular full-time employees at Avista Utilities that were hired prior to January 1, 2014. Individual benefits under this plan are based upon the employee’s years of service, date of hire and average compensation as specified in the plan. Non- union employees hired on or after January 1, 2014 participate in a defined contribution 401(k) plan in lieu of a defined benefit pension plan. The Company’s funding policy is to contribute at least the minimum amounts that are required to be funded under the Employee Retirement Income Security Act, but not more than the maximum amounts that are currently deductible for income tax purposes. The Company contributed $12.0 million in cash to the pension plan in 2015, $32.0 million in 2014 and $44.3 million in 2013. The Company expects to contribute $12.0 million in cash to the pension plan in 2016. The Company also has a SERP that provides additional pension benefits to executive officers and certain key employees of the Company. The SERP is intended to provide benefits to individuals whose benefits under the defined benefit pension plan are reduced due to the application of Section 415 of the Internal Revenue Code of 1986 and the deferral of salary under deferred compensation plans. The liability and expense for this plan are included as pension benefits in the tables included in this Note. The Company expects that benefit payments under the pension plan and the SERP will total (dollars in thousands): 2016 2017 2018 2019 2020 Total 2021-2025 Expected benefit payments $29,182 $30,260 $31,332 $32,804 $34,430 $189,919 The expected long-term rate of return on plan assets is based on past performance and economic forecasts for the types of investments held by the plan. In selecting a discount rate, the Company considers yield rates for highly rated corporate bond portfolios with maturities similar to that of the expected term of pension benefits. The Company provides certain health care and life insurance benefits for eligible retired employees that were hired prior to January 1, 2014. The Company accrues the estimated cost of postretirement benefit obligations during the years that employees 111 Staff_DR_063 Attachment A Page 120 of 180 Table of Contents AVISTA CORPORATION provide services. The liability and expense of this plan are included as other postretirement benefits. Non-union employees hired on or after January 1, 2014, will have access to the retiree medical plan upon retirement; however, Avista Corp. will no longer provide a contribution toward their medical premium. The Company has a Health Reimbursement Arrangement (HRA) to provide employees with tax-advantaged funds to pay for allowable medical expenses upon retirement. The amount earned by the employee is fixed on the retirement date based on the employee’s years of service and the ending salary. The liability and expense of the HRA are included as other postretirement benefits. The Company provides death benefits to beneficiaries of executive officers who die during their term of office or after retirement. Under the plan, an executive officer’s designated beneficiary will receive a payment equal to twice the executive officer’s annual base salary at the time of death (or if death occurs after retirement, a payment equal to twice the executive officer’s total annual pension benefit). The liability and expense for this plan are included as other postretirement benefits. The Company expects that benefit payments under other postretirement benefit plans will total (dollars in thousands): 2016 2017 2018 2019 2020 Total 2021-2025 Expected benefit payments $7,345 $7,522 $7,713 $7,933 $6,907 $36,560 The Company expects to contribute $7.3 million to other postretirement benefit plans in 2016, representing expected benefit payments to be paid during the year excluding the Medicare Part D subsidy. The Company uses a December 31 measurement date for its pension and other postretirement benefit plans. The following table sets forth the pension and other postretirement benefit plan disclosures as of December 31, 2015 and 2014 and the components of net periodic benefit costs for the years ended December 31, 2015, 2014 and 2013 (dollars in thousands): Pension Benefits Other Post- retirement Benefits 2015 2014 2015 2014 Change in benefit obligation: Benefit obligation as of beginning of year $634,674 $527,004 $127,989 $108,249 Service cost 19,791 15,757 2,925 1,844 Interest cost 26,117 26,224 5,158 5,226 Actuarial (gain)/loss (35,790) 97,128 12,668 18,714 Plan change (228) — (1,000) — Transfer of accrued vacation — — — 437 Cumulative adjustment to reclassify liability — — (1,521) — Benefits paid (31,061) (31,439) (7,424) (6,481) Benefit obligation as of end of year $613,503 $634,674 $138,795 $127,989 Change in plan assets: Fair value of plan assets as of beginning of year $539,311 $481,502 $31,312 $29,732 Actual return on plan assets (4,305) 55,974 (444) 1,580 Employer contributions 12,000 32,000 — — Benefits paid (29,772) (30,165) — — Fair value of plan assets as of end of year $517,234 $539,311 $30,868 $31,312 Funded status $(96,269) $(95,363) $(107,927) $(96,677) Unrecognized net actuarial loss 162,961 175,596 92,433 82,421 Unrecognized prior service cost 25 256 (10,180) (10,379) Prepaid (accrued) benefit cost 66,717 80,489 (25,674) (24,635) Additional liability (162,986) (175,852) (82,253) (72,042) Accrued benefit liability $(96,269) $(95,363) $(107,927) $(96,677) Accumulated pension benefit obligation $542,209 $551,615 — — 112 Staff_DR_063 Attachment A Page 121 of 180 Table of Contents AVISTA CORPORATION Pension Benefits Other Post- retirement Benefits 2015 2014 2015 2014 Accumulated postretirement benefit obligation: For retirees $65,652 $58,276 For fully eligible employees $34,498 $31,843 For other participants $38,645 $37,870 Included in accumulated other comprehensive loss (income) (net of tax): Unrecognized prior service cost $16 $166 $(6,617) $(6,747) Unrecognized net actuarial loss 105,925 114,138 60,081 53,574 Total 105,941 114,304 53,464 46,827 Less regulatory asset (99,414) (106,484) (53,341) (46,759) Accumulated other comprehensive loss (income) for unfunded benefit obligation for pensions and other postretirement benefit plans $6,527 $7,820 $123 $68 Pension Benefits Other Post- retirement Benefits 2015 2014 2015 2014 Weighted average assumptions as of December 31: Discount rate for benefit obligation 4.57% 4.21% 4.57% 4.16% Discount rate for annual expense 4.21% 5.10% 4.16% 5.02% Expected long-term return on plan assets 5.30% 6.60% 6.36% 6.40% Rate of compensation increase 4.87% 4.87% Medical cost trend pre-age 65 – initial 7.00% 7.00% Medical cost trend pre-age 65 – ultimate 5.00% 5.00% Ultimate medical cost trend year pre-age 65 2022 2021 Medical cost trend post-age 65 – initial 7.00% 7.00% Medical cost trend post-age 65 – ultimate 5.00% 5.00% Ultimate medical cost trend year post-age 65 2023 2022 Pension Benefits Other Post-retirement Benefits 2015 2014 2013 2015 2014 2013 Components of net periodic benefit cost: Service cost $19,791 $15,757 $19,045 $2,925 $1,844 $4,144 Interest cost 26,117 26,224 23,896 5,158 5,226 5,216 Expected return on plan assets (28,299) (32,131) (27,671) (1,991) (1,903) (1,606) Amortization of prior service cost 2 22 319 (1,199) (1,116) (149) Net loss recognition 9,451 4,731 13,199 5,095 4,289 5,674 Net periodic benefit cost $27,062 $14,603 $28,788 $9,988 $8,340 $13,279 Plan Assets The Finance Committee of the Company’s Board of Directors approves investment policies, objectives and strategies that seek an appropriate return for the pension plan and other postretirement benefit plans and reviews and approves changes to the investment and funding policies. The Company has contracted with investment consultants who are responsible for managing/monitoring the individual investment managers. The investment managers’ performance and related individual fund performance is periodically reviewed by an internal benefits committee and by the Finance Committee to monitor compliance with investment policy objectives and strategies. 113 Staff_DR_063 Attachment A Page 122 of 180 Table of Contents AVISTA CORPORATION Pension plan assets are invested in mutual funds, trusts and partnerships that hold marketable debt and equity securities, real estate, absolute return and commodity funds. In seeking to obtain the desired return to fund the pension plan, the investment consultant recommends allocation percentages by asset classes. These recommendations are reviewed by the internal benefits committee, which then recommends their adoption by the Finance Committee. The Finance Committee has established target investment allocation percentages by asset classes and also investment ranges for each asset class. The target investment allocation percentages are typically the midpoint of the established range. The target investment allocation percentages by asset classes are indicated in the table below: 2015 2014 Equity securities 27% 27% Debt securities 58% 58% Real estate 6% 6% Absolute return 9% 9% The fair value of pension plan assets invested in debt and equity securities was based primarily on fair value (market prices). The fair value of investment securities traded on a national securities exchange is determined based on the reported last sales price; securities traded in the over-the-counter market are valued at the last reported bid price. Investment securities for which market prices are not readily available or for which market prices do not represent the value at the time of pricing, the investment manager estimates fair value based upon other inputs (including valuations of securities that are comparable in coupon, rating, maturity and industry). Investments in common/collective trust funds are presented at estimated fair value, which is determined based on the unit value of the fund. Unit value is determined by an independent trustee, which sponsors the fund, by dividing the fund’s net assets by its units outstanding at the valuation date. The Company's investments in common/collective trusts have redemption limitations that permit quarterly redemptions following notice requirements of 45 to 60 days. The fair values of the closely held investments and partnership interests are based upon the allocated share of the fair value of the underlying assets as well as the allocated share of the undistributed profits and losses, including realized and unrealized gains and losses. Most of the Company's investments in closely held investments and partnership interests have redemption limitations that range from bi-monthly to semi-annually following redemption notice requirements of 60 to 90 days. One investment in a partnership has a lock-up for redemption currently expiring in 2022 and is subject to extension. The fair value of pension plan assets invested in real estate was determined by the investment manager based on three basic approaches: •properties are externally appraised on an annual basis by independent appraisers, additional appraisals may be performed as warranted by specific asset or market conditions, •property valuations are reviewed quarterly and adjusted as necessary, and •loans are reflected at fair value. The fair value of pension plan assets was determined as of December 31, 2015 and 2014. Effective December 31, 2015, the Company adopted ASU No. 2015-07, "Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent)," which removed from the fair value hierarchy, investments for which the practical expedient is used to measure fair value at net asset value (NAV). In prior years, the Company held investments fair valued using NAV and these amounts were included as level 3 items. This ASU was adopted retrospectively; therefore, the 2014 amounts have been reclassified to conform to the 2015 presentation. Also, since these amounts are no longer included in the fair value hierarchy as level 3 items, the level 3 reconciliations are no longer applicable and have been excluded from this footnote. 114 Staff_DR_063 Attachment A Page 123 of 180 Table of Contents AVISTA CORPORATION The following table discloses by level within the fair value hierarchy (see Note 16 for a description of the fair value hierarchy) of the pension plan’s assets measured and reported as of December 31, 2015 at fair value (dollars in thousands): Level 1 Level 2 Level 3 Total Cash equivalents $86 $10,641 $— $10,727 Fixed income securities: U.S. government issues — 47,845 — 47,845 Corporate issues — 187,308 — 187,308 International issues — 34,458 — 34,458 Municipal issues — 22,416 — 22,416 Mutual funds: U.S. equity securities 87,678 — — 87,678 International equity securities 40,343 — — 40,343 Absolute return (1)13,996 — — 13,996 Plan assets measured at NAV (not subject to hierarchy disclosure) Common/collective trusts: Real estate — — — 24,147 Partnership/closely held investments: Absolute return (1)— — — 38,302 Private equity funds (2)— — — 73 Real estate — — — 9,941 Total $142,103 $302,668 $— $517,234 The following table discloses by level within the fair value hierarchy (see Note 16 for a description of the fair value hierarchy) of the pension plan’s assets measured and reported as of December 31, 2014 at fair value (dollars in thousands): Level 1 Level 2 Level 3 Total Cash equivalents $— $3,138 $— $3,138 Fixed income securities: U.S. government issues 19,681 — — 19,681 Corporate issues 104,959 — — 104,959 International issues 19,935 — — 19,935 Municipal issues 2,762 7,788 — 10,550 Mutual funds: Fixed income securities 157,415 8 — 157,423 U.S. equity securities 103,203 — — 103,203 International equity securities 40,838 — — 40,838 Absolute return (1)15,334 — — 15,334 Plan assets measured at NAV (not subject to hierarchy disclosure) Common/collective trusts: Real estate — — — 21,303 Partnership/closely held investments: Absolute return (1)— — — 36,114 Private equity funds (2)— — — 73 Real estate — — — 6,760 Total $464,127 $10,934 $— $539,311 (1)This category invests in multiple strategies to diversify risk and reduce volatility. The strategies include: (a) event driven, relative value, convertible, and fixed income arbitrage, (b) distressed investments, (c) long/short equity and fixed income, and (d) market neutral strategies. (2)This category includes private equity funds that invest primarily in U.S. companies. 115 Staff_DR_063 Attachment A Page 124 of 180 Table of Contents AVISTA CORPORATION The fair value of other postretirement plan assets invested in debt and equity securities was based primarily on market prices. The fair value of investment securities traded on a national securities exchange is determined based on the last reported sales price; securities traded in the over-the-counter market are valued at the last reported bid price. Investment securities for which market prices are not readily available or for which market prices do not represent the value at the time of pricing, are fair-valued by the investment manager based upon other inputs (including valuations of securities that are comparable in coupon, rating, maturity and industry). The target asset allocation was 60 percent equity securities and 40 percent debt securities in both 2015 and 2014. The fair value of other postretirement plan assets was determined as of December 31, 2015 and 2014. The following table discloses by level within the fair value hierarchy (see Note 16 for a description of the fair value hierarchy) of other postretirement plan assets measured and reported as of December 31, 2015 at fair value (dollars in thousands): Level 1 Level 2 Level 3 Total Cash equivalents $— $9 $— $9 Mutual funds: Fixed income securities 12,000 — — 12,000 U.S. equity securities 13,224 — — 13,224 International equity securities 5,635 — — 5,635 Total $30,859 $9 $— $30,868 The following table discloses by level within the fair value hierarchy (see Note 16 for a description of the fair value hierarchy) of other postretirement plan assets measured and reported as of December 31, 2014 at fair value (dollars in thousands): Level 1 Level 2 Level 3 Total Cash equivalents $— $3 $— $3 Mutual funds: Fixed income securities 11,968 — — 11,968 U.S. equity securities 13,210 — — 13,210 International equity securities 6,131 — — 6,131 Total $31,309 $3 $— $31,312 Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-percentage-point increase in the assumed health care cost trend rate for each year would increase the accumulated postretirement benefit obligation as of December 31, 2015 by $9.7 million and the service and interest cost by $0.5 million. A one-percentage-point decrease in the assumed health care cost trend rate for each year would decrease the accumulated postretirement benefit obligation as of December 31, 2015 by $7.5 million and the service and interest cost by $0.4 million. 401(k) Plans and Executive Deferral Plan Avista Utilities and METALfx have salary deferral 401(k) plans that are defined contribution plans and cover substantially all employees. Employees can make contributions to their respective accounts in the plans on a pre-tax basis up to the maximum amount permitted by law. The respective company matches a portion of the salary deferred by each participant according to the schedule in the respective plan. Employer matching contributions were as follows for the years ended December 31 (dollars in thousands): 2015 2014 2013 Employer 401(k) matching contributions $8,011 $6,862 $6,279 The Company has an Executive Deferral Plan. This plan allows executive officers and other key employees the opportunity to defer until the earlier of their retirement, termination, disability or death, up to 75 percent of their base salary and/or up to 100 percent of their incentive payments. Deferred compensation funds are held by the Company in a Rabbi Trust. 116 Staff_DR_063 Attachment A Page 125 of 180 Table of Contents AVISTA CORPORATION There were deferred compensation assets included in other property and investments-net and corresponding deferred compensation liabilities included in other non-current liabilities and deferred credits on the Consolidated Balance Sheets of the following amounts as of December 31 (dollars in thousands): 2015 2014 Deferred compensation assets and liabilities $8,093 $8,677 NOTE 11. ACCOUNTING FOR INCOME TAXES Income tax expense consisted of the following for the years ended December 31 (dollars in thousands): 2015 2014 2013 Current income tax expense (benefit)$12,212 $(67,059) $37,743 Deferred income tax expense 55,237 139,299 20,271 Total income tax expense $67,449 $72,240 $58,014 State income taxes do not represent a significant portion of total income tax expense on the Consolidated Statements of Income for any periods presented. A reconciliation of federal income taxes derived from statutory federal tax rates (35 percent in 2015, 2014 and 2013) applied to income before income taxes as set forth in the accompanying Consolidated Statements of Income is as follows for the years ended December 31 (dollars in thousands): 2015 2014 2013 Federal income taxes at statutory rates $64,967 35.0 % $67,237 35.0 % $56,821 35.0 % Increase (decrease) in tax resulting from: Tax effect of regulatory treatment of utility plant differences 4,358 2.3 4,008 2.1 3,532 2.2 State income tax expense 1,012 0.5 506 0.2 1,553 1.0 Settlement of prior year tax returns and adjustment of tax reserves (992)(0.5) 1,104 0.6 (1,104)(0.7) Manufacturing deduction (1,198)(0.6) (169)(0.1) (2,033)(1.3) Other (698)(0.4) (446)(0.2) (755)(0.5) Total income tax expense $67,449 36.3 % $72,240 37.6 % $58,014 35.7 % 117 Staff_DR_063 Attachment A Page 126 of 180 Table of Contents AVISTA CORPORATION Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes and tax credit carryforwards. The total net deferred income tax liability consisted of the following as of December 31 (dollars in thousands): 2015 2014 Deferred income tax assets: Unfunded benefit obligation $75,716 $72,324 Derivatives 47,009 46,903 Tax credits 15,011 15,080 Power and natural gas deferrals 12,866 3,811 Deferred compensation 10,354 10,796 Other 29,471 20,583 Total gross deferred income tax assets 190,427 169,497 Valuation allowances for deferred tax assets (2,862) (8,145) Total deferred income tax assets after valuation allowances 187,565 161,352 Deferred income tax liabilities: Differences between book and tax basis of utility plant 723,661 654,321 Regulatory asset on utility, property plant and equipment 36,917 36,504 Regulatory asset for pensions and other postretirement benefits 82,253 82,515 Utility energy commodity derivatives 47,010 46,906 Long-term debt and borrowing costs 14,027 11,484 Settlement with Coeur d’Alene Tribe 12,084 12,458 Other regulatory assets 11,691 9,691 Other 7,399 3,021 Total deferred income tax liabilities 935,042 856,900 Net deferred income tax liability $747,477 $695,548 Consolidated balance sheet classification of net deferred income taxes: Current deferred income tax asset (1)$— $14,794 Long-term deferred income tax liability (1)747,477 710,342 Net deferred income tax liability $747,477 $695,548 (1)Effective December 31, 2015, the Company adopted ASU 2015-17 “Income Taxes (Topic 740) - Balance Sheet Classification of Deferred Taxes,” which requires entities to present DTAs and DTLs as noncurrent in a classified balance sheet versus the previous accounting guidance which required separate presentation of current and noncurrent DTAs and DTLs. The Company has elected to adopt this standard on a prospective basis; therefore, the Consolidated Balance Sheet as of December 31, 2014 has not been adjusted to match the current period presentation. See "Note 2 of the Notes to Consolidated Financial Statements" for further discussion of this ASU. The realization of deferred income tax assets is dependent upon the ability to generate taxable income in future periods. The Company evaluated available evidence supporting the realization of its deferred income tax assets and determined it is more likely than not that deferred income tax assets will be realized. As of December 31, 2015, the Company had $15.3 million of state tax credit carryforwards of which it is expected $2.9 million will expire unused; the Company has reflected the net amount of $12.4 million as an asset at December 31, 2015. State tax credits expire from 2019 to 2028. The Company and its eligible subsidiaries file consolidated federal income tax returns. The Company also files state income tax returns in certain jurisdictions, including Idaho, Oregon and Montana. Subsidiaries are charged or credited with the tax effects of their operations on a stand-alone basis. The Internal Revenue Service (IRS) has completed its examination of all tax years through 2011 and all issues were resolved related to these years. The IRS has not completed an examination of the Company’s 2012 and 2014 federal income tax returns. The Company believes that any open tax years for federal or state income taxes will not result in adjustments that would be significant to the consolidated financial statements. The Company had net regulatory assets related to the probable recovery of certain deferred income tax liabilities from customers through future rates as of December 31 (dollars in thousands): 2015 2014 Regulatory assets for deferred income taxes $101,240 $100,412 Regulatory liabilities for deferred income taxes 17,609 14,534 118 Staff_DR_063 Attachment A Page 127 of 180 Table of Contents AVISTA CORPORATION NOTE 12. ENERGY PURCHASE CONTRACTS The below discussion only relates to Avista Utilities. The sole energy purchase contract at AEL&P is a PPA for the Snettisham hydroelectric project and it is accounted for as a capital lease. AEL&P does not have any other significant operating agreements or contractual obligations. See Note 14 for further discussion of the Snettisham PPA. Avista Utilities has contracts for the purchase of fuel for thermal generation, natural gas for resale and various agreements for the purchase or exchange of electric energy with other entities. The termination dates of the contracts range from one month to the year 2042. Total expenses for power purchased, natural gas purchased, fuel for generation and other fuel costs, which are included in utility resource costs in the Consolidated Statements of Income, were as follows for the years ended December 31 (dollars in thousands): 2015 2014 2013 Utility power resources $511,937 $556,915 $524,810 The following table details Avista Utilities’ future contractual commitments for power resources (including transmission contracts) and natural gas resources (including transportation contracts) (dollars in thousands): 2016 2017 2018 2019 2020 Thereafter Total Power resources $261,560 $168,831 $149,375 $145,074 $104,688 $838,536 $1,668,064 Natural gas resources 79,335 64,400 65,144 57,105 45,446 427,435 738,865 Total $340,895 $233,231 $214,519 $202,179 $150,134 $1,265,971 $2,406,929 These energy purchase contracts were entered into as part of Avista Utilities’ obligation to serve its retail electric and natural gas customers’ energy requirements, including contracts entered into for resource optimization. As a result, these costs are recovered either through base retail rates or adjustments to retail rates as part of the power and natural gas cost deferral and recovery mechanisms. The above future contractual commitments for power resources include fixed contractual amounts related to the Company's contracts with certain PUDs to purchase portions of the output of certain generating facilities. Although Avista Utilities has no investment in the PUD generating facilities, the fixed contracts obligate Avista Utilities to pay certain minimum amounts whether or not the facilities are operating. The cost of power obtained under the contracts, including payments made when a facility is not operating, is included in utility resource costs in the Consolidated Statements of Income. The contractual amounts included above consist of Avista Utilities’ share of existing debt service cost and its proportionate share of the variable operating expenses of these projects. The minimum amounts payable under these contracts are based in part on the proportionate share of the debt service requirements of the PUD's revenue bonds for which the Company is indirectly responsible. The Company's total future debt service obligation associated with the revenue bonds outstanding at December 31, 2015 (principal and interest) was $72.0 million. In addition, Avista Utilities has operating agreements, settlements and other contractual obligations related to its generating facilities and transmission and distribution services. The expenses associated with these agreements are reflected as other operating expenses in the Consolidated Statements of Income. The following table details future contractual commitments under these agreements (dollars in thousands): 2016 2017 2018 2019 2020 Thereafter Total Contractual obligations $33,694 $31,134 $26,405 $31,117 $31,811 $192,295 $346,456 NOTE 13. COMMITTED LINES OF CREDIT Avista Corp. Avista Corp. has a committed line of credit with various financial institutions in the total amount of $400.0 million that expires in April 2019. The Company has the option to request an extension for an additional one or two years beyond April 2019, provided, 1) that no event of default has occurred and is continuing prior to the requested extension and 2) the remaining term of agreement, including the requested extension period, does not exceed five years. The committed line of credit is secured by non-transferable first mortgage bonds of the Company issued to the agent bank that would only become due and payable in the event, and then only to the extent, that the Company defaults on its obligations under the committed line of credit. 119 Staff_DR_063 Attachment A Page 128 of 180 Table of Contents AVISTA CORPORATION The committed line of credit agreement contains customary covenants and default provisions. The credit agreement has a covenant which does not permit the ratio of “consolidated total debt” to “consolidated total capitalization” of Avista Corp. to be greater than 65 percent at any time. As of December 31, 2015, the Company was in compliance with this covenant. Balances outstanding and interest rates of borrowings (excluding letters of credit) under the Company’s revolving committed lines of credit were as follows as of December 31 (dollars in thousands): 2015 2014 Balance outstanding at end of period $105,000 $105,000 Letters of credit outstanding at end of period $44,595 $32,579 Average interest rate at end of period 1.18% 0.93% As of December 31, 2015 and 2014, the borrowings outstanding under Avista Corp.'s committed line of credit were classified as short-term borrowings on the Consolidated Balance Sheet. AEL&P AEL&P has a committed line of credit in the amount of $25.0 million that expires in November 2019. As of December 31, 2015, there were no borrowings or letters of credit outstanding under this committed line of credit. The committed line of credit is secured by non-transferable first mortgage bonds of AEL&P issued to the agent bank that would only become due and payable in the event, and then only to the extent, that AEL&P defaults on its obligations under the committed line of credit. The committed line of credit agreement contains customary covenants and default provisions. The credit agreement has a covenant which does not permit the ratio of “consolidated total debt at AEL&P” to “consolidated total capitalization at AEL&P,” including the impact of the Snettisham bonds to be greater than 67.5 percent at any time. As of December 31, 2015, the Company was in compliance with this covenant. 120 Staff_DR_063 Attachment A Page 129 of 180 Table of Contents AVISTA CORPORATION NOTE 14. LONG-TERM DEBT AND CAPITAL LEASES The following details long-term debt outstanding as of December 31 (dollars in thousands): Maturity Year Description Interest Rate 2015 2014 Avista Corp. Secured Long-Term Debt 2016 First Mortgage Bonds 0.84% $90,000 $90,000 2018 First Mortgage Bonds 5.95% 250,000 250,000 2018 Secured Medium-Term Notes 7.39%-7.45% 22,500 22,500 2019 First Mortgage Bonds 5.45% 90,000 90,000 2020 First Mortgage Bonds 3.89% 52,000 52,000 2022 First Mortgage Bonds 5.13% 250,000 250,000 2023 Secured Medium-Term Notes 7.18%-7.54% 13,500 13,500 2028 Secured Medium-Term Notes 6.37% 25,000 25,000 2032 Secured Pollution Control Bonds (1) (1) 66,700 66,700 2034 Secured Pollution Control Bonds (1) (1) 17,000 17,000 2035 First Mortgage Bonds 6.25% 150,000 150,000 2037 First Mortgage Bonds 5.70% 150,000 150,000 2040 First Mortgage Bonds 5.55% 35,000 35,000 2041 First Mortgage Bonds 4.45% 85,000 85,000 2044 First Mortgage Bonds 4.11% 60,000 60,000 2045 First Mortgage Bonds (2) 4.37% 100,000 — 2047 First Mortgage Bonds 4.23% 80,000 80,000 Total Avista Corp. secured long-term debt 1,536,700 1,436,700 AEL&P Secured Long-Term Debt 2044 First Mortgage Bonds 4.54% 75,000 75,000 Total secured long-term debt 1,611,700 1,511,700 AERC Unsecured Long-Term Debt 2019 Unsecured Term Loan 3.85% 15,000 15,000 Total secured and unsecured long-term debt 1,626,700 1,526,700 Other Long-Term Debt Components Capital lease obligations 68,601 74,149 Settled interest rate swaps (3) (26,515) (17,541) Unamortized debt discount (956) (1,122) Unamortized long-term debt issuance costs (10,852) (11,360) Total 1,656,978 1,570,826 Secured Pollution Control Bonds held by Avista Corporation (1) (83,700) (83,700) Current portion of long-term debt and capital leases (93,167) (6,424) Total long-term debt and capital leases $1,480,111 $1,480,702 (1)In December 2010, $66.7 million and $17.0 million of the City of Forsyth, Montana Pollution Control Revenue Refunding Bonds (Avista Corporation Colstrip Project) due in 2032 and 2034, respectively, which had been held by Avista Corp. since 2008 and 2009, respectively, were refunded by new bond issues (Series 2010A and Series 2010B). The new bonds were not offered to the public and were purchased by Avista Corp. due to market conditions. The Company expects that at a later date, subject to market conditions, these bonds may be remarketed to unaffiliated investors. So long as Avista Corp. is the holder of these bonds, the bonds will not be reflected as an asset or a liability on Avista Corp.'s Consolidated Balance Sheets. 121 Staff_DR_063 Attachment A Page 130 of 180 Table of Contents AVISTA CORPORATION (2)In December 2015, Avista Corp. issued $100.0 million of first mortgage bonds to five institutional investors in a private placement transaction. The first mortgage bonds bear an interest rate of 4.37 percent and mature in 2045. The total net proceeds from the sale of the new bonds were used to repay a portion of the borrowings outstanding under the Company’s $400.0 million committed line of credit and for general corporate purposes. (3)Upon settlement of interest rate swaps, these are recorded as a regulatory asset or liability and included as part of long-term debt above. They are amortized as a component of interest expense over the life of the associated debt and included as a part of the Company's cost of debt calculation for ratemaking purposes. The following table details future long-term debt maturities including long-term debt to affiliated trusts (see Note 15) (dollars in thousands): 2016 2017 2018 2019 2020 Thereafter Total Debt maturities $90,000 $— $272,500 $105,000 $52,000 $1,075,047 $1,594,547 Substantially all Avista Utilities' and AEL&P's owned properties are subject to the lien of their respective mortgage indentures. Under the Mortgages and Deeds of Trust (Mortgages) securing their first mortgage bonds (including secured medium-term notes), Avista Utilities and AEL&P may each issue additional first mortgage bonds under their specific mortgage in an aggregate principal amount equal to the sum of: 1) 66-2/3 percent of the cost or fair value (whichever is lower) of property additions at each entity which have not previously been made the basis of any application under the Mortgages, or 2) an equal principal amount of retired first mortgage bonds at each entity which have not previously been made the basis of any application under the Mortgages, or 3) deposit of cash. However, Avista Utilities and AEL&P may not individually issue any additional first mortgage bonds (with certain exceptions in the case of bonds issued on the basis of retired bonds) unless the particular entity issuing the bonds has “net earnings” (as defined in the Mortgages) for any period of 12 consecutive calendar months out of the preceding 18 calendar months that were at least twice the annual interest requirements on all mortgage securities at the time outstanding, including the first mortgage bonds to be issued, and on all indebtedness of prior rank. As of December 31, 2015, property additions and retired bonds would have allowed, and the net earnings test would not have prohibited, the issuance of $1.1 billion in aggregate principal amount of additional first mortgage bonds at Avista Utilities and $5.0 million at AEL&P. See Note 13 for information regarding first mortgage bonds issued to secure the Company’s obligations under its committed line of credit agreement. Snettisham Capital Lease Obligation Included in long-term capital leases above is a power purchase agreement between AEL&P and AIDEA, an agency of the State of Alaska, under which AEL&P has a take-or-pay obligation, expiring in December 2038, to purchase all the output of the 78 MW Snettisham hydroelectric project. For accounting purposes, this power purchase agreement is treated as a capital lease. The balances related to the Snettisham capital lease obligation as of December 31 were as follows (dollars in thousands): 2015 2014 Capital lease obligation (1) $64,455 $69,955 Capital lease asset (2) 71,007 71,007 Accumulated amortization of capital lease asset (2) 5,462 1,821 (1)The capital lease obligation amount is equal to the amount of AIDEA's revenue bonds outstanding. (2)These amounts are included in utility plant in service on the Consolidated Balance Sheet. Interest on the capital lease obligation and amortization of the capital lease asset are included in utility resource costs in the Consolidated Statements of Income and totaled the following amounts for the years ended December 31 (dollars in thousands): 2015 2014 Interest on capital lease obligation $3,587 $1,908 Amortization of capital lease asset 3,641 1,821 AIDEA issued $100.0 million of revenue bonds in 1998 to finance its acquisition of the project and the payments by AEL&P were designed to be more than sufficient to enable the AIDEA to pay the principal of and interest on its revenue bonds, which bore interest at rates ranging from 4.9 percent to 6.0 percent and were set to mature in January 2034. 122 Staff_DR_063 Attachment A Page 131 of 180 Table of Contents AVISTA CORPORATION In August 2015, AIDEA issued $65.7 million of new revenue bonds for the purpose of refunding all of the remaining outstanding revenue bonds for the Snettisham Hydroelectric Project. The new revenue bonds have interest rates ranging from 4.0 percent to 5.0 percent and mature in January 2034. The capital lease obligation on Avista Corp.'s Consolidated Balance Sheet at any given time is equal to the amount of revenue bonds outstanding at that time. AEL&P is scheduled to make its last capital lease payment to AIDEA in December 2033. The payments by AEL&P under the PPA between AEL&P and AIDEA are unconditional, notwithstanding any suspension, reduction or curtailment of the operation of the project. The bonds are payable solely out of AIDEA's receipts under the power purchase agreement. AEL&P is also obligated to operate, maintain and insure the project. The PPA did not change as a result of the refunding and the lower capital lease payments that resulted from the refunding will be passed through to AEL&P. As a result of the refunding, AEL&P recognized a gain of $3.3 million, which was recorded as a regulatory liability. The benefits from the refunding will eventually be passed through to customers in future periods via lower purchased power costs, after a new general rate case is filed. AEL&P's new payments for power under the agreement are approximately $10.4 million per year, while the capital lease principal and interest is approximately $5.5 million per year, which is included in the $10.4 million total cost of power. Snettisham Electric Company, a non-operating subsidiary of AERC, has the option to purchase the Snettisham project with certain conditions at any time for the principal amount of the bonds outstanding at that time. While the power purchase agreement is treated as a capital lease for accounting purposes, for ratemaking purposes this agreement is treated as an operating lease with a constant level of annual rental expense (straight line expense). Because of this regulatory treatment, any difference between the operating lease expense for ratemaking purposes and the expenses recognized under capital lease treatment (interest and depreciation of the capital lease asset) is recorded as a regulatory asset and amortized during the later years of the lease when the capital lease expense is less than the operating lease expense included in base rates. The Company evaluated this agreement to determine if it has a variable interest which must be consolidated. Based on this evaluation, AIDEA will not be consolidated under ASC 810 "Consolidation" because AIDEA is a government agency and ASC 810 has a specific scope exception which does not allow for the consolidation of government organizations. The following table details future capital lease obligations, including interest, under the Snettisham power purchase agreement (dollars in thousands): 2016 2017 2018 2019 2020 Thereafter Total Principal $2,295 $2,415 $2,535 $2,660 $2,800 $51,750 $64,455 Interest 3,157 3,042 2,921 2,795 2,662 19,195 33,772 Total $5,452 $5,457 $5,456 $5,455 $5,462 $70,945 $98,227 Nonrecourse Long-Term Debt Nonrecourse long-term debt represented the long-term debt of Spokane Energy. To provide funding to acquire a long-term fixed rate electric capacity contract from Avista Corp., Spokane Energy borrowed $145.0 million from a funding trust in December 1998. The long-term debt had scheduled monthly installments and interest at a fixed rate of 8.45 percent and the final payment was made in January 2015. Spokane Energy bore full recourse risk for the debt, which was secured by the fixed rate electric capacity contract and $1.6 million of funds held in a trust account. As of December 31, 2015, there is no obligation remaining. NOTE 15. LONG-TERM DEBT TO AFFILIATED TRUSTS In 1997, the Company issued Floating Rate Junior Subordinated Deferrable Interest Debentures, Series B, with a principal amount of $51.5 million to Avista Capital II, an affiliated business trust formed by the Company. Avista Capital II issued $50.0 million of Preferred Trust Securities with a floating distribution rate of LIBOR plus 0.875 percent, calculated and reset quarterly. The distribution rates paid were as follows during the years ended December 31: 2015 2014 2013 Low distribution rate 1.11% 1.10% 1.11% High distribution rate 1.29% 1.11% 1.19% Distribution rate at the end of the year 1.29% 1.11% 1.11% Concurrent with the issuance of the Preferred Trust Securities, Avista Capital II issued $1.5 million of Common Trust Securities to the Company. These debt securities may be redeemed at the option of Avista Capital II at any time and mature on June 1, 2037. In December 2000, the Company purchased $10.0 million of these Preferred Trust Securities. 123 Staff_DR_063 Attachment A Page 132 of 180 Table of Contents AVISTA CORPORATION The Company owns 100 percent of Avista Capital II and has solely and unconditionally guaranteed the payment of distributions on, and redemption price and liquidation amount for, the Preferred Trust Securities to the extent that Avista Capital II has funds available for such payments from the respective debt securities. Upon maturity or prior redemption of such debt securities, the Preferred Trust Securities will be mandatorily redeemed. The Company does not include these capital trusts in its consolidated financial statements as Avista Corp. is not the primary beneficiary. As such, the sole assets of the capital trusts are $51.5 million of junior subordinated deferrable interest debentures of Avista Corp., which are reflected on the Consolidated Balance Sheets. Interest expense to affiliated trusts in the Consolidated Statements of Income represents interest expense on these debentures. NOTE 16. FAIR VALUE The carrying values of cash and cash equivalents, accounts and notes receivable, accounts payable and short-term borrowings are reasonable estimates of their fair values. Long-term debt (including current portion and material capital leases), nonrecourse long-term debt and long-term debt to affiliated trusts are reported at carrying value on the Consolidated Balance Sheets. The fair value hierarchy prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are defined as follows: Level 1 – Quoted prices are available in active markets for identical assets or liabilities. Active markets are those in which transactions for the asset or liability occur with sufficient frequency and volume to provide pricing information on an ongoing basis. Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Level 3 – Pricing inputs include significant inputs that are generally unobservable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. The determination of the fair values incorporates various factors that not only include the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits and letters of credit), but also the impact of Avista Corp.’s nonperformance risk on its liabilities. The following table sets forth the carrying value and estimated fair value of the Company’s financial instruments not reported at estimated fair value on the Consolidated Balance Sheets as of December 31 (dollars in thousands): 2015 2014 Carrying Value Estimated Fair Value Carrying Value Estimated Fair Value Long-term debt (Level 2)$951,000 $1,055,797 $951,000 $1,118,972 Long-term debt (Level 3)592,000 595,018 492,000 527,663 Snettisham capital lease obligation (Level 3)64,455 63,150 69,955 79,290 Nonrecourse long-term debt (Level 3)— — 1,431 1,440 Long-term debt to affiliated trusts (Level 3)51,547 36,083 51,547 38,582 These estimates of fair value of long-term debt and long-term debt to affiliated trusts were primarily based on available market information, which generally consists of estimated market prices from third party brokers for debt with similar risk and terms. The price ranges obtained from the third party brokers consisted of par values of 70.00 to 119.70, where a par value of 100.00 represents the carrying value recorded on the Consolidated Balance Sheets. Level 2 long-term debt represents publicly issued bonds with quoted market prices; however, due to their limited trading activity, they are classified as level 2 because brokers must generate quotes and make estimates if there is no trading activity near a period end. Level 3 long-term debt consists of 124 Staff_DR_063 Attachment A Page 133 of 180 Table of Contents AVISTA CORPORATION private placement bonds and debt to affiliated trusts, which typically have no secondary trading activity. Fair values in Level 3 are estimated based on market prices from third party brokers using secondary market quotes for debt with similar risk and terms to generate quotes for Avista Corp. bonds. Due to the unique nature of the Snettisham capital lease obligation, the estimated fair value of these items was determined based on a discounted cash flow model using available market information. The Snettisham capital lease obligation was discounted to present value using the Moody's Aaa Corporate discount rate as published by the Federal Reserve on December 31, 2015. The following table discloses by level within the fair value hierarchy the Company’s assets and liabilities measured and reported on the Consolidated Balance Sheets as of December 31, 2015 and 2014 at fair value on a recurring basis (dollars in thousands): Level 1 Level 2 Level 3 Counterparty and Cash Collateral Netting (1) Total December 31, 2015 Assets: Energy commodity derivatives $— $74,637 $— $(73,954) $683 Level 3 energy commodity derivatives: Natural gas exchange agreements — — 678 (678) — Foreign currency derivatives — 2 — (2) — Interest rate swaps — 1,548 — — 1,548 Deferred compensation assets: Fixed income securities (2)1,727 — — — 1,727 Equity securities (2)5,761 — — — 5,761 Total $7,488 $76,187 $678 $(74,634) $9,719 Liabilities: Energy commodity derivatives $— $97,193 $— $(88,480) $8,713 Level 3 energy commodity derivatives: Natural gas exchange agreement — — 5,717 (678) 5,039 Power exchange agreement — — 21,961 — 21,961 Power option agreement — — 124 — 124 Interest rate swaps — 85,498 — — 85,498 Foreign currency derivatives — 19 — (2) 17 Total $— $182,710 $27,802 $(89,160) $121,352 125 Staff_DR_063 Attachment A Page 134 of 180 Table of Contents AVISTA CORPORATION Level 1 Level 2 Level 3 Counterparty and Cash Collateral Netting (1) Total December 31, 2014 Assets: Energy commodity derivatives $— $96,729 $— $(95,204) $1,525 Level 3 energy commodity derivatives: Natural gas exchange agreement — — 1,349 (1,349) — Foreign currency derivatives — 1 — (1) — Interest rate swaps — 966 — (506) 460 Funds held in trust account of Spokane Energy 1,600 — — — 1,600 Deferred compensation assets: Fixed income securities (2)1,793 — — — 1,793 Equity securities (2)6,074 — — — 6,074 Total $9,467 $97,696 $1,349 $(97,060) $11,452 Liabilities: Energy commodity derivatives $— $127,094 $— $(110,714) $16,380 Level 3 energy commodity derivatives: Natural gas exchange agreement — — 1,384 (1,349) 35 Power exchange agreement — — 23,299 — 23,299 Power option agreement — — 424 — 424 Foreign currency derivatives — 21 — (1) 20 Interest rate swaps — 77,568 — (29,386) 48,182 Total $— $204,683 $25,107 $(141,450) $88,340 (1)The Company is permitted to net derivative assets and derivative liabilities with the same counterparty when a legally enforceable master netting agreement exists. In addition, the Company nets derivative assets and derivative liabilities against any payables and receivables for cash collateral held or placed with these same counterparties. (2)These assets are trading securities and are included in other property and investments-net on the Consolidated Balance Sheets. Avista Corp. enters into forward contracts to purchase or sell a specified amount of energy at a specified time, or during a specified period, in the future. These contracts are entered into as part of Avista Corp.’s management of loads and resources and certain contracts are considered derivative instruments. The difference between the amount of derivative assets and liabilities disclosed in respective levels and the amount of derivative assets and liabilities disclosed on the Consolidated Balance Sheets is due to netting arrangements with certain counterparties. The Company uses quoted market prices and forward price curves to estimate the fair value of utility derivative commodity instruments included in Level 2. In particular, electric derivative valuations are performed using market quotes, adjusted for periods in between quotable periods. Natural gas derivative valuations are estimated using New York Mercantile Exchange (NYMEX) pricing for similar instruments, adjusted for basin differences, using market quotes. Where observable inputs are available for substantially the full term of the contract, the derivative asset or liability is included in Level 2. To establish fair values for interest rate swaps, the Company uses forward market curves for interest rates for the term of the swaps and discounts the cash flows back to present value using an appropriate discount rate. The discount rate is calculated by third party brokers according to the terms of the swap agreements and evaluated by the Company for reasonableness, with consideration given to the potential non-performance risk by the Company. Future cash flows of the interest rate swaps are equal to the fixed interest rate in the swap compared to the floating market interest rate multiplied by the notional amount for each period. To establish fair value for foreign currency derivatives, the Company uses forward market curves for Canadian dollars against the US dollar and multiplies the difference between the locked-in price and the market price by the notional amount of the derivative. Forward foreign currency market curves are provided by third party brokers. The Company's credit spread is factored into the locked-in price of the foreign exchange contracts. 126 Staff_DR_063 Attachment A Page 135 of 180 Table of Contents AVISTA CORPORATION Deferred compensation assets and liabilities represent funds held by the Company in a Rabbi Trust for an executive deferral plan. These funds consist of actively traded equity and bond funds with quoted prices in active markets. The balance disclosed in the table above excludes cash and cash equivalents of $0.6 million as of December 31, 2015 and $0.8 million as of December 31, 2014. Level 3 Fair Value Under the power exchange agreement the Company purchases power at a price that is based on the on the average operating and maintenance (O&M) charges from three surrogate nuclear power plants around the country. To estimate the fair value of this agreement the Company estimates the difference between the purchase price based on the future O&M charges and forward prices for energy. The Company compares the Level 2 brokered quotes and forward price curves described above to an internally developed forward price which is based on the average O&M charges from the three surrogate nuclear power plants for the current year. Because the nuclear power plant O&M charges are only known for one year, all forward years are estimated assuming an annual escalation. In addition to the forward price being estimated using unobservable inputs, the Company also estimates the volumes of the transactions that will take place in the future based on historical average transaction volumes per delivery year (November to April). Significant increases or decreases in any of these inputs in isolation would result in a significantly higher or lower fair value measurement. Generally, a change in the current year O&M charges for the surrogate plants is accompanied by a directionally similar change in O&M charges in future years. There is generally not a correlation between external market prices and the O&M charges used to develop the internal forward price. For the power commodity option agreement, the Company uses the Black-Scholes-Merton valuation model to estimate the fair value, and this model includes significant inputs not observable or corroborated in the market. These inputs include: 1) the strike price (which is an internally derived price based on a combination of generation plant heat rate factors, natural gas market pricing, delivery and other O&M charges), 2) estimated delivery volumes, and 3) volatility rates for periods beyond January 2018. Significant increases or decreases in any of these inputs in isolation would result in a significantly higher or lower fair value measurement. Generally, changes in overall commodity market prices and volatility rates are accompanied by directionally similar changes in the strike price and volatility assumptions used in the calculation. For the natural gas commodity exchange agreement, the Company uses the same Level 2 brokered quotes described above; however, the Company also estimates the purchase and sales volumes (within contractual limits) as well as the timing of those transactions. Changing the timing of volume estimates changes the timing of purchases and sales, impacting which brokered quote is used. Because the brokered quotes can vary significantly from period to period, the unobservable estimates of the timing and volume of transactions can have a significant impact on the calculated fair value. The Company currently estimates volumes and timing of transactions based on a most likely scenario using historical data. Historically, the timing and volume of transactions have not been highly correlated with market prices and market volatility. The following table presents the quantitative information which was used to estimate the fair values of the Level 3 assets and liabilities above as of December 31, 2015 (dollars in thousands): Fair Value (Net) at December 31, 2015 Valuation Technique Unobservable Input Range Power exchange agreement $(21,961) Surrogate facility pricing O&M charges $33.52-$43.65/MWh (1) Escalation factor 3% - 2016 to 2019 Transaction volumes 233,054 - 397,030 MWhs Power option agreement (124) Black-Scholes- Merton Strike price $35.43/MWh - 2016 $48.78/MWh - 2019 Delivery volumes 157,517 - 285,979 MWhs Volatility rates 0.20 (2) Natural gas exchange agreement (5,039) Internally derived weighted average cost of gas Forward purchase prices $1.67 - $2.84/mmBTU Forward sales prices $1.88 - $3.68/mmBTU Purchase volumes 115,000 - 310,000 mmBTUs Sales volumes 30,000 - 310,000 mmBTUs 127 Staff_DR_063 Attachment A Page 136 of 180 Table of Contents AVISTA CORPORATION (1) The average O&M charges for the delivery year beginning in November 2015 were $39.27 per MWh. For ratemaking purposes the average O&M charges to be included for recovery in retail rates vary slightly between regulatory jurisdictions. The average O&M charges for the delivery year beginning in 2015 are $43.52 for Washington and $39.27 for Idaho. (2) The estimated volatility rate of 0.20 is compared to actual quoted volatility rates of 0.37 for 2016 to 0.24 in January 2018. Avista Corp.'s risk management department and accounting department are responsible for developing the valuation methods described above and both groups report to the Chief Financial Officer. The valuation methods, significant inputs and resulting fair values described above are reviewed on at least a quarterly basis by the risk management department and the accounting department to ensure they provide a reasonable estimate of fair value each reporting period. The following table presents activity for energy commodity derivative assets (liabilities) measured at fair value using significant unobservable inputs (Level 3) for the years ended December 31 (dollars in thousands): Natural Gas Exchange Agreement Power Exchange Agreement Power Option Agreement Total Year ended December 31, 2015: Balance as of January 1, 2015 $(35) $(23,299) $(424) $(23,758) Total gains or losses (realized/unrealized): Included in regulatory assets/liabilities (1)(6,008) (6,198) 300 (11,906) Settlements 1,004 7,536 — 8,540 Ending balance as of December 31, 2015 (2)$(5,039) $(21,961) $(124) $(27,124) Year ended December 31, 2014: Balance as of January 1, 2014 $(1,219) $(14,441) $(775) $(16,435) Total gains or losses (realized/unrealized): Included in regulatory assets/liabilities (1)3,873 (10,002) 351 (5,778) Settlements (2,689) 1,144 — (1,545) Ending balance as of December 31, 2014 (2)$(35) $(23,299) $(424) $(23,758) Year ended December 31, 2013: Balance as of January 1, 2013 $(2,379) $(18,692) $(1,480) $(22,551) Total gains or losses (realized/unrealized): Included in regulatory assets/liabilities (1)2,298 1,017 705 4,020 Settlements (1,138) 3,234 — 2,096 Ending balance as of December 31, 2013 (2)$(1,219) $(14,441) $(775) $(16,435) (1)All gains and losses are included in other regulatory assets and liabilities. There were no gains and losses included in either net income or other comprehensive income during any of the periods presented in the table above. (2)There were no purchases, issuances or transfers from other categories of any derivatives instruments during the periods presented in the table above. NOTE 17. COMMON STOCK The Company had a Direct Stock Purchase and Dividend Reinvestment Plan under which the Company’s shareholders could automatically reinvest their dividends and make optional cash payments for the purchase of the Company’s common stock at current market value. This plan was terminated by the Company in 2014. Shares issued under this plan in 2014 and 2013 are disclosed in the Consolidated Statements of Equity and Redeemable Noncontrolling Interests. The payment of dividends on common stock could be limited by: •certain covenants applicable to preferred stock (when outstanding) contained in the Company’s Restated Articles of Incorporation, as amended (currently there are no preferred shares outstanding), •certain covenants applicable to the Company's outstanding long-term debt and committed line of credit agreements, •the hydroelectric licensing requirements of section 10(d) of the FPA (see Note 1), and. 128 Staff_DR_063 Attachment A Page 137 of 180 Table of Contents AVISTA CORPORATION •certain requirements under the Public Utility Commission of Oregon (OPUC) approval of the AERC acquisition. As of July 1, 2015 (one year following the acquisition date), the OPUC does not permit one-time or special dividends from AERC to Avista Corp. and does not permit Avista Utilities' total equity to total capitalization to be less than 40 percent, without approval from the OPUC. However, the OPUC approval does allow for regular distributions of AERC earnings to Avista Corp. as long as AERC remains sufficiently capitalized and insured. The Company declared the following dividends for the year ended December 31: 2015 2014 2013 Dividends paid per common share $1.32 $1.27 $1.22 Under the covenant applicable to the Company's committed line of credit agreement, which does not permit the ratio of “consolidated total debt” to “consolidated total capitalization” to be greater than 65 percent at any time, the amount of retained earnings available for dividends at December 31, 2015 was limited to approximately $385.3 million. Under the requirements of the OPUC approval of the AERC acquisition as outlined above, the amount available for dividends at December 31, 2015 was limited to approximately $231.0 million. The Company has 10 million authorized shares of preferred stock. The Company did not have any preferred stock outstanding as of December 31, 2015 and 2014. Stock Repurchase Programs During 2014, Avista Corp.'s Board of Directors approved a program to repurchase up to 4 million shares of the Company’s outstanding common stock (2014 program). Repurchases of common stock under this program began on July 7, 2014 and the program expired on December 31, 2014. Repurchases were made in the open market or in privately negotiated transactions. Under the 2014 program the Company repurchased 2,529,615 shares at a total cost of $79.9 million and an average cost of $31.57 per share. The Company did not make any repurchases under this program subsequent to October 2014. Avista Corp. initiated a second stock repurchase program on January 2, 2015 that expired on March 31, 2015 for the repurchase of up to 800,000 shares of the Company's outstanding common stock (first quarter 2015 program). The number of shares repurchased through the first quarter 2015 program was in addition to the number of shares repurchased under the 2014 program, which expired on December 31, 2014. Under the first quarter 2015 program, the Company repurchased 89,400 shares at a total cost of $2.9 million and an average cost of $32.66 per share. All repurchased shares under the 2014 program and the first quarter 2015 program reverted to the status of authorized but unissued shares. 129 Staff_DR_063 Attachment A Page 138 of 180 Table of Contents AVISTA CORPORATION NOTE 18. EARNINGS PER COMMON SHARE ATTRIBUTABLE TO AVISTA CORPORATION SHAREHOLDERS The following table presents the computation of basic and diluted earnings per common share attributable to Avista Corp. shareholders for the years ended December 31 (in thousands, except per share amounts): 2015 2014 2013 Numerator: Net income from continuing operations attributable to Avista Corp. shareholders $118,080 $119,817 $104,273 Net income from discontinued operations attributable to Avista Corp. shareholders 5,147 72,224 6,804 Subsidiary earnings adjustment for dilutive securities (discontinued operations)— 5 (229) Adjusted net income from discontinued operations attributable to Avista Corp. shareholders for computation of diluted earnings per common share $5,147 $72,229 $6,575 Denominator: Weighted-average number of common shares outstanding-basic 62,301 61,632 59,960 Effect of dilutive securities: Performance and restricted stock awards 407 255 37 Weighted-average number of common shares outstanding-diluted 62,708 61,887 59,997 Earnings per common share attributable to Avista Corp. shareholders, basic: Earnings per common share from continuing operations $1.90 $1.94 $1.74 Earnings per common share from discontinued operations $0.08 $1.18 $0.11 Total earnings per common share attributable to Avista Corp. shareholders, basic $1.98 $3.12 $1.85 Earnings per common share attributable to Avista Corp. shareholders, diluted: Earnings per common share from continuing operations $1.89 $1.93 $1.74 Earnings per common share from discontinued operations $0.08 $1.17 $0.11 Total earnings per common share attributable to Avista Corp. shareholders, diluted $1.97 $3.10 $1.85 There were no shares excluded from the calculation because they were antidilutive. All stock options had exercise prices which were less than the average market price of Avista Corp. common stock during the respective period. NOTE 19. COMMITMENTS AND CONTINGENCIES In the course of its business, the Company becomes involved in various claims, controversies, disputes and other contingent matters, including the items described in this Note. Some of these claims, controversies, disputes and other contingent matters involve litigation or other contested proceedings. For all such matters, the Company intends to vigorously protect and defend its interests and pursue its rights. However, no assurance can be given as to the ultimate outcome of any particular matter because litigation and other contested proceedings are inherently subject to numerous uncertainties. For matters that affect Avista Utilities’ or AEL&P's operations, the Company intends to seek, to the extent appropriate, recovery of incurred costs through the ratemaking process. California Refund Proceeding Recently, APX, a market maker in these proceedings in whose markets Avista Energy participated in the summer of 2000, has asserted that Avista Energy and its other customer/participants may be responsible for a share of the disgorgement penalty APX may be found to owe to the California parties. The penalty arises as a result of the FERC finding that APX committed violations in the California market in the summer of 2000. APX is making these assertions despite Avista Energy having been dismissed in FERC Opinion No. 536 from the on-going administrative proceeding at the FERC regarding potential wrongdoing in the California markets in the summer of 2000. APX has identified Avista Energy’s share of APX’s exposure to be as much as $16.0 million even though no wrongdoing allegations are specifically attributable to Avista Energy. Avista Energy believes its settlement insulates it from any such liability and that as a dismissed party it cannot be drawn back into the litigation. Avista Energy intends to vigorously dispute APX’s assertions of indirect liability, but cannot at this time predict the eventual outcome. 130 Staff_DR_063 Attachment A Page 139 of 180 Table of Contents AVISTA CORPORATION Pacific Northwest Refund Proceeding In July 2001, the FERC initiated a preliminary evidentiary hearing to develop a factual record as to whether prices for spot market sales of wholesale energy in the Pacific Northwest between December 25, 2000 and June 20, 2001 were just and reasonable. In June 2003, the FERC terminated the Pacific Northwest refund proceedings, after finding that the equities do not justify the imposition of refunds. In August 2007, the Ninth Circuit found that the FERC had failed to take into account new evidence of market manipulation and that such failure was arbitrary and capricious and, accordingly, remanded the case to the FERC, stating that the FERC's findings must be reevaluated in light of the new evidence. The Ninth Circuit expressly declined to direct the FERC to grant refunds. On October 3, 2011, the FERC issued an Order on Remand. On April 5, 2013, the FERC issued an Order on Rehearing expanding the temporal scope of the proceeding to permit parties to submit evidence on transactions during the period from January 1, 2000 through and including June 20, 2001. The Order on Remand established an evidentiary, trial-type hearing before an ALJ, and reopened the record to permit parties to present evidence of unlawful market activity. The Order on Remand stated that parties seeking refunds must submit evidence demonstrating that specific unlawful market activity occurred, and must demonstrate that such activity directly affected negotiations with respect to the specific contract rate about which they complain. Simply alleging a general link between the dysfunctional spot market in California and the Pacific Northwest spot market would not be sufficient to establish a causal connection between a particular seller's alleged unlawful activities and the specific contract negotiations at issue. The hearing was conducted in August through October 2013. On July 11, 2012 and March 28, 2013, Avista Energy and Avista Utilities filed settlements of all issues in this docket with regard to the claims made by the City of Tacoma and the California AG (on behalf of CERS). The FERC has approved the settlements and they are final. The remaining direct claimant against Avista Utilities and Avista Energy in this proceeding is the City of Seattle, Washington (Seattle). With regard to the Seattle claims, on March 28, 2014, the Presiding ALJ issued her Initial Decision finding that: 1) Seattle failed to demonstrate that either Avista Utilities or Avista Energy engaged in unlawful market activity and also failed to identify any specific contracts at issue; 2) Seattle failed to demonstrate that contracts with either Avista Utilities or Avista Energy imposed an excessive burden on consumers or seriously harmed the public interest; and that 3) Seattle failed to demonstrate that either Avista Utilities or Avista Energy engaged in any specific violations of substantive provisions of the FPA or any filed tariffs or rate schedules. Accordingly, the ALJ denied all of Seattle’s claims under both section 206 and section 309 of the FPA. On May 22, 2015, the FERC issued its Order on Initial Decision in which it upheld the ALJ’s Initial Decision denying all of Seattle’s claims against Avista Utilities and Avista Energy. Seattle filed a Request for Rehearing of the FERC’s Order on Initial Decision which was denied on December 31, 2015. The Company does not expect that this matter will have a material adverse effect on its financial condition, results of operations or cash flows. Sierra Club and Montana Environmental Information Center Complaint Against the Owners of Colstrip On March 6, 2013, the Sierra Club and Montana Environmental Information Center (MEIC) (collectively "Plaintiffs"), filed a Complaint in the United States District Court for the District of Montana, Billings Division, against the Owners of the Colstrip Generating Project ("Colstrip"). Avista Corp. owns a 15 percent interest in Units 3 & 4 of Colstrip. The other Colstrip co-Owners are Talen (formerly PPL Montana), Puget Sound Energy, Portland General Electric Company, NorthWestern Energy and PacifiCorp. The Complaint alleges certain violations of the Clean Air Act, including the New Source Review, Title V and opacity requirements. On September 27, 2013, the Plaintiffs filed an Amended Complaint. The Amended Complaint withdrew from the original Complaint fifteen claims related to seven pre-January 1, 2001 Colstrip maintenance projects, upgrade projects and work projects and claims alleging violations of Title V and opacity requirements. The Amended Complaint alleges certain violations of the Clean Air Act and the New Source Review and adds claims with respect to post- January 1, 2001 Colstrip projects. On August 27, 2014, the Plaintiffs filed a Second Amended Complaint. The Second Amended Complaint withdraws from the Amended Complaint five claims and adds one new claim. The Second Amended Complaint alleges certain violations of the Clean Air Act and the New Source Review. The Plaintiffs request that the Court grant injunctive and declaratory relief, order remediation of alleged environmental damages, impose civil penalties, require a beneficial environmental project in the areas affected by the alleged air pollution and require payment of Plaintiffs’ costs of litigation and attorney fees. The Plaintiffs have since indicated that they do not intend to pursue two of the seven projects, leaving a total of five projects remaining. A number of motions for summary judgment were filed by both the Plaintiffs and the defendants. The Court issued its rulings on these motions and, as a result, only two projects remain for trial. The Plaintiffs have filed objections to the order. The case has been bifurcated into separate liability and remedy trials. The Court has set the liability trial date for May 31, 2016. No date has been set for the remedy trial. 131 Staff_DR_063 Attachment A Page 140 of 180 Table of Contents AVISTA CORPORATION Management believes that it is reasonably possible that this matter could result in a loss to the Company. However, due to uncertainties concerning this matter, Avista Corp. cannot predict the outcome or determine whether it would have a material impact on the Company. Cabinet Gorge Total Dissolved Gas Abatement Plan Dissolved atmospheric gas levels (referred to as "TDG") in the Clark Fork River exceed state of Idaho and federal water quality numeric standards downstream of Cabinet Gorge during periods when excess river flows must be diverted over the spillway. Under the terms of the Clark Fork Settlement Agreement as incorporated in Avista Corp.'s FERC license for the Clark Fork Project, Avista Corp. has worked in consultation with agencies, tribes and other stakeholders to address this issue. Under the terms of a gas supersaturation mitigation plan, Avista is reducing TDG by constructing spill crest modifications on spill gates at the dam, and the Company expects to continue spill crest modifications over the next several years, in ongoing consultation with key stakeholders. Avista Corp. cannot at this time predict the outcome or estimate a range of costs associated with this contingency; however, the Company will continue to seek recovery, through the ratemaking process, of all operating and capitalized costs related to this issue. Fish Passage at Cabinet Gorge and Noxon Rapids In 1999, the United States Fish and Wildlife Service (USFWS) listed bull trout as threatened under the Endangered Species Act. In 2010, the USFWS issued a revised designation of critical habitat for bull trout, which includes the lower Clark Fork River. The USFWS issued a final recovery plan in October 2015. The Clark Fork Settlement Agreement describes programs intended to help restore bull trout populations in the project area. Using the concept of adaptive management and working closely with the USFWS, the Company evaluated the feasibility of fish passage at Cabinet Gorge and Noxon Rapids. The results of these studies led, in part, to the decision to move forward with development of permanent facilities, among other bull trout enhancement efforts. Fishway designs for Cabinet Gorge have been completed, and the Company is developing construction cost estimates currently. The Company believes its ongoing efforts through the Clark Fork Settlement Agreement continue to effectively address issues related to bull trout. Avista Corp. cannot at this time predict the outcome or estimate a range of costs associated with this contingency; however, the Company will continue to seek recovery, through the ratemaking process, of all operating and capitalized costs related to fish passage at Cabinet Gorge and Noxon Rapids. Collective Bargaining Agreements The Company’s collective bargaining agreements with the IBEW represents approximately 45 percent of all of Avista Utilities’ employees. The agreement with the local union in Washington and Idaho representing the majority (approximately 90 percent) of the Avista Utilities' bargaining unit employees expires in March 2016. In October 2015, a new collective bargaining agreement concerning wages over the three-year period 2016 through 2018 was approved by the local IBEW in Washington and Idaho. The new collective bargaining agreement will be effective in March 2016. A three-year agreement in Oregon, which covers approximately 50 employees, expires in March 2017. A collective bargaining agreement with the local union of the IBEW in Alaska expires in March 2017. The collective bargaining agreement with the IBEW in Alaska represents approximately 54 percent of all AERC employees. The remainder of AERC's employees are non-union. There is a risk that if collective bargaining agreements expire and new agreements are not reached in each of our jurisdictions, employees could strike. Given the magnitude of employees that are covered by collective bargaining agreements, this could result in disruptions of our operations. However, the Company believes that the possibility of this occurring is remote. Customer Information and Work Management Systems Project Cost Recovery Over the past four years, Avista Corp. has invested significant capital into Project Compass. Project Compass was completed and went into service during the first quarter of 2015. As part of the Washington electric and natural gas general rate cases filed in February 2015 and the Oregon natural gas general rate case filed in May 2015, Avista Utilities requested the full recovery of the Washington and Oregon share of the costs associated with this project. On July 27, 2015, the UTC Staff in the Company's electric and natural gas general rate cases filed responsive testimony. Included in their testimony was a recommendation to disallow $12.7 million (Washington's share) of Project Compass costs primarily related to the delay in the completion of the project. In a UTC order received in January 2016, the UTC approved the full recovery of Washington's share of Project Compass costs with no disallowances. 132 Staff_DR_063 Attachment A Page 141 of 180 Table of Contents AVISTA CORPORATION In October 2015, the OPUC staff filed testimony in the Company's natural gas general rate case which included a recommendation to disallow $1.2 million (Oregon's share) of Project Compass costs, similar to the initial recommendation in Washington. In January 2016, following the January 2016 UTC order approving the full recovery of Washington's share of Project Compass costs, the OPUC staff withdrew its proposal for a disallowance, with the exception of an inconsequential amount which is still open for discussion. Other Contingencies In the normal course of business, the Company has various other legal claims and contingent matters outstanding. The Company believes that any ultimate liability arising from these actions will not have a material impact on its financial condition, results of operations or cash flows. It is possible that a change could occur in the Company’s estimates of the probability or amount of a liability being incurred. Such a change, should it occur, could be significant. The Company routinely assesses, based on studies, expert analyses and legal reviews, its contingencies, obligations and commitments for remediation of contaminated sites, including assessments of ranges and probabilities of recoveries from other responsible parties who either have or have not agreed to a settlement as well as recoveries from insurance carriers. The Company’s policy is to accrue and charge to current expense identified exposures related to environmental remediation sites based on estimates of investigation, cleanup and monitoring costs to be incurred. For matters that affect Avista Utilities’ or AEL&P's operations, the Company seeks, to the extent appropriate, recovery of incurred costs through the ratemaking process. The Company has potential liabilities under the Endangered Species Act for species of fish, plants and wildlife that have either already been added to the endangered species list, listed as “threatened” or petitioned for listing. Thus far, measures adopted and implemented have had minimal impact on the Company. However, the Company will continue to seek recovery, through the ratemaking process, of all operating and capitalized costs related to these issues. Under the federal licenses for its hydroelectric projects, the Company is obligated to protect its property rights, including water rights. In addition, the company holds additional non-hydro water rights. The state of Montana is examining the status of all water right claims within state boundaries through a general adjudication. Claims within the Clark Fork River basin could adversely affect the energy production of the Company’s Cabinet Gorge and Noxon Rapids hydroelectric facilities. The state of Idaho has initiated adjudication in northern Idaho, which will ultimately include the lower Clark Fork River, the Spokane River and the Coeur d’Alene basin. The Company is and will continue to be a participant in these and any other relevant adjudication processes. The complexity of such adjudications makes each unlikely to be concluded in the foreseeable future. As such, it is not possible for the Company to estimate the impact of any outcome at this time. The Company will continue to seek recovery, through the ratemaking process, of all operating and capitalized costs related to this issue. 133 Staff_DR_063 Attachment A Page 142 of 180 Table of Contents AVISTA CORPORATION NOTE 20. REGULATORY MATTERS Regulatory Assets and Liabilities The following table presents the Company’s regulatory assets and liabilities as of December 31, 2015 (dollars in thousands): Receiving Regulatory Treatment Remaining Amortization Period (1) Earning A Return Not Earning A Return (2) Expected Recovery or Refund Total 2015 Total 2014 Regulatory Assets: Investment in exchange power-net 2019 $8,983 $— $— $8,983 $11,433 Regulatory assets for deferred income tax (3) 101,240 — — 101,240 100,412 Regulatory assets for pensions and other postretirement benefit plans (4) — 235,009 — 235,009 235,758 Current regulatory asset for utility derivatives (5) — 17,260 — 17,260 29,640 Unamortized debt repurchase costs (6) 15,520 — — 15,520 17,357 Regulatory asset for settlement with Coeur d’Alene Tribe 2059 46,576 — — 46,576 47,887 Demand side management programs (3) — 3,168 — 3,168 4,603 Montana lease payments (3) 947 — — 947 1,984 Lancaster Plant 2010 net costs 2015 — — — — 1,247 Deferred maintenance costs 2017 — 4,823 — 4,823 5,804 Decoupling 2017 13,312 — — 13,312 — Power deferrals (3) 933 — — 933 8,291 Regulatory asset for interest rate swaps (7) — 83,973 — 83,973 77,063 Non-current regulatory asset for utility derivatives (5) — 32,420 — 32,420 24,483 Other regulatory assets (3) 3,132 7,412 4,924 15,468 13,038 Total regulatory assets $190,643 $384,065 $4,924 $579,632 $579,000 Regulatory Liabilities: Natural gas deferrals (3) $17,880 $— $— $17,880 $3,921 Power deferrals (3) 18,747 — — 18,747 14,186 Regulatory liability for utility plant retirement costs (8) 261,594 — — 261,594 254,140 Income tax related liabilities (3) — 17,609 — 17,609 14,534 Regulatory liability for Spokane Energy (9) — — — — 29,028 Regulatory liability for rate refunds (3) — 8,814 3,423 12,237 10,131 Decoupling 2017 2,373 — — 2,373 — Other regulatory liabilities (3) 2,395 1,048 — 3,443 7,688 Total regulatory liabilities $302,989 $27,471 $3,423 $333,883 $333,628 (1)Earning a return includes either interest on the regulatory asset/liability or a return on the investment as a component of rate base at the allowed rate of return. (2)Expected recovery is pending regulatory treatment including regulatory assets and liabilities with prior regulatory precedence. (3)Remaining amortization period varies depending on timing of underlying transactions. (4)As the Company has historically recovered and currently recovers its pension and other postretirement benefit costs related to its regulated operations in retail rates, the Company records a regulatory asset for that portion of its pension and other postretirement benefit funding deficiency. 134 Staff_DR_063 Attachment A Page 143 of 180 Table of Contents AVISTA CORPORATION (5)The UTC and the IPUC issued accounting orders authorizing Avista Corp. to offset commodity derivative assets or liabilities with a regulatory asset or liability. This accounting treatment is intended to defer the recognition of mark-to-market gains and losses on energy commodity transactions until the period of settlement. The orders provide for Avista Corp. to not recognize the unrealized gain or loss on utility derivative commodity instruments in the Consolidated Statements of Income. Realized gains or losses are recognized in the period of settlement, subject to approval for recovery through retail rates. Realized gains and losses, subject to regulatory approval, result in adjustments to retail rates through purchased gas cost adjustments, the ERM in Washington, the PCA mechanism in Idaho, and periodic general rates cases. (6)For the Company’s Washington jurisdiction and for any debt repurchases beginning in 2007 in all jurisdictions, premiums paid to repurchase debt are amortized over the remaining life of the original debt that was repurchased or, if new debt is issued in connection with the repurchase, these costs are amortized over the life of the new debt. In the Company’s other regulatory jurisdictions, premiums paid to repurchase debt prior to 2007 are being amortized over the average remaining maturity of outstanding debt when no new debt was issued in connection with the debt repurchase. These costs are recovered through retail rates as a component of interest expense. (7)For interest rate swap agreements, each period Avista Utilities records all mark-to-market gains and losses as assets and liabilities and records offsetting regulatory assets and liabilities, such that there is no income statement impact. This is similar to the treatment of energy commodity derivatives described above. Upon settlement of interest rate swaps, the regulatory asset or liability (included as part of long-term debt) is amortized as a component of interest expense over the term of the associated debt. (8)This amount is dependent upon the cost of removal of underlying utility plant assets and the life of utility plant. (9)Consists of a regulatory liability recorded for the cumulative retained earnings of Spokane Energy that the Company will flow through regulatory accounting mechanisms in future periods. During 2015, Spokane Energy was dissolved and the fixed rate electric capacity contract that was held at Spokane Energy was transferred to Avista Corp. Power Cost Deferrals and Recovery Mechanisms Deferred power supply costs are recorded as a deferred charge on the Consolidated Balance Sheets for future prudence review and recovery through retail rates. The power supply costs deferred include certain differences between actual net power supply costs incurred by Avista Utilities and the costs included in base retail rates. This difference in net power supply costs primarily results from changes in: •short-term wholesale market prices and sales and purchase volumes, •the level and availability of hydroelectric generation, •the level and availability of thermal generation (including changes in fuel prices), and •retail loads. In Washington, the ERM allows Avista Utilities to periodically increase or decrease electric rates with UTC approval to reflect changes in power supply costs. The ERM is an accounting method used to track certain differences between actual power supply costs, net of wholesale sales and sales of fuel, and the amount included in base retail rates for Washington customers. Total net deferred power costs under the ERM were a liability of $18.0 million as of December 31, 2015 compared to a liability of $14.2 million as of December 31, 2014, and these deferred power cost balances represent amounts due to customers. Avista Utilities has a PCA mechanism in Idaho that allows it to modify electric rates on October 1 of each year with IPUC approval. Under the PCA mechanism, Avista Utilities defers 90 percent of the difference between certain actual net power supply expenses and the amount included in base retail rates for its Idaho customers. These annual October 1 rate adjustments recover or rebate power costs deferred during the preceding July-June twelve-month period. Total net power supply costs deferred under the PCA mechanism were a regulatory asset of $0.2 million as of December 31, 2015 compared to a regulatory asset of $8.3 million as of December 31, 2014. Natural Gas Cost Deferrals and Recovery Mechanisms Avista Utilities files a PGA in all three states it serves to adjust natural gas rates for: 1) estimated commodity and pipeline transportation costs to serve natural gas customers for the coming year, and 2) the difference between actual and estimated commodity and transportation costs for the prior year. Total net deferred natural gas costs to be refunded to customers were a liability of $17.9 million as of December 31, 2015 compared to a liability of $3.9 million as of December 31, 2014. Decoupling and Earnings Sharing Mechanisms Decoupling is a mechanism designed to sever the link between a utility's revenues and consumers' energy usage. The Company's actual revenue, based on kilowatt hour and therm sales will vary, up or down, from the level included in a general 135 Staff_DR_063 Attachment A Page 144 of 180 Table of Contents AVISTA CORPORATION rate case, which could be caused by changes in weather, energy conservation or the economy. Generally, the Company's electric and natural gas revenues will be adjusted each month to be based on the number of customers, rather than kilowatt hour and therm sales. The difference between revenues based on sales and revenues based on the number of customers will be deferred and either surcharged or rebated to customers beginning in the following year. Washington Decoupling and Earnings Sharing In Washington, the UTC approved the Company's decoupling mechanisms for electric and natural gas for a five-year period that commenced January 1, 2015. Electric and natural gas decoupling surcharge rate adjustments to customers are limited to 3 percent on an annual basis, with any remaining surcharge balance carried forward for recovery in a future period. There is no limit on the level of rebate rate adjustments. The decoupling mechanisms each include an after-the-fact earnings test. At the end of each calendar year, separate electric and natural gas earnings calculations will be made for the prior calendar year. These earnings tests will reflect actual decoupled revenues, normalized power supply costs and other normalizing adjustments. As of December 31, 2015, the Company had a total net decoupling surcharge (asset) of $10.9 million for Washington electric and natural gas customers and a liability (rebate to customers) for earnings sharing of $3.4 million for Washington electric customers. Idaho Fixed Cost Adjustment (FCA) and Earnings Sharing Mechanisms In Idaho, the IPUC approved the implementation of FCAs for electric and natural gas (similar in operation and effect to the Washington decoupling mechanisms) for an initial term of three years, commencing on January 1, 2016. For the period 2013 through 2015, the Company had an after-the-fact earnings test, such that if Avista Corp., on a consolidated basis for electric and natural gas operations in Idaho, earned more than a 9.8 percent ROE, the Company was required to share with customers 50 percent of any earnings above the 9.8 percent. There was no provision for a surcharge to customers if the Company's ROE was less than 9.8 percent. This after-the-fact earnings test was discontinued as part of the settlement of the Company's 2015 Idaho electric and natural gas general rates cases. As of December 31, 2015 and December 31, 2014, the Company had total cumulative earnings sharing liabilities (rebates to customers) of $8.8 million and $10.1 million, respectively for electric and natural gas customers. NOTE 21. INFORMATION BY BUSINESS SEGMENTS The business segment presentation reflects the basis used by the Company's management to analyze performance and determine the allocation of resources. The Company's management evaluates performance based on income (loss) from operations before income taxes as well as net income (loss) attributable to Avista Corp. shareholders. The accounting policies of the segments are the same as those described in the summary of significant accounting policies. Avista Utilities' business is managed based on the total regulated utility operation; therefore, it is considered one segment. AEL&P (acquired in the AERC acquisition on July 1, 2014) is a separate reportable business segment as it has separate financial reports that are reviewed in detail by the Chief Operating Decision Maker and its operations and risks are sufficiently different from Avista Utilities and the other businesses at AERC that it cannot be aggregated with any other operating segments. All goodwill associated with the AERC acquisition was assigned to the AEL&P reportable business segment. The Other category, which is not a reportable segment, includes Spokane Energy, which was dissolved during the third quarter of 2015, other investments and operations of various subsidiaries, as well as certain other operations of Avista Capital. Ecova is a provider of facility information and cost management services for multi-site customers throughout North America. The Ecova business segment was disposed of as of June 30, 2014. All income statement amounts were reclassified to discontinued operations on the Consolidated Statements of Income for all periods presented. 136 Staff_DR_063 Attachment A Page 145 of 180 Table of Contents AVISTA CORPORATION The following table presents information for each of the Company’s business segments (dollars in thousands): Avista Utilities Alaska Electric Light and Power Company Total Utility Other Intersegment Eliminations (1) Total For the year ended December 31, 2015: Operating revenues $1,411,863 $44,778 $1,456,641 $28,685 $(550) $1,484,776 Resource costs 644,991 11,973 656,964 — — 656,964 Other operating expenses 292,096 11,125 303,221 30,076 (550) 332,747 Depreciation and amortization 138,236 5,263 143,499 695 — 144,194 Income (loss) from operations 241,228 14,072 255,300 (2,086) — 253,214 Interest expense (2)76,405 3,558 79,963 610 (132) 80,441 Income taxes 64,489 4,202 68,691 (1,242) — 67,449 Net income (loss) from continuing operations attributable to Avista Corp. shareholders 113,360 6,641 120,001 (1,921) — 118,080 Capital expenditures (3)381,174 12,251 393,425 885 — 394,310 For the year ended December 31, 2014: Operating revenues $1,413,499 $21,644 $1,435,143 $39,219 $(1,800) $1,472,562 Resource costs 672,344 5,900 678,244 — — 678,244 Other operating expenses 280,964 5,868 286,832 32,218 (1,800) 317,250 Depreciation and amortization 126,987 2,583 129,570 610 — 130,180 Income from operations 239,976 6,221 246,197 6,391 — 252,588 Interest expense (2)73,750 1,382 75,132 1,004 (384) 75,752 Income taxes 67,634 1,816 69,450 2,790 — 72,240 Net income from continuing operations attributable to Avista Corp. shareholders 113,263 3,152 116,415 3,236 166 119,817 Capital expenditures (3)323,931 1,585 325,516 406 — 325,922 For the year ended December 31, 2013: Operating revenues $1,403,995 $— $1,403,995 $39,549 $(1,800) $1,441,744 Resource costs 689,586 — 689,586 — — 689,586 Other operating expenses 276,228 — 276,228 40,451 (1,800) 314,879 Depreciation and amortization 117,174 — 117,174 581 — 117,755 Income (loss) from operations 232,572 — 232,572 (1,483) — 231,089 Interest expense (2)75,663 — 75,663 2,247 (325) 77,585 Income taxes 60,472 — 60,472 (2,458) — 58,014 Net income (loss) from continuing operations attributable to Avista Corp. shareholders 108,598 — 108,598 (4,650) 325 104,273 Capital expenditures (3)294,363 — 294,363 371 — 294,734 Total Assets: As of December 31, 2015 $4,601,708 $265,735 $4,867,443 $39,206 $— $4,906,649 As of December 31, 2014 (4)$4,357,760 $263,070 $4,620,830 $80,141 $— $4,700,971 As of December 31, 2013 (4) (5)$3,930,251 $— $3,930,251 $81,282 $— $4,011,533 (1)Intersegment eliminations reported as operating revenues and resource costs represent intercompany purchases and sales of electric capacity and energy between Avista Utilities and Spokane Energy (included in other). Intersegment eliminations reported as interest expense and net income (loss) attributable to Avista Corp. shareholders represent intercompany interest. (2)Including interest expense to affiliated trusts. 137 Staff_DR_063 Attachment A Page 146 of 180 Table of Contents AVISTA CORPORATION (3)The capital expenditures for the other businesses are included as other capital expenditures on the Consolidated Statements of Cash Flows. The remainder of the balance included in other capital expenditures on the Consolidated Statements of Cash Flows for 2014 and 2013 are related to Ecova. (4)The total assets balances as of December 31, 2014 and December 31, 2013 were updated to reflect the adoption of FASB ASU No. 2015-03, "Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs" as of December 31, 2015, which resulted in the reclassification of long-term debt issuance costs from an asset to a reduction of long-term debt. See Note 2 of the Notes to Consolidated Financial Statements for further discussion of the adoption of this ASU. (5)The total assets as of December 31, 2013 exclude the total assets associated with Ecova of $339.6 million. NOTE 22. SELECTED QUARTERLY FINANCIAL DATA (Unaudited) The Company’s energy operations are significantly affected by weather conditions. Consequently, there can be large variances in revenues, expenses and net income between quarters based on seasonal factors such as, but not limited to, temperatures and streamflow conditions. During the second quarter of 2014, Avista Corp. reported Ecova as discontinued operations (see Note 5). Accordingly, periods prior to the second quarter of 2014 were restated to reflect Ecova as discontinued operations. A summary of quarterly operations (in thousands, except per share amounts) for 2015 and 2014 follows: Three Months Ended March 31 June 30 September 30 December 31 2015 Operating revenues from continuing operations $446,490 $337,332 $313,649 $387,305 Operating expenses from continuing operations 356,915 279,972 277,737 316,938 Income from continuing operations $89,575 $57,360 $35,912 $70,367 Net income from continuing operations $46,462 $25,078 $12,754 $33,876 Net income from discontinued operations — 196 289 4,662 Net income 46,462 25,274 13,043 38,538 Net income attributable to noncontrolling interests (13) (28) (32) (17) Net income attributable to Avista Corporation shareholders $46,449 $25,246 $13,011 $38,521 Amounts attributable to Avista Corp. shareholders: Net income from continuing operations attributable to Avista Corp. shareholders $46,449 $25,050 $12,722 $33,859 Net income from discontinued operations attributable to Avista Corp. shareholders — 196 289 4,662 Net income attributable to Avista Corp. shareholders $46,449 $25,246 $13,011 $38,521 Outstanding common stock: Weighted average, basic 62,318 62,281 62,299 62,308 Weighted average, diluted 62,889 62,600 62,688 62,758 Earnings per common share attributable to Avista Corp. shareholders, diluted: Earnings per common share from continuing operations $0.74 $0.40 $0.21 $0.54 Earnings per common share from discontinued operations — — — 0.07 Total earnings per common share attributable to Avista Corp. shareholders, diluted $0.74 $0.40 $0.21 $0.61 138 Staff_DR_063 Attachment A Page 147 of 180 Table of Contents AVISTA CORPORATION Three Months Ended March 31 June 30 September 30 December 31 2014 Operating revenues from continuing operations $446,578 $312,580 $301,558 $411,846 Operating expenses from continuing operations 356,236 249,849 268,796 345,093 Income from continuing operations $90,342 $62,731 $32,762 $66,753 Net income from continuing operations $47,466 $31,270 $10,526 $30,604 Net income (loss) from discontinued operations 1,515 69,312 (55) 1,639 Net income 48,981 100,582 10,471 32,243 Net loss (income) attributable to noncontrolling interests (482) 289 (20) (23) Net income attributable to Avista Corporation shareholders $48,499 $100,871 $10,451 $32,220 Amounts attributable to Avista Corp. shareholders: Net income from continuing operations attributable to Avista Corp. shareholders $47,476 $31,254 $10,506 $30,581 Net income (loss) from discontinued operations attributable to Avista Corp. shareholders 1,023 69,617 (55) 1,639 Net income attributable to Avista Corp. shareholders $48,499 $100,871 $10,451 $32,220 Outstanding common stock: Weighted average, basic 60,122 60,184 63,934 62,290 Weighted average, diluted 60,168 60,463 64,244 62,671 Earnings per common share attributable to Avista Corp. shareholders, diluted: Earnings per common share from continuing operations $0.79 $0.52 $0.16 $0.48 Earnings per common share from discontinued operations 0.02 1.15 — 0.03 Total earnings per common share attributable to Avista Corp. shareholders, diluted $0.81 $1.67 $0.16 $0.51 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure Not applicable. Item 9A. Controls and Procedures Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures The Company has disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (Act) that are designed to ensure that information required to be disclosed in the reports it files or submits under the Act is recorded, processed, summarized and reported on a timely basis. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by the Company in the reports that it files or submits under the Act is accumulated and communicated to the Company’s management, including its principal executive and principal financial officers, as appropriate, to allow timely decisions regarding required disclosure. With the participation of the Company’s principal executive officer and principal financial officer, the Company's management evaluated its disclosure controls and procedures as of the end of the period covered by this report. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives. Based upon this evaluation, the Company’s principal executive officer and principal financial officer have concluded that the Company’s disclosure controls and procedures are effective at a reasonable assurance level as of December 31, 2015. Management’s Report on Internal Control Over Financial Reporting The Company’s management, together with its consolidated subsidiaries, is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934). The Company’s internal control over financial reporting is a process designed under the supervision of the Company’s principal executive officer and principal financial officer to provide reasonable assurance regarding the reliability of financial reporting 139 Staff_DR_063 Attachment A Page 148 of 180 Table of Contents AVISTA CORPORATION and the preparation of the Company’s financial statements for external reporting purposes in accordance with accounting principles generally accepted in the United States of America. The Company’s internal control over financial reporting includes policies and procedures that pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect transactions and dispositions of assets; provide reasonable assurances that transactions are recorded as necessary to permit preparation of financial statements in accordance with accounting principles generally accepted in the United States of America, and that receipts and expenditures are being made only in accordance with authorizations of management and the directors of the Company; and provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the Company’s financial statements. Under the supervision and with the participation of the Company’s management, including the Company’s principal executive officer and principal financial officer, the Company conducted an assessment of the effectiveness of the Company’s internal control over financial reporting based on the framework established in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, management determined that the Company’s internal control over financial reporting as of December 31, 2015 is effective at a reasonable assurance level. The Company’s independent registered public accounting firm, Deloitte & Touche LLP, has issued an attest report on the Company’s internal control over financial reporting as of December 31, 2015. Changes in Internal Control Over Financial Reporting There have been no changes in the Company’s internal control over financial reporting that occurred during the Company’s last fiscal quarter that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting. 140 Staff_DR_063 Attachment A Page 149 of 180 Table of Contents AVISTA CORPORATION REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors and Shareholders of Avista Corporation Spokane, Washington We have audited the internal control over financial reporting of Avista Corporation and subsidiaries (the “Company”) as of December 31, 2015, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements. Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2015, based on the criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2015 of the Company and our report dated February 23, 2016 expressed an unqualified opinion on those financial statements. /s/ Deloitte & Touche LLP Seattle, Washington February 23, 2016 141 Staff_DR_063 Attachment A Page 150 of 180 Table of Contents AVISTA CORPORATION Item 9B. Other Information None. PART III Item 10. Directors, Executive Officers and Corporate Governance The information required by this Item (other than the information regarding executive officers and the Company's Code of Business Conduct and Ethics set forth below) is omitted pursuant to General Instruction G to Form 10-K. Such information is incorporated herein by reference as follows: •on and after the date of filing with the SEC the Registrant's definitive Proxy Statement relating to its Annual Meeting of Shareholders scheduled to be held on May 12, 2016, from such Proxy Statement; and •prior to such date, from the Registrant's definitive Proxy Statement, dated March 27, 2015, relating to its Annual Meeting of Shareholders held on May 7, 2015. Executive Officers of the Registrant Name Age Business Experience Scott L. Morris 58 Chairman, President and Chief Executive Officer effective January 1, 2008. Director since February 9, 2007; President and Chief Operating Officer May 2006 – December 2007; Senior Vice President February 2002 – May 2006; Vice President November 2000 – February 2002; President – Avista Utilities August 2000 – December 2008; General Manager – Avista Utilities for the Oregon and California operations October 1991 – August 2000; various other management and staff positions with the Company since 1981. Mark T. Thies 52 Treasurer since January 2013; Senior Vice President and Chief Financial Officer (Principal Financial Officer) since September 2008; prior to employment with the Company held the following positions with Black Hills Corporation: Executive Vice President and Chief Financial Officer March 2003 to January 2008; Senior Vice President and Chief Financial Officer March 2000 to March 2003; Controller May 1997 to March 2000. Marian M. Durkin 62 Senior Vice President, General Counsel and Chief Compliance Officer since November 2005; Senior Vice President and General Counsel August 2005 – November 2005; prior to employment with the Company: held several legal positions with United Air Lines, Inc. from 1995 to August 2005, most recently served as Vice President Deputy General Counsel and Assistant Secretary. Karen S. Feltes 60 Senior Vice President of Human Resources and Corporate Secretary since November 2005; Vice President of Human Resources and Corporate Secretary March 2003 – November 2005; Vice President of Human Resources and Corporate Services February 2002 – March 2003; various human resources positions with the Company April 1998 – February 2002. Dennis P. Vermillion 54 Senior Vice President since January 2010; Vice President July 2007- December 2009; President – Avista Utilities since January 2009; Vice President of Energy Resources and Optimization – Avista Utilities July 2007 – December 2008; President and Chief Operating Officer of Avista Energy February 2001 – July 2007; various other management and staff positions with the Company since 1985. Jason R. Thackston 45 Senior Vice President since January 2014; Vice President of Energy Resources since December 2012; Vice President of Customer Solutions – Avista Utilities June 2012 - December 2012; Vice President of Energy Delivery April 2011 – December 2012; Vice President of Finance June 2009 – April 2011; various other management and staff positions with the Company since 1996. Ryan L. Krasselt 46 Vice President, Controller and Principal Accounting Officer since October 2015; various other management and staff positions with the Company since 2001. Kevin J. Christie 48 Vice President of Customer Solutions since February 2015; various other management and staff positions with the Company since 2005. James M. Kensok 57 Vice President and Chief Information Officer since January 2007; Chief Information Officer February 2001 – December 2006; various other management and staff positions with the Company since 1996. David J. Meyer 62 Vice President and Chief Counsel for Regulatory and Governmental Affairs since February 2004; Senior Vice President and General Counsel September 1998 – February 2004. 142 Staff_DR_063 Attachment A Page 151 of 180 Table of Contents AVISTA CORPORATION Executive Officers of the Registrant Name Age Business Experience Kelly O. Norwood 57 Vice President since November 2000; Vice President of State and Federal Regulation – Avista Utilities since March 2002; Vice President and General Manager of Energy Resources - Avista Utilities August 2000 – March 2002; various other management and staff positions with the Company since 1981. Heather L. Rosentrater 38 Vice President of Energy Delivery and Customer Service since December 2015; various other management and staff positions with the Company since 1996. Ed D. Schlect 55 Vice President and Chief Strategy Officer since September 2015; prior to employment with the Company was the Executive Vice President of Corporate Development at Ecova, Inc. Roger D. Woodworth 59 President of Avista Development since December 2015; Vice President November 1998 – November 2015; Vice President and Chief Strategy Officer April 2011 – September 2015; Vice President, Sustainable Energy Solutions Avista Utilities February 2007 – April 2011; Vice President, Customer Solutions for Avista Utilities March 2003 – February 2007; Vice President of Utility Operations of Avista Utilities September 2001 – March 2003; Vice President – Corporate Development November 1998 – September 2001; various other management and staff positions with the Company since 1979. All of the Company’s executive officers, with the exception of James M. Kensok, David J. Meyer, Kelly O. Norwood, Kevin J. Christie and Heather L. Rosentrater were officers or directors of one or more of the Company’s subsidiaries in 2015. The Company’s executive officers are elected annually by the Board of Directors. The Company has adopted a Code of Conduct for directors, officers (including the principal executive officer, principal financial officer and principal accounting officer), and employees. The Code of Conduct is available on the Company’s Web site at www.avistacorp.com and will also be provided to any shareholder without charge upon written request to: Avista Corp. General Counsel P.O. Box 3727 MSC-12 Spokane, Washington 99220-3727 Any changes to or waivers for executive officers and directors of the Company’s Code of Conduct will be posted on the Company’s Web site. Item 11. Executive Compensation The information required by this Item is omitted pursuant to General Instruction G to Form 10-K. Such information is incorporated herein by reference as follows: •on and after the date of filing with the SEC the Registrant's definitive Proxy Statement relating to its Annual Meeting of Shareholders scheduled to be held on May 12, 2016, from such Proxy Statement; and •prior to such date, from the Registrant's definitive Proxy Statement, dated March 27, 2015, relating to its Annual Meeting of Shareholders held on May 7, 2015. Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters (a)Security ownership of certain beneficial owners (owning 5 percent or more of Registrant’s voting securities): Information regarding security ownership of certain beneficial owners (owning 5 percent or more of Registrant’s voting securities) has been omitted pursuant to General Instruction G to Form 10-K. Such information is incorporated herein by reference as follows: •on and after the date of filing with the SEC the Registrant's definitive Proxy Statement relating to its Annual Meeting of Shareholders scheduled to be held on May 12, 2016, from such Proxy Statement; and •prior to such date, from the Registrant's definitive Proxy Statement, dated March 27, 2015, relating to its Annual Meeting of Shareholders held on May 7, 2015; reference also being made to Schedules 13G, as amended, in file with the SEC with respect to the Registrant's voting securities (the information contained in such schedules 13G, as amended, not being incorporated herein by reference). 143 Staff_DR_063 Attachment A Page 152 of 180 Table of Contents AVISTA CORPORATION (b)Security ownership of management: The information required by this Item regarding the security ownership of management is omitted pursuant to General Instruction G to Form 10-K. Such information is incorporated herein by reference as follows: •on and after the date of filing with the SEC the Registrant's definitive Proxy Statement relating to its Annual Meeting of Shareholders scheduled to be held on May 12, 2016, from such Proxy Statement; and •prior to such date, from the Registrant's definitive Proxy Statement, dated March 27, 2015, relating to its Annual Meeting of Shareholders held on May 7, 2015. (c)Changes in control: None. (d)Securities authorized for issuance under equity compensation plans as of December 31, 2015: Plan category (a) Number of securities to be issued upon exercise of outstanding options, warrants and rights (b) Weighted average exercise price of outstanding options, warrants and rights (c) Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) (1) Equity compensation plans approved by security holders (2)— $— 398,571 (1)Excludes unvested restricted shares and performance share awards granted under Avista Corp.’s Long Term Incentive Plan. At December 31, 2015, 106,091 Restricted Share awards were outstanding. Performance and market-based share awards may be paid out at zero shares at a minimum achievement level; 335,584 shares at target level; or 671,168 shares at a maximum level. Because there is no exercise price associated with restricted shares or performance and market-based share awards, such shares are not included in the weighted-average price calculation. (2)Includes the Long-Term Incentive Plan approved by shareholders in 1998 and the Non-Employee Director Stock Plan approved by shareholders in 1996. In February 2005, the Board of Directors elected to terminate the Non-Employee Director Stock Plan. Item 13. Certain Relationships and Related Transactions, and Director Independence The information required by this Item is omitted pursuant to General Instruction G to Form 10-K. Such information is incorporated herein by reference as follows: •on and after the date of filing with the SEC the Registrant's definitive Proxy Statement relating to its Annual Meeting of Shareholders scheduled to be held on May 12, 2016, from such Proxy Statement; and •prior to such date, from the Registrant's definitive Proxy Statement, dated March 27, 2015, relating to its Annual Meeting of Shareholders held on May 7, 2015. Item 14. Principal Accounting Fees and Services The information required by this Item is omitted pursuant to General Instruction G to Form 10-K. Such information is incorporated herein by reference as follows: •on and after the date of filing with the SEC the Registrant's definitive Proxy Statement relating to its Annual Meeting of Shareholders scheduled to be held on May 12, 2016, from such Proxy Statement; and •prior to such date, from the Registrant's definitive Proxy Statement, dated March 27, 2015, relating to its Annual Meeting of Shareholders held on May 7, 2015. 144 Staff_DR_063 Attachment A Page 153 of 180 Table of Contents AVISTA CORPORATION PART IV Item 15. Exhibits, Financial Statement Schedules (a)1. Financial Statements (Included in Part II of this report): Report of Independent Registered Public Accounting Firm Consolidated Statements of Income for the Years Ended December 31, 2015, 2014 and 2013 Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2015, 2014 and 2013 Consolidated Balance Sheets as of December 31, 2015 and 2014 Consolidated Statements of Cash Flows for the Years Ended December 31, 2015, 2014 and 2013 Consolidated Statements of Equity and Redeemable Noncontrolling Interests for the Years Ended December 31, 2015, 2014 and 2013 Notes to Consolidated Financial Statements (a)2. Financial Statement Schedules: None (a)3. Exhibits: Reference is made to the Exhibit Index commencing on page 148. The Exhibits include the management contracts and compensatory plans or arrangements required to be filed as exhibits to this Form 10-K pursuant to Item 15(b). 145 Staff_DR_063 Attachment A Page 154 of 180 Table of Contents AVISTA CORPORATION SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. AVISTA CORPORATION February 23, 2016 By /s/ Scott L. Morris Date Scott L. Morris Chairman of the Board, President and Chief Executive Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated. Signature Title Date /s/ Scott L. Morris Principal Executive Officer February 23, 2016 Scott L. Morris Chairman of the Board, President and Chief Executive Officer /s/ Mark T. Thies Principal Financial Officer February 23, 2016 Mark T. Thies (Senior Vice President, Chief Financial Officer, and Treasurer) /s/ Ryan L. Krasselt Principal Accounting Officer February 23, 2016 Ryan L. Krasselt (Vice President, Controller and Principal Accounting Officer) /s/ Erik J. Anderson Director February 23, 2016 Erik J. Anderson /s/ Kristianne Blake Director February 23, 2016 Kristianne Blake /s/ Donald C. Burke Director February 23, 2016 Donald C. Burke /s/ John F. Kelly Director February 23, 2016 John F. Kelly /s/ Rebecca A. Klein Director February 23, 2016 Rebecca A. Klein /s/ Marc F. Racicot Director February 23, 2016 Marc F. Racicot 146 Staff_DR_063 Attachment A Page 155 of 180 Table of Contents AVISTA CORPORATION /s/ Heidi B. Stanley Director February 23, 2016 Heidi B. Stanley /s/ R. John Taylor Director February 23, 2016 R. John Taylor /s/ Janet D. Widmann Director February 23, 2016 Janet D. Widmann 147 Staff_DR_063 Attachment A Page 156 of 180 Table of Contents AVISTA CORPORATION EXHIBIT INDEX Previously Filed (1) Exhibit With Registration Number As Exhibit 3.1 (with June 30, 2012 Form 10-Q) 3.1 Restated Articles of Incorporation of Avista Corporation, as amended and restated June 6, 2012. 3.2 (with Form 8-K filed as of November 14, 2014) 3.2 Bylaws of Avista Corporation, as amended November 14, 2014. 4.1 2-4077 B-3 Mortgage and Deed of Trust, dated as of June 1, 1939. 4.2 2-9812 4(c) First Supplemental Indenture, dated as of October 1, 1952. 4.3 2-60728 2(b)-2 Second Supplemental Indenture, dated as of May 1, 1953. 4.4 2-13421 4(b)-3 Third Supplemental Indenture, dated as of December 1, 1955. 4.5 2-13421 4(b)-4 Fourth Supplemental Indenture, dated as of March 15, 1967. 4.6 2-60728 2(b)-5 Fifth Supplemental Indenture, dated as of July 1, 1957. 4.7 2-60728 2(b)-6 Sixth Supplemental Indenture, dated as of January 1, 1958. 4.8 2-60728 2(b)-7 Seventh Supplemental Indenture, dated as of August 1, 1958. 4.9 2-60728 2(b)-8 Eighth Supplemental Indenture, dated as of January 1, 1959. 4.10 2-60728 2(b)-9 Ninth Supplemental Indenture, dated as of January 1, 1960. 4.11 2-60728 2(b)-10 Tenth Supplemental Indenture, dated as of April 1, 1964. 4.12 2-60728 2(b)-11 Eleventh Supplemental Indenture, dated as of March 1, 1965. 4.13 2-60728 2(b)-12 Twelfth Supplemental Indenture, dated as of May 1, 1966. 4.14 2-60728 2(b)-13 Thirteenth Supplemental Indenture, dated as of August 1, 1966. 4.15 2-60728 2(b)-14 Fourteenth Supplemental Indenture, dated as of April 1, 1970. 4.16 2-60728 2(b)-15 Fifteenth Supplemental Indenture, dated as of May 1, 1973. 4.17 2-60728 2(b)-16 Sixteenth Supplemental Indenture, dated as of February 1, 1975. 4.18 2-60728 2(b)-17 Seventeenth Supplemental Indenture, dated as of November 1, 1976. 4.19 2-69080 2(b)-18 Eighteenth Supplemental Indenture, dated as of June 1, 1980. 4.20 (with 1980 Form 10-K) 4(a)-20 Nineteenth Supplemental Indenture, dated as of January 1, 1981. 4.21 2-79571 4(a)-21 Twentieth Supplemental Indenture, dated as of August 1, 1982. 4.22 (with Form 8-K dated September 20, 1983) 4(a)-22 Twenty-First Supplemental Indenture, dated as of September 1, 1983. 4.23 2-94816 4(a)-23 Twenty-Second Supplemental Indenture, dated as of March 1, 1984. 148 Staff_DR_063 Attachment A Page 157 of 180 Table of Contents AVISTA CORPORATION Previously Filed (1) Exhibit With Registration Number As Exhibit 4.24 (with 1986 Form 10-K) 4(a)-24 Twenty-Third Supplemental Indenture, dated as of December 1, 1986. 4.25 (with 1987 Form 10-K) 4(a)-25 Twenty-Fourth Supplemental Indenture, dated as of January 1, 1988. 4.26 (with 1989 Form 10-K) 4(a)-26 Twenty-Fifth Supplemental Indenture, dated as of October 1, 1989. 4.27 33-51669 4(a)-27 Twenty-Sixth Supplemental Indenture, dated as of April 1, 1993. 4.28 (with 1993 Form 10-K) 4(a)-28 Twenty-Seventh Supplemental Indenture, dated as of January 1, 1994. 4.29 (with 2001 Form 10-K) 4(a)-29 Twenty-Eighth Supplemental Indenture, dated as of September 1, 2001. 4.30 333-82502 4(b) Twenty-Ninth Supplemental Indenture, dated as of December 1, 2001. 4.31 (with June 30, 2002 Form 10-Q) 4(f) Thirtieth Supplemental Indenture, dated as of May 1, 2002. 4.32 333-39551 4(b) Thirty-First Supplemental Indenture, dated as of May 1, 2003. 4.33 (with September 30, 2003 Form 10- Q) 4(f) Thirty-Second Supplemental Indenture, dated as of September 1, 2003. 4.34 333-64652 4(a)33 Thirty-Third Supplemental Indenture, dated as of May 1, 2004. 4.35 (with Form 8-K dated as of December 15, 2004) 4.1 Thirty-Fourth Supplemental Indenture, dated as of November 1, 2004. 4.36 (with Form 8-K dated as of December 15, 2004) 4.2 Thirty-Fifth Supplemental Indenture, dated as of December 1, 2004. 4.37 (with Form 8-K dated as of December 15, 2004) 4.3 Thirty-Sixth Supplemental Indenture, dated as of December 1, 2004. 4.38 (with Form 8-K dated as of December 15, 2004) 4.4 Thirty-Seventh Supplemental Indenture, dated as of December 1, 2004. 4.39 (with Form 8-K dated as of May 12, 2005) 4.1 Thirty-Eighth Supplemental Indenture, dated as of May 1, 2005. 4.40 (with Form 8-K dated as of November 17, 2005) 4.1 Thirty-Ninth Supplemental Indenture, dated as of November 1, 2005. 4.41 (with Form 8-K dated as of April 6, 2006) 4.1 Fortieth Supplemental Indenture, dated as of April 1, 2006. 4.42 (with Form 8-K dated as of December 15, 2006) 4.1 Forty-First Supplemental Indenture, dated as of December 1, 2006. 4.43 (with Form 8-K dated as of April 3, 2008) 4.1 Forty-Second Supplemental Indenture, dated as of April 1, 2008. 4.44 (with Form 8-K dated as of November 26, 2008) 4.1 Forty-Third Supplemental Indenture, dated as of November 1, 2008. 4.45 (with Form 8-K dated as of December 16, 2008) 4.1 Forty-Fourth Supplemental Indenture, dated as of December 1, 2008. 4.46 (with Form 8-K dated as of December 30, 2008) 4.3 Forty-Fifth Supplemental Indenture, dated as of December 1, 2008. 4.47 (with Form 8-K dated as of September 15, 2009) 4.1 Forty-Sixth Supplemental Indenture, dated as of September 1, 2009. 4.48 (with Form 8-K dated as of November 25, 2009) 4.1 Forty-Seventh Supplemental Indenture, dated as of November 1, 2009. 4.49 (with Form 8-K dated as of December 15, 2010) 4.5 Forty-Eighth Supplemental Indenture, dated as of December 1, 2010. 4.50 (with Form 8-K dated as of December 20, 2010) 4.1 Forty-Ninth Supplemental Indenture, dated as of December 1, 2010. 149 Staff_DR_063 Attachment A Page 158 of 180 Table of Contents AVISTA CORPORATION Previously Filed (1) Exhibit With Registration Number As Exhibit 4.51 (with Form 8-K dated as of December 30, 2010) 4.1 Fiftieth Supplemental Indenture, dated as of December 1, 2010. 4.52 (with Form 8-K dated as of February 11, 2011) 4.1 Fifty-First Supplemental Indenture, dated as of February 1, 2011. 4.53 (with Form 8-K dated as of August 16, 2011) 4.1 Fifty-Second Supplemental Indenture, dated as of August 1, 2011. 4.54 (with Form 8-K dated as of December 14, 2011) 4.1 Fifty-Third Supplemental Indenture, dated as of December 1, 2011. 4.55 (with Form 8-K dated as of November 30, 2012) 4.1 Fifty-Fourth Supplemental Indenture, dated as of November 1, 2012. 4.56 (with Form 8-K dated as of August 14, 2013) 4.1 Fifty-Fifth Supplemental Indenture, dated as of August 1, 2013. 4.57 (with Form 8-K dated as of April 18, 2014) 4.1 Fifty-Sixth Supplemental Indenture, dated as of April 1, 2014. 4.58 (with Form 8-K dated as of December 18, 2014) 4.1 Fifty-Seventh Supplemental Indenture, dated as of December 1, 2014. 4.59 (with Form 8-K dated as of December 16, 2015) 4.1 Fifty-Eighth Supplemental Indenture, dated as of December 1, 2015. 4.60 (with Form 8-K dated as of December 15, 2004) 4.5 Supplemental Indenture No. 1, dated as of December 1, 2004 to the Indenture dated as of April 1, 1998 between Avista Corporation and JPMorgan Chase Bank, N.A. 4.61 333-82165 4(a) Indenture dated as of April 1, 1998 between Avista Corporation and The Bank of New York, as Successor Trustee. 4.62 (with Form 8-K dated as of December 15, 2010) 4.1 Loan Agreement between City of Forsyth, Montana and Avista Corporation $66,700,000 City of Forsyth, Montana Pollution Control Revenue Refunding Bonds (Avista Corporation Colstrip Project) Series 2010A dated as of December 1, 2010. 4.63 (with Form 8-K dated as of December 15, 2010) 4.3 Trust Indenture between City of Forsyth, and the Bank of New York Mellon Trust Company, N.A., as Trustee, $66,700,000 City of Forsyth, Montana Pollution Control Revenue Refunding Bonds (Avista Corporation Colstrip Project) Series 2010A, dated as of December 1, 2010. 4.64 (with Form 8-K dated as of December 15, 2010) 4.2 Loan Agreement between City of Forsyth, Montana and Avista Corporation $17,000,000 City of Forsyth, Montana Pollution Control Revenue Refunding Bonds (Avista Corporation Colstrip Project) Series 2010B dated as of December 1, 2010. 4.65 (with Form 8-K dated as of December 15, 2010) 4.4 Trust Indenture between City of Forsyth, and the Bank of New York Mellon Trust Company, N.A., as Trustee, $17,000,000 City of Forsyth, Montana Pollution Control Revenue Refunding Bonds (Avista Corporation Colstrip Project) Series 2010B, dated as of December 1, 2010. 4.66 (with June 30, 2012 Form 10-Q) 3.1 Restated Articles of Incorporation of Avista Corporation, as amended and restated June 6, 2012 (see Exhibit 3.1 herein). 4.67 (with Form 8-K filed as of November 14, 2014) 3.2 Bylaws of Avista Corporation, as amended November 14, 2014 (see Exhibit 3.2 herein). 4.68 (Form 10/A) N/A Post-Effective Amendment No. 1 on Form 10/A, filed February 26, 2015, to Registration Statement on Form 10, filed September 1952. 10.1 (with Form 8-K dated as of February 11, 2011) 10.1 Credit Agreement, dated as of February 11, 2011, among Avista Corporation, the Banks Party hereto, The Bank of New York Mellon, Keybank National Association, and U.S. Bank National Association, as Co-Documentation Agents, Wells Fargo Bank National Association as Syndication Agent and an Issuing Bank, and Union Bank N.A. as Administrative Agent and an Issuing Bank. 10.2 (with Form 8-K dated as of February 11, 2011) 10.2 Bond Delivery Agreement, dated as of February 11, 2011, between Avista Corporation and Union Bank, N.A. 150 Staff_DR_063 Attachment A Page 159 of 180 Table of Contents AVISTA CORPORATION Previously Filed (1) Exhibit With Registration Number As Exhibit 10.3 (with Form 8-K dated as of April 18, 2014) 10.1 Second Amendment to Credit Agreement, dated as of April 18, 2014, among Avista Corporation, Wells Fargo Bank, National Association, as an Issuing Bank, Union Bank, N.A. as Administrative Agent and an Issuing Bank, and the financial institutions identified hereof as Continuing Lenders and Exiting Lender. 10.4 (with Form 8-K dated as of April 18, 2014) 10.2 Bond Delivery Agreement, dated as of April 18, 2014, between Avista Corporation and Union Bank, N.A. 10.5 (with Form 8-K dated as of August 14, 2013) 10.1 Term Loan Agreement, dated as of August 14, 2013, among Avista Corporation, the Lenders Party hereto and Union Bank N.A. as Administrative Agent. 10.6 (with Form 8-K dated as of August 14, 2013) 10.2 Bond Delivery Agreement, dated as of August 14, 2013, between Avista Corporation and Union Bank, N.A. 10.7 (with Form 8-K dated as of December 14, 2011) 10.1 First Amendment and Waiver Thereunder, dated as of December 14, 2011, to the Credit Agreement dated as of February 11, 2011, among Avista Corporation, the Banks Party hereto, Wells Fargo Bank National Association as an Issuing Bank, and Union Bank N.A. as Administrative Agent and an Issuing Bank. 10.8 (with 2002 Form 10-K) 10(b)-3 Priest Rapids Project Product Sales Contract executed by Public Utility District No. 2 of Grant County, Washington and Avista Corporation dated December 12, 2001 (effective November 1, 2005 for the Priest Rapids Development and November 1, 2009 for the Wanapum Development). 10.9 (with 2002 Form 10-K) 10(b)-4 Priest Rapids Project Reasonable Portion Power Sales Contract executed by Public Utility District No. 2 of Grant County, Washington and Avista Corporation dated December 12, 2001 (effective November 1, 2005 for the Priest Rapids Development and November 1, 2009 for the Wanapum Development). 10.10 (with 2002 Form 10-K) 10(b)-5 Additional Product Sales Agreement (Priest Rapids Project) executed by Public Utility District No. 2 of Grant County, Washington and Avista Corporation dated December 12, 2001 (effective November 1, 2005 for the Priest Rapids Development and November 1, 2009 for the Wanapum Development). 10.11 2-60728 5(g) Power Sales Contract (Wells Project) with Public Utility District No. 1 of Douglas County, Washington, dated as of September 18, 1963. 10.12 2-60728 5(g)-1 Amendment to Power Sales Contract (Wells Project) with Public Utility District No. 1 of Douglas County, Washington, dated as of February 9, 1965. 10.13 2-60728 5(h) Reserved Share Power Sales Contract (Wells Project) with Public Utility District No. 1 of Douglas County, Washington, dated as of September 18, 1963. 10.14 2-60728 5(h)-1 Amendment to Reserved Share Power Sales Contract (Wells Project) with Public Utility District No. 1 of Douglas County, Washington, dated as of February 9, 1965. 10.15 (with September 30, 1985 Form 10- Q) 1 Settlement Agreement and Covenant Not to Sue executed by the United States Department of Energy acting by and through the Bonneville Power Administration and the Company, dated as of September 17, 1985, describing the settlement of Project 3 litigation. 10.16 (with 1981 Form 10-K) 10(s)-7 Ownership and Operation Agreement for Colstrip Units No. 3 and 4, dated as of May 6, 1981. 10.17 (with 1992 Form 10-K) 10(s)-1 Agreements for Purchase and Sale of Firm Capacity between the Company and Portland General Electric Company dated March and June 1992. 10.18 (with 2011 Form 10-K) 10.15 Avista Corporation Executive Deferral Plan. (3) 10.19 (with 2011 Form 10-K) 10.16 Avista Corporation Executive Deferral Plan. (3)(8) 151 Staff_DR_063 Attachment A Page 160 of 180 Table of Contents AVISTA CORPORATION Previously Filed (1) Exhibit With Registration Number As Exhibit 10.20 (with 2011 Form 10-K) 10.17 Avista Corporation Supplemental Executive Retirement Plan. (3)(8) 10.21 (with 2011 Form 10-K) 10.18 Avista Corporation Supplemental Executive Retirement Plan. (3)(8) 10.22 (with 1992 Form 10-K) 10(t)-11 The Company’s Unfunded Supplemental Executive Disability Plan. (3) 10.23 (with 2007 Form 10-K) 10.34 Income Continuation Plan of the Company. (3) 10.24 (with 2010 Definitive Proxy Statement filed March 31, 2010) Appendix A Avista Corporation Long-Term Incentive Plan. (3) 10.25 (with 2010 Form 10-K) 10.23 Avista Corporation Performance Award Plan Summary. (3) 10.26 (with 2010 Form 10-K) 10.24 Avista Corporation Performance Award Agreement 2010. (3) 10.27 (with 2011 Form 10-K) 10.24 Avista Corporation Performance Award Agreement 2011. (3) 10.28 (with 2012 Form 10-K) 10.25 Avista Corporation Performance Award Agreement 2012. (3) 10.29 (with 2013 Form 10-K) 10.27 Avista Corporation Performance Award Agreement 2013. (3) 10.30 (with 2014 Form 10-K) 10.30 Avista Corporation Performance Award Agreement 2014. (3) 10.31 (2) Avista Corporation Performance Award Agreement 2015. (3) 10.32 (with Form 8-K dated June 21, 2005) 10.1 Employment Agreement between the Company and Marian Durkin in the form of a Letter of Employment. (3) 10.33 (with Form 8-K dated August 13, 2008) 10.1 Employment Agreement between the Company and Mark T. Thies in the form of a Letter of Employment. (3) 10.34 333-47290 99.1 Non-Officer Employee Long-Term Incentive Plan. 10.35 (with 2010 Form 10-K) Form of Change of Control Agreement between the Company and its Executive Officers. (3)(5) 10.36 (with 2010 Form 10-K) Form of Change of Control Agreement between the Company and its Executive Officers. (3)(6) 10.37 (with 2010 Form 10-K) Form of Change of Control Agreement between the Company and its Executive Officers. (3)(7) 10.38 (with 2010 Form 10-K) Form of Change of Control Agreement between the Company and its Executive Officers. (3)(7) 10.39 (2) Avista Corporation Non-Employee Director Compensation. 12 (2) Statement Re: computation of ratio of earnings to fixed charges. 21 (2) Subsidiaries of Registrant. 23 (2) Consent of Independent Registered Public Accounting Firm. 31.1 (2) Certification of Chief Executive Officer (Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002). 31.2 (2) Certification of Chief Financial Officer (Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002). 32 (4) Certification of Corporate Officers (Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002). 152 Staff_DR_063 Attachment A Page 161 of 180 Table of Contents AVISTA CORPORATION Previously Filed (1) Exhibit With Registration Number As Exhibit 101 (2) The following financial information from the Annual Report on Form 10 K for the period ended December 31, 2015, formatted in XBRL (Extensible Business Reporting Language) and filed electronically herewith: (i) the Consolidated Statements of Income; (ii) Consolidated Statements of Comprehensive Income; (iii) the Consolidated Balance Sheets; (iv) the Consolidated Statements of Cash Flows; (v) the Consolidated Statements of Equity and Redeemable Noncontrolling Interests; and (vi) the Notes to Consolidated Financial Statements. (1)Incorporated herein by reference. (2)Filed herewith. (3)Management contracts or compensatory plans filed as exhibits to this Form 10-K pursuant to Item 15(b). (4)Furnished herewith. (5)Applies to James M. Kensok, David J. Meyer, Kelly O. Norwood, Jason R. Thackston, Dennis P. Vermillion and Roger D. Woodworth. (6)Applies to Marian M. Durkin, Karen S. Feltes, Scott L. Morris, and Mark T. Thies. (7)Applies to executive officers appointed after October 1, 2010. This applies to Kevin J. Christie, Ryan L. Krasselt, Ed D. Schlect and Heather L. Rosentrater. (8)Applies to executive officers appointed after February 4, 2011. This applies to Kevin J. Christie, Ryan L. Krasselt, Ed D. Schlect and Heather L. Rosentrater. 153 Staff_DR_063 Attachment A Page 162 of 180 Exhibit 10.31 AVISTA CORPORATION PERFORMANCE AWARD AGREEMENT This Performance Award Agreement (the “Agreement”) is made by and between Avista Corporation, a Washington Corporation (the “Company”) and the individual named in section 1 (the “Participant”) as designated by the Avista Corporation Compensation and Organization Committee (the “Plan Administrator”). WHEREAS, Performance Awards are granted under the May 13, 2010 amended and restated Avista Corporation Long-Term Incentive Plan (the “Plan”). The terms and conditions of the Performance Awards are set forth below and in the Plan, which is incorporated into this Agreement by reference. NOW, THEREFORE, in consideration of the premises contained herein and in the Plan, it is agreed as follows: 1.Terms of Performance Awards. The terms of the Performance Awards are set forth as follows: (a)The "Participant" is (Participant’s name) (b)The "Grant Date” is February 5, 2015. (c)The total target number of eligible "Performance Awards" shall be (# of) units. “Performance Awards” granted under this Agreement are units that will be reflected in a book account maintained by the Company or a third party administrator during the Performance Cycle, and that will be settled in cash or shares of Avista Corporation Common Stock (“Common Stock”) to the extent provided in this Agreement and the Plan. (d)The "Performance Cycle" is the period beginning on January 1, 2015 and ending on December 31, 2017. 2.Conditions to Award. Pursuant to this Award, the number of Performance Awards earned will depend upon the Company’s performance against specific performance metrics. The performance metrics are (i) Relative Total Shareholder Return, which accounts for (# of) units of the total target award as set forth in section 1(c), and (ii) Cumulative Earnings Per Share (“CEPS”) which accounts for (# of) units of the total target award set forth in section 1(c). The total number of shares of Stock that will be issued in the settlement of this Award, based upon the Company’s satisfaction of the metrics, will be determined by multiplying the Target Number of units allocated for each metric set forth in this section 2 by the applicable Payout Factor in accordance with the provisions of Exhibit 1 and Exhibit 2, which is attached to and forms a part of this Agreement. 3.Settlement of Performance Awards. The Company shall deliver to the Participant one share of Common Stock (or cash equal to the Fair Market Value of one share of Common Stock) for each Performance Award earned by the Participant, as determined in accordance with the provisions of Exhibit 1 and Exhibit 2, which is attached to and forms a part of this Agreement. The earned Performance Award payable to the Participant shall be paid in shares of Common Stock or in cash (based on the Fair Market Value of the Common Stock as of the date the Plan Administrator certifies the attainment of the Page 1 of 10 Staff_DR_063 Attachment A Page 163 of 180 performance goals), or in a combination of the two, as determined by the Plan Administrator in its sole discretion, except that cash may be distributed in lieu of any fractional share of Common Stock. All Performance Awards and any Dividend Equivalents (as described in Section 5 below) earned by a Participant under this Agreement are subject to the Recoupment Policy adopted by the Company’s Board of Directors as amended from time to time (“Recoupment Policy”). If a Participant becomes subject to the Recoupment Policy any Performance Award and associated Dividend Equivalent may be forfeited in whole or in part and all or part of any distribution payable to a Participant or his or her beneficiary under this Agreement may be recovered by the Company pursuant to the Recoupment Policy. 4.Time of Payment. Except as otherwise provided in this Agreement, payment of Performance Awards earned will be delivered as soon as feasible after the end of the Performance Cycle and after the Plan Administrator certifies the attainment of the performance goals. 5.Dividend Equivalent Rights. Any Performance Awards may, in the Plan Administrator’s discretion, earn Dividend Equivalent Rights. In respect of any Performance Award that is outstanding on the dividend record date for Common Stock, the Participant may be credited with an amount equal to the cash distributions that would have been paid on the shares of Common Stock covered by such Award had such covered shares been issued and outstanding on such dividend record date. Dividend Equivalent Rights are to be paid in cash based on the total number of Performance Awards earned at the end of the Performance Cycle and delivered as soon as feasible after the Performance Cycle and after the Plan Administrator certifies the attainment of the performance goals. Dividend Equivalent Rights are subject to all applicable taxes, which are the responsibility of the Participant. The Dividend Equivalent Rights in respect of any Performance Awards that are not earned as of the end of a Performance Cycle, shall be forfeited as of the end of the Performance Cycle. 6.Termination of Employment during Performance Cycle. Except as otherwise provided in section 7, this section 6 shall apply if the Participant’s employment terminates during a Performance Cycle. If the Participant’s employment with the Company and/or Subsidiaries terminates during the Performance Cycle because of Retirement, Disability, or Death, the Participant shall be entitled to a prorated value of the Performance Award earned in accordance with Exhibit 1 and Exhibit 2, determined at the end of the Performance Cycle, and based on the ratio of the number of whole months the Participant was employed during the Performance Cycle to the total number of months in the Performance Cycle (36). If a Participant's employment or services with the Company and/or Subsidiaries terminate on or as of the last day of a Performance Cycle, such Participant will be deemed to have terminated after the end of such Performance Cycle. If the Participant’s employment with the Company and/or Subsidiaries terminates during the Performance Cycle for any reason other than Retirement, Disability, or Death, the Performance Award granted under this Agreement will be forfeited on the Date of Termination (as defined in section 9(b)); provided, however, that in such circumstances, the Plan Administrator, in its sole discretion, may determine that the Participant will be entitled to receive a prorated or other portion of the Performance Award. In case of termination for Cause, the Performance Award granted shall automatically terminate upon first notification to the Participant of such termination, unless the Plan Administrator determines otherwise. If a Participant’s employment with the Company is suspended pending an investigation of whether the Participant shall be terminated for Cause, all the Participant’s rights under any Award likewise shall be suspended during the period of investigation. The effect of a Company-approved leave of absence on the terms and conditions of an Award shall be determined by the Plan Administrator, in its sole discretion. 7.Change in Control. If a Change in Control occurs during the Performance Cycle, and the Participant’s Date of Termination (as defined in section 9(b)) does not occur before the Change in Control date, the Participant shall be entitled to a prorated value of the Performance Award that would have been earned by the Participant in accordance with Exhibit 1 and Exhibit 2, determined as of the date of the Change in Control, prorated based on the ratio of the number of whole months the Participant is employed during the Performance Cycle through the date of the Change in Control, to the total number of months in the Performance Cycle; provided, however, that a Payout Factor of at least 100% as set forth 2/5/2015 Page 2 of 10 Staff_DR_063 Attachment A Page 164 of 180 in Exhibit 1 and Exhibit 2 for the Performance Cycle shall be deemed to have been achieved as of the date of the Change in Control. Notwithstanding the provisions of sections 3 (with the exception of the application of the Recoupment Policy), 4, and 5, the value of the Performance Award, and any Dividend Equivalent Right, earned in accordance with the foregoing provisions of this section shall be delivered to the Participant in a lump sum cash payment as soon as feasible after the occurrence of a Change in Control, with the value of a Performance Award equal to the Fair Market Value of a share of Common Stock determined under the provision of section 3 as of the date of the Change in Control. Distributions to the Participant under sections 3 and 5 shall not be affected by payments under this section, except that the number of Performance Awards and Dividend Equivalent Rights earned by and payable to the Participant shall be reduced by the number of Performance Awards and Dividend Equivalent Rights with respect to which payment was made to the Participant under this section. 8.Taxes. The Participant is liable for any and all taxes, including withholding taxes, arising out of the grant, vesting, payment or settlement of any Performance Awards and Dividend Equivalent Rights. The Company shall have the right to require the Participant to remit to the Company, or to withhold awarded shares of Common Stock, or from any Dividend Equivalent Rights or other amounts due to the Participant, as compensation or otherwise, an amount sufficient to satisfy all federal, state and local withholding tax requirements. 9.Definitions. For purposes of this Agreement, the terms used in this Agreement shall be subject to the following: (a)Change in Control. The term "Change in Control" is defined in section 2.4 of the amended and restated Avista Corp. Long Term Incentive Plan. (b)Date of Termination. The Participant’s "Date of Termination" shall be the first day occurring on or after the Grant Date on which the Participant is not employed by the Company or any Subsidiary, regardless of the reason for the termination of employment; provided that a termination of employment shall not be deemed to occur by reason of a transfer of the Participant between the Company and a Subsidiary or between two Subsidiaries; and further provided that the Participant’s employment shall not be considered terminated while the Participant is on a leave of absence from the Company or a Subsidiary approved by the Participant’s employer. If, as a result of a sale or other transaction, the Participant’s employer ceases to be a Subsidiary (and the Participant’s employer is or becomes an entity that is separate from the Company), and the Participant is not, at the end of the 30-day period following the transaction, employed by the Company or an entity that is then a Subsidiary, then the occurrence of such transaction shall be treated as the Participant’s Date of Termination caused by the Participant being discharged by the employer. (c)Disability. ‘‘Disability’’ means ‘‘disability’’ as that term is defined for purposes of the Company’s Long Term Disability Plan or other similar successor plan applicable to employees. (d)Retirement. "Retirement" of the Participant shall mean retirement as of the individual’s retirement date under the Retirement Plan for Employees of Avista Corporation or other similar successor plan applicable to employees. 10.Assignability. No Performance Award or Dividend Equivalent Right granted or awarded under the Plan may be assigned or transferred by the Participant other than by will or by the applicable laws of descent and distribution, and, during the Participant’s lifetime, settlements of such Awards may be payable only to the Participant or a permitted assignee or transferee of the Participant (as provided below). Notwithstanding the foregoing, the Plan Administrator, in its sole discretion, may permit such assignment or transfer and may permit a Participant of such Performance Awards or Dividend Equivalent Rights to designate a beneficiary who may receive compensation settlement under the Performance 2/5/2015 Page 3 of 10 Staff_DR_063 Attachment A Page 165 of 180 Award after the Participant’s death; provided, however, that any amount so assigned or transferred shall be subject to all the same terms and conditions contained in this Agreement. 11.General 11.1 Award Agreements. Performance Awards granted under the Plan shall be evidenced by a written agreement that shall contain such terms, conditions, limitations and restrictions as the Plan Administrator shall deem advisable and that are not inconsistent with the Plan. 11.2 Continued Employment or Services; Rights in Awards. Nothing contained in this Agreement, the Plan, or any action of the Plan Administrator taken under the Plan or this Agreement shall be construed as giving any Participant or employee of the Company any right to be retained in the employ of the Company or any Subsidiary or to limit the Company’s or any Subsidiary’s right to terminate the employment or services of the Participant. 11.3 Registration. At the present time, the Company has an effective registration statement with respect to the shares. The Company intends to maintain this registration but has no obligation to do so. In the event that such registration ceases to be effective, the Participant will not receive a Performance Award settlement or payment unless exemptions from registration under federal and state securities laws are available; such exemptions from registration are very limited and might be unavailable. By accepting the Agreement, the Participant hereby acknowledges that he/she has read the section of the Plan and this Agreement entitled Registration. 11.4 No Rights as a Shareholder. No Award under this Agreement shall entitle the Participant to any dividends (except to the extent provided in an award of Dividend Equivalent Rights), voting or any other right of a shareholder unless and until the date of issuance under the Plan of the shares that are the subject of such Performance Award, are free of all applicable restrictions. 11.5 Compliance with Laws and Regulations. Notwithstanding anything in the Plan to the contrary, the Board of Directors, in its sole discretion, may bifurcate the Plan so as to restrict, limit or condition the use of any provision of the Plan to Participants who are officers or directors subject to Section 16 of the Exchange Act without so restricting, limiting or conditioning the Plan with respect to other Participants. 11.6 Severability. The invalidity or unenforceability of any provision of this Agreement shall not affect the validity and enforceability of any other provision of this Agreement. If any provision of the Agreement is determined to be invalid, illegal or unenforceable in any jurisdiction, or as to any person, or would disqualify any Performance Award under any law deemed applicable by the Plan Administrator, such provision shall be construed or deemed amended by the Plan Administrator to conform to applicable laws, or, if the Plan Administrator determines that the provision cannot be so construed or deemed amended without materially altering the intent of the Plan or the Performance Award, such provision shall be stricken as to such jurisdiction, person or Performance Award, and the remainder of the Agreement and any such Performance Award shall remain in full force and effect. 12.Administration. The authority to manage and control the operation and administration of this Agreement shall be vested in the Plan Administrator, and the Plan Administrator shall have all powers with respect to this Agreement as it has with respect to the Plan. Any interpretation of the Agreement by the Plan Administrator and any decision made by it with respect to the Agreement are final and binding. 13.Construction. This Agreement is subject to and shall be construed in accordance with the Plan, the terms of which are explicitly made applicable hereto. Unless otherwise defined herein, capitalized terms in this Agreement shall have the same definitions as set forth in the Plan. In the event of any conflict between the provisions hereof and those of the Plan, the provisions of the Plan shall govern. 2/5/2015 Page 4 of 10 Staff_DR_063 Attachment A Page 166 of 180 14.Amendment. This Agreement may be amended by written agreement of the Participant and the Company, without the consent of any other person. 15.Governing Law. The validity, construction, interpretation and enforceability of this Agreement shall be determined and governed by the laws of the State of Washington without giving effect to the principles of conflicts of laws. For the purpose of litigating any dispute that arises under this Agreement, the parties hereby consent to exclusive jurisdiction in Washington State and agree that such litigation shall be conducted in the courts of Spokane County, Washington or the federal courts of the United States for the eastern district of Washington. 16.Successors. The Company shall require any successor (whether direct or indirect, by purchase, merger, consolidation or otherwise to all or substantially all of the business and/or assets of the Company) to agree in writing to assume the Company’s obligations under this Agreement and to perform such obligations in the same manner and to the same extent that the Company is required to perform them. As used in this Agreement, “Company” shall mean the Company and any successor to its business and/or assets that assumes and agrees to perform the Company’s obligations under the Agreement by operation of law or otherwise. IN WITNESS WHEREOF, the Participant has executed this Agreement, and the Company has caused these presents to be executed in its name and on its behalf, all effective as of the Grant Date. AVISTA CORPORATION By: Scott L. Morris Chairman of the Board, President and Chief Executive Officer 2/5/2015 Page 5 of 10 Staff_DR_063 Attachment A Page 167 of 180 EXHIBIT 1 Performance Award Plan Relative Total Shareholder Return Metric and Goals2015 - 2017 Performance Cycle The following graph and table represent the relationship between the Company’s relative three-year Total Shareholder Return (“TSR”) commencing January 1, 2015 and ending December 31, 2017 and the target award opportunity. The number of shares delivered at the end of the three-year Performance Cycle can range from zero to 200% of the target number of units allocated under this metric. The actual issuance of shares depends on Avista’s three-year TSR performance compared to the returns of the peer companies reported in the S&P 400 Utilities Index and how we rank among them. To receive 100% of the Award allocated under this metric, Avista must perform at the 50th percentile among the companies in the S&P 400 Utilities Index. To receive 200% of the Award, Avista must rank at the 100th percentile. If Avista ranks below the 40th percentile, no stock awards or cash Dividend Equivalent Rights will be earned. Dividend Equivalent Rights are calculated and paid out in cash when and to the extent the Performance Awards are issued. The following graph demonstrates the relationship between TSR ranking and various payout factors. Performance Awards are interpolated on a straight line for performance results between the figures shown. Relative TSR Percentile Payout Factor Maximum 100th 200% 85th 150% 70th 125% Target 50th 100% 45th 70% Threshold 40th 40% <40th No Award TSR is calculated using S&P Research Insight and reflects share price appreciation plus the impact of dividend distributions and the reinvestment of such dividends. To compute the TSR, an adjusted price is calculated by applying a monthly return factor to the average closing share prices on the last trading day of November and December for the start and end of the Performance Cycle. 2/5/2015 Page 6 of 10 Staff_DR_063 Attachment A Page 168 of 180 From one year to the next, if S&P drops a company out of the index and adds another, the new company will be included in the ranking and the dropped company will be excluded. When a new company is added, they will be added to the ranking as if they had been in the ranking from the beginning – provided that there is pricing and dividend data at the beginning of the cycle. When a company is dropped everything related to that company will be excluded from the ranking as if the company was never part of the ranking. Settlement Formula Example: Assuming that 970 Performance Award units were allocated under this metric at the beginning of the three-year Performance Cycle and Avista’s TSR ranked at the 45t h percentile after the three-year Performance Cycle, the Participant would receive 70% of 970 or 679 shares of Avista common stock plus cash dividend equivalents. Payout Factor (% of Target) Target Number of Performance Awards Granted Final Number of Common Stocks Issued 70%X 970 =679 shares plus cash dividends Percentile Ranking Methodology: The percentile rank is calculated using the PERCENTRANK function in MS Excel, excluding Avista from the list and rounding all results to the nearest whole percentile. The calculation can be replicated by arranging the TSR data from highest to lowest for all peers except Avista. A percentile ranking is calculated for each data point assuming 100.0th %ile for the highest data point, 0.0 %ile for the lowest data point, and the corresponding percentile for every other data point with an equal difference in percentile ranking for each data point. The TSR for Avista is calculated by determining Avista’s rank in the list and interpolating between the percentile rankings for the companies immediately above and below based on the differences in TSR. An example, based on sample data is as follows: Company Ranking TSR Percentile Rank 1 201.6%100.0% 2 135.9%98.2% 47 (ABC Corp)20.3%17.8% 48 (XYZ Corp)16.0%16.0% 56 -3.3%1.7% 57 -10.5%0.0% If a company’s TSR is 18.9%, the resulting percentile ranking would be 17%, calculated as follows: 17% = 16.0% + [(18.9% - 16.0%) / (20.3% - 16.0%) * (17.8% - 16.0%)] Total Shareholder Return (TSR) Methodology: For purposes of this Agreement, a methodology for calculating a total return to shareholder with dividend reinvestment was established. Returns are calculated daily based on stock price changes and dividend payments and then accumulated over the Performance Cycle. Below are additional assumptions used in Avista’s calculation for TSR. General Assumptions: The starting and ending prices are determined by averaging the closing price on the last trading day of November and the last trading day of December at the beginning and the end of the Performance Cycle. An example, based on sample data is as follows: the stock price for the start of the Performance Cycle for Avista is $34.90, which is the average of $35.35 (12/31/2014) and $34.45 (11/28/2014). Dividends are 2/5/2015 Page 7 of 10 Staff_DR_063 Attachment A Page 169 of 180 reinvested on a daily basis. For this example, a fictional ex-date for dividends per share is used for demonstration purposes. Daily returns are calculated over the performance cycle and added together resulting in the Cumulative TSR for the performance cycle. Date Closing Price Dividend Daily TSR 11/21/2014 33.90 0 NA 11/24/2014 33.80 0 (0.2950%) 11/25/2014 34.06 0.3175 1.7086%* 11/26/2014 34.29 0 0.6753% 11/27/2014 34.29 0 0.00% 11/28/2014 34.45 0 0.4666% Cumulative TSR 11/21/2014 to 11/28/2014 2.5555% * [(34.06 + 0.3175) / 33.80] -1 EXHIBIT 2 Performance Award Plan Cumulative Earnings Per Share Metric and Goals 2015 - 2017 Performance Period The following graph and table represent the relationship between the Company’s Cumulative Earnings Per Share (“CEPS”) commencing January 1, 2015 and ending December 31, 2017 and the target award opportunity. The number of shares delivered at the end of the three-year Performance Cycle can range from zero to 200% of the target number of units allocated under this metric. The actual issuance of shares depends on Avista’s CEPS growth performance over the three-year Performance Cycle. To receive 100% of the Performance Award allocated under this metric, Avista must achieve CEPS compounded growth of 4.50% or $6.15 based on 2015 earnings guidance. To receive 200% of the Award, Avista must achieve CEPS compounded growth of 6.00% or $6.56. If Avista’s CEPS compounded growth is less than 3.00% or below $5.75, no stock awards or cash Dividend Equivalent Rights will be earned. Dividend Equivalent Rights are calculated and paid out in cash when and to the extent the Performance Awards are issued. The following graph demonstrates the relationship between CEPS and various payout factors. Performance Awards are interpolated on a straight line for performance results between the figures shown. 2/5/2015 Page 8 of 10 Staff_DR_063 Attachment A Page 170 of 180 Cumulative Growth Cumulative EPS Payout Factor Maximum 6%$6.56 200% 5.625%$6.45 173% 5.25%$6.35 149% 4.875%$6.25 125% Target 4.5%$6.15 100% 4.125%$6.05 85% 3.75%$5.95 70% 3.375%$5.85 55% Threshold 3%$5.75 40% <3%<$5.75 No Award Performance is tracked over a three-year Performance Cycle thereby focusing on sustainability. The performance metric CEPS provides for Performance Awards if the Company's cumulative EPS grows at a certain rate on a compounded annual basis. Cumulative EPS is fully diluted earnings per share determined in accordance with generally accepted accounting principles, and may be adjusted to remove the effects of such items as regulatory charges, income tax legislative changes and/or items of a non- routine or items of an extraordinary nature as determined by the Plan Administrator. Settlement Formula Example: Assuming that 485 Performance Award units were allocated under this metric at the beginning of the Performance Cycle and Avista’s cumulative EPS grew 4.875% over three years or EPS was $6.25 compounded annually after the three-year performance period, the Participant would receive 125% of 485 or 607 shares of Avista common stock plus dividend equivalents in cash. Payout Factor (% of Target) Target Number of Performance Awards Granted Number of Common Stocks Issued 125%X 485 =607 shares plus cash dividends Using the example formulas in Exhibit 1 and Exhibit 2, the Participant would receive in total 88% of 1,455 (total target # of Performance Awards granted) or 1,286 Shares of Common Stock plus cash dividend equivalents. Payout Factor (% of Target) Target Number of Performance Awards Granted Number of Common Stocks Issued TSR 70%X 970 =679 CEPS 125%X 485 =607 Total 88%X 1,455 =1,286 2/5/2015 Page 9 of 10 Staff_DR_063 Attachment A Page 171 of 180 ACCEPTANCE AND ACKNOWLEDGMENT I, a resident of the state of _, accept the Performance Award described in this Agreement and in the Plan, and acknowledge that I have received a copy of this Agreement and the Plan. I have read and understand the Plan, and I hereby make the representations, warranties and acknowledgments, and undertake the indemnity and other obligations, therein specified. Dated: Social Security Number Signature of Employee Printed Name 2/5/2015 Page 10 of 10 Staff_DR_063 Attachment A Page 172 of 180 Exhibit 10.39 Avista Corporation Non-Employee Director Compensation - 2015 Prior to August 21, 2015, directors who were not employees of the Company received an annual retainer of $125,000 with $50,000 of the total retainer to be paid in stock each year. Directors had the option of taking the remaining $75,000 in cash, stock or a combination of both cash and stock. The cash portion of the retainer is paid quarterly. Directors were also paid $1,500 for each meeting of the Board or any Committee meeting of the Board. Directors who served as Board Committee Chairs received an additional $7,500 annual retainer, with the exception of the Audit Committee Chair, who received an additional $13,000 annual retainer and the Compensation Committee Chair, who received an additional $10,000 annual retainer. The Lead Director received an additional annual retainer of $20,000. Each year, the Governance Committee reviews all components of director compensation. During 2015, the Governance Committee engaged Meridian Compensation Partners LLC (“Meridian”) to assist in this review. The information provided by Meridian was used to compare the Company’s current director compensation with peer companies in the utility industry and general industry companies of similar size (the “Director Peer Group”). The companies comprising the Director Peer Group are those companies in the S&P 400 Utilities Index. At its August 21, 2015 meeting, the Board reviewed survey results from Meridian regarding current pay practices for director compensation. The Board approved an increase in the annual retainer of an additional $15,000, effective September 1, 2015. The total annual retainer is now $140,000 with $65,000 of the total retainer to be paid in stock each year. Directors will have the option of taking the remaining $75,000 in cash, stock or a combination of both cash and stock. Each director is entitled to reimbursement of reasonable out-of-pocket expenses incurred in connection with meetings of the Board or its Committees and related activities, including director education courses and materials. These expenses include travel to and from the meetings, as well as any expenses they incur while attending the meetings. The Company has a minimum stock ownership expectation for all Board members. Outside directors are expected to achieve a minimum investment of five times the minimum portion of their equity retainer payable in Company common stock within five years of becoming a Board member, and retain at least that level of investment during his/her tenure as a Board member. Shares previously deferred under the former Non- Employee Director Stock Plan count for purposes of determining whether a director has achieved the ownership expectation. Directors are prohibited from engaging in short-sales, pledging, or hedging the economic interest in their Company shares. The ownership expectation illustrates the Board’s philosophy of the importance of stock ownership for directors to further strengthen the commonality of interest between the Board and shareholders. The Governance Committee annually reviews director holdings to determine whether they meet ownership expectations. All directors currently comply based on their years of service completed on the Board. There were no annual stock option grants or non-stock incentive plan compensation payments to directors for services in 2015 and none are currently contemplated under the current compensation structure. The Company also does not provide a retirement plan or deferred compensation plan to its directors. Staff_DR_063 Attachment A Page 173 of 180 Exhibit 12 AVISTA CORPORATION Computation of Ratio of Earnings to Fixed Charges Consolidated (Thousands of Dollars) Years Ended December 31 2015 2014 2013 2012 2011 Fixed charges, as defined: Interest charges $80,613 $74,025 $73,772 $71,843 $69,536 Amortization of debt expense and premium - net 3,415 3,635 3,813 3,803 4,617 Interest portion of rentals 1,287 1,187 1,146 1,294 1,139 Total fixed charges $85,315 $78,847 $78,731 $76,940 $75,292 Earnings, as defined: Pre-tax income from continuing operations $185,619 $192,106 $162,347 $116,567 $139,438 Add (deduct): Capitalized interest (3,546) (3,924) (3,676) (2,401) (2,942) Total fixed charges above 85,315 78,847 78,731 76,940 75,292 Total earnings $267,388 $267,029 $237,402 $191,106 $211,788 Ratio of earnings to fixed charges 3.13 3.39 3.02 2.48 2.81 Staff_DR_063 Attachment A Page 174 of 180 Exhibit 21 AVISTA CORPORATION SUBSIDIARIES OF REGISTRANT Subsidiary State or Country of Incorporation Avista Capital, Inc.Washington Avista Development, Inc.Washington Avista Energy, Inc.Washington Avista Northwest Resources, LLC Washington Pentzer Corporation Washington Pentzer Venture Holding II, Inc.Washington Bay Area Manufacturing, Inc.Washington Advanced Manufacturing and Development, Inc.California Avista Capital II Delaware Steam Plant Square, LLC Washington Steam Plant Brew Pub, LLC Washington Courtyard Office Center, LLC Washington Alaska Energy and Resources Company Alaska Alaska Electric Light and Power Company Alaska AJT Mining Properties, Inc.Alaska Snettisham Electric Company Alaska Salix, Inc.Washington Staff_DR_063 Attachment A Page 175 of 180 Exhibit 23 CONSENT OF INDEPENDENT REGISTERED ACCOUNTING FIRM We consent to the incorporation by reference in Registration Statement Nos. 333-33790, 333-126577 and 333-179042 on Form S‑8 and in Registration Statement No. 333-187306 on Form S-3, relating to the consolidated financial statements of Avista Corporation and subsidiaries, and the effectiveness of Avista Corporation’s internal control over financial reporting, appearing in this Annual Report on Form 10‑K of Avista Corporation for the year ended December 31, 2015. /s/ Deloitte & Touche LLP Seattle, Washington February 23, 2016 Staff_DR_063 Attachment A Page 176 of 180 Exhibit 31.1 CERTIFICATION I, Scott L. Morris, certify that: 1.I have reviewed this report on Form 10-K of Avista Corporation; 2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and d.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and 5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions): a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Date:February 23, 2016 /s/ Scott L. Morris Scott L. Morris Chairman of the Board, President and Chief Executive Officer (Principal Executive Officer) Staff_DR_063 Attachment A Page 177 of 180 Exhibit 31.2 CERTIFICATION I, Mark T. Thies, certify that: 1.I have reviewed this report on Form 10-K of Avista Corporation; 2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and d.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and 5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions): a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. Date:February 23, 2016 /s/ Mark T. Thies Mark T. Thies Senior Vice President, Chief Financial Officer, and Treasurer (Principal Financial Officer) Staff_DR_063 Attachment A Page 178 of 180 Exhibit 32 AVISTA CORPORATION __________________________________________________________________________________________ CERTIFICATION OF CORPORATE OFFICERS (Furnished Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002) __________________________________________________________________________________________ Each of the undersigned, Scott L. Morris, Chairman of the Board, President and Chief Executive Officer of Avista Corporation (the “Company”), and Mark T. Thies, Senior Vice President and Chief Financial Officer of the Company, hereby certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that the Company’s Annual Report on Form 10-K for the year ended December 31, 2015 fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934, as amended, and that the information contained therein fairly presents, in all material respects, the financial condition and results of operations of the Company. Date: February 23, 2016 /s/ Scott L. Morris Scott L. Morris Chairman of the Board, President and Chief Executive Officer /s/ Mark T. Thies Mark T. Thies Senior Vice President, Chief Financial Officer, and Treasurer Staff_DR_063 Attachment A Page 179 of 180 Staff_DR_063 Attachment A Page 180 of 180 BRINGINGENERGYTO LIFE 1411 EAST MISSION AVENUE | SPOKANE, WASHINGTON 99202 | 509.489.0500 | AVISTACORP.COM 2015 ANNUAL REPORT ON THE COVER AVISTA GENERATES AND DELIVERS SAFE, RELIABLE ENERGY. IT’S WHAT OUR CUSTOMERS EXPECT FROM US. BUT WE DELIVER EVEN MORE. EVERYTHING WE DO IS GUIDED BY THE PURPOSE OF BRINGING ENERGY TO LIFE. THE ENERGY WE DELIVER HEATS, COOLS AND LIGHTS HOMES AND BUSINESSES, POWERS MANUFACTURING AND ENABLES THE FUNCTION OF MODERN COMMUNITIES. BEYOND THAT, OUR RESOURCES AND THE PEOPLE BEHIND THEM IMPROVE LIVES IN MANY WAYS — FROM HELPING A REGION RECOVER FROM A WIND STORM, TO FUNDING COLLEGE SCHOLARSHIPS OR FOSTERING THE NEXT GENERATION OF BASEBALL FANS, AVISTA BRINGS ENERGY TO LIFE. Staff_DR_063 Attachment B Page 1 of 160 WE HAVE ENERGY FOR THAT CORPORATE INFORMATION COMPANY HEADQUARTERS Spokane, Washington AVISTA ON THE INTERNET Financial results, stock quotes, news releases and documents filed with the Securities and Exchange Commission (SEC), and information on the company’s products and services are available on Avista’s website at www.avistacorp.com. DIRECT STOCK PURCHASE AND DIVIDEND REINVESTMENT PLAN Computershare sponsors and administers the Computershare Investment Plan (CIP) for Avista Corp. common stock. To invest, obtain forms or for information about your holdings, please contact the transfer agent using the information below. TRANSFER AGENT Computershare P.O. Box 30170 College Station, TX 77842-3170 800.642.7365 www.computershare.com/investor INVESTOR INFORMATION A copy of the company’s financial reports, including the reports on Forms 10-K and 10-Q filed with the SEC, will be provided without charge upon request to: Avista Corp. Investor Relations P.O. Box 3727 MSC-19 Spokane, WA 99220-3727 800.222.4931 ANNUAL MEETING OF SHAREHOLDERS Shareholders are invited to attend the company’s annual meeting to be held at 8:15 a.m. PDT on Thursday, May 12, 2016, at Avista Corp. headquarters, 1411 East Mission Avenue, Spokane, Washington. The annual meeting will be webcast. Please go to www.avistacorp.com to preregister for the webcast and to listen to the live webcast. The webcast will be archived at www.avistacorp.com for one year to allow shareholders to listen at their convenience. EXCHANGE LISTING Ticker Symbol: AVA New York Stock Exchange CERTIFICATIONS On June 2, 2015, the Chief Executive Officer (CEO) of Avista Corp. filed a Section 303A.12(a) Annual CEO Certification with the New York Stock Exchange. The CEO Certification attests that the CEO is not aware of any violations by the company of NYSE’s Corporate Governance Listing Standards. Avista Corp. has included as exhibits to its annual report on Form 10-K for the year 2015, filed with the SEC, certifications of Avista’s Chief Executive Officer and Chief Financial Officer regarding the quality of Avista’s public disclosure in compliance with Section 302 of the Sarbanes-Oxley Act of 2002. This annual report contains forward-looking statements regarding the company’s current expectations. These statements are subject to a variety of risks and uncertainties that could cause actual results to differ materially from the expectations. These risks and uncertainties include, in addition to those discussed herein, all factors discussed in the company’s annual report on Form 10-K for the year 2015. Our 2015 annual report is provided for shareholders. It is not intended for use in connection with any sale or purchase of or any solicitation of others to buy or sell securities. © 2016, Avista Corp. All rights reserved. ACKNOWLEDGEMENTS The 2015 annual report is produced through a partnership of Avista employees and companies within Avista’s service area. Design and Production: Klündt | Hosmer Photography: Dean Davis Photography and Mike Janes, AEL&P Printing: Lawton Printing Services HELP US HELP THE ENVIRONMENT Managing costs is a primary goal for Avista. You can help us meet this goal by agreeing to receive future annual reports and proxy statements electronically. This service saves on the costs of printing and mailing, provides timely delivery of information, and helps protect our environment by saving energy and decreasing the need for paper, printing and mailing materials. FOR MORE INFORMATION, PLEASE VISIT www.avistacorp.com Staff_DR_063 Attachment B Page 2 of 160 1 Our financial results this year met our expectations in spite of the challenging weather patterns that brought us warmer than average temperatures through the first and second quarters. We saw near- record hydroelectric conditions early in the year that then deteriorated significantly by May. The decoupling mechanism in Washington helped us offset some of the impacts of weather. A severe wind storm in November set a record for us in terms of customer outage numbers and impact on our infrastructure. The costs to repair our electric system were primarily capital, with some operating and maintenance costs incurred as well. For more specific information about these costs, please refer to the 10-K at the end of this book. Consolidated earnings were $1.97 per diluted share, with net income of $123.2 million for the year ended Dec. 31, 2015. Our balance sheet and credit ratings remain healthy. At year-end, Avista Corp. had $250.4 million of available liquidity under our $400 million line of credit. We added cost-effective long-term debt At Avista, we actively engage with the elements of change that surround us, and we pursue the strategies that position us well to serve our customers in the future, while taking care of business today. TO OUR SHAREHOLDERS: Each year, our industry experiences change, and this year was no exception. There’s been much talk about the utility of the future — from pundits to journalists, from CEOs to the workplace grapevine. Indeed, our world has changed — we’re transitioning from a traditional operations focus to one of purposeful attention to the evolving expectations for choices from our customers. We’ve noted three elements that now characterize our industry and which we believe will impact our future. The utility world is being shaped by changing business models that have the potential to disrupt our relationships with our customers through political, regulatory, technological or advocacy actions. We can choose to push back and resist, or we can embrace the new paradigms and make them work for our customers in ways that make sense for them, our business, our regulators, our investors and our communities. We choose rst to engage. Innovation and action are keys to success. We will continue seeking and implementing effective and efficient new technologies and business process improvements to meet the expectations of a public that is increasingly more comfortable in the cyber world. We continue to innovate. Our employee base is changing from a culture of Baby Boomers to that of Millennials (age range 18 to 35). That brings with it changes in communication styles and information channels, work/life expectations and other generational differences. We are purposeful and rigorous in the professional development of our employees and their customer focus. We are proactive in building our future. 1 2 3 AN OVERVIEW OF 2015 FINANCIAL RESULTS Staff_DR_063 Attachment B Page 3 of 160 2 through the private placement market by issuing $100 million of Avista Corp. first mortgage bonds, bearing an interest rate of 4.37 percent, which will mature in December 2045. Long-term corporate earnings growth of 4 percent to 5 percent continues to be our target. We believe earnings growth will continue to prove positive through our focus on updating and replacing aging infrastructure, continued cost management, investment in essential digital technologies and other growth platforms. Our projection for customer and load growth remains near 1 percent. I’m pleased to note that the board of directors raised the dividend on Avista Corp. common stock for the 13th consecutive year, for an annualized dividend of $1.32. REGULATED OPERATIONS AVISTA UTILITIES Avista Utilities contributed $1.81 per diluted share to earnings in 2015. Continuing our investment in replacing and updating aging infrastructure, our capital expenditures totaled $415 million for the year. We are planning to invest $375 million in 2016 and $405 million in 2017 to maintain the reliability and strength of our electric and natural gas energy systems. The timely recovery of these costs continues to be essential to earning an adequate return on our shareholders’ investment. In Washington, the utility commission granted new electric and natural gas rates that went into effect on Jan. 11, 2016. Additional information is available in the 10-K at the end of this book. In Idaho, we received approval for new electric and natural gas rates, as well as a decoupling mechanism, that went into effect on Jan. 1, 2016. Finally, new natural gas rates went into effect in Oregon in April 2015. Then in May, we filed a new natural gas rate case in Oregon, and the state utility commission has up to 10 months to make a decision on that request. I’ve said in the past that we were “green” before it was cool to be “green.” While our company was founded on clean, renewable hydro power, today our diversified generating resource mix includes biomass, wind, solar, natural gas and a small amount of coal. We’re still ranked as one of the lowest carbon emitters among the country’s top 100 energy producers, but the call for increased use of renewable resources brings with it the challenge of integrating the power from those sources into our electric system. This year we received a grant from the Washington Department of Commerce Clean Energy Fund, which we matched, to pilot a utility-scale energy storage project in Pullman, Wash. The project is the first to use vanadium-flow batteries, which we’re proud to say are manufactured here in Washington state. The lessons we learn from this project, together with insights we’re gathering from the newly constructed community solar project in Spokane, will give us additional valuable, executable information about how to better integrate intermittent renewable energy into the electric grid. Updating our legacy hydroelectric projects on the Spokane River to replace outdated and inefficient facilities and equipment was one important area of our capital spend for the year. This work will enhance power delivery, safety and reliability. Upgrades to the Post Falls South Channel dam on the Spokane River were essentially completed over the summer. Renovations and upgrades are underway at our Nine Mile and Little Falls hydroelectric projects farther downstream to overhaul, rebuild and upgrade these century-old plants. At Nine Mile, the work will result in additional generating capacity, giving us increased ability to meet customer demand and an incremental increase to the renewable portion of our diverse generation mix. Our employees built upon our company’s history of innovation to meet customer needs again in 2015. The new customer information and work management system was completed and put into service in February. Later in the year, we launched an updated and dynamic outage information center on www.avistautilities.com that communicates with customers through the channels they are most frequently using — Web via laptop, tablet and smart phone. This fresh approach to sharing information gives us the opportunity to enhance our customers’ user experience with us and to provide the key information elements that we know they desire: time of outage, location, cause, estimated restoration time and crew dispatch. Together, these and other new technology enhancements will give Avista customers the kind of interaction with our company they have come to expect in today’s world. ONGOING RENOVATIONS AND UPGRADES AT AVISTA’S HYDROELECTRIC PROJECTS ON THE SPOKANE RIVER WILL INCREASE GENERATING CAPACITY TO MEET CUSTOMER DEMAND. 2 Staff_DR_063 Attachment B Page 4 of 160 ALASKA ELECTRIC LIGHT AND POWER COMPANY Operations at our Juneau, Alaska, utility — Alaska Electric Light & Power Company (AEL&P) — went smoothly this year. Juneau recorded the second wettest year in history, having received nearly 85 inches of rainfall, about 26 percent more than average. This is good news for a utility that derives nearly all its power from hydroelectric generation. AEL&P operations contributed $0.11 per diluted share to Avista Corp.’s earnings and made $13 million in capital expenditures. They plan to invest $17 million in capital projects in 2016. Helping Juneau residents manage energy costs, providing energy choices and improving regional air quality are all factors that have gone into our strategic decision to explore the viability of building a natural gas local distribution company (LDC) in Juneau. We estimate that the total investment for this project would be $130 million over a 10-year period, with about half being invested in the first five years. For the project to be economically feasible, we will need a combination of low-cost debt financing, as well as assistance for customer conversion costs. The current low price of oil, however, may impede customer conversion decisions in the near term. We will continue our due diligence, and we will be ready to proceed if and when the economics prove favorable for customers and our company. We’ve joined with our AEL&P employees in attending and supporting civic and community events in Juneau, where we’ve been warmly welcomed. We are pleased that AEL&P President Tim McLeod has joined the board of the Avista Foundation to help shape our philanthropy in this region. In 2015, we made donations totaling $110,000 to non-profits in Juneau, not including sponsorships, dues and registration fees paid to civic and economic development organizations. NON-REGULATED OPERATIONS Through Avista Capital, we are continuing to explore strategic opportunities for corporate growth. In 2014, we launched Salix, a subsidiary whose focus is to explore markets that could be served with liquefied natural gas (LNG), primarily in the West and Pacific Northwest. As of this date, Salix is one of two finalists in an RFP process to provide LNG to the Interior Energy Project, specifically for Fairbanks and North Pole, Alaska. The Alaska Industrial Development and Export Authority will make its final decision on a provider early in 2016. Avista Development, a subsidiary that focuses on growth opportunities in the realm of economic vitality in the communities we serve, has a new president. Roger Woodworth, who previously was our chief strategy officer, is now heading this business. He brings his wealth of experience in conceptualizing, developing and implementing innovative and unique solutions to add value to the enterprise and our communities. THE FUTURE IS NOW We’ve talked for the past few years about the impending “silver tsunami” — the retirement of those in the Baby Boomer generation — here and throughout the energy industry. This year saw the retirement of two long-time Avista executives — Vice President, Controller and Principal Accounting Officer Christy Burmeister-Smith and Don Kopczynski, vice president, energy delivery and customer service. Planning for the future through leadership development prepared two new leaders to step into those positions in 2015: Ryan Krasselt and Heather Rosentrater, respectively. In addition, Kevin Christie, previously senior director of customer solutions, was promoted to vice president, customer solutions, and Ed Schlect, former executive vice president at Ecova, returned to Avista as vice president and chief strategy officer. I want to thank Christy and Don for their years of dedicated service to our company and welcome Ryan, Heather, Kevin and Ed to the executive team. With our strong leadership team in place, I believe we are well-positioned to meet our business objectives in this dynamic energy industry environment. As a last comment, I find that I am filled with pride — for our employees, for our customers and for the communities we serve. Just before Thanksgiving, the Inland Northwest experienced a wind storm of epic proportions, an event that we are not accustomed to in this part of the country. Following the near-hurricane force winds, more than 180,000 of our electric customers were without power — roughly half of our total electric customer base. As we saw the storm approaching, we were prepared with well-practiced emergency operating plans, stocked warehouse shelves and solid relationships with our community and utility partners. You’ll read more about this historic event later in this book. For now, I want to say thank you to our employees for their tireless efforts to bring energy to life and to you, our shareholders, for your continued support of our company. Scott L. Morris Chairman, President and Chief Executive Of cer THE TIRELESS EFFORTS OF AVISTA EMPLOYEES, ALONG WITH PRACTICED EMERGENCY OPERATING PLANS, RESTORED POWER TO CUSTOMERS FOLLOWING AN EPIC WIND STORM IN NOVEMBER 2015. Staff_DR_063 Attachment B Page 5 of 160 4 MAXIMIZING OUR RENEWABLE RESOURCES Over the past 15 years, Avista has invested capital dollars in upgrading and enhancing the operation of its major hydroelectric projects on the Clark Fork River in Montana and Idaho — Noxon Rapids and Cabinet Gorge — that were built more than 50 years ago. The focus for these upgrade efforts now has shifted to the legacy hydroelectric projects on the Spokane River in Idaho and Washington. Just nine miles downstream of Idaho’s Coeur d’Alene Lake, Avista’s Post Falls Dam has been producing power since 1906. Certain upgrades were made to the powerhouse on the middle channel of the river in 2012, and it now produces 18 megawatts of clean energy — enough to power 13,500 homes. In 2014, work began on the South Channel dam to restore and upgrade the non-generating dam structure. Now complete, new concrete facings and spillway gates have been installed and other new equipment will improve the operational efficiencies, allowing greater flexibility in responding to changing river levels. This, in turn, will enhance the safety and reliability of the river’s recreational opportunities. Updating and renovating the Nine Mile Dam just west of Spokane began in 2013. The plant, built in 1908, is one of the oldest in Avista’s fleet of hydroelectric generation facilities. Turbine units 1 and 2 are the last of the original generators, and when replacement is complete, they will add enough capacity to power more than 7,500 homes. An additional feature of the Nine Mile work is the creation of a new small craft take-out point upriver of the facility. This enhanced recreational asset gives outdoor enthusiasts safer and better access to the beauty of the Spokane River. The Little Falls Dam, the third capital project underway on the Spokane River, was built in 1910. The multi-year upgrade project will replace the original turbines, along with other equipment upgrades and enhancements. The project is slated for completion in 2018. ENHANCING ENERGY DELIVERY Avista is committed to investing in modernizing our electric grid to meet current energy needs and to be prepared for future demands. We are also committed to offering customers information and choices to help them better manage their energy costs. For the past five years, we have collaborated with regional partners to complete the Pacific Northwest Smart Grid Demonstration Project. The goal of the project was to illustrate how a system with the ability to share information between the utility and its customers can improve reliability, efficiency and the adjustment of loads based on demand, while assisting in energy conservation. Battelle Memorial Institute’s Technology Performance Report noted this project “was one of the largest and most comprehensive demonstrations of electricity grid modernization ever completed.” Avista’s contribution to the project transformed Pullman, Wash., into the region’s first “smart city.” Customers had Advanced Metering Infrastructure (AMI) placed at their homes and businesses. Smart thermostats were installed in a subset of the customers’ homes, which had the capability to display usage information as well as communicate this data to Avista through the customer’s AMI “smart” meter. Utilizing AMI technology allowed Avista to manage service remotely, which translated into improved customer service and a reduced number of service calls. The reduction in service calls increased operating efficiency, which translated into a savings of approximately $235,000 annually for this region. In addition, fault detection, isolation and restoration systems, and other reliability enhancements led to an annual average of 17 percent fewer outages and shortened outages by 12 percent. The next step is to put this knowledge to work on a broader scale through deployment of AMI technology for our Washington customers. Planning is underway, and installation is expected to begin in 2017. Energy — we use it every day. And, typically we don’t think about where it comes from or how it gets to our homes and businesses when we need it. Avista has provided safe, reliable energy for 126 years. It started with a power plant on the banks of the Spokane River, with a few poles and wires that brought light to the residents of the developing city of Spokane Falls. A network of poles and wires now crisscrosses the Inland Northwest bringing power from a diverse mix of generating resources. In much the same way, Avista natural gas has traveled through a growing network of main and distribution pipelines to be used for heating homes, cooking food, making hot water and running businesses for nearly 60 years. All of this is bringing energy to life. CONNECTING PEOPLE WITH ENERGY Staff_DR_063 Attachment B Page 6 of 160 HISTORIC STORM DIMS THANKSGIVING, BRINGS PARTNERSHIPS TO LIGHT On Nov. 17, 2015, Avista’s electric grid in eastern Washington and northern Idaho experienced the worst devastation ever seen in the company’s 126-year history. A windstorm packing near hurricane-force winds, clocked at over 70 miles per hour, hit about 4 p.m. As the winds subsided a few hours later, the number of electric customers without power stood at more than 180,000, nearly half of the company’s electric customer base and nearly twice the number impacted in the historic 1996 ice storm. With Thanksgiving just nine days away, Avista workers were joined by contract and mutual aid crews from six western states and British Columbia. A total of 130 crews worked around the clock to rebuild the transmission and substation backbone, then the distribution system. Towering Ponderosa and other fir and spruce trees snapped in the winds. As they went down, they took out feeders, switches, communications equipment and transformers. As trees and power poles fell they blocked streets and alleyways and crashed into homes and yards, making repair and restoration an exercise in creative logging. Often crews resorted to hand carrying poles to difficult-to-reach easements and hand- digging new holes for placement. For some customers, power was restored in just a few days; more than 95 percent of those impacted had power by Thanksgiving. All customer power was restored by early the next morning — day 10. This tested our emergency operating plans, our crew training and safety practices, our logistic and supply chain operations, and our use of web and social media communications. It was a monumental effort of partnerships — within our company, with our sister utilities, and with local, state and non-profit agencies. THE NUMBER OF SAFETY INCIDENTS AND ACCIDENTS FOR AVISTA, CONTRACTOR AND MUTUAL AID CREWS THE NUMBER OF MILES OF POWER LINES REPLACED THE NUMBER OF POLES REPLACED THE NUMBER OF INDIVIDUAL LINE AND SERVICE CREW MEMBERS WHO WORKED AROUND THE CLOCK TO RESTORE SERVICE TOTAL VISITS TO AVISTA’S ONLINE OUTAGE CENTER, LAUNCHED JUST TWO WEEKS PRIOR TO THE STORM DOLLARS SPENT IN SUPPORT OF FOOD AND WARMING SHELTERS FOR CUSTOMERS WITHOUT POWER $573,125837,76746856700+0 5 Staff_DR_063 Attachment B Page 7 of 160 6 INTEGRATING MORE RENEWABLE ENERGY INTO THE GRID Across the country there are calls for more renewable energy in utilities’ generation portfolios. The reality is that a diversified mix of resources for power generation is a balanced means to provide customers with reliable, safe energy for their lives. Avista’s 2015 Electric Integrated Resource Plan notes that the company has sufficient resources to meet customers’ energy needs through 2020. Our Preferred Resource Strategy for meeting increased energy demand over the plan’s 20-year horizon includes energy efficiency, upgrades to existing generation facilities and new natural gas-fired generation. Innovation and finding creative, effective and efficient solutions are hallmarks of our company. One of the challenges with renewable resources is integrating the intermittent power they produce into a grid that needs a reliable flow of energy for customers. Understanding how to store power when it is abundant and then distribute it when it is needed is the basis of Avista’s small-scale Energy Storage Project. The $7 million project is funded by a $3.2 million grant from the Washington State Department of Commerce Clean Energy Fund and $3.8 million from Avista. The one-megawatt battery system is the largest capacity vanadium-flow battery in operation to date in North America and Europe. Over the next 18 months, Avista will test seven different uses for energy storage in real-world scenarios, including using battery power as back-up energy in case of a power outage impacting manufacturing facilities at Schweitzer Engineering Laboratories in Pullman, Wash., where reliability is critical to their operations. Pioneering battery storage to facilitate renewable energy integration is one way we are working with customers and researchers to make sure energy is available when it is needed. GIVING CUSTOMERS THE CHOICES THEY WANT Avista’s vision statement calls for delivering reliable energy service and the choices that matter most to our customers. Those choices are being shaped by a new generation of customers and the experiences they are having with other commercial entities, websites and evolving new technology. As a utility, what we do and how we do it are impacted by regulations, state and federal agencies, and the often single-focused view of others who want to steer the work we do to meet their particular ideological agenda. Our focus is first on our customers and meeting their energy needs reliably, safely and at a fair price. Once, we thought of customers only in three categories — residential, commercial and industrial. Today, our customer engagement activities are more complex and founded in the data we gather from the technology we’ve put in place to tell us their preferences for communication, for paying their bills and for interacting with their utility company. We’re in the beginning stages of getting our arms around this “big data” to help us understand how to personalize and enrich our customers’ experiences with us. As customers think more about renewable resources, Avista is giving them choices. Since 2002, we’ve offered customers the opportunity to purchase blocks of power. Each block provides 300 kWh of energy from renewable resources — wind, solar and biomass. Today, we’ve added access to information about solar installations for their homes and businesses. We’ve developed a “solar concierge” page on our website that helps customers determine if solar is a cost-effective alternative for them and their life style. For those who want solar but don’t want to build it themselves, Avista offers the first and largest community solar project among investor-owned utilities in the Pacific Northwest. We know that communication is the key to any good relationship and that holds true with our customers. Enhancements to the customer information system — replacing our legacy system that was developed in the early 1990s — were successfully launched in February 2015. This tool could add functionality, while helping us integrate data collection and track preference information to give customers a more robust experience with us. It also provides Avista with a deeper understanding of our customers and their needs when they contact us and enhances our ability to meet those needs in a timely and accurate manner. OUR NEW ONLINE OUTAGE INFORMATION CENTER, LAUNCHED A MERE TWO WEEKS BEFORE A SEVERE STORM HIT OUR SERVICE TERRITORY IN NOVEMBER, WAS AN ESSENTIAL CONDUIT OF INFORMATION. SUPPLEMENTING THIS CHANNEL WITH SOCIAL MEDIA VIA TWITTER AND FACEBOOK GIVES US EASY AND POPULAR CHANNELS FOR TWO-WAY COMMUNICATION WITH OUR CUSTOMERS, THE MEDIA AND OTHERS WHO FOLLOW US IN OUR SERVICE TERRITORY AND AROUND THE COUNTRY. WWW.AVISTAUTILITIES.COM Staff_DR_063 Attachment B Page 8 of 160 AEL&P USING TECHNOLOGY TO MANAGE AVALANCHES The City and Borough of Juneau, Alaska, are situated in some of the most scenic and rugged country in the United States. AEL&P, owned by Avista since 2014, provides power to 16,000 customers in the capital city, primarily with hydroelectric generation from lakes high in the surrounding mountains. While snow pack is essential to power generation, it can also be the source of dangerous and ever-present avalanche threat. Crews travel via helicopter, tram or on foot to areas as diverse as mountain tops and urban hillsides to use state-of-the-art snow pack probes that help pinpoint weak snow layers before they become a threat to transmission lines and other utility infrastructure. Carrying on our company’s legacy of innovation, AEL&P is one of the first utility companies in the country to use snow pack probe technology that provides real-time avalanche forecasting, enhancing safety and reliability for our employees and our customers. 7 Staff_DR_063 Attachment B Page 9 of 160 8 2016 CAPITAL BUDGET Total capital budget $392 million ($ in millions) TOTAL SHAREHOLDER RETURN Assumes $100 was invested in Avista Corp. and each index on Dec. 31, 2010, and that all dividends were reinvested when paid COMMON STOCK DIVIDENDS PAID BY AVISTA CORP. Annualized Dividend (paid in dollars) Avista Corp.’s board of directors raised the dividend in each of the last 13 years, reflecting their confidence in the financial strength of the company. ELECTRICITY GENERATION RESOURCE MIX As of Dec. 31, 2015 Excludes AEL&P FINANCIAL AND OPERATING HIGHLIGHTSHIGHLIGHTS $0 $40$20 $60 $80 $100 $120 TRANSMISSION& DISTRIBUTION $131 GENERATION $52 TECHNOLOGY $51 NATURAL GAS $47 GROWTH $43 ENVIRONMENTAL $22 FACILITIES $20 FLEET $6 OTHER $3 AEL&P $17 ‘15 1.32 ‘14 1.27 ’13 1.22 ‘12 1.16 ’11 1.10 ‘10 1.00 ’09 .81 ‘08 .69 ’07 .595 ‘06 .57$125 $175 ‘12 ‘13 ‘14 ‘15‘10 Avista Corp. (AVA) $100 $150 $200 ‘11 S&P 500 Index S&P 400 Utilities Index $100 $120 $117 $144 $187 $195 HYDRO (40% Avista & 8% Contracts) NATURAL GAS (35%) COAL (9%) WIND (6%) BIOMASS (2%) Staff_DR_063 Attachment B Page 10 of 160 (dollars in thousands except statistics and per share amounts or as otherwise indicated)2015 2014 2013 FINANCIAL RESULTS Operating revenues $ 1,484,776 $ 1,472,562 $ 1,441,744 Operating expenses 1,231,562 1,219,974 1,210,655 Income from operations 253,214 252,588 231,089 Net income from continuing operations 118,170 119,866 104,333 Net income from discontinued operations 5,147 72,411 7,961 Net income 123,317 192,277 112,294 Net income attributable to Avista Corp. shareholders 123,227 192,041 111,077 Earnings per common share from continuing operations, diluted 1.89 1.93 1.74 Earnings per common share from discontinued operations, diluted 0.08 1.17 0.11 Total earnings per common share attributable to Avista Corp. shareholders, diluted 1.97 3.10 1.85 Earnings per common share from continuing operations, basic 1.90 1.94 1.74 Earnings per common share from discontinued operations, basic 0.08 1.18 0.11 Total earnings per common share attributable to Avista Corp. shareholders, basic 1.98 3.12 1.85 Dividends paid per common share 1.32 1.27 1.22 Book value per common share $ 24.53 $ 23.84 $ 21.61 Average common shares outstanding 62,301 61,632 59,960 Actual common shares outstanding 62,313 62,243 60,077 Return on average Avista Corp. stockholders’ equity 8.2%13.7% 8.7% Common stock closing price $ 35.37 $ 35.35 $ 28.19 OPERATING RESULTS AVISTA UTILITIES Retail electric revenues $ 762,809 $ 757,130 $ 742,370 Retail kWh sales (in millions) 8,603 8,776 8,897 Retail electric customers at year-end 374,848 370,086 366,206 Wholesale electric revenues $ 127,253 $ 138,162 $ 127,556 Wholesale kWh sales (in millions) 3,145 3,686 3,874 Sales of fuel $ 82,853 $ 83,732 $ 126,657 Other electric revenues 25,839 27,467 36,071 Decoupling (electric) 4,740 — — Provision for electric earnings sharing (5,621) (7,503) (2,048) Retail natural gas revenues 297,150 313,502 314,835 Wholesale natural gas revenues 204,289 228,187 194,717 Transportation and other natural gas revenues 13,566 15,196 16,149 Decoupling (natural gas) 6,004 — — Provision for natural gas earnings sharing $ — $ (221) $ (442) Total therms delivered (in thousands) 1,268,431 1,025,942 1,023,043 Retail natural gas customers at year-end 334,573 329,564 325,757 Net income attributable to Avista Corp. shareholders $ 113,360 $ 113,263 $ 108,598 ALASKA ELECTRIC LIGHT AND POWER COMPANY Revenues $ 44,778 $ 21,644 $ — Retail kWh sales (in millions) 398 189 — Retail electric customers at year-end 16,672 16,394 — Net income attributable to Avista Corp. shareholders 6,641 3,152 — OTHER Revenues $ 28,685 $ 39,219 $ 39,549 Net income (loss) attributable to Avista Corp. shareholders (1,921) 3,236 (4,650) FINANCIAL CONDITION Total assets (excludes Ecova for 2013) $ 4,906,649 $ 4,700,971 $ 4,011,533 Long-term debt and capital leases (including current portion) 1,573,278 1,487,126 1,262,036 Nonrecourse long-term debt of Spokane Energy (including current portion) — 1,431 17,838 Long-term debt to affiliated trusts 51,547 51,547 51,547 Total Avista Corp. stockholders’ equity $ 1,528,626 $ 1,483,671 $ 1,298,266 Staff_DR_063 Attachment B Page 11 of 160 10 ERIK J. ANDERSON, 57 President, Westriver Management, LLC Kirkland, Washington Director since 2000 KRISTIANNE BLAKE, 62 President, Kristianne Gates Blake, P.S. Spokane, Washington Director since 2000 DONALD C. BURKE, 55 Donald C. Burke, CPA Langhorne, Pennsylvania Director since 2011 CORPORATE GOVERNANCE/ NOMINATING COMMITTEE Kristianne Blake Marc F. Racicot R. John Taylor John F. Kelly — Chair EXECUTIVE COMMITTEE Kristianne Blake John F. Kelly R. John Taylor Scott L. Morris — Chair SCOTT L. MORRIS, 58 Chairman of the Board, President & CEO MARK T. THIES, 52 Senior Vice President, CFO & Treasurer MARIAN M. DURKIN, 62 Senior Vice President, General Counsel & Chief Compliance Officer KAREN S. FELTES, 60 Senior Vice President, Chief HR Officer & Corporate Secretary DENNIS P. VERMILLION, 54 Senior Vice President & Environmental Compliance Officer President, Avista Utilities JOHN F. KELLY, 71 President & CEO, John F. Kelly & Associates Winter Park, Florida Director since 1997 REBECCA A. KLEIN, 50 Principal, Klein Energy, LLC Austin, Texas Director since 2010 SCOTT L. MORRIS, 58 Chairman of the Board, President & CEO, Avista Corp. Spokane, Washington Director since 2007 MARC F. RACICOT, 67 Bigfork, Montana Director since 2009 HEIDI B. STANLEY, 59 Co-owner & Chair, Empire Bolt & Screw Inc. Spokane, Washington Director since 2006 R. JOHN TAYLOR, 66 Chairman & CEO, Green Leaf Alliance Lewiston, Idaho Director since 1985 JANET D. WIDMANN, 49 CEO, Rock Health, Inc. San Francisco, California Director since 2014 AUDIT COMMITTEE Donald C. Burke (Financial Expert) Heidi B. Stanley Kristianne Blake — Chair COMPENSATION & ORGANIZATION COMMITTEE John F. Kelly Rebecca A. Klein R. John Taylor — Chair KEVIN J. CHRISTIE, 48 Vice President, Customer Solutions JAMES M. KENSOK, 57 Vice President, CIO & Chief Security Officer RYAN L. KRASSELT, 46 Vice President, Controller & Principal Accounting Officer DAVID J. MEYER, 62 Vice President & Chief Counsel for Regulatory & Governmental Affairs KELLY O. NORWOOD, 57 Vice President, State & Federal Regulation FINANCE COMMITTEE Donald C. Burke Heidi B. Stanley Janet D. Widmann Erik J. Anderson — Chair ENVIRONMENTAL, TECHNOLOGY & OPERATIONS COMMITTEE Erik J. Anderson Marc F. Racicot Janet D. Widmann Rebecca A. Klein — Chair HEATHER L. ROSENTRATER, 38 Vice President, Energy Delivery EDWARD D. SCHLECT, JR., 55 Vice President & Chief Strategy Officer JASON R. THACKSTON, 46 Senior Vice President, Energy Resources ROGER D. WOODWORTH, 59 Vice President & President, Avista Development TIMOTHY D. MCLEOD, 64 President & General Manager, Alaska Electric Light & Power Co. CORPORATE & BUSINESS UNIT OFFICERS BOARD COMMITTEES BOARD OF DIRECTORS Ages are as of the proxy date — March 31, 2016 Staff_DR_063 Attachment B Page 12 of 160 BUILDING CONNECTIONS Connecting people to the Spokane River is an important part of Avista’s work. Avista, Washington State Parks and the Washington State Department of Natural Resources recently partnered to improve the recreational opportunities around the Nine Mile Falls hydroelectric project on the river. This new non-motorized boat launch provides river access above Nine Mile Dam. Vehicle parking, a portage pathway and concrete terraces enable safe launching of kayaks, canoes and other human-powered watercraft. 11 Staff_DR_063 Attachment B Page 13 of 160 FILED: FEBRUARY 23, 2016 (PERIOD: DECEMBER 31, 2015) ANNUAL REPORT WHICH PROVIDES A COMPREHENSIVE OVERVIEW OF THE COMPANY FOR THE PAST YEAR. AVISTA CORP. FORM 10-K (NYSE:AVA) Staff_DR_063 Attachment B Page 14 of 160 UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K (Mark One)  ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 2015 OR  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM TO Commission file number 1-3701 AVISTA CORPORATION (Exact name of Registrant as specified in its charter) Washington 91-0462470 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 1411 East Mission Avenue, Spokane, Washington 99202-2600 (Address of principal executive offices) (Zip Code) Registrant’s telephone number, including area code: 509-489-0500 website: http://www.avistacorp.com Securities registered pursuant to Section 12(b) of the Act: Title of Class Name of Each Exchange on Which Registered Common Stock, no par value New York Stock Exchange Securities registered pursuant to Section 12(g) of the Act: Title of Class Preferred Stock, Cumulative, Without Par Value Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes  No  Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. Yes  No  Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes  No  Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes  No  Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of Registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  Indicate by check mark whether the registrant is a large accelerated filer, accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one) Large accelerated filer  Accelerated filer  Non-accelerated filer  Smaller reporting company  (Do not check if a smaller reporting company) Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes  No  The aggregate market value of the Registrant’s outstanding Common Stock, no par value (the only class of voting stock), held by non-affiliates is $1,909,309,138 based on the last reported sale price thereof on the consolidated tape on June 30, 2015. As of January 31, 2016, 62,494,881 shares of Registrant’s Common Stock, no par value (the only class of common stock), were outstanding. Documents Incorporated By Reference Part of Form 10-K into Which Document Document is Incorporated Proxy Statement to be filed in connection with the annual Part III, Items 10, 11, meeting of shareholders to be held May 12, 2016. 12, 13 and 14 Prior to such filing, the Proxy Statement filed in connection with the annual meeting of shareholders held on May 7, 2015. Staff_DR_063 Attachment B Page 15 of 160 I AVISTA INDEX ITEM NO. PAGE NO. Acronyms and Terms ..................................................................................................................................................................................................................... IV Forward-Looking Statements ..................................................................................................................................................................................................... 1 Available Information..................................................................................................................................................................................................................... 2 PART I 1. Business ............................................................................................................................................................................................................................................ 3 Company Overview .............................................................................................................................................................................................................. 3 Avista Utilities ....................................................................................................................................................................................................................... 3 General.................................................................................................................................................................................................................................... 3 Electric Operations .............................................................................................................................................................................................................. 3 Electric Requirements ........................................................................................................................................................................................................ 4 Electric Resources ............................................................................................................................................................................................................... 4 Hydroelectric Licenses ....................................................................................................................................................................................................... 6 Future Resource Needs ...................................................................................................................................................................................................... 6 Natural Gas Operations ...................................................................................................................................................................................................... 7 Regulatory Issues ................................................................................................................................................................................................................ 8 Federal Laws Related to Wholesale Competition ........................................................................................................................................................ 9 Regional Transmission Organizations ............................................................................................................................................................................. 9 Regional Transmission Planning ....................................................................................................................................................................................... 9 Regional Energy Markets ................................................................................................................................................................................................... 9 Reliability Standards ........................................................................................................................................................................................................... 10 Avista Utilities Operating Statistics ................................................................................................................................................................................ 11 Alaska Electric Light and Power Company .................................................................................................................................................................... 14 Other Businesses ................................................................................................................................................................................................................. 15 1A. Risk Factors ...................................................................................................................................................................................................................................... 16 1B. Unresolved Staff Comments ........................................................................................................................................................................................................ 20 2. Properties ......................................................................................................................................................................................................................................... 21 Avista Utilities ....................................................................................................................................................................................................................... 21 Alaska Electric Light and Power Company .................................................................................................................................................................... 22 3. Legal Proceedings .......................................................................................................................................................................................................................... 23 4. Mine Safety Disclosures ............................................................................................................................................................................................................... 23* PART II 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities ........................................... 23 6. Selected Financial Data ................................................................................................................................................................................................................ 24 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations ....................................................................................... 25 Business Segments .................................................................................................................................................................................................................. 25 Executive Level Summary ....................................................................................................................................................................................................... 25 Regulatory Matters ................................................................................................................................................................................................................... 27 Results of Operations—Overall ............................................................................................................................................................................................. 32 Results of Operations—Avista Utilities .............................................................................................................................................................................. 33 Results of Operations—Alaska Electric Light and Power Company............................................................................................................................ 44 Results of Operations—Ecova—Discontinued Operations ........................................................................................................................................... 45 Results of Operations—Other Businesses ......................................................................................................................................................................... 45 Accounting Standards to Be Adopted in 2016 .................................................................................................................................................................... 45 Critical Accounting Policies and Estimates ........................................................................................................................................................................ 46 Liquidity and Capital Resources ............................................................................................................................................................................................ 48 Overall Liquidity ......................................................................................................................................................................................................................... 48 Review of Consolidated Cash Flow Statement .................................................................................................................................................................. 48 Capital Resources ..................................................................................................................................................................................................................... 50 Capital Expenditures ................................................................................................................................................................................................................ 51 Off-Balance Sheet Arrangements......................................................................................................................................................................................... 52 Staff_DR_063 Attachment B Page 16 of 160 AVISTA II INDEX (CONTINUED) ITEM NO. PAGE NO. Pension Plan ............................................................................................................................................................................................................................... 52 Credit Ratings ............................................................................................................................................................................................................................. 52 Dividends ..................................................................................................................................................................................................................................... 52 Contractual Obligations ........................................................................................................................................................................................................... 53 Competition ................................................................................................................................................................................................................................. 53 Economic Conditions and Utility Load Growth .................................................................................................................................................................. 54 Environmental Issues and Other Contingencies ............................................................................................................................................................... 55 Enterprise Risk Management ................................................................................................................................................................................................. 58 7A. Quantitative and Qualitative Disclosures about Market Risk.............................................................................................................................................. 58 8. Financial Statements and Supplementary Data ..................................................................................................................................................................... 63 Report of Independent Registered Public Accounting Firm ........................................................................................................................................... 64 Financial Statements ................................................................................................................................................................................................................ 65 Consolidated Statements of Income .................................................................................................................................................................................... 65 Consolidated Statements of Comprehensive Income ...................................................................................................................................................... 66 Consolidated Balance Sheets ................................................................................................................................................................................................ 67 Consolidated Statements of Cash Flows ............................................................................................................................................................................. 69 Consolidated Statements of Equity and Redeemable Noncontrolling Interests ....................................................................................................... 71 Notes to Consolidated Financial Statements ..................................................................................................................................................................... 73 Note 1. Summary of Significant Accounting Policies .................................................................................................................................................. 73 Note 2. New Accounting Standards ................................................................................................................................................................................ 80 Note 3. Variable Interest Entities ..................................................................................................................................................................................... 81 Note 4. Business Acquisitions .......................................................................................................................................................................................... 81 Note 5. Discontinued Operations ..................................................................................................................................................................................... 83 Note 6. Derivatives and Risk Management .................................................................................................................................................................... 85 Note 7. Jointly Owned Electric Facilities ....................................................................................................................................................................... 88 Note 8. Property, Plant and Equipment ........................................................................................................................................................................... 89 Note 9. Asset Retirement Obligations ............................................................................................................................................................................. 89 Note 10. Pension Plans and Other Postretirement Benefit Plans ............................................................................................................................ 90 Note 11. Accounting for Income Taxes ........................................................................................................................................................................... 95 Note 12. Energy Purchase Contracts .............................................................................................................................................................................. 96 Note 13. Committed Lines of Credit ................................................................................................................................................................................. 97 Note 14. Long-Term Debt and Capital Leases ............................................................................................................................................................... 98 Note 15. Long-Term Debt to Affiliated Trusts ................................................................................................................................................................ 100 Note 16. Fair Value ............................................................................................................................................................................................................... 101 Note 17. Common Stock ...................................................................................................................................................................................................... 105 Note 18. Earnings per Common Share Attributable to Avista Corporation Shareholders ................................................................................. 106 Note 19. Commitments and Contingencies .................................................................................................................................................................... 106 Note 20. Regulatory Matters ............................................................................................................................................................................................. 109 Note 21. Information by Business Segments ................................................................................................................................................................ 110 Note 22. Selected Quarterly Financial Data (Unaudited) ........................................................................................................................................... 112 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure ..................................................................................... 113* 9A. Controls and Procedures .............................................................................................................................................................................................................. 113 9B. Other Information ........................................................................................................................................................................................................................... 115 PART III 10. Directors, Executive Officers and Corporate Governance .................................................................................................................................................. 115 11. Executive Compensation .............................................................................................................................................................................................................. 116 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters .............................................................. 117 13. Certain Relationships and Related Transactions, and Director Independence .............................................................................................................. 117 14. Principal Accounting Fees and Services .................................................................................................................................................................................. 117 Staff_DR_063 Attachment B Page 17 of 160 III AVISTA INDEX (CONTINUED) ITEM NO. PAGE NO. PART IV 15. Exhibits, Financial Statement Schedules ................................................................................................................................................................................. 118 Signatures ........................................................................................................................................................................................................................................ 119 Exhibit Index ..................................................................................................................................................................................................................................... 120 * = not an applicable item in the 2015 calendar year for Avista Corp. Staff_DR_063 Attachment B Page 18 of 160 AVISTA IV ACRONYMS AND TERMS (The following acronyms and terms are found in multiple locations within the document) Acronym/Term Meaning aMW – Average Megawatt—a measure of the average rate at which a particular generating source produces energy over a period of time AEL&P – Alaska Electric Light and Power Company, the primary operating subsidiary of AERC, which provides electric services in Juneau, Alaska AERC – Alaska Energy and Resources Company, the Company’s wholly-owned subsidiary based in Juneau, Alaska AFUDC – Allowance for Funds Used During Construction; represents the cost of both the debt and equity funds used to finance utility plant additions during the construction period AM&D – Advanced Manufacturing and Development, does business as METALfx ASC – Accounting Standards Codification ASU – Accounting Standards Update Avista Capital – Parent company to the Company’s non-utility businesses Avista Corp. – Avista Corporation, the Company Avista Energy – Avista Energy, Inc., an inactive electricity and natural gas marketing, trading and resource management business, subsidiary of Avista Capital Avista Utilities – Operating division of Avista Corp. (not a subsidiary) comprising the regulated utility operations in the Pacific Northwest BPA – Bonneville Power Administration Capacity – The rate at which a particular generating source is capable of producing energy, measured in kW or MW Cabinet Gorge – The Cabinet Gorge Hydroelectric Generating Project, located on the Clark Fork River in Idaho Colstrip – The coal-fired Colstrip Generating Plant in southeastern Montana Coyote Springs 2 – The natural gas-fired combined-cycle Coyote Springs 2 Generating Plant located near Boardman, Oregon CT – Combustion turbine Deadband or ERM deadband – The first $4.0 million in annual power supply costs above or below the amount included in base retail rates in Washington under the ERM in the state of Washington Dekatherm – Unit of measurement for natural gas; a dekatherm is equal to approximately one thousand cubic feet (volume) or 1,000,000 BTUs (energy) Ecology – The state of Washington’s Department of Ecology Ecova – Ecova, Inc., a provider of facility information and cost management services for multi-site customers and energy efficiency program management for commercial enterprises and utilities throughout North America, subsidiary of Avista Capital. Ecova was sold on June 30, 2014. EIM – Energy Imbalance Market Staff_DR_063 Attachment B Page 19 of 160 V AVISTA ACRONYMS AND TERMS (CONTINUED) (The following acronyms and terms are found in multiple locations within the document) Acronym/Term Meaning Energy – The amount of electricity produced or consumed over a period of time, measured in kWh or MWh. Also, refers to natural gas consumed and is measured in dekatherms. EPA – Environmental Protection Agency ERM – The Energy Recovery Mechanism, a mechanism for accounting and rate recovery of certain power supply costs accepted by the utility commission in the state of Washington FASB – Financial Accounting Standards Board FERC – Federal Energy Regulatory Commission GAAP – Generally Accepted Accounting Principles GHG – Greenhouse gas GS – Generating station IPUC – Idaho Public Utilities Commission IRP – Integrated Resource Plan Jackson Prairie – Jackson Prairie Natural Gas Storage Project, an underground natural gas storage field located near Chehalis, Washington Juneau – The City and Borough of Juneau, Alaska kV – Kilovolt (1000 volts): a measure of capacity on transmission lines kW, kWh – Kilowatt (1000 watts): a measure of generating output or capability. Kilowatt-hour (1000 watt hours): a measure of energy produced Lancaster Plant – A natural gas-fired combined cycle combustion turbine plant located in Idaho MPSC – Public Service Commission of the State of Montana MW, MWh – Megawatt: 1000 kW. Megawatt-hour: 1000 kWh NERC – North American Electricity Reliability Corporation Noxon Rapids – The Noxon Rapids Hydroelectric Generating Project, located on the Clark Fork River in Montana OPUC – The Public Utility Commission of Oregon PCA – The Power Cost Adjustment mechanism, a procedure for accounting and rate recovery of certain power supply costs accepted by the utility commission in the state of Idaho PGA – Purchased Gas Adjustment PLP – Potentially liable party Staff_DR_063 Attachment B Page 20 of 160 AVISTA VI ACRONYMS AND TERMS (CONTINUED) (The following acronyms and terms are found in multiple locations within the document) Acronym/Term Meaning PUD – Public Utility District PURPA – The Public Utility Regulatory Policies Act of 1978, as amended RCA – The Regulatory Commission of Alaska REC – Renewable energy credit RTO – Regional Transmission Organization Salix – Salix, Inc., a subsidiary of Avista Capital, launched in 2014 to explore markets that could be served with liquefied natural gas (LNG), primarily in western North America Spokane Energy – Spokane Energy, LLC (dissolved in the third quarter of 2015), a special purpose limited liability company and all of its membership capital was owned by Avista Corp. Therm – Unit of measurement for natural gas; a therm is equal to approximately one hundred cubic feet (volume) or 100,000 BTUs (energy) UTC – Washington Utilities and Transportation Commission Watt – Unit of measurement for electricity; a watt is equal to the rate of work represented by a current of one ampere under a pressure of one volt Staff_DR_063 Attachment B Page 21 of 160 1 AVISTA FORWARD-LOOKING STATEMENTS From time-to-time, we make forward-looking statements such as statements regarding projected or future: • financial performance; • cash flows; • capital expenditures; • dividends; • capital structure; • other financial items; • strategic goals and objectives; • business environment; and • plans for operations. These statements are based upon underlying assumptions (many of which are based, in turn, upon further assumptions). Such statements are made both in our reports filed under the Securities Exchange Act of 1934, as amended (including this Annual Report on Form 10-K), and elsewhere. Forward-looking statements are all statements except those of historical fact including, without limitation, those that are identified by the use of words that include “will,” “may,” “could,” “should,” “intends,” “plans,” “seeks,” “anticipates,” “estimates,” “expects,” “forecasts,” “projects,” “predicts,” and similar expressions. Forward-looking statements (including those made in this Annual Report on Form 10-K) are subject to a variety of risks and uncertainties and other factors. Most of these factors are beyond our control and may have a significant effect on our operations, results of operations, financial condition or cash flows, which could cause actual results to differ materially from those anticipated in our statements. Such risks, uncertainties and other factors include, among others: Financial Risk • weather conditions (temperatures, precipitation levels and wind patterns) which affect both energy demand and electric generating capability, including the effect of precipitation and temperature on hydroelectric resources, the effect of wind patterns on wind-generated power, weather-sensitive customer demand, and similar effects on supply and demand in the wholesale energy markets; • our ability to obtain financing through the issuance of debt and/or equity securities, which can be affected by various factors including our credit ratings, interest rates and other capital market conditions and the global economy; • changes in interest rates that affect borrowing costs, our ability to effectively hedge interest rates for anticipated debt issuances, variable interest rate borrowing and the extent we recover interest costs through utility operations; • changes in actuarial assumptions, interest rates and the actual return on plan assets for our pension and other postretirement benefit plans, which can affect future funding obligations, pension and other postretirement benefit expense and the related liabilities; • external pressure to meet financial goals that can lead to short-term or expedient decisions that reduce the likelihood of long-term objectives being met; • deterioration in the creditworthiness of our customers; • the outcome of pending legal proceedings arising out of the “western energy crisis” of 2000 and 2001, specifically related to the Pacific Northwest refund proceedings; • the outcome of legal proceedings and other contingencies; • economic conditions in our service areas, including the economy’s effects on customer demand for utility services; • declining energy demand related to customer energy efficiency and/or conservation measures; • changes in the long-term global and our utilities’ service area climates, which can affect, among other things, customer demand patterns and the volume and timing of streamflows to our hydroelectric resources; • changes in industrial, commercial and residential growth and demographic patterns in our service territory or changes in demand by significant customers; Utility Regulatory Risk • state and federal regulatory decisions that affect our ability to recover costs and earn a reasonable return including, but not limited to, disallowance or delay in the recovery of capital investments, operating costs and commodity costs and discretion over allowed return on investment; • possibility that our integrated resource plans for electric and natural gas will not be acknowledged by the state commissions; Energy Commodity Risk • volatility and illiquidity in wholesale energy markets, including the availability of willing buyers and sellers, changes in wholesale energy prices that can affect operating income, cash requirements to purchase electricity and natural gas, value received for wholesale sales, collateral required of us by counterparties in wholesale energy transactions and credit risk to us from such transactions, and the market value of derivative assets and liabilities; • default or nonperformance on the part of any parties from whom we purchase and/or sell capacity or energy; • potential obsolescence of our power supply resources; Operational Risk • severe weather or natural disasters, including, but not limited to, avalanches, wind storms, wildfires, snow and ice storms, that can disrupt energy generation, transmission and distribution, as well as the availability and costs of materials, equipment, supplies and support services; • explosions, fires, accidents, mechanical breakdowns or other incidents that may impair assets and may disrupt operations of any of our generation facilities, transmission and distribution systems or other operations and may require us to purchase replacement power; • public injuries or damage arising from or allegedly arising from our operations; • blackouts or disruptions of interconnected transmission systems (the regional power grid); • terrorist attacks, cyber attacks or other malicious acts that may disrupt or cause damage to our utility assets or to the national economy in general, including any effects of terrorism, cyber attacks or vandalism that damage or disrupt information technology systems; Staff_DR_063 Attachment B Page 22 of 160 AVISTA 2 • work force issues, including changes in collective bargaining unit agreements, strikes, work stoppages, the loss of key executives, availability of workers in a variety of skill areas, and our ability to recruit and retain employees; • increasing costs of insurance, more restrictive coverage terms and our ability to obtain insurance; • delays or changes in construction costs, and/or our ability to obtain required permits and materials for present or prospective facilities; • third party construction of buildings, billboard signs or towers within our rights of way, or placement of fuel receptacles within close proximity to our transformers or other equipment, including overbuild atop natural gas distribution lines; • the loss of key suppliers for materials or services or disruptions to the supply chain; • increasing health care costs and the resulting effect on employee injury costs and health insurance provided to our employees and retirees; • adverse impacts to our Alaska operations that could result from an extended outage of its hydroelectric generating resources or its inability to deliver energy, due to its lack of interconnectivity to any other electrical grids and the extensive cost of replacement power (diesel); Compliance Risk • compliance with extensive federal, state and local legislation and regulation, including numerous environmental, health, safety, infrastructure protection, reliability and other laws and regulations that affect our operations and costs; • the ability to comply with the terms of the licenses and permits for our hydroelectric or thermal generating facilities at cost-effective levels; Technology Risk • cyber attacks on us or our vendors or other potential lapses that result in unauthorized disclosure of private information, which could result in liabilities against us, costs to investigate, remediate and defend, and damage to our reputation; • disruption to or breakdowns of information systems, automated controls and other technologies that we rely on for our operations, communications and customer service; • changes in the costs to operate and maintain current production technology or to implement new information technology systems that impede our ability to complete such projects timely and effectively; • changes in technologies, possibly making some of the current technology we utilize obsolete or the introduction of new technology that may create new cyber security related risk; • insufficient technology skills, which could lead to the inability to develop, modify or maintain our information systems; Strategic Risk • growth or decline of our customer base and the extent to which new uses for our services may materialize or existing uses may decline, including, but not limited to, the effect of the trend toward distributed generation at customer sites; • potential difficulties in integrating acquired operations and in realizing expected opportunities, diversions of management resources and losses of key employees, challenges with respect to operating new businesses and other unanticipated risks and liabilities; • the potential effects of negative publicity regarding business practices, whether true or not, which could result in litigation or a decline in our common stock price; • changes in our strategic business plans, which may be affected by any or all of the foregoing, including the entry into new businesses and/or the exit from existing businesses and the extent of our business development efforts where potential future business is uncertain; External Mandates Risk • changes in environmental laws, regulations, decisions and policies, including present and potential environmental remediation costs and our compliance with these matters; • the potential effects of legislation or administrative rulemaking at the federal, state or local levels, including possible effects on our generating resources of restrictions on greenhouse gas emissions to mitigate concerns over global climate changes; • political pressures or regulatory practices that could constrain or place additional cost burdens on our energy supply sources, such as campaigns to halt coal-fired power generation and opposition to other thermal generation, wind turbines or hydroelectric facilities; • wholesale and retail competition including alternative energy sources, growth in customer-owned power resource technologies that displace utility-supplied energy or that may be sold back to the utility, and alternative energy suppliers and delivery arrangements; • failure by us to identify changes in legislation, taxation and regulatory issues which are detrimental or beneficial to our overall business; and • the risk of municipalization in any of our service territories. Our expectations, beliefs and projections are expressed in good faith. We believe they are reasonably based on, without limitation, an examination of historical operating trends, our records and other information available from third parties. However, there can be no assurance that our expectations, beliefs or projections will be achieved or accomplished. Furthermore, any forward-looking statement speaks only as of the date on which such statement is made. We undertake no obligation to update any forward-looking statement or statements to reflect events or circumstances that occur after the date on which such statement is made or to reflect the occurrence of unanticipated events. New risks, uncertainties and other factors emerge from time to time, and it is not possible for us to predict all such factors, nor can we assess the effect of each such factor on our business or the extent that any such factor or combination of factors may cause actual results to differ materially from those contained in any forward-looking statement. AVAILABLE INFORMATION Our website address is www.avistacorp.com. We make annual, quarterly and current reports available on our website as soon as practicable after electronically filing these reports with the U.S. Securities and Exchange Commission (SEC). Information contained on our website is not part of this report. Staff_DR_063 Attachment B Page 23 of 160 3 AVISTA PART I ITEM 1. BUSINESS COMPANY OVERVIEW Avista Corporation, incorporated in the territory of Washington in 1889, is primarily an electric and natural gas utility with certain other business ventures. As of December 31, 2015, we employed 1,711 people in our Pacific Northwest utility operations (Avista Utilities) and 227 people in our subsidiary businesses (including our Juneau, Alaska utility operations). Our corporate headquarters are in Spokane, Washington, the second-largest city in Washington. Spokane serves as the business, transportation, medical, industrial and cultural hub of the Inland Northwest region (eastern Washington and northern Idaho). Regional services include government and higher education, medical services, retail trade and finance. Through our subsidiary AEL&P, we also provide electric utility services in the City and Borough of Juneau (Juneau), Alaska. As of December 31, 2015, we have two reportable business segments as follows: • Avista Utilities—an operating division of Avista Corp. (not a subsidiary) that comprises our regulated utility operations in the Pacific Northwest. Avista Utilities generates, transmits and distributes electricity and distributes natural gas, serving electric and natural gas customers in eastern Washington and northern Idaho and natural gas customers in parts of Oregon. We also supply electricity to a small number of customers in Montana, most of whom are our employees who operate our Noxon Rapids generating facility. Avista Utilities also engages in wholesale purchases and sales of electricity and natural gas as an integral part of energy resource management and our load-serving obligation. • AEL&P—a utility providing electric services in Juneau, Alaska and the primary operating subsidiary of AERC. We acquired AERC on July 1, 2014, and as of that date, AERC became a wholly-owned subsidiary of Avista Corp. See “Note 4 of the Notes to Consolidated Financial Statements” for further discussion regarding this acquisition. We have other businesses, including sheet metal fabrication, venture fund investments, real estate investments, a company that explores markets that could be served with LNG, as well as certain other investments of Avista Capital, which is a direct, wholly owned subsidiary of Avista Corp. These activities do not represent a reportable business segment and are conducted by various direct and indirect subsidiaries of Avista Corp., including AM&D, doing business as METALfx. Total Avista Corp. shareholders’ equity was $1,528.6 million as of December 31, 2015, of which $57.4 million represented our investment in Avista Capital and $95.4 million represented our investment in AERC. See “Item 6. Selected Financial Data” and “Note 21 of the Notes to Consolidated Financial Statements” for information with respect to the operating performance of each business segment (and other subsidiaries). AVISTA UTILITIES General At the end of 2015, we supplied retail electric service to 375,000 customers and retail natural gas service to 335,000 customers across Avista Utilities’ service territory. Avista Utilities’ service territory covers 30,000 square miles with a population of 1.6 million. See “Item 2. Properties” for further information on our utility assets. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Economic Conditions and Utility Load Growth” for information on economic conditions in our service territory. Electric Operations General—Avista Utilities generates, transmits and distributes electricity, serving electric customers in eastern Washington, northern Idaho and a small number of customers in Montana. Avista Utilities generates electricity from facilities that we own and purchases capacity, energy and fuel for generation under long-term and short-term contracts to meet customer load obligations. We also sell electric capacity and energy, as well as surplus fuel in the wholesale market in connection with our resource optimization activities as described below. As part of Avista Utilities’ resource procurement and management operations in the electric business, we engage in an ongoing process of resource optimization, which involves the economic selection from available energy resources to serve our load obligations and then capture additional economic value through market transactions. We engage in transactions in the wholesale markets by selling and purchasing electric capacity and energy, fuel for electric generation, and derivative instruments related to capacity, energy, transport and fuel. Such transactions are part of the process of matching available resources with load obligations and hedging the related financial risks. These transactions range from terms of intra-hour up to multiple years. We make continuing projections of: • electric loads at various points in time (ranging from intra-hour to multiple years) based on, among other things, estimates of customer usage and weather, historical data and contract terms, and • resource availability at these points in time based on, among other things, fuel choices and fuel markets, estimates of streamflows, availability of generating units, historic and forward market information, contract terms, and experience. On the basis of these projections, we make purchases and sales of electric capacity and energy, fuel for electric generation, and related derivative instruments to match expected resources to expected electric load requirements and reduce our exposure to electricity (or fuel) market price changes. Resource optimization involves scheduling and dispatching available resources as well as the following: • purchasing fuel for generation, • when economical, selling fuel and substituting wholesale electric purchases, and • other wholesale transactions to capture the value of generating resources, transmission contract rights and fuel delivery (transport) capacity contracts. Staff_DR_063 Attachment B Page 24 of 160 AVISTA 4 This optimization process includes entering into hedging transactions to manage risks. Transactions include both physical energy contracts and related derivative instruments. Avista Utilities’ generation assets are interconnected through the regional transmission system and are operated on a coordinated basis to enhance load-serving capability and reliability. Avista acquires both long term and short term transmission capacity to facilitate all of our energy and capacity transactions. We provide transmission and ancillary services in eastern Washington, northern Idaho and western Montana. Electric Requirements Avista Utilities’ peak electric native load requirement for 2015 occurred on August 12, 2015, at which time our peak electric native load was 1,638 MW. In 2014 and 2013, our peak electric native load requirements were 1,715 and 1,669 MW, respectively, both of which occurred during the winter. Electric Resources Avista Utilities has a diverse electric resource mix of Company-owned and contracted hydroelectric projects, thermal generating facilities, wind generation facilities, and power purchases and exchanges. At the end of 2015, our Company-owned facilities had a total net capability of 1,841 MW, of which 55 percent was hydroelectric and 45 percent was thermal. See “Item 2. Properties” for detailed information on generating facilities. Hydroelectric Resources—Avista Utilities owns and operates six hydroelectric projects on the Spokane River and two hydroelectric projects on the Clark Fork River. Hydroelectric generation is typically our lowest cost source per MWh of electricity and the availability of hydroelectric generation has a significant effect on total power supply costs. Under normal streamflow and operating conditions, we estimate that we would be able to meet approximately one-half of our total average electric requirements (both retail and long-term wholesale) with the combination of our hydroelectric generation and long-term hydroelectric purchase contracts with certain PUDs in the state of Washington. Our estimate of normal annual hydroelectric generation for 2016 (including resources purchased under long-term hydroelectric contracts with certain PUDs) is 533 aMW (or 4.6 million MWhs). The following graph shows Avista Utilities’ hydroelectric generation (in thousands of MWhs) during the year ended December 31: 0 750 1,500 2,250 3,000 3,750 4,500 5,250 Noxon Rapids Cabinet Gorge Post Falls Upper Falls Monroe Street Nine Mile Long Lake Little Falls Long-term hydroelectric contracts with PUDs Normal hydroelectric generation (1) 2015 Th o u s a n d s o f M W h s HYDROELECTRIC GENERATION 2014 2013 4,319 5,020 4,616 (1) Normal hydroelectric generation is determined by applying an upstream regulation calculation to median natural water flow information. Natural water flow is the flow of the rivers without the influence of dams, whereas regulated water flow takes into account any water flow changes from upstream dams due to releasing or holding back water. The calculation of normal varies annually due to the timing of upstream dam regulation throughout the year. Staff_DR_063 Attachment B Page 25 of 160 5 AVISTA Thermal Resources—Avista Utilities owns the following thermal resources: • the combined cycle CT natural gas-fired Coyote Springs 2 located near Boardman, Oregon, • a 15 percent interest in a twin-unit, coal-fired boiler generating facility, Colstrip 3 & 4, located in southeastern Montana, • a wood waste-fired boiler generating facility known as the Kettle Falls Generating Station (Kettle Falls GS) in northeastern Washington, • a two-unit natural gas-fired CT generating facility, located in northeastern Spokane (Northeast CT), • a two-unit natural gas-fired CT generating facility in northern Idaho (Rathdrum CT), and • two small natural gas-fired generating facilities (Boulder Park and Kettle Falls CT). Coyote Springs 2, which is operated by Portland General Electric Company, is supplied with natural gas under both term contracts and spot market purchases, including transportation agreements with bilateral renewal rights. Colstrip, which is operated by Talen Energy LLC, is supplied with fuel from adjacent coal reserves under coal supply and transportation agreements in effect through 2019. The primary fuel for the Kettle Falls GS is wood waste generated as a by-product and delivered by trucks from forest industry operations within 100 miles of the plant. A combination of long-term contracts and spot purchases has provided, and is expected to meet, fuel requirements for the Kettle Falls GS. The Northeast CT, Rathdrum CT, Boulder Park and Kettle Falls CT generating units are primarily used to meet peaking electric requirements. We also operate these facilities when marginal costs are below prevailing wholesale electric prices. These generating facilities have access to natural gas supplies that are adequate to meet their respective operating needs. See “Item 2. Properties—Avista Utilities—Generation Properties” for the nameplate rating and present generating capabilities of the above thermal resources. Lancaster Plant—We have the exclusive rights to capacity of the Lancaster Plant, a 270 MW natural gas-fired combined cycle combustion turbine plant located in northern Idaho, owned by an unrelated third-party. All of the output from the Lancaster Plant is contracted to us through 2026 under a power purchase agreement (PPA). Under the terms of the PPA, we make the dispatch decisions, provide all natural gas fuel and receive all of the electric energy output from the Lancaster Plant; therefore, we consider this plant in our baseload resources. See “Note 3 of the Notes to Consolidated Financial Statements” for further discussion of this PPA. The following graph shows Avista Utilities’ thermal generation (in thousands of MWhs) during the year ended December 31: 0 750 1,500 2,250 3,000 3,750 4,500 5,250 6,000 Lancaster Plant PPA Northeast CT, Rathdrum CT, Boulder Park and Kettle Falls CT Kettle Falls GS Colstrip Coyote Springs 2 2015 Th o u s a n d s o f M W h s THERMAL GENERATION 2014 2013 5,508 4,447 5,039 Wind Resources—Palouse Wind is a wind generation project developed by Palouse Wind, LLC, and located in Whitman County, Washington. We have a 30-year PPA (expires in 2042) to acquire all of the power and renewable attributes produced by the project at a fixed price per MWh with a fixed escalation of the price over the term of the agreement. The project has a nameplate capacity of approximately 105 MW. Generation from Palouse Wind was 293,563 MWhs in 2015, 335,291 MWhs in 2014 and 297,027 MWhs in 2013. We have an annual option to purchase the wind project following the 10th anniversary of its December 2012 commercial operation date. The purchase price per the PPA is a fixed price per kW of in-service capacity with a fixed decline in the price per kW over the remaining 20 year term of the agreement. Other Purchases, Exchanges and Sales—In addition to the resources described above, we purchase and sell power under various long-term contracts and we also enter into short-term purchases and sales. Further, pursuant to the PURPA, as amended, we are required to purchase generation from qualifying facilities. This includes, among other resources, hydroelectric projects, cogeneration projects and wind generation projects at rates approved by the UTC and the IPUC. See “Avista Utilities Operating Statistics—Electric Operations—Electric Energy Resources” for annual quantities of Staff_DR_063 Attachment B Page 26 of 160 AVISTA 6 purchased power, wholesale power sales and power from exchanges in 2015, 2014 and 2013. See “Electric Operations” for additional information with respect to the use of wholesale purchases and sales as part of our resource optimization process and also see “Future Resource Needs” for the magnitude of these power purchase and sales contracts in future periods. Hydroelectric Licenses Avista Corp. is a licensee under the Federal Power Act (FPA) as administered by the FERC, which includes regulation of hydroelectric generation resources. Excluding the Little Falls Hydroelectric Generating Project, our other seven hydroelectric plants are regulated by the FERC through two project licenses. The licensed projects are subject to the provisions of Part I of the FPA. These provisions include payment for headwater benefits, condemnation of licensed projects upon payment of just compensation, and take-over of such projects after the expiration of the license upon payment of the lesser of “net investment” or “fair value” of the project, in either case, plus severance damages. Cabinet Gorge and Noxon Rapids are under one 45-year FERC license issued in March 2001. See “Cabinet Gorge Total Dissolved Gas Abatement Plan” in “Note 19 of the Notes to Consolidated Financial Statements” for discussion of dissolved atmospheric gas levels that exceed state of Idaho and federal numeric water quality standards downstream of Cabinet Gorge during periods when we must divert excess river flows over the spillway as well as of our mitigation plans and efforts. Five of our six hydroelectric projects on the Spokane River (Long Lake, Nine Mile, Upper Falls, Monroe Street and Post Falls) are under one 50-year FERC license issued in June 2009 and are referred to collectively as the Spokane River Project. The sixth, Little Falls, is operated under separate Congressional authority and is not licensed by the FERC. Future Resource Needs Avista Utilities has operational strategies to provide sufficient resources to meet our energy requirements under a range of operating conditions. These operational strategies consider the amount of energy needed, which varies widely because of the factors that influence demand over intra-hour, hourly, daily, monthly and annual durations. Our average hourly load was 1,047 aMW in 2015, 1,062 aMW in 2014 and 1,086 aMW in 2013. The following is a forecast of our average annual energy requirements and resources for 2016 through 2019: aM W FORECASTED ELECTRIC ENERGY REQUIREMENTS AND RESOURCES Requirements Resources 1,137 1,558 1,146 1,516 1,131 1,5021,569 1,174 0 500 1,000 1,500 2,000 Additional available energy (2) Other contracts for power purchases Company-owned and contract thermal generation (3) Company-owned and contract hydro generation (4) Contracts for power sales (1) System load Resources 2019 Requirements 2019 Resources 2018 Requirements 2018 Resources 2017 Requirements 2017 Resources 2016 Requirements 2016 (1) The contracts for power sales decrease due to certain contracts expiring in each of these years. We are evaluating the future plan for the additional resources made available due to the expiration of these contracts. (2) The combined maximum capacity of Boulder Park GS, Kettle Falls CT, Northeast CT and Rathdrum CT is 278 MW, with estimated available energy production as indicated for each year. (3) Includes the Lancaster Plant PPA. Excludes Boulder Park GS, Kettle Falls CT, Northeast CT and Rathdrum CT, as these are considered peaking facilities and are generally not used to meet our base load requirements. (4) The forecast assumes near normal hydroelectric generation. Staff_DR_063 Attachment B Page 27 of 160 7 AVISTA In August 2015, we filed our 2015 Electric IRP with the UTC and the IPUC. The UTC and IPUC review the IRPs and give the public the opportunity to comment. The UTC and IPUC do not approve or disapprove of the content in the IRPs; rather they only acknowledge that the IRPs were prepared in accordance with applicable standards if that is the case. The IRP details projected growth in demand for energy and the new resources needed to serve customers over the next 20 years. We regard the IRP as a tool for resource evaluation, rather than an acquisition plan for a particular project. Highlights of the 2015 IRP include: • We have adequate resources between our owned and contractually controlled generation, combined with conservation and market purchases, to meet customer needs through 2020. • 565 MW of additional generation capacity is required for the period 2020 through 2034. • We expect to meet or exceed the renewable energy requirements of the Washington state Energy Independence Act through the 20-year IRP time frame with a combination of qualifying hydroelectric upgrades, the 30-year PPA with Palouse Wind, the Kettle Falls GS and selective REC purchases. • Load growth is expected to be approximately 0.6 percent, a decline from the growth of 1.0 percent forecasted in 2013. This delays the need for a new natural gas-fired resource by one year. The decrease in expected load growth is primarily due to energy efficiency programs (using less energy to perform activities) over the next 20 years and the load impacts of increased prices. See “Item 7. Management Discussion and Analysis of Financial Condition and Results of Operations—Forecasted Customer and Load Growth and Economic Conditions and Utility Load Growth” for further discussion regarding utility customer growth, load growth, and the general economic conditions in our service territory. The estimates of future load growth in the IRP and at “Item 7. Management Discussion and Analysis of Financial Condition and Results of Operations—Forecasted Customer and Load Growth and Economic Conditions and Utility Load Growth” differ slightly due to the timing of when the two estimates were prepared and due to the time period that each estimate is focused on. • Colstrip remains a cost effective and reliable source of power to meet future customer needs. • Energy efficiency offsets more than half of projected load growth through the 20-year IRP time frame. • Demand response (temporarily reducing the demand for energy) was eliminated from the Preferred Resource Strategy due to higher estimated costs. We are required to file an IRP every two years, with the next IRP expected to be filed during the third quarter of 2017. Our resource strategy may change from the 2015 IRP based on market, legislative and regulatory developments. We are subject to the Washington state Energy Independence Act, which requires us to obtain a portion of our electricity from qualifying renewable resources or through purchase of RECs and acquiring all cost effective conservation measures. Future generation resource decisions will be impacted by legislation for restrictions on GHG emissions and renewable energy requirements. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Environmental Issues and Contingencies” for information related to existing laws, as well as potential legislation that could influence our future electric resource mix. Natural Gas Operations General—Avista Utilities provides natural gas distribution services to retail customers in parts of eastern Washington, northern Idaho, and northeastern and southwestern Oregon. Market prices for natural gas, like other commodities, can be volatile. Our natural gas procurement strategy is to provide reliable supply to our customers with some level of price certainty. We procure natural gas from various supply basins and over varying time periods. The resulting portfolio is a diversified mix of spot market purchases and forward fixed price purchases, utilizing physical and financial derivative instruments. We also use natural gas storage to support high demand periods and to procure natural gas when prices may be lower. Securing prices throughout the year and even into subsequent years provides a level of price certainty and can mitigate price volatility to customers between years. Weather is a key component of our natural gas customer load. This load is highly variable and daily natural gas loads can differ significantly from the monthly forecasted load projections. We make continuing projections of our natural gas loads and assess available natural gas resources. On the basis of these projections, we plan and execute a series of transactions to hedge a portion of our customers’ projected natural gas requirements through forward market transactions and derivative instruments. These transactions may extend for multiple years into the future with the highest volumes hedged for the current and most immediate upcoming natural gas operating year (November through October). We also leave a portion of our natural gas supply requirements unhedged for purchase in the short-term spot markets. Our purchase of natural gas supply is governed by our procurement plan, which is reviewed and approved annually by the Risk Management Committee (RMC), which is comprised of certain officers and other management personnel. Once approval is received, the plan is implemented and monitored by our gas supply and risk management groups. The plan’s progress is also presented to the UTC and IPUC staff in semi-annual meetings, and updates are given to the OPUC staff quarterly. Other stakeholders (Public Counsel Unit of the Office of the Attorney General, Citizen Utility Board) are invited to participate. The RMC is provided with an update on plan results and changes in their monthly meetings. These activities provide transparency for the natural gas supply procurement plan. Any material changes to the plan are documented and communicated to RMC members. Staff_DR_063 Attachment B Page 28 of 160 AVISTA 8 As part of the process of balancing natural gas retail load requirements with resources, we engage in the wholesale purchase and sale of natural gas. We plan for sufficient natural gas delivery capacity to serve our retail customers for a theoretical peak day event. As such, we generally have more pipeline and storage capacity than what is needed during periods other than a peak day. We optimize our natural gas resources by using market opportunities to generate economic value that helps mitigate fixed costs. Wholesale sales are delivered through wholesale market facilities outside of our natural gas distribution system. Natural gas resource optimization activities include, but are not limited to: • wholesale market sales of surplus natural gas supplies, • purchases and sales of natural gas to optimize use of pipeline and storage capacity, and • participation in the transportation capacity release market. We also provide distribution transportation service to qualified, large commercial and industrial natural gas customers who purchase natural gas through third-party marketers. For these customers, we receive their purchased natural gas from such third-party marketers into our distribution system and redeliver it to the customers’ premise. Optimization transactions that we engage in throughout the year are included in our annual purchased gas cost adjustment filings with the various commissions and they are subject to review for prudency during this process. Natural Gas Supply—Avista Utilities purchases all of its natural gas in wholesale markets. We are connected to multiple supply basins in the western United States and Canada through firm capacity transportation rights on six different pipeline networks. Access to this diverse portfolio of natural gas resources allows us to make natural gas procurement decisions that benefit our natural gas customers. These interstate pipeline transportation rights provide the capacity to serve approximately 25 percent of peak natural gas customer demands from domestic sources and 75 percent from Canadian sourced supply. Natural gas prices in the Pacific Northwest are affected by global energy markets, as well as supply and demand factors in other regions of the United States and Canada. Future prices and delivery constraints may cause our resource mix to vary. Natural Gas Storage—Avista Utilities owns a one-third interest in Jackson Prairie, an underground aquifer natural gas storage field located near Chehalis, Washington. Jackson Prairie has a total peak day deliverability of 12 million therms, with a total working natural gas capacity of 256 million therms. As an owner, our share is one-third of the peak day deliverability and total working capacity. We also contract for additional storage capacity and delivery at Jackson Prairie from Northwest Pipeline for a portion of their one-third share of the storage project. We optimize our natural gas storage capacity by purchasing and storing natural gas when prices are traditionally lower, typically in the summer, and withdraw during higher priced months, typically during the winter. However, if market conditions and prices indicate that we should buy or sell natural gas during other times in the year, we engage in optimization transactions to capture value in the marketplace. Jackson Prairie is also used as a variable peaking resource and to protect from extreme daily price volatility during cold weather or other events affecting the market. Future Resource Needs—In August 2014, we filed our 2014 Natural Gas IRP with the UTC, IPUC and the OPUC. The natural gas IRPs are similar in nature to the electric IRPs and the process for preparation and review by the state commissions of both the electric and natural gas IRPs is similar. The IRP details projected growth in demand for energy and the new resources needed to serve customers over the next 20 years. We regard the IRP as a tool for resource evaluation, rather than an acquisition plan for a particular project. Highlights of the 2014 IRP include: • We have sufficient natural gas transportation resources well into the future with resource needs not occurring during the 20 year planning horizon in Washington, Idaho, or Oregon. • Natural gas commodity prices continue to be relatively stable due to robust North American supplies led by shale gas development; and • As forecasted demand is relatively flat, we will monitor actual demand for signs of increased growth which could accelerate resource needs. We are required to file an IRP every two years, with the next IRP expected to be filed during the third quarter of 2016. Our resource strategy may change from the 2014 IRP based on market, legislative and regulatory developments. Regulatory Issues General—As a public utility, Avista Corp. is subject to regulation by state utility commissions for prices, accounting, the issuance of securities and other matters. The retail electric and natural gas operations are subject to the jurisdiction of the UTC, the IPUC, the OPUC and the MPSC. Approval of the issuance of securities is not required from the MPSC. We are also subject to the jurisdiction of the FERC for licensing of hydroelectric generation resources, and for electric transmission services and wholesale sales. Since Avista Corp. is a “holding company,” we are also subject to the jurisdiction of the FERC under the Public Utility Holding Company Act of 2005, which imposes certain reporting and other requirements. We, and all of our subsidiaries (whether or not engaged in any energy related business), are required to maintain books, accounts and other records in accordance with the FERC regulations and to make them available to the FERC and the state utility commissions. In addition, upon the request of any state utility commission, or of Avista Corp., the FERC would have the authority to review assignment of costs of non-power goods and administrative services among us and our subsidiaries. The FERC has the authority generally to require that rates subject to its jurisdiction be just and reasonable and in this context would continue to be able to, among other things, review transactions of any affiliated company. Our rates for retail electric and natural gas services (other than specially negotiated retail rates for industrial or large commercial customers, which are subject to regulatory review and approval) are generally determined on a “cost of service” basis. Rates are designed to provide an opportunity for us to recover allowable operating expenses and earn a return of and a reasonable return on “rate base.” Rate base is generally determined by reference to the original cost (net of accumulated depreciation) of utility plant in service, subject to various adjustments for deferred income taxes and other items. Over time, rate base is increased by additions to utility plant in service and reduced by depreciation and retirement of utility plant and write-offs as authorized by the utility commissions. Our operating expenses and rate base are allocated or directly assigned among five regulatory jurisdictions: electric in Washington and Idaho, and natural Staff_DR_063 Attachment B Page 29 of 160 9 AVISTA gas in Washington, Idaho and Oregon. In general, requests for new retail rates are made on the basis of net investment, operating expenses and revenues for a test year that ended prior to the date of the request, plus certain adjustments, which differ among the various jurisdictions, designed to reflect the expected revenues, expenses and net investment during the period new retail rates will be in effect. The retail rates approved by the state commissions in a rate proceeding may not provide sufficient revenues to provide recovery of costs and a reasonable return on investment for a number of reasons, including but not limited to, unexpected changes in revenues, expenses and investment following the time new retail rates are requested in the rate proceeding, and exclusion of certain costs and investment by the commission from the rate making process. Our rates for wholesale electric and natural gas transmission services are based on either “cost of service” principles or market- based rates as set forth by the FERC. See “Notes 1 and 20 of the Notes to Consolidated Financial Statements” for additional information about regulation, depreciation and deferred income taxes. General Rate Cases—Avista Utilities regularly reviews the need for electric and natural gas rate changes in each state in which we provide service. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Regulatory Matters— General Rate Cases” for information on general rate case activity. Power Cost Deferrals—Avista Utilities defers the recognition in the income statement of certain power supply costs that vary from the level currently recovered from our retail customers as authorized by the UTC and the IPUC. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Regulatory Matters—Power Cost Deferrals and Recovery Mechanisms” and “Note 20 of the Notes to Consolidated Financial Statements” for information on power cost deferrals and recovery mechanisms in Washington and Idaho. Purchased Gas Adjustment (PGA)—Under established regulatory practices in each state, Avista Utilities defers the recognition in the income statement of the natural gas costs that vary from the level currently recovered from our retail customers as authorized by each of our jurisdictions. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Regulatory Matters— Purchased Gas Adjustments” and “Note 20 of the Notes to Consolidated Financial Statements” for information on natural gas cost deferrals and recovery mechanisms in Washington, Idaho and Oregon. Federal Laws Related to Wholesale Competition Federal law promotes practices that open the electric wholesale energy market to competition. The FERC requires electric utilities to transmit power and energy to or for wholesale purchasers and sellers, and requires electric utilities to enhance or construct transmission facilities to create additional transmission capacity for the purpose of providing these services. Public utilities (through subsidiaries or affiliates) and other entities may participate in the development of independent electric generating plants for sales to wholesale customers. Public utilities operating under the FPA are required to provide open and non-discriminatory access to their transmission systems to third parties and establish an Open Access Same-Time Information System to provide an electronic means by which transmission customers can obtain information about available transmission capacity and purchase transmission access. The FERC also requires each public utility subject to the rules to operate its transmission and wholesale power merchant operating functions separately and to comply with standards of conduct designed to ensure that all wholesale users, including the public utility’s power merchant operations, have equal access to the public utility’s transmission system. Our compliance with these standards has not had any substantive impact on the operation, maintenance and marketing of our transmission system or our ability to provide service to customers. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Competition” for further information. Regional Transmission Organizations Beginning with FERC Order No. 888 and continuing with subsequent rulemakings and policies, the FERC has encouraged better coordination and operational consistency aimed to capture efficiencies that might otherwise be gained through the formation of a Regional Transmission Organization (RTO) or an independent system operator (ISO). Regional Transmission Planning Avista Utilities meets its FERC requirements to coordinate transmission planning activities with other regional entities through ColumbiaGrid. ColumbiaGrid is a Washington nonprofit membership corporation with an independent board formed to improve the operational efficiency, reliability, and planned expansion of the transmission grid in the Pacific Northwest. We became a member of ColumbiaGrid in 2006 during its formation. ColumbiaGrid is not an ISO, but performs those functions that its members request, as set forth in specific agreements. Currently, ColumbiaGrid fills the role of facilitating our regional transmission planning as required in FERC Order No. 1000 and other clarifying FERC Orders. ColumbiaGrid and its members also work with other western organizations to address transmission planning, including WestConnect and the Northern Tier Transmission Group (NTTG). In 2011, we became a registered Planning Participant of the NTTG. We will continue to assess the benefits of entering into other functional agreements with ColumbiaGrid and/or participating in other forums to attain operational efficiencies and to meet FERC policy objectives. Regional Energy Markets The California Independent System Operator (CAISO) recently implemented an EIM in the western United States. Several Pacific Norhwest utilities are either participants in the CAISO EIM or plan to integrate into the market in the next few years, which could reduce bilateral market liquidity and transaction opportunities in the Pacific Northwest. Avista Utilities is monitoring the CAISO EIM implementation but currently does not plan to join as a participating member. We will continue to monitor the CAISO EIM expansion and the associated impacts. As market fundamentals and our business needs evolve, we will weigh the advantages and disadvantages of joining the CAISO EIM or other organized energy markets in the future. Staff_DR_063 Attachment B Page 30 of 160 AVISTA 10 Reliability Standards Among its other provisions, the U.S. Energy Policy Act provides for the implementation of mandatory reliability standards and authorizes the FERC to assess penalties for non-compliance with these standards and other FERC regulations. The FERC certified the NERC as the single Electric Reliability Organization authorized to establish and enforce reliability standards and delegate authority to regional entities for the purpose of establishing and enforcing reliability standards. The FERC approved the NERC Reliability Standards, including western region standards, making up the set of legally enforceable standards for the United States bulk electric system. The first of these reliability standards became effective in June 2007. We are required to self-certify our compliance with these standards on an annual basis and undergo regularly scheduled periodic reviews by the NERC and its regional entity, the Western Electricity Coordinating Council (WECC). Our failure to comply with these standards could result in financial penalties of up to $1 million per day per violation. Annual self-certification and audit processes to date have demonstrated our substantial compliance with these standards. Requirements relating to cyber security are continually evolving. Our compliance with version 5 of the NERC’s Critical Infrastructure Protection standard is driving several physical and electronic security initiatives in our control centers, generating stations and substations. We do not expect the costs of the physical and electronic securities initiatives to have a material impact to our financial results. Staff_DR_063 Attachment B Page 31 of 160 11 AVISTA AVISTA CORPORATION Avista Utilities Electric Operating Statistics Years Ended December 31, 2015 2014 2013 Electric Operations Operating Revenues (Dollars in Thousands): Residential $ 335,552 $ 338,697 $ 331,867 Commercial 308,210 300,109 289,604 Industrial 111,770 110,775 113,632 Public street and highway lighting 7,277 7,549 7,267 Total retail 762,809 757,130 742,370 Wholesale 127,253 138,162 127,556 Sales of fuel 82,853 83,732 126,657 Other 25,839 27,467 36,071 Decoupling 4,740 — — Provision for earnings sharing (5,621) (7,503) (2,048) Total electric operating revenues $ 997,873 $ 998,988 $ 1,030,606 Energy Sales (Thousands of MWhs): Residential 3,571 3,694 3,745 Commercial 3,197 3,189 3,147 Industrial 1,812 1,868 1,979 Public street and highway lighting 23 25 26 Total retail 8,603 8,776 8,897 Wholesale 3,145 3,686 3,874 Total electric energy sales 11,748 12,462 12,771 Energy Resources (Thousands of MWhs): Hydro generation (from Company facilities) 3,434 4,143 3,646 Thermal generation (from Company facilities) 3,983 3,252 3,383 Purchased power 4,899 5,615 6,375 Power exchanges (2) (25) (20) Total power resources 12,314 12,985 13,384 Energy losses and Company use (566) (523) (613) Total energy resources (net of losses) 11,748 12,462 12,771 Number of Retail Customers (Average for Period): Residential 327,057 324,188 321,098 Commercial 41,296 40,988 40,202 Industrial 1,353 1,385 1,386 Public street and highway lighting 529 531 527 Total electric retail customers 370,235 367,092 363,213 Residential Service Averages: Annual use per customer (kWh) 10,827 11,394 11,664 Revenue per kWh (in cents) 9.40 9.17 8.86 Annual revenue per customer $ 1,017.21 $ 1,044.76 $ 1,033.54 Average Hourly Load (aMW) 1,047 1,062 1,086 Staff_DR_063 Attachment B Page 32 of 160 AVISTA 12 AVISTA CORPORATION (CONTINUED) Avista Utilities Electric Operating Statistics Years Ended December 31, 2015 2014 2013 Electric Operations (continued) Retail Native Load at time of system peak (MW): Winter 1,529 1,715 1,669 Summer 1,638 1,606 1,577 Cooling Degree Days: (1) Spokane, WA Actual 805 631 709 Historical average 334 394 394 % of average 241% 160% 180% Heating Degree Days: (2) Spokane, WA Actual 5,614 6,215 6,683 Historical average 6,491 6,820 6,780 % of average 86% 91% 99% (1) Cooling degree days are the measure of the warmness of weather experienced, based on the extent to which the average of high and low temperatures for a day exceeds 65 degrees Fahrenheit (annual degree days above historic indicate warmer than average temperatures). In 2015, we switched to a rolling 20-year average for calculating cooling degree days, whereas in prior years we used a 30-year rolling average. (2) Heating degree days are the measure of the coldness of weather experienced, based on the extent to which the average of high and low temperatures for a day falls below 65 degrees Fahrenheit (annual degree days below historic indicate warmer than average temperatures). In 2015, we switched to a rolling 20-year average for calculating heating degree days, whereas in prior years we used a 30-year rolling average. Staff_DR_063 Attachment B Page 33 of 160 13 AVISTA AVISTA CORPORATION (CONTINUED) Avista Utilities Natural Gas Operating Statistics Years Ended December 31, 2015 2014 2013 Natural Gas Operations Operating Revenues (Dollars in Thousands): Residential $ 193,825 $ 203,373 $ 206,330 Commercial 96,751 103,179 102,225 Interruptible 2,782 2,792 2,681 Industrial 3,792 4,158 3,599 Total retail 297,150 313,502 314,835 Wholesale 204,289 228,187 194,717 Transportation 7,988 7,735 7,576 Other 5,578 7,461 8,573 Decoupling 6,004 — — Provision for earnings sharing — (221) (442) Total natural gas operating revenues $ 521,009 $ 556,664 $ 525,259 Therms Delivered (Thousands of Therms): Residential 176,613 190,171 204,711 Commercial 107,894 116,748 122,245 Interruptible 4,708 5,033 5,694 Industrial 5,070 5,648 5,181 Total retail 294,285 317,600 337,831 Wholesale 809,132 545,620 524,818 Transportation 164,679 162,311 159,976 Interdepartmental and Company use 335 411 418 Total therms delivered 1,268,431 1,025,942 1,023,043 Number of Retail Customers (Average for Period): Residential 296,005 291,928 288,708 Commercial 34,229 34,047 33,932 Interruptible 35 37 38 Industrial 261 264 259 Total natural gas retail customers 330,530 326,276 322,937 Residential Service Averages: Annual use per customer (therms) 593 651 709 Revenue per therm (in dollars) $ 1.10 $ 1.07 $ 1.01 Annual revenue per customer $ 650.83 $ 696.66 $ 714.67 Heating Degree Days: (1) Spokane, WA Actual 5,614 6,215 6,683 Historical average (2) 6,491 6,820 6,780 % of average 86% 91% 99% Medford, OR Actual 3,534 3,382 4,576 Historical average (2) 4,150 4,539 4,539 % of average 85% 75% 101% (1) Heating degree days are the measure of the coldness of weather experienced, based on the extent to which the average of high and low temperatures for a day falls below 65 degrees Fahrenheit (annual degree days below historic indicate warmer than average temperatures). (2) In 2015, we switched to a rolling 20-year average for calculating heating degree days, whereas in prior years we used a 30-year rolling average. Staff_DR_063 Attachment B Page 34 of 160 AVISTA 14 ALASKA ELECTRIC LIGHT AND POWER COMPANY AEL&P is the primary operating subsidiary of AERC. AEL&P is the sole utility providing electrical energy in Juneau, Alaska. Juneau is a geographically isolated community with no electric interconnections with the transmission facilities of other utilities and no pipeline access to natural gas or other fuels. Juneau’s economy is primarily driven by government activities, tourism, commercial fishing, and mining, as well as activities as the commercial hub of southeast Alaska. AEL&P owns and operates electric generation, transmission and distribution facilities located in Juneau. AEL&P operates five hydroelectric generation facilities with 102.7 MW of hydroelectric generation capacity as of December 31, 2015. AEL&P owns four of these generation facilities (totaling 24.7 MW of capacity) and has a PPA for the output of the Snettisham hydroelectric project (totaling 78 MW of capacity). The Snettisham hydroelectric project is owned by the Alaska Industrial Development and Export Authority (AIDEA), a public corporation of the State of Alaska. AEL&P has a PPA and operating and maintenance agreement with the AIDEA to operate and maintain the facility. This PPA is a take-or-pay obligation expiring in December 2038, to purchase all of the output of the project. For accounting purposes, this PPA is treated as a capital lease and as of December 31, 2015, the capital lease obligation was $64.5 million. Snettisham Electric Company, a non-operating subsidiary of AERC, has the option to purchase the Snettisham project at any time for the principal amount of the bonds outstanding at that time. See “Note 14 of the Notes to Consolidated Financial Statements” for further discussion of the Snettisham capital lease obligation. As of December 31, 2015, AEL&P also had 93.9 MW of diesel generating capacity from three facilities to provide back-up service to firm customers when necessary. The following graph shows AEL&P’s hydroelectric generation (in thousands of MWhs) during the time periods indicated below: 2015 422 HYDROELECTRIC GENERATION 2014 420 207 Second half of 2014 Gold Creek Annex Creek Salmon Creek Lake Dorothy Snettisham 0 50 100 150 200 250 300 350 400 450 Normal hydroelectric generation Only the hydroelectric generation for the second half of 2014 in the graph above was included in Avista Corp.’s overall results for 2014. The full 12 months of 2014 in the graph above is presented for information purposes only. As of December 31, 2015, AEL&P served approximately 17,000 customers. Its primary customers include city, state and federal governmental entities located in Juneau, as well as a mine located in the Juneau area. Most of AEL&P’s customers are served on a firm basis while certain of its customers, including its largest customer, are served on an interruptible sales basis. AEL&P maintains separate rate tariffs for each of its customer classes, as well as seasonal rates. AEL&P’s operations are subject to regulation by the RCA with respect to rates, standard of service, facilities, accounting and certain other matters, but not with respect to the issuance of securities. Rate adjustments for AEL&P’s customers require approval by the RCA pursuant to RCA regulations. AEL&P’s last general rate case was filed in 2010 and approved by the RCA in 2011. The RCA approved a capital structure including 53.8 percent equity and an authorized return on equity of 12.875 percent. We expect that AEL&P will maintain a similar capital structure going forward. AEL&P is also subject to the jurisdiction of the FERC concerning the permits and licenses necessary to operate certain of its hydroelectric facilities. One of these licenses (for the Salmon Creek and Annex Creek hydroelectric projects) expires in 2018. Since AEL&P has Staff_DR_063 Attachment B Page 35 of 160 15 AVISTA no electric interconnection with other utilities and makes no wholesale sales, it is not subject to general FERC jurisdiction. The Snettisham hydroelectric project is subject to regulation by the State of Alaska with respect to dam safety and certain aspects of its operations. In addition, AEL&P is subject to regulation with respect to air and water quality, land use and other environmental matters under both federal and state laws. OTHER BUSINESSES The following graph shows our assets related to our other businesses as of December 31 (dollars in thousands): Do l l a r s i n T h o u s a n d s TOTAL ASSETS $0 $20,000 $40,000 $60,000 $80,000 $100,000 Other Avista Capital—standalone Alaska companies (AERC and AJT Mining) Steam Plant and Courtyard Ofce Center METALfx Spokane Energy 2015 $39,206 2014 $80,141 Spokane Energy was a special purpose limited liability company and all of its membership capital was owned by Avista Corp. Spokane Energy was formed in December 1998, to assume ownership of a fixed rate electric capacity contract between Avista Corp. and Portland General Electric Company. The fixed rate electric capacity contract, which expires in December 2016, was transferred from Spokane Energy to Avista Corp. during the second quarter of 2015. Spokane Energy was then dissolved during the third quarter of 2015. The fixed rate electric capacity contract has a value of $14.7 million as of December 31, 2015, compared to $28.2 million as of December 31, 2014. AM&D doing business as METALfx performs custom sheet metal fabrication of electronic enclosures, parts and systems for the computer, construction, telecom, renewable energy and medical industries. Steam Plant and Courtyard Office Center consist of real estate investments (primarily mixed use commercial and retail office space). AJT Mining is a wholly-owned subsidiary of AERC and is an inactive mining company holding certain properties. The assets at Avista Capital—standalone as of December 31, 2014 primarily consisted of the escrow receivables related to the sale of Ecova on June 30, 2014. The escrow receivables were settled and we received the proceeds during the fourth quarter of 2015. See “Note 5 of the Notes to Consolidated Financial Statements” for further detail regarding this transaction. Our other investments and operations include emerging technology venture capital funds. Over time as opportunities arise, we dispose of investments and phase out operations that do not fit with our overall corporate strategy. However, we may invest incremental funds to protect our existing investments and invest in new businesses that we believe fit with our overall corporate strategy. We continue to evaluate the opportunity to bring natural gas to Juneau, Alaska. If we pursue this project, we estimate that the total investment for our local distribution company (LDC) project would be about $130 million over 10 years, with about half being invested during the first five years. Lower oil prices have made it more difficult for customers to justify converting to natural gas. In addition, we have yet to secure a mechanism to provide funds that are needed to help customers with the conversion costs, thus challenging the economics of the project. In addition, the state of Alaska has not yet adopted legislation that would enable the state to provide customer assistance for conversions. We will continue our due diligence and we will be ready to proceed if and when the economics prove favorable for customers and our Company. Salix was notified by AIDEA in December 2015 that its proposal to build an LNG liquefaction plant to serve the Interior Energy Project, specifically to serve the Fairbanks, Alaska area, was selected as one of the two finalists. A decision by the AIDEA board is expected in early 2016. Staff_DR_063 Attachment B Page 36 of 160 AVISTA 16 ITEM 1A. RISK FACTORS RISK FACTORS The following factors could have a significant impact on our operations, results of operations, financial condition or cash flows. These factors could cause future results or outcomes to differ materially from those discussed in our reports filed with the SEC (including this Annual Report on Form 10-K), and elsewhere. Please also see “Forward-Looking Statements” for additional factors which could have a significant impact on our operations, results of operations, financial condition or cash flows and could cause actual results to differ materially from those anticipated in such statements. Financial Risk Factors Weather (temperatures, precipitation levels, wind patterns and storms) has a significant effect on our results of operations, financial condition and cash flows. Weather impacts are described in the following subtopics: • certain retail electricity and natural gas sales, • the cost of natural gas supply, and • the cost of power supply. Certain retail electricity and natural gas sales volumes vary directly with changes in temperatures. We normally have our highest retail (electric and natural gas) energy sales during the winter heating season in the first and fourth quarters of the year. We also have high electricity demand for air conditioning during the summer (third quarter) in the Pacific Northwest. In general, warmer weather in the heating season and cooler weather in the cooling season will reduce our customers’ energy demand and retail operating revenues. The cost of natural gas supply tends to increase with higher demand during periods of cold weather. Increased costs adversely affect cash flows when we purchase natural gas for retail supply at prices above the amount then allowed for recovery in retail rates. We defer differences between actual natural gas supply costs and the amount currently recovered in retail rates and we are generally allowed to recover substantially all of these differences after regulatory review. However, these deferred costs require cash outflows from the time of natural gas purchases until the costs are later recovered through retail sales. Inter-regional natural gas pipelines and competition for supply can allow demand-driven price volatility in other regions of North America to affect prices in our region, even though there may be less extreme weather conditions in our area. The cost of power supply can be significantly affected by weather. Precipitation (consisting of snowpack, its water content and melting pattern plus rainfall) and other streamflow conditions (such as regional water storage operations) significantly affect hydroelectric generation capability. Variations in hydroelectric generation inversely affect our reliance on market purchases and thermal generation. To the extent that hydroelectric generation is less than normal, significantly more costly power supply resources must be acquired and the ability to realize net benefits from surplus hydroelectric wholesale sales is reduced. Wholesale prices also vary based on wind patterns as wind generation capacity is material in our region but its contribution to supply is inconsistent. The price of power in the wholesale energy markets tends to be higher during periods of high regional demand, such as occurs with temperature extremes. We may need to purchase power in the wholesale market during peak price periods. The price of natural gas as fuel for natural gas-fired electric generation also tends to increase during periods of high demand which are often related to temperature extremes. We may need to purchase natural gas fuel in these periods of high prices to meet electric demands. The cost of power supply during peak usage periods may be higher than the retail sales price or the amount allowed in retail rates by our regulators. To the extent that power supply costs are above the amount allowed currently in retail rates, the difference is partially absorbed by the Company in current expense and it is partially deferred or shared with customers through regulatory mechanisms. The price of power tends to be lower during periods with excess supply, such as the spring when hydroelectric conditions are usually at their maximum and various facilities are required to operate to meet environmental mandates. Oversupply can be exacerbated when intermittent resources such as wind generation are producing output that may be supported by price subsidies. In extreme situations, we may be required to sell excess energy at negative prices. As a result of these combined factors, our net cost of power supply—the difference between our costs of generation and market purchases, reduced by our revenue from wholesale sales—varies significantly because of weather. We rely on regular access to financial markets but we cannot assure favorable or reasonable financing terms will be available when we need them. Access to capital markets is critical to our operations and our capital structure. We have significant capital requirements that we expect to fund, in part, by accessing capital markets. As such, the state of financial markets and credit availability in the global, United States and regional economies impacts our financial condition. We could experience increased borrowing costs or limited access to capital on reasonable terms. We access long-term capital markets to finance capital expenditures, repay maturing long-term debt and obtain additional working capital from time to time. Our ability to access capital on reasonable terms is subject to numerous factors and market conditions, many of which are beyond our control. If we are unable to obtain capital on reasonable terms, it may limit or prohibit our ability to finance capital expenditures and repay maturing long-term debt. Our liquidity needs could exceed our short-term credit availability and lead to defaults on various financing arrangements. We would also likely be prohibited from paying dividends on our common stock. Performance of the financial markets could also result in significant declines in the market values of assets held by our pension plan and/or a significant increase in the pension liability (which impacts the funded status of the plan) and could increase future funding obligations and pension expense. We rely on credit from financial institutions for short-term borrowings. We need adequate levels of credit with financial institutions for short-term liquidity. We have a $400.0 million committed line of credit that expires in April 2019. Our subsidiary AEL&P has a committed line of credit in the amount of $25.0 million that expires in November 2019. There is no assurance that we will have access to credit beyond these expiration dates. The committed line of credit agreements contain customary covenants and default provisions. In the event of default, it would be difficult for us to obtain financing on Staff_DR_063 Attachment B Page 37 of 160 17 AVISTA reasonable terms to pay creditors or fund operations. We would also likely be prohibited from paying dividends on our common stock. We hedge a portion of our interest rate risk with financial derivative instruments, which may include interest rate swaps and U.S. Treasury lock agreements. If market interest rates decrease below the interest rates we have locked in, this will result in a liability related to our interest rate swap agreements, which can be significant. As of December 31, 2015, we had a net interest rate derivative liability of $84.0 million, reflecting a decline in interest rates since the time we entered the agreements. We did not have any U.S. Treasury lock agreements outstanding as of December 31, 2015. We may be required to post cash or letters of credit as collateral depending on fluctuations in the fair value of the derivative instruments. Settlement of interest rate derivative instruments in a liability position could require a significant amount of cash, which could negatively impact our liquidity and short-term credit availability and increase interest expense over the term of the associated debt. Downgrades in our credit ratings could impede our ability to obtain financing, adversely affect the terms of financing and impact our ability to transact for or hedge energy resources. If we do not maintain our investment grade credit rating with the major credit rating agencies, we could expect increased debt service costs, limitations on our ability to access capital markets or obtain other financing on reasonable terms, and requirements to provide collateral (in the form of cash or letters of credit) to lenders and counterparties. In addition, credit rating downgrades could reduce the number of counterparties willing to do business with us or result in the termination of outstanding regulatory authorizations for certain financing activities. Credit risk may be affected by industry concentration and geographic concentration. We have concentrations of suppliers and customers in the electric and natural gas industries including: • electric and natural gas utilities, • electric generators and transmission providers, • oil and natural gas producers and pipelines, • financial institutions including commodity clearing exchanges and related parties, and • energy marketing and trading companies. We have concentrations of credit risk related to our geographic location in the western United States and western Canada energy markets. These concentrations of counterparties and concentrations of geographic location may affect our overall exposure to credit risk because the counterparties may be similarly affected by changes in conditions. Utility Regulatory Risk Factors Regulators may not grant rates that provide timely or sufficient recovery of our costs or allow a reasonable rate of return for our shareholders. We have experienced higher expenses and capital costs for utility operations in the last several years. We have also made significant capital investments into utility plant assets. Our ability to recover these expenses and capital costs depends on the amount and timeliness of retail rate changes allowed by regulatory agencies. We expect to periodically file for rate increases with regulatory agencies to recover our expenses and capital costs and provide an opportunity to earn a reasonable rate of return for shareholders. If regulators grant substantially lower rate increases than our requests in the future or if recovery of deferred expenses is disallowed, it could have a negative effect on our operating revenues, net income and cash flows. In the future, we may no longer meet the criteria for continued application of regulatory accounting practices for all or a portion of our regulated operations. If we could no longer apply regulatory accounting, we could be: • required to write off our regulatory assets, and • precluded from the future deferral of costs or decoupled revenues not recovered through rates at the time such amounts are incurred, even if we are expected to recover these amounts from customers in the future. See further discussion at “Note 1 of the Notes to Consolidated Financial Statements—Regulatory Deferred Charges and Credits.” Energy Commodity Risk Factors Energy commodity price changes affect our cash flows and results of operations. Energy commodity prices can be volatile. A combination of factors exposes our operations to commodity price risks. We rely on energy markets and other counterparties for energy supply, surplus and optimization transactions and commodity price hedging. These factors include: • our obligation to serve our retail customers at rates set through the regulatory process—we cannot change retail rates to reflect current energy prices unless and until we receive regulatory approval, • customer demand, which is beyond our control because of weather, customer choices, prevailing economic conditions and other factors, • some of our energy supply cost is fixed by the nature of the energy-producing assets or through contractual arrangements— however, a significant portion of our energy resource costs are not fixed, and • the potential non-performance by commodity counterparties, which could lead to replacement of the scheduled energy or natural gas at higher prices. Because we must supply the amount of energy demanded by our customers and we must sell it at fixed rates and only a portion of our energy supply costs are fixed, we are subject to the risk of buying energy at higher prices in wholesale energy markets (and the risk of selling energy at lower prices if we are in a surplus position). Electricity and natural gas in wholesale markets are commodities with historically high price volatility. Changes in wholesale energy prices affect, among other things, the cash requirements to purchase electricity and natural gas for retail customers or wholesale obligations and the market value of derivative assets and liabilities. When we enter into fixed price energy commodity transactions for future delivery, we are subject to credit terms that may require us to provide collateral to wholesale counterparties related to the difference between current prices and the agreed upon fixed prices. These collateral requirements can place significant demands on our cash flows or borrowing arrangements. Price volatility can cause collateral requirements to change quickly and significantly. Staff_DR_063 Attachment B Page 38 of 160 AVISTA 18 Cash flow deferrals related to energy commodities can be significant. We are permitted to collect from customers only amounts approved by regulatory commissions. However, our costs to provide energy service can be much higher or lower than the amounts currently billed to customers. We are permitted to defer most of this difference for review by the regulatory commissions who have discretion as to the extent and timing of future recovery or refund to customers. Power and natural gas costs higher than those recovered in retail rates reduce cash flows. Amounts that are not allowed for deferral or which are not approved to become part of customer rates affect our results of operations. We defer income statement recognition and recovery from customers of certain power and natural gas costs that are higher or lower than what are currently authorized in retail rates by regulators. These power and natural gas costs are recorded as deferred charges with the opportunity for future recovery through retail rates. These deferred costs are subject to review for prudence and potential disallowance by regulators. Despite the opportunity to recover deferred power and natural gas costs, our operating cash flows can be negatively affected until these costs are recovered from customers. Our energy resource risk management processes can cause volatility in our cash flows and results of operations. We engage in active hedging and resource optimization practices to reduce energy cost volatility and economic exposure related to commodity price fluctuations. We routinely enter into contracts to hedge a portion of our purchase and sale commitments for electricity and natural gas, as well as forecasted excess or deficit energy positions and inventories of natural gas. We use physical energy contracts and derivative instruments, such as forwards, futures, swaps and options traded in the over-the-counter markets or on exchanges. We cannot and do not attempt to fully hedge our energy resource assets or our forecasted net positions for various time horizons. To the extent we have positions that are not hedged, or if hedging positions do not fully match the corresponding purchase or sale, fluctuating commodity prices could have a material effect on our operating revenues, resource costs, derivative assets and liabilities, and operating cash flows. In addition, actual loads and resources typically vary from forecasts, sometimes to a significant degree, which require additional transactions or dispatch decisions that impact cash flows. The hedges we enter into are reviewed for prudence by the various regulators and any deferred costs (including those as a result of our hedging transactions) are subject to review for prudence and potential disallowance by regulators. Generation plants may become obsolete. We rely on a variety of generation and energy commodity market sources to fulfill our obligation to serve customers and meet the demands of our counterparty agreements. There is the potential that some of our generation sources, such as coal, may become obsolete. This could result in higher commodity costs to customers to replace the lost generation, as well as higher costs to retire the generation source before the end of its expected life. Operational Risk Factors We are subject to various operational and event risks. Our operations are subject to operational and event risks that include: • severe weather or natural disasters, including, but not limited to, avalanches, wind storms, wildfires, snow and ice storms, that can disrupt energy generation, transmission and distribution, as well as the availability and costs of materials, equipment, supplies and support services; • blackouts or disruptions of interconnected transmission systems (the regional power grid); • unplanned outages at generating plants; • fuel cost and availability, including delivery constraints; • explosions, fires, accidents, or mechanical breakdowns that may occur while operating and maintaining our generation; transmission and distribution systems; • damage or injuries to third parties caused by our generation, transmission and distribution systems; • natural disasters that can disrupt energy generation, transmission and distribution and general business operations; and • terrorist attacks or other malicious acts that may disrupt or cause damage to our utility assets or the vendors we utilize. Disasters may affect the general economy, financial and capital markets, specific industries, or our ability to conduct business. As protection against operational and event risks, we maintain business continuity and disaster recovery plans, maintain insurance coverage against some, but not all, potential losses and we seek to negotiate indemnification arrangements with contractors for certain event risks. However, insurance or indemnification agreements may not be adequate to protect us against liability, extra expenses and operating disruptions from all of the operational and event risks described above. In addition, we are subject to the risk that insurers and/or other parties will dispute or be unable to perform on their obligations to us. Damage to facilities may be caused by severe weather, such as snow, ice, wind storms or avalanches. The cost to implement rapid or any repair to such facilities can be significant. Overhead electric lines are most susceptible to damage caused by severe weather. Adverse impacts may occur at our Alaska operations that could result from an extended outage of their hydroelectric generating resources or its inability to deliver energy, due to their lack of interconnectivity to any other electrical grids and the extensive cost of replacement power (diesel). AEL&P operates several hydroelectric power generation facilities and has diesel generating capacity from multiple facilities to provide backup service to firm customers when necessary; however, a single hydroelectric power generation facility, the Snettisham hydroelectric project, provides approximately two-thirds of AEL&P’s hydroelectric power generation. Any issues that negatively affect AEL&P’s ability to generate or transmit power or any decrease in the demand for the power generated by AEL&P could negatively affect our results of operations, financial condition and cash flows. Staff_DR_063 Attachment B Page 39 of 160 19 AVISTA Compliance Risk Factors There have been numerous changes in legislation, related administrative rulemakings, and Executive Orders, including periodic audits of compliance with such rules, which may adversely affect our operational and financial performance. We expect to continue to be affected by legislation at the national, state and local level, as well as by administrative rules and requirements published by government agencies, including but not limited to the FERC, the EPA and state regulators. We are also subject to NERC and WECC reliability standards. The FERC, the NERC and the WECC perform periodic audits of the Company. Failure to comply with the FERC, the NERC, or the WECC requirements can result in financial penalties of up to $1 million per day per violation. Future legislation or administrative rules could have a material adverse effect on our operations, results of operations, financial condition and cash flows. Actions or limitations to address concerns over the long-term global and our utilities’ service area climate changes may affect our operations and financial performance. Legislative developments and advocacy at the state, national and international levels concerning climate change and other environmental issues could have significant impacts on our operations. The electric utility industry is one of the largest and most immediate industries to be more heavily regulated in some proposals. For example, various legislative proposals have been made to limit or place further restrictions on byproducts of combustion, including sulfur dioxide, nitrogen oxide, carbon dioxide, and other greenhouse gases and mercury emissions. Such proposals, if adopted, could restrict the operation and raise the cost of our power generation resources. We expect continuing activity in the future and we are evaluating the extent to which potential changes to environmental laws and regulations may: • increase the operating costs of generating plants, • increase the lead time and capital costs for the construction of new generating plants, • require modification of our existing generating plants, • require existing generating plant operations to be curtailed or shut down, • reduce the amount of energy available from our generating plants, • restrict the types of generating plants that can be built or contracted with, and • require construction of specific types of generation plants at higher cost. We have contingent liabilities, including certain matters related to potential environmental liabilities, and cannot predict the outcome of these matters. In the normal course of our business, we have matters that are the subject of ongoing litigation, mediation, investigation and/or negotiation. We cannot predict the ultimate outcome or potential impact of any particular issue, including the extent, if any, of insurance coverage or that amounts payable by us may be recoverable through the ratemaking process. We are subject to environmental regulation by federal, state and local authorities related to our past, present and future operations. See “Note 19 of the Notes to Consolidated Financial Statements” for further details of these matters. Technology Risk Factors Cyber attacks, terrorism or other malicious acts could disrupt our businesses and have a negative impact on our results of operations and cash flows. In the course of our operations, we rely on interconnected technology systems for operation of our generating plants, electric transmission and distribution systems, natural gas distribution systems, customer billing and customer service, accounting and other administrative processes and compliance with various regulations. There are various risks associated with technology systems such as hardware or software failure, communications failure, data distortion or destruction, unauthorized access to data, misuse of proprietary or confidential data, unauthorized control through electronic means, programming mistakes and other deliberate or inadvertent human errors. In particular, cyber attacks, terrorism or other malicious acts could damage, destroy or disrupt these systems. Additionally, the facilities and systems of clients, suppliers and third party service providers could be vulnerable to these same risks and, to the extent of interconnection to our technology, may impact us. Any failure, unexpected, or unauthorized unavailability of technology systems could result in a loss of operating revenues, an increase in operating expenses and costs to repair or replace damaged assets. Any of the above could also result in the loss or release of confidential customer information or other proprietary data that could adversely affect our reputation, competitiveness, and result in costly litigation and impact on our results of operations. As these potential cyber attacks become more common and sophisticated, we could be required to incur costs to strengthen our systems and respond to emerging concerns. Terrorist attacks could also be directed at physical electric and natural gas facilities, as well as technology systems. We may be adversely affected by our inability to successfully implement certain technology projects. We are currently investigating whether to replace all of our electric meter infrastructure in Washington State with advanced metering infrastructure (AMI). If we were to proceed with this AMI project, there is the potential that the costs associated with retiring our current meters could be disallowed by regulators. There is also the risk that regulators will not allow the full recovery of new AMI if we proceed with the project. In addition, there are inherent risks associated with replacing and changing these types of systems, such as incorrect or nonfunctioning metering and/or delayed or inaccurate customer bills or unplanned outages, which could have a material adverse effect on our results of operations, financial condition and cash flows. Staff_DR_063 Attachment B Page 40 of 160 AVISTA 20 Strategic Risk Factors Changes in our strategic business plans, which may be affected by any or all of the foregoing, including the entry into new businesses and/or the exit from existing businesses and the extent of our business development efforts where potential future business is uncertain. Our strategic business plans could be affected by or result in any of the following: • disruptive innovations in the marketplace may outpace our ability to compete or manage our risk, • potential difficulties in integrating acquired operations and in realizing expected opportunities, diversions of management resources and losses of key employees, challenges with respect to operating new businesses and other unanticipated risks and liabilities, and • potential reputational risk arising from repeated general rate case filings, degradation in the quality of service, or from failed strategic investments and opportunities, which could erode shareholder, customer and community satisfaction with our Company. Our acquisition of AERC may not achieve its intended results. On July 1, 2014, we acquired AERC, and its subsidiary, AEL&P, the sole provider of electric services in Juneau, Alaska. Achieving the anticipated earnings contribution from AERC is subject to numerous uncertainties, including market conditions and risks related to AERC’s business. This transaction could result in increased costs, decreases in the expected revenues from AERC, the impairment of goodwill or other assets, and diversion of management time and resources, which could have a material adverse effect on our results of operations, financial condition and cash flows. External Mandates Risk Factors External mandate risk involves forces outside the Company, which may include significant changes in customer expectations, disruptive technologies that result in obsolescence of our business model and government action that could impact our Company. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Environmental Issues and Contingencies” and “Forward-Looking Statements” for discussion of or reference to external mandates which could have a material adverse effect on our results of operations, financial condition and cash flows. ITEM 1B. UNRESOLVED STAFF COMMENTS As of the filing date of this Annual Report on Form 10-K, we have no unresolved comments from the staff of the SEC. Staff_DR_063 Attachment B Page 41 of 160 21 AVISTA ITEM 2. PROPERTIES AVISTA UTILITIES Substantially all of Avista Utilities’ properties are subject to the lien of Avista Corp.’s mortgage indenture. Our utility electric properties, located in the states of Washington, Idaho, Montana and Oregon, include the following: GENERATION PROPERTIES Nameplate Present No. of Rating Capability Units (MW) (1) (MW) (2) Hydroelectric Generating Stations (River) Washington: Long Lake (Spokane) 4 70.0 88.0 Little Falls (Spokane) 4 32.0 35.6 Nine Mile (Spokane) (3) 4 26.4 19.5 Upper Falls (Spokane) 1 10.0 10.2 Monroe Street (Spokane) 1 14.8 15.0 Idaho: Cabinet Gorge (Clark Fork) (4) 4 265.0 273.0 Post Falls (Spokane) 6 14.8 15.4 Montana: Noxon Rapids (Clark Fork) 5 487.8 562.4 Total Hydroelectric 920.8 1,019.1 Thermal Generating Stations (cycle, fuel source) Washington: Kettle Falls GS (combined-cycle, wood waste) (5) 1 50.7 53.5 Kettle Falls CT (combined-cycle, natural gas) (5) 1 7.2 6.9 Northeast CT (simple-cycle, natural gas) 2 61.8 64.8 Boulder Park GS (simple-cycle, natural gas) 6 24.6 24.0 Idaho: Rathdrum CT (simple-cycle, natural gas) 2 166.5 166.5 Montana: Colstrip Units 3 and 4 (simple-cycle, coal) (6) 2 233.4 222.0 Oregon: Coyote Springs 2 (combined-cycle, natural gas) 1 287.0 284.4 Total Thermal 831.2 822.1 Total Generation Properties 1,752.0 1,841.2 (1) Nameplate Rating, also referred to as “installed capacity,” is the manufacturer’s assigned power capability under specified conditions. (2) Present capability is the maximum capacity of the plant under standard test conditions without exceeding specified limits of temperature, stress and environmental conditions. Information is provided as of December 31, 2015. (3) There are four units at the Nine Mile plant; however, Units 1 and 2 are not operating due to a mechanical failure. A project is underway to replace these units and restore capability. The present capability disclosed above represents the capability of the two operating units, which have a nameplate rating of 18 MW combined. (4) For Cabinet Gorge, we have water rights permitting generation up to 265 MW. However, if natural stream flows will allow for generation above our water rights, we are able to generate above our water rights. If natural stream flows only allow for generation at or below 265 MW, we are limited to generation of 265 MW. The present capability disclosed above represents the capability based on maximum stream flow conditions when we are allowed to generate above our water rights. (5) These generating stations can operate as separate single-cycle plants or combined-cycle with the natural gas plant providing exhaust heat to the wood boiler to increase efficiency. (6) Jointly owned; data refers to our 15 percent interest. Staff_DR_063 Attachment B Page 42 of 160 AVISTA 22 Electric Distribution and Transmission Plant Avista Utilities owns and operates approximately 19,000 miles of primary and secondary electric distribution lines providing service to retail customers. We have an electric transmission system of 685 miles of 230 kV line and 1,565 miles of 115 kV line. We also own an 11 percent interest in approximately 500 miles of a 500 kV line between Colstrip, Montana and Townsend, Montana. Our transmission and distribution systems also include numerous substations with transformers, switches, monitoring and metering devices, and other equipment. The 230 kV lines are the backbone of our transmission grid and are used to transmit power from generation resources, including Noxon Rapids, Cabinet Gorge and the Mid-Columbia hydroelectric projects, to the major load centers in our service area, as well as to transfer power between points of interconnection with adjoining electric transmission systems. These lines interconnect at various locations with the BPA, Grant County PUD, PacifiCorp, NorthWestern Energy and Idaho Power Company and serve as points of delivery for power from generating facilities outside of our service area, including Colstrip, Coyote Springs 2 and the Lancaster Plant. These lines also provide a means for us to optimize resources by entering into short-term purchases and sales of power with entities within and outside of the Pacific Northwest. The 115 kV lines provide for transmission of energy and the integration of smaller generation facilities with our service-area load centers, including the Spokane River hydroelectric projects, the Kettle Falls projects, Rathdrum CT, Boulder Park and the Northeast CT. These lines interconnect with the BPA, Chelan County PUD, the Grand Coulee Project Hydroelectric Authority, Grant County PUD, NorthWestern Energy, PacifiCorp and Pend Oreille County PUD. Both the 115 kV and 230 kV interconnections with the BPA are used to transfer energy to facilitate service to each other’s customers that are connected through the other’s transmission system. We hold a long-term transmission agreement with the BPA that allows us to serve our native load customers that are connected through the BPA’s transmission system. Natural Gas Plant Avista Utilities has natural gas distribution mains of approximately 3,400 miles in Washington, 2,000 miles in Idaho and 2,300 miles in Oregon. We have natural gas transmission mains of approximately 75 miles in Washington and 50 miles in Oregon. Our natural gas system includes numerous regulator stations, service distribution lines, monitoring and metering devices, and other equipment. We own a one-third interest in Jackson Prairie, an underground natural gas storage field located near Chehalis, Washington. See “Part 1—Item 1. Business—Avista Utilities—Natural Gas Operations” for further discussion of Jackson Prairie. ALASKA ELECTRIC LIGHT AND POWER COMPANY Substantially all of AEL&P’s utility properties are subject to the lien of the AEL&P mortgage indenture. AEL&P’s utility electric properties, located in Alaska include the following: GENERATION PROPERTIES AND TRANSMISSION AND DISTRIBUTION LINES Nameplate Present No. of Rating Capability Units (MW) (1) (MW) (2) Hydroelectric Generating Stations Snettisham (3) 3 78.2 78.2 Lake Dorothy 1 14.3 14.3 Salmon Creek 1 8.4 5.0 Annex Creek 2 4.1 3.6 Gold Creek 3 1.6 1.6 Total Hydroelectric 106.6 102.7 Diesel Generating Stations Lemon Creek 11 61.4 57.5 Auke Bay 3 36.2 28.3 Gold Creek 5 8.2 8.1 Total Diesel 105.8 93.9 Total Generation Properties 212.4 196.6 (1) Nameplate Rating, also referred to as “installed capacity,” is the manufacturer’s assigned power capability under specified conditions. (2) Present capability is the maximum capacity of the plant under standard test conditions without exceeding specified limits of temperature, stress and environmental conditions. Information is provided as of December 31, 2015. (3) AEL&P does not own this generating facility but has a PPA under which it has the right to purchase, and the obligation to pay for (whether or not energy is received), all of the capacity and energy of this facility. See further information at “Part 1. Item 1. Business—Alaska Electric Light and Power Company.” In addition to the generation properties above, AEL&P owns approximately 61 miles of transmission lines, which is primarily comprised of 69 kV line, and approximately 184 miles of distribution lines. Staff_DR_063 Attachment B Page 43 of 160 23 AVISTA ITEM 3. LEGAL PROCEEDINGS See “Note 19 of Notes to Consolidated Financial Statements” for information with respect to legal proceedings. ITEM 4. MINE SAFETY DISCLOSURES Not applicable. PART II ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES Avista Corp. Market Information and Dividend Policy Avista Corp.’s common stock is listed on the New York Stock Exchange under the ticker symbol “AVA.” As of January 31, 2016, there were 8,753 registered shareholders of our common stock. Avista Corp.’s Board of Directors considers the level of dividends on our common stock on a regular basis, taking into account numerous factors including, without limitation: • our results of operations, cash flows and financial condition, • the success of our business strategies, and • general economic and competitive conditions. Avista Corp.’s net income available for dividends is generally derived from our regulated utility operations (Avista Utilities and AEL&P). The payment of dividends on common stock could be limited by: • certain covenants applicable to the Company’s outstanding long-term debt and committed line of credit agreements (see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Executive Level Summary and Capital Resources” for compliance with these covenants), • the hydroelectric licensing requirements of section 10(d) of the FPA (see “Note 1 of Notes to Consolidated Financial Statements”), • certain requirements under the OPUC approval of the AERC acquisition. The OPUC does not permit one-time or special dividends from AERC to Avista Corp. and does not permit Avista Utilities’ total equity to total capitalization to be less than 40 percent, without approval from the OPUC. However, the OPUC approval does allow for regular distributions of AERC earnings to Avista Corp. as long as AERC remains sufficiently capitalized and insured, and • certain covenants applicable to preferred stock (when outstanding) contained in the Company’s Restated Articles of Incorporation, as amended (currently there are no preferred shares outstanding). On February 5, 2016, Avista Corp.’s Board of Directors declared a quarterly dividend of $0.3425 per share on the Company’s common stock. This was an increase of $0.0125 per share, or 3.8 percent from the previous quarterly dividend of $0.33 per share. For additional information, see “Notes 1, 17 and 18 of Notes to Consolidated Financial Statements.” The following table presents quarterly high and low stock prices as reported on the consolidated reporting system, as well as dividend information: Three Months Ended March June September December 31 30 30 31 2015 Dividends paid per common share $ 0.33 $ 0.33 $ 0.33 $ 0.33 Trading price range per common share: High $ 38.30 $ 34.25 $ 33.99 $ 36.06 Low $ 32.22 $ 30.41 $ 29.93 $ 32.86 2014 Dividends paid per common share $ 0.3175 $ 0.3175 $ 0.3175 $ 0.3175 Trading price range per common share: High $ 30.83 $ 33.58 $ 33.60 $ 37.37 Low $ 27.71 $ 30.02 $ 30.35 $ 30.55 For information with respect to securities authorized for issuance under equity compensation plans, see “Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.” Staff_DR_063 Attachment B Page 44 of 160 AVISTA 24 ITEM 6. SELECTED FINANCIAL DATA Avista Corporation (in thousands, except per share data and ratios) Years Ended December 31, 2015 2014 2013 2012 2011 Operating Revenues: Avista Utilities $ 1,411,863 $ 1,413,499 $ 1,403,995 $ 1,354,185 $ 1,443,322 AEL&P 44,778 21,644 — — — Other 28,685 39,219 39,549 38,953 40,410 Intersegment eliminations (550) (1,800) (1,800) (1,800) (1,800) Total $ 1,484,776 $ 1,472,562 $ 1,441,744 $ 1,391,338 $ 1,481,932 Income (Loss) from Operations (pre-tax): Avista Utilities $ 241,228 $ 239,976 $ 232,572 $ 188,778 $ 202,373 AEL&P 14,072 6,221 — — — Other (2,086) 6,391 (1,483) (1,680) 4,714 Total $ 253,214 $ 252,588 $ 231,089 $ 187,098 $ 207,087 Net income from continuing operations $ 118,170 $ 119,866 $ 104,333 $ 76,803 $ 90,658 Net income from discontinued operations 5,147 72,411 7,961 1,997 12,881 Net income $ 123,317 $ 192,277 $ 112,294 $ 78,800 $ 103,539 Net income attributable to noncontrolling interests $ (90) $ (236) $ (1,217) $ (590) $ (3,315) Net Income (Loss) attributable to Avista Corporation shareholders: Avista Utilities $ 113,360 $ 113,263 $ 108,598 $ 81,704 $ 90,902 AEL&P 6,641 3,152 — — — Ecova—Discontinued operations 5,147 72,390 7,129 1,825 9,671 Other (1,921) 3,236 (4,650) (5,319) (349) Net income attributable to Avista Corp. shareholders $ 123,227 $ 192,041 $ 111,077 $ 78,210 $ 100,224 Average common shares outstanding—basic 62,301 61,632 59,960 59,028 57,872 Average common shares outstanding—diluted 62,708 61,887 59,997 59,201 58,092 Common shares outstanding at year-end 62,313 62,243 60,077 59,813 58,423 Earnings per common share attributable to Avista Corp. shareholders—basic: Earnings per common share from continuing operations $ 1.90 $ 1.94 $ 1.74 $ 1.30 $ 1.56 Earnings per common share from discontinued operations 0.08 1.18 0.11 0.02 0.17 Total earnings per common share attributable to Avista Corp. shareholders—basic $ 1.98 $ 3.12 $ 1.85 $ 1.32 $ 1.73 Earnings per common share attributable to Avista Corp. shareholders—diluted: Earnings per common share from continuing operations $ 1.89 $ 1.93 $ 1.74 $ 1.30 $ 1.56 Earnings per common share from discontinued operations 0.08 1.17 0.11 0.02 0.16 Total earnings per common share attributable to Avista Corp. shareholders—diluted $ 1.97 $ 3.10 $ 1.85 $ 1.32 $ 1.72 Dividends declared per common share $ 1.32 $ 1.27 $ 1.22 $ 1.16 $ 1.10 Book value per common share $ 24.53 $ 23.84 $ 21.61 $ 21.06 $ 20.30 Staff_DR_063 Attachment B Page 45 of 160 25 AVISTA SELECTED FINANCIAL DATA (CONTINUED) Avista Corporation (in thousands, except per share data and ratios) Years Ended December 31, 2015 2014 2013 2012 2011 Total Assets at Year-End: Avista Utilities $ 4,601,708 $ 4,357,760 $ 3,930,251 $ 3,883,602 $ 3,797,160 AEL&P 265,735 263,070 — — — Other 39,206 80,141 81,282 95,638 112,145 Total (1) (2) $ 4,906,649 $ 4,700,971 $ 4,011,533 $ 3,979,240 $ 3,909,305 Long-Term Debt and Capital Leases (including current portion) (2) $ 1,573,278 $ 1,487,126 $ 1,262,036 $ 1,217,520 $ 1,165,014 Nonrecourse Long-Term Debt of Spokane Energy (including current portion) $ — $ 1,431 $ 17,838 $ 32,803 $ 46,471 Long-Term Debt to Affiliated Trusts $ 51,547 $ 51,547 $ 51,547 $ 51,547 $ 51,547 Total Avista Corp. Shareholders’ Equity $ 1,528,626 $ 1,483,671 $ 1,298,266 $ 1,259,477 $ 1,185,701 Ratio of Earnings to Fixed Charges (3) 3.13 3.39 3.02 2.48 2.81 (1) The total assets at year-end for the years 2013 to 2011 exclude the total assets associated with Ecova of $339.6 million, $322.7 million and $292.9 million, respectively. (2) The total assets and total long-term debt and capital leases for 2014 through 2011 were adjusted due to the adoption of ASU No. 2015-03, “Interest—Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs.” See “Note 2 of the Notes to Consolidated Financial Statements” for further discussion of the adoption of this ASU. (3) See Exhibit 12 for computations. ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS BUSINESS SEGMENTS As of December 31, 2015, we have two reportable business segments, Avista Utilities and AEL&P. We also have other businesses which do not represent a reportable business segment and are conducted by various direct and indirect subsidiaries of Avista Corp. See “Part I, Item 1. Business—Company Overview” for further discussion of our business segments. The following table presents net income (loss) attributable to Avista Corp. shareholders for each of our business segments (and the other businesses) for the year ended December 31 (dollars in thousands): 2015 2014 2013 Avista Utilities $ 113,360 $ 113,263 $ 108,598 AEL&P 6,641 3,152 — Ecova—Discontinued operations (1) 5,147 72,390 7,129 Other (1,921) 3,236 (4,650) Net income attributable to Avista Corporation shareholders $ 123,227 $ 192,041 $ 111,077 (1) The results for the year ended December 31, 2014 include the net gain on sale of Ecova of $69.7 million. EXECUTIVE LEVEL SUMMARY Overall Results Net income attributable to Avista Corp. shareholders was $123.2 million for 2015, a decrease from $192.0 million for 2014. The decrease was primarily due to the disposition of Ecova during 2014, which resulted in the recognition of a $74.8 million net gain, with $69.7 million being recognized in 2014 and the remainder being recognized in 2015. Avista Utilities’ earnings increased slightly primarily due to the implementation of a general rate increase in Washington, lower net power supply costs, a decrease in the provision for earnings sharing in Idaho and increased cooling loads during the summer. This was mostly offset by weather that was significantly warmer than normal and warmer than the prior year in the first quarter, which reduced heating loads, which was partially offset by the new decoupling mechanism in Washington (implemented January 1, 2015). Also, we experienced expected increases in other operating expenses, depreciation and amortization, taxes other than income taxes, and interest expense. Results for 2015 also include earnings at AEL&P for the full period, whereas 2014 results only include AEL&P for the third and fourth quarters. Results for 2014 include a $9.8 million net gain at Avista Energy related to the settlement of the California power markets litigation. The net gain from the litigation settlement was partially offset by a pre-tax contribution of $6.4 million of the proceeds to the Avista Foundation, a charitable organization funded by Avista Corp. Both of these transactions are reflected in the results of the other businesses. Staff_DR_063 Attachment B Page 46 of 160 AVISTA 26 Avista Utilities Avista Utilities is our most significant business segment. Our utility financial performance is dependent upon, among other things: • weather conditions (temperatures, precipitation levels and wind patterns) which affect energy demand and electric generation, including the effect of precipitation and temperature on hydroelectric resources, the effect of wind patterns on wind-generated power, weather-sensitive customer demand, and similar impacts on supply and demand in the wholesale energy markets, • regulatory decisions, allowing our utility to recover costs, including purchased power and fuel costs, on a timely basis, and to earn a reasonable return on investment, • the price of natural gas in the wholesale market, including the effect on the price of fuel for generation, and • the price of electricity in the wholesale market, including the effects of weather conditions, natural gas prices and other factors affecting supply and demand. Forecasted Customer and Load Growth Based on our forecast for 2016 through 2019 for Avista Utilities’ service area, we expect annual electric customer growth to average 1.0 percent, within a forecast range of 0.6 percent to 1.4 percent. We expect annual natural gas customer growth to average 1.1 percent, within a forecast range of 0.6 percent to 1.6 percent. We anticipate retail electric load growth to average 0.7 percent, within a forecast range of 0.4 percent and 1.0 percent. We expect natural gas load growth to average 1.1 percent, within a forecast range of 0.6 percent and 1.6 percent. The forecast ranges reflect (1) the inherent uncertainty associated with the economic assumptions on which forecasts are based and (2) the historic variability of natural gas customer and load growth. In AEL&P’s service area, we expect annual residential customer growth to be in a narrow range around 0.4 percent for 2016 through 2019. We expect no significant growth in commercial and government customers over the same period. We anticipate that average annual total load growth will be in a narrow range around 0.6 percent, with residential load growth averaging 0.6 percent; commercial 0.8 percent; and government 0 percent (no load growth). For further discussion regarding utility customer growth, load growth, and the general economic conditions in our service territory, see “Economic Conditions and Utility Load Growth.” See also “Competition” for a discussion of competitive factors that could affect our results of operations in the future. Capital Expenditures We are making significant capital investments in generation, transmission and distribution systems to preserve and enhance service reliability for our customers and replace aging infrastructure. The following table summarizes our actual and expected capital expenditures as of and for the year ended December 31, 2015 (in thousands): Avista Utilities AEL&P 2015 Actual capital expenditures Capital expenditures (per the Consolidated Statement of Cash Flows) 381,174 12,251 Expected total annual capital expenditures (by year) 2016 375,000 17,000 2017 405,000 13,000 2018 405,000 18,000 Avista Utilities’ 2015 calendar year capital costs, including capital costs of approximately $35.2 million that was unpaid for and accrued in accounts payable as of December 31, 2015, were $415.9 million. These estimates of capital expenditures are subject to continuing review and adjustment. Alaska Energy and Resources Company Acquisition On July 1, 2014, we acquired AERC, based in Juneau, Alaska. The completion of this transaction makes the financial results for 2015 and 2014 incomparable since the first half of 2014 does not contain any financial results from AERC. This transaction resulted in the recording of $52.4 million in goodwill. For additional information regarding the AERC transaction, including pro forma financial comparisons, see “Note 4 of the Notes to Consolidated Financial Statements.” Ecova Disposition On June 30, 2014, Avista Capital completed the sale of its interest in Ecova to Cofely USA Inc., an indirect subsidiary of GDF SUEZ, a French multinational utility company, for a sales price of $335.0 million in cash, less the payment of debt and other customary closing adjustments. The sale of Ecova provided total cash proceeds to Avista Corp., net of debt, payment to option and minority holders, income taxes and transaction expenses, of $143.7 million and resulted in a net gain of $74.8 million. Almost all of the net gain was recognized in 2014 with some minor true-ups during 2015. The completion of this transaction makes the financial results for 2015 and 2014 incomparable since the first half of 2014 contains the financial results of Ecova (in discontinued operations) and 2015 does not have any material results from Ecova. For additional information regarding the Ecova disposition, see “Note 5 of the Notes to Consolidated Financial Statements.” Staff_DR_063 Attachment B Page 47 of 160 27 AVISTA Stock Repurchase Programs During 2014, Avista Corp. repurchased 2,529,615 shares of our outstanding common stock at a total cost of $79.9 million and an average cost of $31.57 per share through our 2014 stock repurchase program. We did not make any repurchases under this program subsequent to October 2014 and the program expired on December 31, 2014. In the first quarter of 2015, Avista Corp. repurchased 89,400 shares of our outstanding common stock at a total cost of $2.9 million and an average cost of $32.66 per share under a second stock repurchase program that expired on March 31, 2015. All repurchased shares reverted to the status of authorized but unissued shares. Wind Storm On November 17, 2015, a historic wind storm occurred in our service territory. The storm had wind speeds exceeding 70 miles per hour which knocked down numerous trees and power poles and caused severe damage to our electrical system. Most of the damage occurred in Spokane County. The storm resulted in significant customer power outages and at the height of the storm approximately 180,000 customers (about 48 percent of our total retail electric customers) were without power, causing the most significant damage and the highest number of customer outages Avista Utilities has ever experienced. It took Avista Utilities crews from throughout the region, along with contract and mutual aid crews, approximately 10 days to fully restore power to all affected customers. Most of the storm- related costs incurred were capital costs (labor and materials) to repair the electrical system, but there were also operating and maintenance costs. The capital repair costs for power restoration were $22.9 million and $2.9 million for incremental utility operating and maintenance costs. In addition, there was approximately $0.4 million of incremental nonutility operating and maintenance costs. The damage and restoration costs were primarily incurred in Washington state and we plan to include the incremental operating and maintenance costs in the calculations for earnings sharing (see “Regulatory Matters— Decoupling and Earnings Sharing Mechanisms” for further discussion of the earnings sharing mechanisms). Liquidity and Capital Resources Avista Corp. has a $400.0 million committed line of credit with various financial institutions that expires in April 2019. We have an option to request an extension for an additional one or two years beyond April 2019, provided, 1) that no event of default has occurred and is continuing prior to the requested extension and 2) the remaining term of agreement, including the requested extension period, does not exceed five years. As of December 31, 2015, there were $105.0 million of cash borrowings and $44.6 million in letters of credit outstanding, leaving $250.4 million of available liquidity under this line of credit. The Avista Corp. facility contains customary covenants and default provisions, including a covenant which does not permit our ratio of “consolidated total debt” to “consolidated total capitalization” to be greater than 65 percent at any time. As of December 31, 2015, we were in compliance with this covenant with a ratio of 53.1 percent. AEL&P has a $25.0 million committed line of credit which expires in November 2019. As of December 31, 2015, there were no borrowings or letters of credit outstanding under this committed line of credit. The AEL&P committed line of credit agreement contains customary covenants and default provisions including a covenant which does not permit the ratio of “consolidated total debt at AEL&P” to “consolidated total capitalization at AEL&P,” (including the impact of the Snettisham obligation) to be greater than 67.5 percent at any time. As of December 31, 2015, AEL&P was in compliance with this covenant with a ratio of 57.2 percent. In December 2015, we issued $100.0 million of first mortgage bonds to five institutional investors in a private placement transaction. The first mortgage bonds bear an interest rate of 4.37 percent and mature in 2045. In connection with this pricing, we cash-settled five interest rate swap contracts (notional aggregate amount of $75.0 million) and paid a total of $9.3 million. Upon settlement of interest rate swaps, the regulatory asset or liability (included as part of long-term debt) is amortized as a component of interest expense over the term of the associated debt. In 2015, we issued $1.6 million (net of issuance costs) of common stock under the employee plans. For 2016, we expect to issue approximately $155.0 million of long-term debt and $55.0 million of common stock in order to maintain an appropriate capital structure and to fund planned capital expenditures. After considering the expected issuances of long-term debt and common stock during 2016, we expect net cash flows from operating activities, together with cash available under our committed line of credit agreements, to provide adequate resources to fund capital expenditures, dividends, and other contractual commitments. REGULATORY MATTERS General Rate Cases We regularly review the need for electric and natural gas rate changes in each state in which we provide service. We will continue to file for rate adjustments to: • seek recovery of operating costs and capital investments, and • seek the opportunity to earn reasonable returns as allowed by regulators. With regards to the timing and plans for future filings, the assessment of our need for rate relief and the development of rate case plans takes into consideration short-term and long-term needs, as well as specific factors that can affect the timing of rate filings. Such factors include, but are not limited to, in-service dates of major capital investments and the timing of changes in major revenue and expense items. Washington General Rate Cases 2012 General Rate Cases In December 2012, the UTC approved a settlement agreement in Avista Utilities’ electric and natural gas general rate cases filed in April 2012. The settlement, effective January 1, 2013 provided that base rates for our Washington electric customers increase by an overall 3.0 percent (designed to increase annual revenues by $13.6 million), and base rates for our Washington natural gas customers increased by an overall 3.6 percent (designed to increase annual revenues by $5.3 million). The approved settlement also provided that, effective January 1, 2014, base rates increase for our Washington electric customers by an overall 3.0 percent (designed to increase annual revenues by $14.0 million), and increase for our Washington natural gas Staff_DR_063 Attachment B Page 48 of 160 AVISTA 28 customers by an overall 0.9 percent (designed to increase annual revenues by $1.4 million). The settlement agreement provided for an authorized return on equity (ROE) of 9.8 percent and an equity ratio of 47 percent, resulting in an overall rate of return on rate base (ROR) of 7.64 percent. 2014 General Rate Cases In November 2014, the UTC approved an all-party settlement agreement related to Avista Utilities’ electric and natural gas general rate cases filed in February 2014 and new rates became effective on January 1, 2015. The settlement was designed to increase annual electric base revenues by $12.3 million, or 2.5 percent, inclusive of a $5.3 million power supply update as required in the settlement agreement (explained below). The settlement was designed to increase annual natural gas base revenues by $8.5 million, or 5.6 percent. The settlement agreement also included the implementation of decoupling mechanisms for electric and natural gas and a related after-the-fact earnings test. See “Decoupling and Earnings Sharing Mechanisms” below for further discussion of these mechanisms. Specific capital structure ratios and the cost of capital components were not agreed to in the settlement agreement. The revenue increases in the settlement were not tied to the 7.32 percent ROR used in conjunction with the after-the fact earnings test discussed under “Decoupling and Earnings Sharing Mechanisms” below. The electric and natural gas revenue increases were negotiated numbers, with each party using its own set of assumptions underlying its agreement to the revenue increases. The parties agreed that the 7.32 percent ROR will be used to calculate the AFUDC and other purposes. 2015 General Rate Cases In January 2016, we received an order that concluded our electric and natural gas general rate cases that were originally filed with the UTC in February 2015. New electric and natural gas rates were effective on January 11, 2016. The UTC approved rates designed to provide a 1.6 percent, or $8.1 million decrease in electric base revenue, and a 7.4 percent, or $10.8 million increase in natural gas base revenue. The UTC also approved an ROR on rate base of 7.29 percent, with a common equity ratio of 48.5 percent and a 9.5 percent ROE. Throughout the rate case process, certain circumstances and costs changed, causing us to revise our overall proposed rate requests downward, especially for our electric operations. Our need for electric rate relief was reduced primarily due to the following: • a decrease in power supply costs of approximately $24.0 million caused by the continuing decline in the price of natural gas used to run our natural gas-fired generation and lower contract costs associated with a new PPA from Chelan PUD, • updated information related to federal tax adjustments and state allocations, • the delay in the expected completion date of the Nine Mile hydroelectric generation project upgrade from late 2015 to late 2016, and • a delay of the start date to begin amortization of existing electric meters from 2016 to a future year, associated with our proposed AMI project. The natural gas revenue increase approved by the UTC is related to our ownership and operating costs to run the natural gas business. Changes in the commodity costs of natural gas for natural gas customers are reflected in our annual PGA, which is generally effective November 1st each year. On November 1, 2015 natural gas customers’ bills were reduced approximately 15 percent related to the decline in the market price of natural gas. In responsive testimony filed by the UTC Staff in July 2015 in our electric and natural gas general rate cases, they recommended a disallowance of $12.7 million (Washington’s share) of the costs associated with the replacement of our customer information and work management systems (Project Compass) primarily related to the delay in the completion of the project. In the January 6, 2016 UTC order, they approved the full recovery of Washington’s portion of Project Compass costs. UTC Issues Order Denying Industrial Customers of Northwest Utilities/ Public Counsel Joint Motion for Clarification, UTC Staff Motion to Reconsider and UTC Staff Motion to Reopen Record On February 19, 2016, the UTC issued an order denying the Motions summarized below and affirmed their original January 2016 order of an $8.1 million decrease in electric base revenue, thus finalizing our 2015 electric and natural gas general rate cases. On January 19, 2016, the Industrial Customers of Northwest Utilities (ICNU) and the Public Counsel Unit of the Washington State Office of the Attorney General (PC) filed a Joint Motion for Clarification with the UTC. In its Motion for Clarification, ICNU and PC requested that the UTC clarify the calculation of the electric attrition adjustment and the end-result revenue decrease of $8.1 million. ICNU and PC provided their own calculations in their Motion, and suggested that the revenue decrease should have been $19.8 million based on their reading of the UTC’s Order. On January 19, 2016, the UTC Staff, which is a separate party in the general rate case proceedings from the UTC Advisory Staff that supports the Commissioners, filed a Motion to Reconsider with the UTC. In its Motion to Reconsider, the Staff provided calculations and explanations that suggested that the electric revenue decrease should have been a revenue decrease of $27.4 million instead of $8.1 million, based on its reading of the UTC’s Order. Further, on February 4, 2016, the UTC Staff filed a Motion to Reopen Record for the Limited Purpose of Receiving into Evidence Instruction on Use and Application of Staff’s Attrition Model, and sought to supplement the record “to incorporate all aspects of the Company’s Power Cost Update.” Within this Motion, UTC Staff updated its suggested electric revenue decrease to $19.6 million. None of the parties in their Motions raised issues with the UTC’s decision on the natural gas revenue increase of $10.8 million. Petition for an Accounting Order to Defer Existing Washington Electric Meters In January 2016, we filed a Petition with the UTC for an Accounting Order to defer and include in a regulatory asset the undepreciated value of our existing Washington electric meters for later recovery. This requested accounting treatment is related to our plans to replace approximately 253,000 of our existing electric meters with new two-way digital meters through our Advanced Metering Infrastructure (AMI) project in Washington state. Staff_DR_063 Attachment B Page 49 of 160 29 AVISTA The petition requests that the UTC allow the deferral, with prudence of the overall AMI project and ultimate recovery, to be addressed in a future regulatory proceeding. The undepreciated value estimated for this deferred accounting treatment is approximately $18.6 million. We have requested recovery of this regulatory asset, with a full rate of return, over fifteen years starting in January 2017, within our February 19, 2016 general rate case filing. 2016 General Rate Cases On February 19, 2016, we filed electric and natural gas general rates cases with the UTC. Our proposal includes an 18-month rate plan, with new rates taking effect on January 1, 2017 and January 1, 2018. Under this plan, we would not file a future rate case for new rates to be effective prior to July 1, 2018. The 2017 increase, if approved, would increase overall base electric rates 7.8 percent (designed to increase annual electric revenues by $38.6 million) and overall base natural gas rates 5.0 percent (designed to increase annual natural gas revenues by $4.4 million). In addition, we have requested a second step increase effective January 1, 2018, which would increase overall base electric rates by 3.9 percent (designed to increase annual electric revenues by $10.3 million) and overall base natural gas rates by 1.8 percent (designed to increase annual natural gas revenues by $0.9 million). We have proposed to offset the electric increase, for the period January through June 2018, with available ERM dollars. As a result, customers would not see an electric general rate case bill increase in 2018 prior to July 1, 2018. Our requests are based on a proposed ROR on rate base of 7.64 percent with a common equity ratio of 48.5 percent and a 9.9 percent ROE. The UTC has up to 11 months to review the filings and issue a decision. Idaho General Rate Cases 2012 General Rate Cases In March 2013, the IPUC approved a settlement agreement in Avista Utilities’ electric and natural gas general rate cases filed in October 2012. As agreed to in the settlement, new rates were implemented in two phases: April 1, 2013 and October 1, 2013. Effective April 1, 2013, base rates increased for our Idaho natural gas customers by an overall 4.9 percent (designed to increase annual revenues by $3.1 million). There was no change in base electric rates on April 1, 2013. The settlement also provided that, effective October 1, 2013, base rates increased for our Idaho natural gas customers by an overall 2.0 percent (designed to increase annual revenues by $1.3 million). Further, the settlement provided that, effective October 1, 2013, base rates increased for our Idaho electric customers by an overall 3.1 percent (designed to increase annual revenues by $7.8 million). The settlement agreement provided for an authorized ROE of 9.8 percent and an equity ratio of 50.0 percent. 2014 Rate Plan Extension Avista Utilities did not file new general rate cases in Idaho in 2014; instead, we developed an extension to the 2013 and 2014 rate plan and reached a settlement agreement with all interested parties. In September 2014, the IPUC approved the settlement, which reflected agreement among all interested parties, for a one-year extension to our current rate plan, which was set to expire on December 31, 2014. Under the approved extension, base retail rates remained unchanged through December 31, 2015. The settlement provided an estimated $3.7 million increase in pre-tax income by reducing planned expenses in 2015 for our Idaho operations. 2015 General Rate Cases In December 2015, the IPUC approved a settlement agreement between Avista Utilities and all interested parties related to our electric and natural gas general rate cases, which were originally filed with the IPUC on June 1, 2015. New rates were effective on January 1, 2016. The settlement agreement is designed to increase annual electric base revenues by $1.7 million or 0.7 percent and annual natural gas base revenues by $2.5 million or 3.5 percent. The settlement is based on a ROR of 7.42 percent with a common equity ratio of 50 percent and a 9.5 percent ROE. The settlement agreement also reflects the following: • the discontinuation of the after-the-fact earnings test (provision for earnings sharing) that was originally agreed to as part of the settlement of our 2012 electric and natural gas general rate cases, and • the implementation of electric and natural gas Fixed Cost Adjustment mechanisms, as discussed below. 2016 General Rate Cases We expect to file electric and natural gas general rate cases in Idaho during the first half of 2016. Oregon General Rate Cases 2013 General Rate Case In January 2014, the OPUC approved a settlement agreement in Avista Utilities’ natural gas general rate case (originally filed in August 2013). As agreed to in the settlement, new rates were implemented in two phases: February 1, 2014 and November 1, 2014. Effective February 1, 2014, rates increased for Oregon natural gas customers on a billed basis by an overall 4.4 percent (designed to increase annual revenues by $3.8 million). Effective November 1, 2014, rates for Oregon natural gas customers were to increase on a billed basis by an overall 1.6 percent (designed to increase annual revenues by $1.4 million). The billed rate increase on November 1, 2014 was dependent upon the completion of Project Compass and the actual costs incurred through September 30, 2014, and the actual costs incurred through June 30, 2014 related to the Company’s Aldyl A distribution pipeline replacement program. Project Compass was completed in February 2015. The November 1, 2014 rate increase was reduced from $1.4 million to $0.3 million due to the delay of Project Compass. The approved settlement agreement provides for an overall authorized ROR of 7.47 percent, with a common equity ratio of 48 percent and a 9.65 percent ROE. 2014 General Rate Case In January 2015, Avista Utilities filed an all-party settlement agreement with the OPUC related to our natural gas general rate case, which was originally filed in September 2014. On February 23, 2015, the OPUC issued an order rejecting the all-party settlement agreement. The OPUC expressed concerns related to, among other things, various rate design issues. Staff_DR_063 Attachment B Page 50 of 160 AVISTA 30 In March 2015, Avista Utilities filed an amended all-party settlement agreement with the OPUC which addressed the OPUC’s concerns regarding the initial settlement agreement. The amended settlement agreement was designed to increase base natural gas revenues by $5.3 million. Included in this base rate increase is $0.3 million in base revenues that we are already receiving from customers through a separate rate adjustment. Therefore, the net increase in base revenues was $5.0 million, or 4.9 percent on a billed basis. The parties requested that new retail rates become effective on April 16, 2015. On April 9, 2015, the OPUC issued an Order approving the amended settlement agreement as filed. This settlement agreement provided for an overall authorized ROR of 7.516 percent with a common equity ratio of 51 percent and a 9.5 percent ROE. 2015 General Rate Case On May 1, 2015, we filed a natural gas general rate case with the OPUC. We have requested an overall increase in base natural gas rates of 8 percent (designed to increase annual natural gas revenues by $8.6 million). Our request is based on a proposed ROR on rate base of 7.72 percent with a common equity ratio of 50 percent and a 9.9 percent ROE. Avista Corp. and all parties to our natural gas general rate case reached agreement on certain issues, and a partial settlement agreement was filed with the OPUC in November 2015. The partial settlement agreement reduced our requested natural gas revenue increase from $8.6 million to $6.7 million or 6.3 percent. The partial settlement, if approved by the OPUC, would resolve a number of issues including the calculation of state income taxes for rate-making purposes, wages and salaries, the revenue forecast for the rate period, and working capital. The agreement does not resolve other issues including the appropriate ROE and capital structure, the appropriate level of additions to rate base, and medical and pension expenses. In January 2016, we entered into an additional all-party partial settlement to further reduce our revenue increase request to $6.1 million, related to updated information related to deferred taxes and its effect on rate base. The agreement includes a provision for the implementation of a decoupling mechanism, similar to the Washington and Idaho mechanisms described above. In addition to the partial settlement agreements above, the OPUC staff filed testimony which included a recommendation to disallow $1.2 million (Oregon’s share) of Project Compass costs primarily related to the delay in the full completion of the project. In January 2016, following the January 6, 2016 UTC order approving the full recovery of Washington’s portion of Project Compass costs, the OPUC staff withdrew its proposal for a disallowance, with the exception of an inconsequential amount which is still open for discussion. The procedural schedule includes an expected decision from the OPUC by February 29, 2016. Alaska General Rate Case AEL&P’s last general rate case was filed in 2010 and approved by the RCA in 2011. We are evaluating the need to file an electric general rate case with the RCA in 2016. Purchased Gas Adjustments PGAs are designed to pass through changes in natural gas costs to Avista Utilities’ customers with no change in gross margin (operating revenues less resource costs) or net income. In Oregon, we absorb (cost or benefit) 10 percent of the difference between actual and projected natural gas costs included in retail rates for supply that is not hedged. Total net deferred natural gas costs among all jurisdictions were a liability of $17.9 million as of December 31, 2015 and a liability of $3.9 million as of December 31, 2014. The following PGAs went into effect in our various jurisdictions during 2013, 2014 and 2015: Percentage Increase/ Jurisdiction PGA Effective Date (Decrease) in Billed Rates Washington November 1, 2013 9.2% November 1, 2014 1.2% November 1, 2015 (15.0)% Idaho October 1, 2013 7.5% November 1, 2014 (2.1)% November 1, 2015 (14.5)% Oregon November 1, 2013 (7.9)% November 1, 2014 8.3% November 1, 2015 (14.1)% Power Cost Deferrals and Recovery Mechanisms The ERM is an accounting method used to track certain differences between Avista Utilities’ actual power supply costs, net of wholesale sales and sales of fuel, and the amount included in base retail rates for our Washington customers. Total net deferred power costs under the ERM were a liability of $18.0 million as of December 31, 2015 compared to a liability $14.2 million as of December 31, 2014, and these deferred power cost balances represent amounts due to customers. The difference in net power supply costs under the ERM primarily results from changes in: • short-term wholesale market prices and sales and purchase volumes, • the level and availability of hydroelectric generation, • the level and availability of thermal generation (including changes in fuel prices), and • retail loads. Staff_DR_063 Attachment B Page 51 of 160 31 AVISTA Under the ERM, Avista Utilities absorbs the cost or receives the benefit from the initial amount of power supply costs in excess of or below the level in retail rates, which is referred to as the deadband. The annual (calendar year) deadband amount is $4.0 million. The following is a summary of the ERM: Deferred for Future Surcharge Expense or Benefit Annual Power Supply Cost Variability of Rebate to Customers to the Company within +/- $0 to $4 million (deadband) 0% 100% higher by $4 million to $10 million 50% 50% lower by $4 million to $10 million 75% 25% higher or lower by over $10 million 90% 10% Under the ERM, Avista Utilities makes an annual filing on or before April 1 of each year to provide the opportunity for the UTC staff and other interested parties to review the prudence of and audit the ERM deferred power cost transactions for the prior calendar year. We made our annual filing on March 31, 2015. The ERM provides for a 90-day review period for the filing; however, the period may be extended by agreement of the parties or by UTC order. The 2014 ERM deferred power costs transactions were approved by an order from the UTC. Avista Utilities has a PCA mechanism in Idaho that allows us to modify electric rates on October 1 of each year with IPUC approval. Under the PCA mechanism, we defer 90 percent of the difference between certain actual net power supply expenses and the amount included in base retail rates for our Idaho customers. The October 1 rate adjustments recover or rebate power supply costs deferred during the preceding July–June twelve-month period. Total net power supply costs deferred under the PCA mechanism were an asset of $0.2 million as of December 31, 2015 compared to an asset of $8.3 million as of December 31, 2014. Decoupling and Earnings Sharing Mechanisms Decoupling is a mechanism designed to sever the link between a utility’s revenues and consumers’ energy usage. Our actual revenue, based on kilowatt hour and therm sales will vary, up or down, from the level included in a general rate case, which could be caused by changes in weather, energy conservation or the economy. Generally, our electric and natural gas revenues will be adjusted each month to be based on the number of customers, rather than kilowatt hour and therm sales. The difference between revenues based on sales and revenues based on the number of customers will be deferred and either surcharged or rebated to customers beginning in the following year. Washington Decoupling and Earnings Sharing In Washington, the UTC approved our decoupling mechanisms for electric and natural gas for a five-year period that commenced January 1, 2015. Electric and natural gas decoupling surcharge rate adjustments to customers are limited to 3 percent on an annual basis, with any remaining surcharge balance carried forward for recovery in a future period. There is no limit on the level of rebate rate adjustments. The decoupling mechanisms each include an after-the-fact earnings test. At the end of each calendar year, separate electric and natural gas earnings calculations will be made for the prior calendar year. These earnings tests will reflect actual decoupled revenues, normalized power supply costs and other normalizing adjustments. • If we have a decoupling rebate balance for the prior year and earn in excess of a 7.32 percent ROR, the rebate to customers would be increased by 50 percent of the earnings in excess of the 7.32 percent ROR. • If we have a decoupling rebate balance for the prior year and earn a 7.32 percent ROR or less, only the base amount of the rebate to customers would be made. • If we have a decoupling surcharge balance for the prior year and earn in excess of a 7.32 percent ROR, the surcharge to customers would be reduced by 50 percent of the earnings in excess of the 7.32 percent ROR (or eliminated). If 50 percent of the earnings in excess of the 7.32 percent ROR exceeds the decoupling surcharge balance, the dollar amount that exceeds the surcharge balance would create a rebate balance for customers. • If we have a decoupling surcharge balance for the prior year and earn a 7.32 percent ROR or less, the base amount of the surcharge to customers would be made. As of December 31, 2015, we had a total net decoupling surcharge (asset) of $10.9 million for Washington electric and natural gas customers and a liability (rebate to customers) for earnings sharing of $3.4 million for Washington electric customers. Idaho Fixed Cost Adjustment (FCA) and Earnings Sharing Mechanisms In Idaho, the IPUC approved the implementation of FCAs for electric and natural gas (similar in operation and effect to the Washington decoupling mechanisms) for an initial term of three years, commencing on January 1, 2016. For the period 2013 through 2015, we had an after-the-fact earnings test, such that if Avista Corp., on a consolidated basis for electric and natural gas operations in Idaho, earned more than a 9.8 percent ROE, we were required to share with customers 50 percent of any earnings above the 9.8 percent. There was no provision for a surcharge to customers if our ROE was less than 9.8 percent. This after-the-fact earnings test was discontinued as part of the settlement of our 2015 Idaho electric and natural gas general rates cases (discussed in further detail above). As of December 31, 2015 and December 31, 2014, we had total cumulative earnings sharing liabilities (rebates to customers) of $8.8 million and $10.1 million, respectively for electric and natural gas customers. Of the total rebate balance as of December 31, 2015, approximately $5.8 million will be returned to customers during January 1, 2016 through December 31, 2017 and the remainder of the balance will be addressed at a future date. See “Results of Operations—Avista Utilities” for further discussion of the amounts recorded to operating revenues in 2013 through 2015 related to the decoupling and earnings sharing mechanisms. Staff_DR_063 Attachment B Page 52 of 160 AVISTA 32 RESULTS OF OPERATIONS—OVERALL The following provides an overview of changes in our Consolidated Statements of Income. More detailed explanations are provided, particularly for operating revenues and operating expenses, in the business segment discussions (Avista Utilities, AEL&P, Ecova—Discontinued Operations and the other businesses) that follow this section. As discussed in “Executive Level Summary,” Ecova was disposed of as of June 30, 2014. As a result, in accordance with GAAP, all of Ecova’s operating results were removed from each line item on the Consolidated Statements of Income and reclassified into discontinued operations for all periods presented. The discussion of continuing operations below does not include any Ecova amounts. For our discussion of discontinued operations and Ecova, see “Ecova— Discontinued Operations.” The balances included below for utility operations reconcile to the Consolidated Statements of Income. Beginning on July 1, 2014, AEL&P is included in the overall utility results. 2015 Compared to 2014 Utility revenues increased $22.7 million, after elimination of intracompany revenues (within Avista Utilities) of $107.0 million for 2015 and $142.2 million for 2014. Avista Utilities’ portion of utility revenues increased $1.6 million and AEL&P’s revenues increased $23.1 million due to a full year of AEL&P results in 2015 as compared to six months in 2014. Including intracompany revenues, Avista Utilities’ electric revenues decreased $1.1 million and natural gas revenues decreased $35.7 million. Other non-utility revenues decreased $10.5 million primarily due to the long-term fixed rate electric capacity contract that was previously held by Spokane Energy being transferred to Avista Corp. during the second quarter of 2015. The capacity revenue from this contract was included in non-utility revenues when it was held by Spokane Energy. Utility resource costs decreased $21.3 million, after elimination of intracompany resource costs of $107.0 million for 2015 and $142.2 million for 2014. Avista Utilities’ portion of resource costs decreased $27.4 million and AEL&P’s resource costs increased $6.1 million due to a full year of AEL&P results in 2015 as compared to six months in 2014. Including intracompany resource costs, Avista Utilities’ electric resource costs decreased $17.6 million and natural gas resource costs decreased $44.9 million. Utility other operating expenses increased $16.4 million. Avista Utilities’ portion of other operating expenses increased $11.1 million and AEL&P’s other operating expenses increased $5.3 million due to a full year of AEL&P results in 2015 as compared to six months in 2014. Avista Utilities incurred increased generation, transmission and distribution operating expenses of $5.7 million, increased administrative and general wages of $9.8 million and increased pension and other postretirement benefit expenses of $10.0 million. In addition, Avista Utilities incurred incremental storm restoration costs associated with the November 2015 wind storm of approximately $2.9 million. These increases were partially offset by decreases in outside services and generation maintenance of $7.8 million and decreases in other various accounts. Utility depreciation and amortization increased $13.9 million driven by additions to utility plant and the inclusion of a full year of AEL&P depreciation as compared to only six months of AEL&P in 2014. Income taxes decreased $4.8 million and our effective tax rate was 36.3 percent for 2015 compared to 37.6 percent for 2014. The decrease in expense was primarily due to a decrease in income before income taxes. There were no material changes in any other account balances on the Consolidated Statement of Income for the year ended December 31, 2015 as compared to the year ended December 31, 2014. 2014 Compared to 2013 Utility revenues increased $31.1 million, after elimination of intracompany revenues (within Avista Utilities) of $142.2 million for 2014 and $151.9 million for 2013. Avista Utilities’ portion of utility revenues increased $9.5 million and AEL&P had electric revenues of $21.6 million, representing its revenues for the six months ended December 31, 2014. Including intracompany revenues, Avista Utilities’ electric revenues decreased $31.6 million and natural gas revenues increased $31.4 million. Utility resource costs decreased $11.3 million, after elimination of intracompany resource costs of $142.2 million for 2014 and $151.9 million for 2013. Avista Utilities’ portion of resource costs decreased $17.2 million and this was offset by utility resource costs at AEL&P of $5.9 million, representing its resource costs for the six months ended December 31, 2014. Including intracompany resource costs, Avista Utilities’ electric resource costs decreased $57.7 million and natural gas resource costs increased $30.7 million. Utility other operating expenses increased $10.6 million and was partially the result of AEL&P being included for the six months ended December 31, 2014, which added $5.9 million to other operating expenses. Avista Utilities incurred increased generation, transmission and distribution operating and maintenance expenses and increased outside services. There were also transaction fees associated with the AERC acquisition of $1.3 million in 2014 compared to $1.6 million in 2013. These were partially offset by a decrease in pension and other postretirement benefits expense. The remainder of the change resulted from various smaller changes in other accounts. Utility depreciation and amortization increased $12.4 million driven by additions to utility plant and the inclusion of $2.6 million related to AEL&P for the second half of the year. Other non-utility operating expenses decreased $8.2 million primarily due to the receipt of $15.0 million related to the settlement of the California power markets litigation (which was recorded as a reduction to operating expenses), partially offset by a $6.4 million contribution to the Avista Foundation. Income taxes increased $14.2 million and our effective tax rate was 37.6 percent for 2014 compared to 35.7 percent for 2013. The increase in expense was primarily due to an increase in income before income taxes. The increase in the effective tax rate was primarily the result of the Section 199 Domestic Manufacturing Deduction not being available to the Company due to limitations on taxable qualified production activities income. There were no material changes in any other account balances on the Consolidated Statement of Income for the year ended December 31, 2014 as compared to the year ended December 31, 2013. Staff_DR_063 Attachment B Page 53 of 160 33 AVISTA RESULTS OF OPERATIONS—AVISTA UTILITIES Non-GAAP Financial Measures The following discussion for Avista Utilities includes two financial measures that are considered “non-GAAP financial measures,” electric gross margin and natural gas gross margin. In the AEL&P section, we include a discussion of electric gross margin. Generally, a non-GAAP financial measure is a numerical measure of a company’s financial performance, financial position or cash flows that excludes (or includes) amounts that are included (excluded) in the most directly comparable measure calculated and presented in accordance with GAAP. The presentation of electric gross margin and natural gas gross margin for Avista Utilities and electric gross margin for AEL&P is intended to supplement an understanding of Avista Utilities’ and AEL&P’s operating performance. We use these measures to determine whether the appropriate amount of energy costs are being collected from our customers to allow for recovery of operating costs, as well as to analyze how changes in loads (due to weather, economic or other conditions), rates, supply costs and other factors impact our results of operations. These measures are not intended to replace income from operations as determined in accordance with GAAP as an indicator of operating performance. The calculations of electric and natural gas gross margins are presented below. 2015 Compared to 2014 The following graphs present Avista Utilities’ operating revenues, resource costs and resulting gross margin for the year ended December 31 (dollars in millions): Gross MarginResource CostsRevenuesGross MarginResource CostsRevenues ELECTRIC RESULTS $997.9 $999.0 $400.9 $418.5 $597.0 $580.5 2015 2014 2015 2014NATURAL GAS RESULTS $521.0 $556.7 $351.1 $396.0 $169.9 $160.7 Total results of operations for electric and natural gas in the graphs above include intracompany revenues and resource costs of $107.0 million and $142.2 million for the years ended December 31, 2015 and December 31, 2014, respectively. Gross MarginResource CostsRevenues COMBINED ELECTRIC AND NATURAL GAS RESULTS (EXCLUDING INTRACOMPANY) $1,411.9 $1,413.5 $645.0 $672.3 $766.9 $741.2 2015 2014 The gross margin on electric sales increased $16.5 million and the gross margin on natural gas sales increased $9.2 million. The increase in electric gross margin was primarily due to a general rate increase in Washington, lower net power supply costs and a $1.9 million decrease in the provision for earnings sharing (which is an offset to revenue). We experienced weather that was significantly warmer than normal and warmer than the prior year, which decreased heating loads in the first quarter and increased cooling loads in the second quarter. Loads in the third quarter were slightly higher than the prior year. Loads for the fourth quarter were lower than the prior year, particularly for residential and industrial customers. For 2015, the decoupling mechanism in Washington had a positive effect on each of electric revenues and gross margin as did the decrease in the overall provision for earnings sharing (see the details by jurisdiction in the table below). For 2015, we recognized a pre-tax benefit of $6.3 million under the ERM in Washington compared to a benefit of $5.4 million for 2014. This change represents a decrease in net power supply costs primarily due to lower natural gas fuel and purchased power prices in 2015, partially offset by lower hydroelectric generation (due to warm and dry conditions in the second and third quarters). Staff_DR_063 Attachment B Page 54 of 160 AVISTA 34 The increase in natural gas gross margin was primarily due to a decrease in natural gas resources costs and a decrease in the provision for earnings sharing, partially offset by a decrease in natural gas revenues. The decrease in natural gas revenues resulted from lower heating loads from significantly warmer weather that was partially offset by general rate increases. The earnings impact of the decrease in heating loads was partially offset by the decoupling mechanism in Washington, which had a positive effect on natural gas revenues and gross margin (see the details by jurisdiction in the graph below). Intracompany revenues and resource costs represent purchases and sales of natural gas between our natural gas distribution operations and our electric generation operations (as fuel for our generation plants). These transactions are eliminated in the presentation of total results for Avista Utilities and in the consolidated financial statements but are reflected in the presentation of the separate results for electric and natural gas below. The following graphs present Avista Utilities’ electric operating revenues and megawatt-hour (MWh) sales for the year ended December 31 (dollars in millions and MWhs in thousands): ELECTRIC OPERATING REVENUES Provision for Earnings Share Decoupling Other Sales of Fuel Wholesale Industrial Commercial Residential 2015 2014 $335.6 $338.7 $308.2 $300.1 $111.8 $110.8 $7.3 $7.5 $127.3 $138.2 $82.9 $83.7 $25.8 $27.5 $4.7 $0.0 ($5.6) ($7.5) ELECTRIC ENERGY MWh SALES 3,571 3,694 3,145 3,686 3,197 3,189 1,812 1,868 23 25 WholesalePublic Street and Highway LightingIndustrialCommercialResidential 2015 2014 Staff_DR_063 Attachment B Page 55 of 160 35 AVISTA The following table presents Avista Utilities’ decoupling and customer earnings sharing mechanisms by jurisdiction that are included in utility electric operating revenues for the year ended December 31 (dollars in thousands): Electric Operating Revenues 2015 2014 Washington Decoupling $ 4,740 $ — Provision for earnings sharing (3,423) — Total 1,317 — Idaho Decoupling — — Provision for earnings sharing (2,198) (7,503) Total $ (2,198) $ (7,503) Total electric revenues decreased $1.1 million for 2015 as compared to 2014 due to the following: • a $5.7 million increase in retail electric revenues due to an increase in revenue per MWh (increased revenues $21.0 million), partially offset by a decrease in total MWhs sold (decreased revenues $15.3 million). The increase in revenue per MWh was primarily due to a general rate increase in Washington. The decrease in total MWhs sold was primarily the result of weather that was significantly warmer than normal and warmer than the prior year, which decreased the electric heating load in the first quarter. Compared to 2014, residential electric use per customer decreased 5 percent and commercial use per customer decreased 2 percent. Heating degree days in Spokane were 14 percent below normal and 10 percent below 2014. The impact from reduced heating loads was partially offset by increased cooling loads in the summer. Year-to-date cooling degree days were 141 percent above normal and 28 percent above the prior year. • a $10.9 million decrease in wholesale electric revenues due to a decrease in sales volumes (decreased revenues $21.9 million), partially offset by an increase in sales prices (increased revenues $11.0 million). The fluctuation in volumes and prices was primarily the result of our optimization activities. • a $0.9 million decrease in sales of fuel due to a decrease in sales of natural gas fuel as part of thermal generation resource optimization activities. For 2015, $50.0 million of these sales were made to our natural gas operations and are included as intracompany revenues and resource costs. For 2014, $67.4 million of these sales were made to our natural gas operations. • a $4.7 million increase in electric revenue due to decoupling, which reflected decreased heating loads in the first and fourth quarters, partially offset by increased cooling loads in the second and third quarters. • a $1.9 million decrease in the provision for earnings sharing, primarily due to a decrease of $5.3 million for our Idaho electric operations, partially offset by an increase of $3.4 million for our Washington electric operations. In 2014, we recorded a provision for earnings sharing of $7.5 million for Idaho electric customers with $5.6 million representing our estimate for 2014 and $1.9 million representing an adjustment of our 2013 estimate. Staff_DR_063 Attachment B Page 56 of 160 AVISTA 36 The following graphs present Avista Utilities’ natural gas operating revenues and therms delivered for the year ended December 31 (dollars in millions and therms in thousands): NATURAL GAS OPERATING REVENUES Provision For Earnings Share Decoupling Other Transportation Wholesale Industrial Interruptible Commercial Residential 2015 2014 $193.8 $203.4 $96.8 $103.2 $2.8 $2.8 $3.8 $4.2 $8.0 $7.7 $6.0 $0.0 $5.6 $7.5 $204.3 $228.2 $0.0 ($0.2) Other Transportation Wholesale Industrial Interruptible Commercial Residential THERMS DELIVERED 176,613 190,171 107,894 116,748 164,679 162,311 335 411 4,708 5,033 5,070 5,648 809,132 545,620 2015 2014 Staff_DR_063 Attachment B Page 57 of 160 37 AVISTA The following table presents Avista Utilities’ decoupling and customer earnings sharing mechanisms by jurisdiction that are included in utility natural gas operating revenues for the year ended December 31 (dollars in thousands): Natural Gas Operating Revenues 2015 2014 Washington Decoupling $ 6,004 $ — Provision for earnings sharing — — Total 6,004 — Idaho Decoupling — — Provision for earnings sharing — (221) Total $ — $ (221) Total natural gas revenues decreased $35.7 million for 2015 as compared to 2014 due to the following: • a $16.4 million decrease in retail natural gas revenues due to a decrease in volumes (decreased revenues $23.6 million), partially offset by higher retail rates (increased revenues $7.2 million). Higher retail rates were due to PGAs implemented in November 2014, which passed through higher costs of natural gas, and general rate cases. This was partially offset by PGA rate decreases implemented in November 2015, which passed through lower costs. We sold less retail natural gas in 2015 as compared to 2014 primarily due to weather that was warmer than normal and warmer than the prior year. Compared to 2014, residential use per customer decreased 9 percent and commercial use per customer decreased 9 percent. Heating degree days in Spokane were 14 percent below historical average for 2015, and 10 percent below 2014. Heating degree days in Medford were 15 percent below historical average for 2015, and 4 percent above 2014. • a $23.9 million decrease in wholesale natural gas revenues due to a decrease in prices (decreased revenues $90.4 million), partially offset by an increase in volumes (increased revenues $66.5 million). In 2015, $57.0 million of these sales were made to our electric generation operations and are included as intracompany revenues and resource costs. In 2014, $74.7 million of these sales were made to our electric generation operations. Differences between revenues and costs from sales of resources in excess of retail load requirements and from resource optimization are accounted for through the PGA mechanisms. • a $6.0 million increase for natural gas decoupling revenues due primarily to significantly warmer than normal weather and the impact on heating loads. The following table presents Avista Utilities’ average number of electric and natural gas retail customers for the year ended December 31: Electric Customers Natural Gas Customers 2015 2014 2015 2014 Residential 327,057 324,188 296,005 291,928 Commercial 41,296 40,988 34,229 34,047 Interruptible — — 35 37 Industrial 1,353 1,385 261 264 Public street and highway lighting 529 531 — — Total retail customers 370,235 367,092 330,530 326,276 Staff_DR_063 Attachment B Page 58 of 160 AVISTA 38 The following graphs present Avista Utilities’ resource costs for the year ended December 31 (dollars in millions): ELECTRIC RESOURCE COSTS Other electric resource costs Other regulatory amortizations—net Other fuel costs Fuel for generation Power cost amortizations—net Power purchased 2015 $166.6 2014 $185.0 $120.8 $116.4 $72.4 $82.4 $12.9 $20.6 $20.6 $20.7 $7.6 ($6.5) 2015 2014 $331.5 $397.7 $5.8 $6.4 $13.7 ($8.1) NATURAL GAS RESOURCE COSTS Natural gas purchased Total resource costs in the graphs above include intracompany resource costs of $107.0 million and $142.2 million for the years ended December 31, 2015 and December 31, 2014, respectively. Total resource costs decreased $27.4 million for 2015 as compared to 2014 primarily due to the following: • a $18.3 million decrease in power purchased due to a decrease in the volume of power purchases (decreased costs $23.6 million), partially offset by an increase in wholesale prices (increased costs $5.3 million). The fluctuation in volumes and prices was primarily the result of our overall optimization activities. • a $14.2 million increase from amortizations and deferrals of power costs due to the following. • increases to expense in 2015: • a $5.8 million surcharge to customers of previously deferred power costs in Idaho through the PCA. • an $11.3 million deferral in Washington and a $2.0 million deferral in Idaho for probable future benefit to customers due to actual power supply costs being below the amount included in base retail rates. • a $2.0 million deferral in Washington of RECs for probable future benefit to customers. • decreases to expense in 2015: • an $8.0 million refund to Washington customers through an ERM rebate. • a $5.4 million refund to Washington customers through a REC rebate. • a $4.4 million increase in fuel for generation primarily due to an increase in thermal generation (due in part to decreased hydroelectric generation), partially offset by a decrease in natural gas fuel prices. • a $10.0 million decrease in other fuel costs. This represents fuel and the related derivative instruments that were purchased for generation but were later sold when conditions indicated that it was more economical to sell the fuel as part of the resource optimization process. When the fuel or related derivative instruments are sold, that revenue is included in sales of fuel. • a $7.7 million decrease in other electric resource costs primarily due to the benefit from a capacity contract of Spokane Energy, which was mostly deferred for probable future benefit to customers through the ERM and PCA. • a $66.1 million decrease in natural gas purchased due to a decrease in the price of natural gas (decreased costs $138.3 million), partially offset by an increase in total therms purchased (increased costs $72.2 million). Total therms purchased increased due to an increase in wholesale sales, partially offset by a decrease in retail sales. • a $21.8 million increase from amortizations and deferrals of natural gas costs. This reflects lower natural gas prices and the deferral of lower costs for future rebate to customers. • a $35.1 million decrease in intracompany resource costs (which has the effect of increasing overall net resource costs). Staff_DR_063 Attachment B Page 59 of 160 39 AVISTA 2014 Compared to 2013 The following graphs present Avista Utilities’ operating revenues, resource costs and resulting gross margin for the year ended December 31 (dollars in millions): Gross MarginResource CostsRevenuesGross MarginResource CostsRevenues ELECTRIC RESULTS $999.0 $1,030.6 $418.5 $476.2 $580.5 $554.4 2014 2013 2014 2013NATURAL GAS RESULTS $556.7 $525.3 $396.0 $365.2 $160.7 $160.1 Total results of operations for electric and natural gas in the graphs above include intracompany revenues and resource costs of $142.2 million and $151.9 million for the years ended December 31, 2014 and December 31, 2013, respectively. Gross MarginResource CostsRevenues COMBINED ELECTRIC AND NATURAL GAS RESULTS (EXCLUDING INTRACOMPANY) $1,413.5 $1,404.0 $672.3 $689.6 $741.2 $714.4 2014 2013 The gross margin on electric sales increased $26.0 million and the gross margin on natural gas sales increased $0.7 million. Electric gross margin for 2014 included a pre-tax benefit of $5.4 million under the ERM in Washington compared to a pre-tax expense of $4.7 million for 2013. This change represents a decrease in net power supply costs due to the Colstrip outage in 2013 and increased hydroelectric generation in 2014. Electric gross margin for 2013 included the net benefit from the settlement with the BPA of $5.1 million. Staff_DR_063 Attachment B Page 60 of 160 AVISTA 40 The following graphs present Avista Utilities’ electric operating revenues and megawatt-hour (MWh) sales for the year ended December 31 (dollars in millions and MWhs in thousands): ELECTRIC OPERATING REVENUES Provision for Earnings Share Other Sales of Fuel Wholesale Industrial Commercial Residential 2014 2013 $338.7 $331.9 $300.1 $289.6 $110.8 $113.6 $7.5 $7.3 $138.2 $127.6 $83.7 $126.7 $27.5 $36.1 ($7.5) ($2.0) ELECTRIC ENERGY MWh SALES 3,694 3,745 3,686 3,874 3,189 3,147 1,868 1,979 25 26 WholesalePublic Street and Highway LightingIndustrialCommercialResidential 2014 2013 Staff_DR_063 Attachment B Page 61 of 160 41 AVISTA Total electric revenues decreased $31.6 million for 2014 as compared to 2013 due to the following: • a $14.8 million increase in retail electric revenue primarily due to general rate increases and a change in revenue mix (which increased revenue by $25.2 million), partially offset by a decrease in volumes (which decreased revenue by $10.4 million). The decrease in residential volumes was primarily due to warmer weather in the fourth quarter, partially offset by customer growth. The decrease in total MWhs sold to industrial customers was primarily due to the expiration and replacement of a contract with one of our largest industrial customers in Idaho, effective July 1, 2013. The change resulting from this new contract did not impact gross margin because any change in revenues and expenses was tracked through the PCA in Idaho at 100 percent until such time as the contract was included in the Company’s base rates, • a $10.6 million increase in wholesale electric revenues due to an increase in sales prices (increased revenues $17.6 million), partially offset by a decrease in sales volumes (decreased revenues $7.0 million). The fluctuation in volumes and prices was primarily the result of our optimization activities during the period, • a decrease of $42.9 million in sales of natural gas fuel as part of thermal generation resource optimization activities. For 2014, $67.4 million of these sales were made to our natural gas operations and are included as intracompany revenues and resource costs. For 2013, $102.4 million of these sales were made to our natural gas operations, • an $8.6 million decrease in other electric revenues primarily due to the receipt of $11.7 million of revenue from the Bonneville Power Administration in 2013 for past use of our electric transmission system, and • a $5.5 million increase in the provision for earnings sharing for Idaho electric customers primarily due to the 2014 provision for earnings sharing including a $1.9 million adjustment of our 2013 estimate. The following graph presents Avista Utilities’ natural gas operating revenues for the year ended December 31 (dollars in millions): NATURAL GAS OPERATING REVENUES Provision For Earnings Share Other Transportation Wholesale Industrial Interruptible Commercial Residential 2014 2013 $203.4 $206.3 $103.2 $102.2 $2.8 $2.7 $4.2 $3.6 $7.5 $8.6 $7.7 $7.6 $288.2 $194.7 ($0.2) ($0.4) Staff_DR_063 Attachment B Page 62 of 160 AVISTA 42 The following graph presents Avista Utilities’ therms delivered for the year ended December 31 (therms in thousands): Other Transportation Wholesale Industrial Interruptible Commercial Residential THERMS DELIVERED 190,171 204,711 116,748 122,245 162,311 159,976 411 418 5,033 5,694 5,648 5,181 545,620 524,818 2014 2013 Natural gas revenues increased $31.4 million for 2014 as compared to 2013 due to the following: • a $1.3 million decrease in retail natural gas revenues due to a decrease in volumes (decreased revenues by $20.0 million), partially offset by general rate increases and higher PGA rates, which passed through costs of natural gas (increased revenues by $18.7 million). We had decreased volumes primarily due to weather that was warmer than normal and warmer than the prior year during the fourth quarter, • an increase of $33.5 million in wholesale natural gas revenues due to an increase in prices (increased revenues by $24.8 million) and an increase in volumes (increased revenues by $8.7 million). In 2014, $74.7 million of wholesale sales were made to our electric generation operations and are included as intracompany revenues and resource costs. In 2013, $49.5 million of these sales were made to our electric generation operations, and • a $0.2 million reduction to revenue in 2014 for the provision for earnings sharing for Idaho natural gas customers, compared to a reduction to revenue of $0.4 million in 2013. The following table presents Avista Utilities’ average number of electric and natural gas retail customers for the year ended December 31: Electric Customers Natural Gas Customers 2014 2013 2014 2013 Residential 324,188 321,098 291,928 288,708 Commercial 40,988 40,202 34,047 33,932 Interruptible — — 37 38 Industrial 1,385 1,386 264 259 Public street and highway lighting 531 527 — — Total retail customers 367,092 363,213 326,276 322,937 Staff_DR_063 Attachment B Page 63 of 160 43 AVISTA The following graphs present Avista Utilities’ resource costs for the year ended December 31 (dollars in millions): ELECTRIC RESOURCE COSTS Other electric resource costs Other regulatory amortizations—net Other fuel costs Fuel for generation Power cost amortizations—net Power purchased 2014 $185.0 2013 $189.9 $116.4 $133.7 $82.4 $122.0 $20.6 $22.1 $20.7 $22.7 ($6.5) ($14.2) Other regulatory amortizations—net Natural gas cost amortizations—net Natural gas purchased 2014 2013 $397.7 $353.1 $6.4 $7.4 ($8.1) $4.8 NATURAL GAS RESOURCE COSTS Total resource costs in the graphs above include intracompany resource costs of $142.2 million and $151.9 million for the years ended December 31, 2014 and December 31, 2013, respectively. Total resource costs decreased $31.4 million for 2014 as compared to 2013 primarily due to the following: • a decrease of $5.0 million in power purchased due to a decrease in the volume of power purchases, partially offset by an increase in wholesale prices. The fluctuation in volumes and prices was primarily the result of our overall optimization activities during the year. The decrease in volumes purchased was also due to increased hydroelectric generation, • a decrease to 2014 electric resource costs of $6.5 million for amortizations and deferrals of power costs, compared to a decrease of $14.2 million for 2013. • increases to expense in 2014: • a $1.6 million deferral in Idaho and a $4.2 million deferral in Washington for probable future benefit to customers due to actual power supply costs being below the amount included in retail rates. • decreases to expense in 2014: • a $2.3 million refund to Idaho customers of previously deferred power costs through the PCA rebate. • an $8.5 million refund to Washington customers through an ERM rebate. • a $1.6 million deferral of RECs for probable future benefit to Washington customers. • a decrease of $17.2 million for fuel for generation primarily due to a decrease in natural gas generation, • a decrease of $39.6 million in other fuel costs due to the resource optimization process, and • an increase of $44.6 million in natural gas purchased due to an increase in the price of natural gas and a slight increase in total therms purchased. Total therms purchased increased due to an increase in wholesale sales as part of the natural gas procurement and resource optimization process, mostly offset by a decrease in retail sales. Staff_DR_063 Attachment B Page 64 of 160 AVISTA 44 RESULTS OF OPERATIONS—ALASKA ELECTRIC LIGHT AND POWER COMPANY AEL&P was acquired on July 1, 2014 and only the results for the second half of 2014 are included in the actual overall results of Avista Corp. The discussion below is only for AEL&P’s earnings that were included in Avista Corp.’s overall earnings. 2015 Compared to 2014 Net income for AEL&P was $6.6 million for the year ended December 31, 2015, compared to $3.2 million for the second half of 2014. The following table presents AEL&P’s operating revenues, resource costs and resulting gross margin for the year ended December 31, 2015 and the second half of 2014 (dollars in thousands): Second half 2015 of 2014 Operating revenues $ 44,778 $ 21,644 Resource costs 11,973 5,900 Gross margin $ 32,805 $ 15,744 The following table presents AEL&P’s electric operating revenues and megawatt-hour (MWh) sales for the year ended December 31, 2015 and the second half of 2014 (dollars and MWhs in thousands): Electric Operating Revenues Electric Energy MWh sales Second half Second half 2015 of 2014 2015 of 2014 Residential $ 18,017 $ 8,283 139 63 Commercial and government 26,049 12,948 258 125 Public street and highway lighting 215 150 1 1 Total retail 44,281 21,381 398 189 Other 497 263 — — Total $ 44,778 $ 21,644 398 189 AEL&P has a relatively stable load profile as it does not have a large population of customers in its service territory with electric heating and cooling requirements; therefore, their revenues are not as sensitive to weather fluctuations as Avista Utilities. However, AEL&P does have higher winter rates for its customers during the peak period of November through May of each year, which drives higher revenues during those periods. Government sales are similar to commercial sales in that they are primarily firm customers, but are government entities. Commercial and government revenues from interruptible or non-firm customers were $8.3 million for 2015, including $7.2 million from AEL&P’s largest customer. These revenues from non-firm customers are deferred and passed on for the benefit of firm customers in future periods either through base rates or a cost of power adjustment. As noted at “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Economic Conditions,” one of AEL&P’s largest commercial customers (a retailer), which accounts for approximately 1 percent of AEL&P’s annual firm revenues, is permanently closing in early 2016. It is unknown whether a new business will occupy the building that was occupied by this retailer. The following table presents AEL&P’s average number of electric retail customers for the year ended December 31, 2015 and the second half of 2014: Electric Customers Second half 2015 of 2014 Residential 14,285 14,121 Commercial and government 2,179 2,148 Public street and highway lighting 210 213 Total retail customers 16,674 16,482 The following table presents AEL&P’s resource costs for the year ended December 31, 2015 and the second half of 2014 (dollars in thousands): Resource Costs Second half 2015 of 2014 Snettisham power expenses $ 10,377 $ 5,196 Cost of power adjustment—net 1,501 646 Fuel for generation 95 58 Total electric resource costs $ 11,973 $ 5,900 Staff_DR_063 Attachment B Page 65 of 160 45 AVISTA Snettisham power expenses represent costs associated with operating the Snettisham hydroelectric project, including amounts paid under the take-or-pay PPA for the full capacity of this plant. This agreement is recorded as a capital lease on AEL&P’s balance sheet, but reflected as an operating lease in the income statement. See “Note 14 of the Notes to Consolidated Financial Statements” for further information regarding this capital lease obligation. Cost of power adjustments are primarily derived from certain revenues from interruptible or non-firm customers that are deferred and passed on for the benefit of firm customers in future periods. For instance, revenues from electric sales to cruise ships are passed back to firm customers at 100 percent. The amortization of these deferred balances flows through this account along with the original deferral. RESULTS OF OPERATIONS—ECOVA— DISCONTINUED OPERATIONS Ecova was disposed of as of June 30, 2014. As a result, in accordance with GAAP, all of Ecova’s operating results were removed from each line item on the Consolidated Statements of Income and reclassified into discontinued operations for all periods presented. In addition, since Ecova was a subsidiary of Avista Capital, the net gain recognized on the sale of Ecova was attributable to our other businesses. However, in accordance with GAAP, this gain is included in discontinued operations; therefore, we included the analysis of the gain in the Ecova discontinued operations section rather than in the other businesses section. 2015 Compared to 2014 Ecova’s net income was $5.1 million for 2015, compared to net income of $72.4 million for 2014. The net income for 2015 was primarily related to a tax benefit during 2015 that resulted from the reversal of a valuation allowance against net operating losses at Ecova because the net operating losses were deemed realizable under the current tax code. Additionally, there were some minor true-ups to the gain recognized on the sale due to the settlement of the working capital and indemnification escrow accounts during 2015. The results for 2014 included $69.7 million of the net gain recognized on the sale of Ecova. 2014 Compared to 2013 Ecova’s net income was $72.4 million for 2014 compared to net income of $7.1 million for 2013. The increase was primarily attributable to the net gain recognized on the sale of Ecova of $69.7 million. Excluding the net gain, net income from Ecova’s regular operations through the date of the sale were flat compared to the same period in 2013 and were the result of a decrease in depreciation and amortization expense and an increase in operating revenues, offset by an increase in operating expenses. RESULTS OF OPERATIONS—OTHER BUSINESSES 2015 Compared to 2014 The net loss from these operations was $1.9 million for 2015 compared to net income of $3.2 million for 2014. The decrease in net income compared to 2014 was primarily due to the settlement of the California power markets litigation in 2014, which is described in further detail below. In addition, the net loss for 2015 was primarily related to: • $2.3 million (net of tax) of corporate costs, including costs associated with exploring strategic opportunities, compared to $2.4 million in 2014, • net losses on investments (net of tax) of $0.4 million for 2015, compared to net gains of $0.2 million for 2014, • net income at METALfx of $1.5 million for 2015, compared to net income of $0.9 million for 2014. 2014 Compared to 2013 The net income from these operations was $3.2 million for 2014 compared to a net loss of $4.7 million for 2013. The net income for 2014 was primarily the result of the settlement of the California power markets litigation, where Avista Energy received settlement proceeds from a litigation with various California parties related to the prices paid for power in the California spot markets during the years 2000 and 2001. This settlement resulted in an increase in pre-tax earnings of approximately $15.0 million. This was partially offset by a pre-tax contribution of $6.4 million of the proceeds to the Avista Foundation. METALfx had net income of $0.9 million for 2014, compared to net income of $1.2 million for 2013. In 2014, we also incurred $2.4 million (net of tax) of corporate costs, including costs associated with exploring strategic opportunities. ACCOUNTING STANDARDS TO BE ADOPTED IN 2016 At this time, we are not expecting the adoption of accounting standards to have a material impact on our financial condition, results of operations and cash flows in 2016. For information on accounting standards adopted in 2015 and earlier periods, see “Note 2 of the Notes to Consolidated Financial Statements.” Staff_DR_063 Attachment B Page 66 of 160 AVISTA 46 CRITICAL ACCOUNTING POLICIES AND ESTIMATES The preparation of our consolidated financial statements in conformity with GAAP requires us to make estimates and assumptions that affect amounts reported in the consolidated financial statements. Changes in these estimates and assumptions are considered reasonably possible and may have a material effect on our consolidated financial statements and thus actual results could differ from the amounts reported and disclosed herein. The following accounting policies represent those that our management believes are particularly important to the consolidated financial statements and require the use of estimates and assumptions: • Regulatory accounting, which requires that certain costs and/or obligations be reflected as deferred charges on our Consolidated Balance Sheets and are not reflected in our Consolidated Statements of Income until the period during which matching revenues are recognized. We also have decoupling revenue deferrals. As opposed to cost deferrals which are not recognized in the Consolidated Statements of Income until they are included in rates, decoupling revenue is recognized in the Consolidated Statements of Income during the period in which it occurs (i.e. during the period of revenue shortfall or excess due to fluctuations in customer usage), subject to certain limitations, and a regulatory asset/liability is established which will be surcharged or rebated to customers in future periods. GAAP requires that for any alternative regulatory revenue program, like decoupling, the revenue must be collected from customers within 24 months of the deferral to qualify for recognition in the current period Consolidated Statement of Income. Any amounts included in the Company’s decoupling program that won’t be collected from customers within 24 months are not recorded in the financial statements until the period in which revenue recognition criteria are met. This could ultimately result in more decoupling revenue being collected from customers over the life of the decoupling program than what is deferred and recognized in the current period financial statements. We make estimates regarding the amount of revenue that will be collected with 24 months of deferral. We also make the assumption that there are regulatory precedents for many of our regulatory items and that we will be allowed recovery of these costs via retail rates in future periods. If we were no longer allowed to apply regulatory accounting or no longer allowed recovery of these costs, we could be required to recognize significant write-offs of regulatory assets and liabilities in the Consolidated Statements of Income. See “Notes 1 and 20 of the Notes to Consolidated Financial Statements” for further discussion of our regulatory accounting policy. • Utility energy commodity derivative asset and liability accounting, where we estimate the fair value of outstanding commodity derivatives and we offset energy commodity derivative assets or liabilities with a regulatory asset or liability. This accounting treatment is intended to defer the recognition of mark-to-market gains and losses on energy commodity transactions until the period of delivery. This accounting treatment is supported by accounting orders issued by the UTC and IPUC. If we were no longer allowed to apply regulatory accounting or no longer allowed recovery of these costs, we could be required to recognize significant changes in fair value of these energy commodity derivatives on a regular basis in the Consolidated Statements of Income, which could lead to significant fluctuations in net income. See “Notes 1 and 6 of the Notes to Consolidated Financial Statements” for further discussion of our energy derivative accounting policy. • Interest rate derivative asset and liability accounting, where we estimate the fair value of outstanding interest rate swaps, and U.S. Treasury lock agreements and offset the derivative asset or liability with a regulatory asset or liability. This is similar to the treatment of energy commodity derivatives described above. Upon settlement of interest rate swaps, the regulatory asset or liability (included as part of long-term debt) is amortized as a component of interest expense over the term of the associated debt. If we no longer applied regulatory accounting or were no longer allowed recovery of these costs, we could be required to recognize significant changes in fair value of these interest rate derivatives on a regular basis in the Consolidated Statements of Income, which could lead to significant fluctuations in net income. • Pension Plans and Other Postretirement Benefit Plans, discussed in further detail below. • Contingencies, related to unresolved regulatory, legal and tax issues for which there is inherent uncertainty for the ultimate outcome of the respective matter. We accrue a loss contingency if it is probable that an asset is impaired or a liability has been incurred and the amount of the loss or impairment can be reasonably estimated. We also disclose losses that do not meet these conditions for accrual, if there is a reasonable possibility that a potential loss may be incurred. For all material contingencies, we have made a judgment as to the probability of a loss occurring and as to whether or not the amount of the loss can be reasonably estimated. If the loss recognition criteria are met, liabilities are accrued or assets are reduced. However, no assurance can be given to the ultimate outcome of any particular contingency. See “Notes 1 and 19 of the Notes to Consolidated Financial Statements” for further discussion of our commitments and contingencies. • Discontinued operations, related to the accounting and financial statement presentation for Ecova following its disposition in 2014. In accordance with GAAP, this transaction caused Ecova to be accounted for as a discontinued operation. Ecova’s revenues and expenses are included in the Consolidated Statements of Income in discontinued operations (as a single line item, net of tax). The gain, net of tax, recognized on the sale of Ecova is also included in discontinued operations. All tables throughout the Notes to Consolidated Financial Statements that present Consolidated Statements of Income information were revised to only include amounts from continuing operations. In addition, we are presenting earnings per share calculations for continuing and discontinued operations. Pension Plans and Other Postretirement Benefit Plans—Avista Utilities We have a defined benefit pension plan covering substantially all regular full-time employees at Avista Utilities that were hired prior to January 1, 2014. For substantially all regular non-union full-time employees at Avista Utilities that were hired on or after January 1, 2014, a defined contribution 401(k) plan replaced the defined benefit pension plan. Staff_DR_063 Attachment B Page 67 of 160 47 AVISTA The Finance Committee of the Board of Directors approves investment policies, objectives and strategies that seek an appropriate return for the pension plan and it reviews and approves changes to the investment and funding policies. We have contracted with an independent investment consultant who is responsible for managing/monitoring the individual investment managers. The investment managers’ performance and related individual fund performance is reviewed at least quarterly by an internal benefits committee and by the Finance Committee to monitor compliance with our established investment policy objectives and strategies. Our pension plan assets are invested in debt securities and mutual funds, trusts and partnerships that hold marketable debt and equity securities, real estate and absolute return funds. In seeking to obtain the desired return to fund the pension plan, the investment consultant recommends allocation percentages by asset classes. These recommendations are reviewed by the internal benefits committee, which then recommends their adoption by the Finance Committee. The Finance Committee has established target investment allocation percentages by asset classes and also investment ranges for each asset class. The target investment allocation percentages are typically the midpoint of the established range and are disclosed in “Note 10 of the Notes to Consolidated Financial Statements.” We also have a Supplemental Executive Retirement Plan (SERP) that provides additional pension benefits to our executive officers and others whose benefits under the pension plan are reduced due to the application of Section 415 of the Internal Revenue Code of 1986 and the deferral of salary under deferred compensation plans. Pension costs (including the SERP) were $27.1 million for 2015, $14.6 million for 2014 and $28.8 million for 2013. Of our pension costs, approximately 60 percent are expensed and 40 percent are capitalized consistent with labor charges. The costs related to the SERP are expensed. Our costs for the pension plan are determined in part by actuarial formulas that are dependent upon numerous factors resulting from actual plan experience and assumptions of future experience. Pension costs are affected by among other things: • employee demographics (including age, compensation and length of service by employees), • the amount of cash contributions we make to the pension plan, • the actual return on pension plan assets, • expected return on pension plan assets, • discount rate used in determining the projected benefit obligation and pension costs, • assumed rate of increase in employee compensation, • life expectancy of participants and other beneficiaries, and • expected method of payment (lump sum or annuity) of pension benefits. Any changes in pension plan obligations associated with these factors may not be immediately recognized as pension costs in our Consolidated Statement of Income, but we generally recognize the change in future years over the remaining average service period of pension plan participants. As such, our costs recorded in any period may not reflect the actual level of cash benefits provided to pension plan participants. We revise the key assumption of the discount rate each year. In selecting a discount rate, we consider yield rates at the end of the year for highly rated corporate bond portfolios with cash flows from interest and maturities similar to that of the expected payout of pension benefits. In 2015, the pension plan discount rate (exclusive of the SERP) was 4.58 percent compared to 4.21 percent in 2014 and 5.10 percent in 2013. These changes in the discount rate decreased the projected benefit obligation (exclusive of the SERP) by approximately $31.0 million in 2015 and increased the obligation by $66.3 million in 2014. The expected long-term rate of return on plan assets is reset or confirmed annually based on past performance and economic forecasts for the types of investments held by our plan. We used an expected long-term rate of return of 5.30 percent in 2015, 6.60 percent in 2014 and 6.60 percent in 2013. This change increased pension costs by approximately $6.9 million in 2015. The actual return on plan assets, net of fees, was a loss of $4.3 million (or 0.8 percent) for 2015, a gain of $56.0 million (or 11.6 percent) for 2014 and a gain of $52.5 million (or 12.5 percent) for 2013. The following chart reflects the sensitivities associated with a change in certain actuarial assumptions by the indicated percentage (dollars in thousands): Effect on Projected Change in Benefit Effect on Actuarial Assumption Assumption Obligation Pension Cost Expected long-term return on plan assets (0.5)% $ —* $ 2,670 Expected long-term return on plan assets 0.5% —* (2,670) Discount rate (0.5)% 42,561 4,226 Discount rate 0.5% (37,969) (3,768) * Changes in the expected return on plan assets would not affect our projected benefit obligation. We provide certain health care and life insurance benefits for substantially all of our retired employees. We accrue the estimated cost of postretirement benefit obligations during the years that employees provide service. Assumed health care cost trend rates have a significant effect on the amounts reported for our postretirement plans. A one- percentage-point increase in the assumed health care cost trend rate for each year would increase our accumulated postretirement benefit obligation as of December 31, 2015 by $9.7 million and the service and interest cost by $0.5 million. A one-percentage-point decrease in the assumed health care cost trend rate for each year would decrease our accumulated postretirement benefit obligation as of December 31, 2015 by $7.5 million and the service and interest cost by $0.4 million. As of December 31, 2015, for the estimated retiree medical plan liability and costs, which are included as part of other postretirement benefits, our actuaries adopted an updated method of calculation. For the updated method, the assumed average per-capita claim costs for pre-65 participants and post-65 participants were age-adjusted into 5-year bands as prescribed by the Actuarial Standards of Practice. This change in method resulted in an increase to the accumulated postretirement benefit obligation of approximately $4.6 million in 2015. Staff_DR_063 Attachment B Page 68 of 160 AVISTA 48 LIQUIDITY AND CAPITAL RESOURCES OVERALL LIQUIDITY Avista Corp.’s consolidated operating cash flows are primarily derived from the operations of Avista Utilities. The primary source of operating cash flows for Avista Utilities is revenues from sales of electricity and natural gas. Significant uses of cash flows from Avista Utilities include the purchase of power, fuel and natural gas, and payment of other operating expenses, taxes and interest, with any excess being available for other corporate uses such as capital expenditures and dividends. We design operating and capital budgets to control operating costs and to direct capital expenditures to choices that support immediate and long-term strategies, particularly for our regulated utility operations. In addition to operating expenses, we have continuing commitments for capital expenditures for construction and improvement of utility facilities. Our annual net cash flows from operating activities usually do not fully support the amount required for annual utility capital expenditures. As such, from time to time, we need to access long-term capital markets in order to fund these needs as well as fund maturing debt. See further discussion at “Capital Resources.” We periodically file for rate adjustments for recovery of operating costs and capital investments and to seek the opportunity to earn reasonable returns as allowed by regulators. See further details in the section “Regulatory Matters.” For Avista Utilities, when power and natural gas costs exceed the levels currently recovered from retail customers, net cash flows are negatively affected. Factors that could cause purchased power and natural gas costs to exceed the levels currently recovered from our customers include, but are not limited to, higher prices in wholesale markets when we buy energy or an increased need to purchase power in the wholesale markets. Factors beyond our control that could result in an increased need to purchase power in the wholesale markets include, but are not limited to: • increases in demand (due to either weather or customer growth), • low availability of streamflows for hydroelectric generation, • unplanned outages at generating facilities, and • failure of third parties to deliver on energy or capacity contracts. Avista Utilities has regulatory mechanisms in place that provide for the deferral and recovery of the majority of power and natural gas supply costs. However, if prices rise above the level currently allowed in retail rates in periods when we are buying energy, deferral balances would increase, negatively affecting our cash flow and liquidity until such time as these costs, with interest, are recovered from customers. In addition to the above, Avista Utilities enters into derivative instruments to hedge our exposure to certain risks, including fluctuations in commodity market prices, foreign exchange rates and interest rates (for purposes of issuing long-term debt in the future). These derivative instruments often require collateral (in the form of cash or letters of credit) or other credit enhancements, or reductions or terminations of a portion of the contract through cash settlement, in the event of a downgrade in the Company’s credit ratings or changes in market prices. In periods of price volatility, the level of exposure can change significantly. As a result, sudden and significant demands may be made against the Company’s credit facilities and cash. See “Enterprise Risk Management—Demands for Collateral” below. We monitor the potential liquidity impacts of changes to energy commodity prices and other increased operating costs for our utility operations. We believe that we have adequate liquidity to meet such potential needs through our committed lines of credit. As of December 31, 2015, we had $250.4 million of available liquidity under the Avista Corp. committed line of credit and $25.0 million under the AEL&P committed line of credit. With our $400.0 million credit facility that expires in April 2019 and AEL&P’s $25.0 million credit facility that expires in November 2019, we believe that we have adequate liquidity to meet our needs for the next 12 months. REVIEW OF CONSOLIDATED CASH FLOW STATEMENT Overall—During 2015, cash flows from operating activities were $375.6 million, proceeds from the issuance of long-term debt were $100.0 million and we received $13.9 million from the settlement of the Ecova escrow receivable. Cash requirements included utility capital expenditures of $393.4 million, the redemption of long-term debt of $2.9 million, defined benefit pension plan contributions of $12.0 million, dividends of $82.4 million and the repurchase of common stock of $2.9 million. 2015 Compared to 2014 Consolidated Operating Activities Net cash provided by operating activities was $375.6 million for 2015 compared to $267.3 million for 2014. Net cash used by the changes in certain current assets and liabilities components was $4.1 million for 2015, compared to net cash used of $50.0 million for 2014. The net cash used during 2015 primarily reflects cash outflows from changes in accounts payable, collateral posted for derivative instruments and accounts receivable. This was partially offset by inflows from changes in natural gas stored and income taxes receivable. The gross gain on the sale of Ecova of $0.8 million for 2015 is deducted in reconciling net income to net cash provided by operating activities. The cash proceeds from the sale (which includes the gross gain) is included in investing activities. This is compared to the gross gain recognized in 2014 of $160.6 million. Net amortizations of power and natural gas costs were $21.4 million for 2015 compared to net deferrals of $14.8 million for 2014. The provision for deferred income taxes was $51.8 million for 2015 compared to $144.3 million for 2014. The decrease in 2015 was primarily due to the combination of implementation by the Company of updated federal tax tangible property regulations and increased deductions related to bonus depreciation in 2014. Contributions to our defined benefit pension plan were $12.0 million for 2015 compared to $32.0 million in 2014. Net cash received for income taxes was $10.0 million for 2015 compared to net cash paid of $45.4 million for 2014. Staff_DR_063 Attachment B Page 69 of 160 49 AVISTA Consolidated Investing Activities Net cash used in investing activities was $387.8 million for 2015, an increase compared to $103.7 million for 2014. During 2015, we received cash proceeds (related to the settlement of the escrow accounts) of $13.9 million for the sale of Ecova. We received the majority of the proceeds ($229.9 million) from the sale of Ecova during 2014. The proceeds received in 2014 were used to pay off the balance of Ecova’s long-term borrowings and make payments to option holders and noncontrolling interests (included in financing activities). We also used a portion of these proceeds to pay our $74.8 million tax liability associated with the gain on sale and to fund common stock repurchases. Utility property capital expenditures increased by $67.9 million for 2015 as compared to 2014. During 2014, we received $15.0 million in cash (net of cash paid) related to the acquisition of AERC. Consolidated Financing Activities Net cash provided by financing activities was $0.5 million for 2015 compared to net cash used of $224.0 million for 2014. In 2015 we had the following significant transactions: • issuance and sale of $100.0 million of Avista Corp. first mortgage bonds in December 2015, • cash settlement of interest rate swaps in conjunction with the execution of the purchase agreement for the Avista Corp. first mortgage bonds which resulted in the payment of $9.3 million, • payment of $2.9 million for the redemption and maturity of long-term debt, • cash dividends paid increased to $82.4 million (or $1.32 per share) for 2015 from $78.3 million (or $1.27 per share) for 2014, • issuance of $1.6 million of common stock (net of issuance costs), and • repurchase of $2.9 million of our common stock. In 2014, we had the following significant transactions: • issuance of $150.0 million of long-term debt ($60.0 million of Avista Corp. first mortgage bonds, $75.0 million of AEL&P first mortgage bonds and a $15.0 million AERC unsecured note representing a term loan), • a decrease of $66.0 million in short-term borrowings on Avista Corp.’s committed line of credit, • a decrease of $46.0 million on Ecova’s committed line of credit with $6.0 million in payments throughout the year and $40.0 million related to the close of the Ecova sale, • payment of $40.0 million for the redemption and maturity of long-term debt (primarily related to AEL&P paying off its existing debt), • cash payments of $54.2 million to noncontrolling interests and $20.9 million to stock option holders and redeemable noncontrolling interests of Ecova related to the Ecova sale in 2014, • issuance of $4.1 million of common stock (net of issuance costs) excluding issuances related to the acquisition of AERC. We issued $150.1 million of common stock to AERC shareholders, and this is reflected as a non-cash financing activity, • repurchase of $79.9 million of our common stock during 2014 using the proceeds from our sale of Ecova, and • a $16.2 million increase in cash related to the fluctuation in the balance of customer fund obligations at Ecova. 2014 Compared to 2013 Consolidated Operating Activities Net cash provided by operating activities was $267.3 million for 2014 compared to $242.6 million for 2013. Net cash used by the changes in certain current assets and liabilities components was $50.0 million for 2014, compared to net cash used of $48.2 million for 2013. The net cash used during 2014 primarily reflects cash outflows from changes in accounts payable, natural gas stored and income taxes receivable. These were partially offset by cash inflows from changes in other current liabilities (primarily related to accrued taxes and interest) and accounts receivable. The net cash used during 2013 primarily reflects cash outflows from changes in accounts receivable, accounts payable and other current assets (primarily related to miscellaneous current assets and income taxes receivable). These were partially offset by cash inflows from other current liabilities (primarily related to accrued taxes and interest). The gross gain on the sale of Ecova of $160.6 million for 2014 is deducted in reconciling net income to net cash provided by operating activities. The cash proceeds from the sale (which includes the gross gain) is included in investing activities. Net amortizations of power and natural gas costs were $14.8 million for 2014 compared to $9.4 million for 2013. The provision for deferred income taxes was $144.3 million for 2014 compared to $23.5 million for 2013. The increase for 2014 was primarily due to the combination of implementation by the Company of updated federal tax tangible property regulations and increased deductions related to bonus depreciation. Contributions to our defined benefit pension plan were $32.0 million for 2014 compared to $44.3 million in 2013. Collateral posted for derivative instruments increased by $23.3 million in 2014 compared to an increase of $16.1 million in 2013. We had cash collateral posted of $49.4 million as of December 31, 2014 and $26.1 million as of December 31, 2013. Net cash paid for income taxes was $45.4 million for 2014 compared to $44.8 million for 2013. Cash paid for interest was $73.5 million for 2014 compared to $75.4 million for 2013. Consolidated Investing Activities Net cash used in investing activities was $103.7 million for 2014, a decrease compared to $312.2 million for 2013. During 2014, we received cash proceeds (net of cash sold and escrow amounts) of $229.9 million related to the sale of Ecova. A portion of the proceeds from the Ecova sale was used to pay off the balance of Ecova’s long-term borrowings and make payments to option holders and noncontrolling interests (included in financing activities). We also used a portion of these proceeds to pay our $74.8 million tax liability associated with the gain on sale. Utility property capital expenditures increased by $31.2 million for 2014 as compared to 2013. A significant portion of Ecova’s funds held for clients were held as securities available for sale with purchases of $12.3 million and sales and maturities of $14.6 million in 2014. For 2013, Ecova had purchases of $35.9 million and sales and maturities of $23.0 million. The fluctuation in the balance of funds held for customers resulted in a decrease to cash of $18.9 million for 2014 as compared to an increase to cash of $1.8 million for 2013. We received $15.0 million in cash (net of cash paid) related to the acquisition of AERC during 2014. Staff_DR_063 Attachment B Page 70 of 160 AVISTA 50 Consolidated Financing Activities Net cash used in financing activities was $224.0 million for 2014 compared to net cash provided of $76.8 million for 2013. During 2014, short-term borrowings on Avista Corp.’s committed line of credit decreased $66.0 million. Net borrowings on Ecova’s committed line of credit decreased $46.0 million during the period with $6.0 million in payments throughout the year and $40.0 million related to the close of the Ecova sale. In September 2014, AEL&P issued $75.0 million of first mortgage bonds. In December 2014, Avista Corp. issued $60.0 million of first mortgage bonds and AERC issued a $15.0 million unsecured note representing a term loan. We cash settled interest rate swaps in conjunction with the pricing of the $60.0 million of Avista Corp. first mortgage bonds and received $5.4 million. The majority of the $40.0 million of retirements of long-term debt in 2014 relates to AEL&P paying off its existing debt. In connection with the closing of the Ecova sale, we made cash payments of $54.2 million to noncontrolling interests and $20.9 million to stock option holders and redeemable noncontrolling interests of Ecova. Cash dividends paid increased to $78.3 million (or $1.27 per share) for 2014 from $73.3 million (or $1.22 per share) for 2013. Excluding issuances related to the acquisition of AERC, we issued $4.1 million of common stock during 2014. We issued $150.1 million of common stock to AERC shareholders, and this is reflected as a non-cash financing activity. The fluctuation in the balance of customer fund obligations at Ecova increased cash by $16.2 million. During 2014, we repurchased $79.9 million of common stock. Cash inflows during 2013 were from a $119.0 million increase in short-term borrowings on Avista Corp.’s committed line of credit, the issuance of $90.0 million of long-term debt and the issuance of $4.6 million of common stock. We also cash settled interest rate swap agreements for $2.9 million related to the pricing of the $90.0 million of long-term debt. Cash outflows during 2013 were from the maturity of long-term debt of $50.5 million and a net decrease in borrowings on Ecova’s committed line of credit of $8.0 million (borrowings of $3.0 million and repayments of $11.0 million). CAPITAL RESOURCES Our consolidated capital structure, including the current portion of long-term debt and short-term borrowings, and excluding noncontrolling interests, consisted of the following as of December 31, 2015 and 2014 (dollars in thousands): December 31, 2015 December 31, 2014 Percent Percent Amount of Total Amount of Total Current portion of long-term debt and capital leases $ 93,167 2.9% $ 6,424 0.2% Current portion of nonrecourse long-term debt (Spokane Energy) — —% 1,431 0.1% Short-term borrowings 105,000 3.2% 105,000 3.4% Long-term debt to affiliated trusts 51,547 1.6% 51,547 1.6% Long-term debt and capital leases 1,480,111 45.4% 1,480,702 47.3% Total debt 1,729,825 53.1% 1,645,104 52.6% Total Avista Corporation shareholders’ equity 1,528,626 46.9% 1,483,671 47.4% Total $ 3,258,451 100.0% $ 3,128,775 100.0% Our shareholders’ equity increased $45.0 million during 2015 primarily due to net income, partially offset by the repurchase of common stock and dividends. We need to finance capital expenditures and acquire additional funds for operations from time to time. The cash requirements needed to service our indebtedness, both short-term and long-term, reduce the amount of cash flow available to fund capital expenditures, purchased power, fuel and natural gas costs, dividends and other requirements. See “Executive Level Summary” for a detailed discussion of the liquidity and capital resource transactions which occurred during 2015 and our anticipated needs for 2016. Balances outstanding and interest rates of borrowings (excluding letters of credit) under Avista Corp.’s committed line of credit were as follows as of and for the year ended December 31 (dollars in thousands): 2015 2014 2013 Balance outstanding at end of year $ 105,000 $ 105,000 $ 171,000 Letters of credit outstanding at end of year $ 44,595 $ 32,579 $ 27,434 Maximum balance outstanding during the year $ 180,000 $ 171,000 $ 171,000 Average balance outstanding during the year $ 95,573 $ 62,088 $ 27,580 Average interest rate during the year 0.98% 1.01% 1.14% Average interest rate at end of year 1.18% 0.93% 1.02% Staff_DR_063 Attachment B Page 71 of 160 51 AVISTA Any default on the line of credit or other financing arrangements of Avista Corp. or any of our “significant subsidiaries,” if any, could result in cross-defaults to other agreements of such entity, and/or to the line of credit or other financing arrangements of any other of such entities. Any defaults could also induce vendors and other counterparties to demand collateral. In the event of any such default, it would be difficult for us to obtain financing on reasonable terms to pay creditors or fund operations. We would also likely be prohibited from paying dividends on our common stock. Avista Corp. does not guarantee the indebtedness of any of its subsidiaries. As of December 31, 2015, Avista Corp. and its subsidiaries were in compliance with all of the covenants of their financing agreements, and none of Avista Corp.’s subsidiaries constituted a “significant subsidiary” as defined in Avista Corp.’s committed line of credit. We are restricted under our Restated Articles of Incorporation, as amended, as to the additional preferred stock we can issue. As of December 31, 2015, we could issue $1.3 billion of additional preferred stock at an assumed dividend rate of 6.3 percent. We are not planning to issue preferred stock. Under the Avista Corp. and the AEL&P Mortgages and Deeds of Trust securing Avista Corp.’s and AEL&P’s first mortgage bonds (including Secured Medium-Term Notes), respectively, each entity may issue additional first mortgage bonds in an aggregate principal amount equal to the sum of: • 662/3 percent of the cost or fair value (whichever is lower) of property additions at each entity which have not previously been made the basis of any application under the Mortgages, or • an equal principal amount of retired first mortgage bonds at each entity which have not previously been made the basis of any application under the Mortgages, or • deposit of cash. However, Avista Corp. and AEL&P may not individually issue any additional first mortgage bonds (with certain exceptions in the case of bonds issued on the basis of retired bonds) unless the particular entity issuing the bonds has “net earnings” (as defined in the Mortgages) for any period of 12 consecutive calendar months out of the preceding 18 calendar months that were at least twice the annual interest requirements on all mortgage securities at the time outstanding, including the first mortgage bonds to be issued, and on all indebtedness of prior rank. As of December 31, 2015, property additions and retired bonds would have allowed, and the net earnings test would not have prohibited, the issuance of $1.1 billion in aggregate principal amount of additional first mortgage bonds at Avista Corp. and $5.0 million at AEL&P. We believe that we have adequate capacity to issue first mortgage bonds to meet our financing needs over the next several years. CAPITAL EXPENDITURES Utility cash-basis capital expenditures were $1,013.3 million for the years 2013 through 2015 including $13.8 million at AEL&P for 2014 and 2015. The following table summarizes our expected future capital expenditures by year (in thousands): Avista Utilities AEL&P Expected total annual capital expenditures (by year) 2016 375,000 17,000 2017 405,000 13,000 2018 405,000 18,000 Most of the capital expenditures at Avista Utilities are for upgrading our existing facilities and technology, and not for construction of new facilities. A significant portion of the capital expenditures at AEL&P are for the construction of an additional back-up generation plant planned to be completed in 2016 and a new hydroelectric generation project in 2017 and 2018. The following graph shows the Avista Utilities’ capital budget for 2016: CAPITAL BUDGET AT AVISTA UTILITIES FOR 2016 (DOLLARS IN MILLIONS) Other Environmental Facilities Natural Gas Generation Customer Growth Information Technology Transmission & Distribution $131 $51$43 $52 $47 $20 $22 $9 These estimates of capital expenditures are subject to continuing review and adjustment. Actual capital expenditures may vary from our estimates due to factors such as changes in business conditions, construction schedules and environmental requirements. Staff_DR_063 Attachment B Page 72 of 160 AVISTA 52 OFF-BALANCE SHEET ARRANGEMENTS As of December 31, 2015, we had $44.6 million in letters of credit outstanding under our $400.0 million committed line of credit, compared to $32.6 million as of December 31, 2014. PENSION PLAN We contributed $12.0 million to the pension plan in 2015. We expect to contribute a total of $60.0 million to the pension plan in the period 2016 through 2020, with an annual contribution of $12.0 million over that period. The final determination of pension plan contributions for future periods is subject to multiple variables, most of which are beyond our control, including changes to the fair value of pension plan assets, changes in actuarial assumptions (in particular the discount rate used in determining the benefit obligation), or changes in federal legislation. We may change our pension plan contributions in the future depending on changes to any variables, including those listed above. See “Note 10 of the Notes to Consolidated Financial Statements” for additional information regarding the pension plan. CREDIT RATINGS Our access to capital markets and our cost of capital are directly affected by our credit ratings. In addition, many of our contracts for the purchase and sale of energy commodities contain terms dependent upon our credit ratings. See “Enterprise Risk Management—Demands for Collateral” and “Note 6 of the Notes to Consolidated Financial Statements.” The following table summarizes our credit ratings as of February 23, 2016: Standard & Poor’s (1) Moody’s (2) Corporate/Issuer rating BBB Baa1 Senior secured debt A- A2 Senior unsecured debt BBB Baa1 (1) Standard & Poor’s lowest “investment grade” credit rating is BBB-. (2) Moody’s lowest “investment grade” credit rating is Baa3. A security rating is not a recommendation to buy, sell or hold securities. Each security rating is subject to revision or withdrawal at any time by the assigning rating organization. Each security rating agency has its own methodology for assigning ratings, and, accordingly, each rating should be considered in the context of the applicable methodology, independent of all other ratings. The rating agencies provide ratings at the request of Avista Corp. and charge fees for their services. DIVIDENDS On February 5, 2016, Avista Corp.’s Board of Directors declared a quarterly dividend of $0.3425 per share on the Company’s common stock. This was an increase of $0.0125 per share, or 3.8 percent from the previous quarterly dividend of $0.3300 per share. See “Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities” for a detailed discussion of our dividend policy and the factors which could limit the payment of dividends. Staff_DR_063 Attachment B Page 73 of 160 53 AVISTA CONTRACTUAL OBLIGATIONS The following table provides a summary of our future contractual obligations as of December 31, 2015 (dollars in millions): 2016 2017 2018 2019 2020 Thereafter Avista Utilities: Long-term debt maturities $ 90 $ — $ 273 $ 90 $ 52 $ 949 Long-term debt to affiliated trusts — — — — — 52 Interest payments on long-term debt (1) 74 73 64 56 52 697 Short-term borrowings 105 — — — — — Energy purchase contracts (2) 341 233 215 202 150 1,266 Operating lease obligations (3) 2 1 1 — — 3 Other obligations (4) 34 31 26 31 32 192 Information technology contracts (5) 2 2 — — — — Pension plan funding (6) 12 12 12 12 12 — AERC (consolidated) total contractual commitments (7) 15 15 15 30 15 307 Avista Capital (consolidated) total contractual commitments (8) 2 1 1 1 1 — Total contractual obligations $ 677 $ 368 $ 607 $ 422 $ 314 $ 3,466 (1) Represents our estimate of interest payments on long-term debt, which is calculated based on the assumption that all debt is outstanding until maturity. Interest on variable rate debt is calculated using the rate in effect at December 31, 2015. (2) Energy purchase contracts were entered into as part of the obligation to serve our retail electric and natural gas customers’ energy requirements. As a result, costs are generally recovered either through base retail rates or adjustments to retail rates as part of the power and natural gas cost adjustment mechanisms. (3) Includes the interest component of the lease obligation. (4) Represents operational agreements, settlements and other contractual obligations for our generation, transmission and distribution facilities. These costs are generally recovered through base retail rates. (5) Includes information service contracts which are recorded to other operating expenses in the Consolidated Statements of Income. On March 30, 2015, Avista Corp. provided a cancellation notice, effective May 31, 2015, to one of its information technology service providers. New contracts were entered into to replace the cancelled contract. The replacement contracts result in similar amount of expense each year; however, this resulted in a significant decrease in future information technology contractual commitments because the new contracts do not have minimum committed spending in them and are primarily time and materials contracts. (6) Represents our estimated cash contributions to pension plans and other postretirement benefit plans through 2020. We cannot reasonably estimate pension plan contributions beyond 2020 at this time and have excluded them from the table above. (7) Primarily relates to long-term debt and capital lease maturities and the related interest. AERC contractual commitments also include contractually required capital project funding and operating and maintenance costs associated with the Snettisham hydroelectric project. These costs are generally recovered through base retail rates. (8) Primarily relates to operating lease commitments and a commitment to fund a limited liability company in exchange for equity ownership, made by a subsidiary of Avista Capital. The above contractual obligations do not include income tax payments. Also, asset retirement obligations are not included above and payments associated with these have historically been less than $1 million per year. There are approximately $16.0 million remaining asset retirement obligations as of December 31, 2015. In addition to the contractual obligations disclosed above, we will incur additional operating costs and capital expenditures in future periods for which we are not contractually obligated as part of our normal business operations. COMPETITION Our utility electric and natural gas distribution business has historically been recognized as a natural monopoly. In each regulatory jurisdiction, our rates for retail electric and natural gas services (other than specially negotiated retail rates for industrial or large commercial customers, which are subject to regulatory review and approval) are generally determined on a “cost of service” basis. Rates are designed to provide, after recovery of allowable operating expenses and capital investments, an opportunity for us to earn a reasonable return on investment as allowed by our regulators. In retail markets, we compete with various rural electric cooperatives and public utility districts in and adjacent to our service territories in the provision of service to new electric customers. Alternative energy technologies, including customer-sited solar, wind or geothermal generation, may also compete with us for sales to existing customers. While the risk is currently small in our service territory given the small numbers of customers utilizing these technologies, advances in power generation, energy efficiency and other alternative energy technologies could lead to more wide-spread usage of these technologies, thereby reducing customer demand for the energy supplied by us. This reduction in usage and demand would reduce our revenue and negatively impact our financial condition including possibly leading to our inability to fully recover our investments in generation, transmission and distribution assets. Similarly, our natural gas distribution operations compete with other energy sources including heating oil, propane and other fuels. Staff_DR_063 Attachment B Page 74 of 160 AVISTA 54 Certain natural gas customers could bypass our natural gas system, reducing both revenues and recovery of fixed costs. To reduce the potential for such bypass, we price natural gas services, including transportation contracts, competitively and have varying degrees of flexibility to price transportation and delivery rates by means of individual contracts. These individual contracts are subject to state regulatory review and approval. We have long-term transportation contracts with several of our largest industrial customers under which the customer acquires its own commodity while using our infrastructure for delivery. Such contracts reduce the risk of these customers bypassing our system in the foreseeable future and minimizes the impact on our earnings. Also, non-utility businesses are developing new technologies and services to help energy consumers manage energy in new ways that may improve productivity and could alter demand for the energy we sell. In wholesale markets, competition for available electric supply is influenced by the: • localized and system-wide demand for energy, • type, capacity, location and availability of generation resources, and • variety and circumstances of market participants. These wholesale markets are regulated by the FERC, which requires electric utilities to: • transmit power and energy to or for wholesale purchasers and sellers, • enlarge or construct additional transmission capacity for the purpose of providing these services, and • transparently price and offer transmission services without favor to any party, including the merchant functions of the utility. Participants in the wholesale energy markets include: • other utilities, • federal power marketing agencies, • energy marketing and trading companies, • independent power producers, • financial institutions, and • commodity brokers. ECONOMIC CONDITIONS AND UTILITY LOAD GROWTH The general economic data, on both national and local levels, contained in this section is based, in part, on independent government and industry publications, reports by market research firms or other independent sources. While we believe that these publications and other sources are reliable, we have not independently verified such data and can make no representation as to its accuracy. We track multiple economic indicators affecting three distinct metropolitan statistical areas in our Avista Utilities service area: Spokane, Washington, Coeur d’Alene, Idaho, and Medford, Oregon. Several key indicators are employment change, unemployment rates and foreclosure rates. On a year-over-year basis, December 2015 showed positive job growth, and lower unemployment rates in all three metropolitan areas. However, the unemployment rates in Spokane and Medford are still above the national average. Except for Medford, foreclosure rates are in line with or below the U.S rate in all areas, and key leading indicators, initial unemployment claims and residential building permits, continue to signal modest growth over the next 12 months. Therefore, in 2016, we expect economic growth in our service area to be somewhat stronger than the U.S. as a whole. Nonfarm employment (non-seasonally adjusted) in our eastern Washington, northern Idaho, and southwestern Oregon metropolitan service areas exhibited moderate growth between December 2014 and December 2015. In Spokane, Washington employment growth was 2.5 percent with gains in all major sectors except leisure and hospitality. Employment increased by 4.4 percent in Coeur d’Alene, Idaho, reflecting gains in all major sectors except information and leisure and hospitality. In Medford, Oregon, employment growth was 3.3 percent, with gains in all major sectors except construction. U.S. nonfarm sector jobs grew by 1.9 percent in the same 12-month period. Seasonally adjusted unemployment rates went down in December 2015 from the year earlier in Spokane, Coeur d’Alene, and Medford. In Spokane the rate was 7.7 percent in December 2014 and declined to 6.3 percent in December 2015; in Coeur d’Alene the rate went from 5.1 percent to 4.7 percent; and in Medford the rate declined from 8.2 percent to 6.5 percent. The U.S. rate declined from 5.6 percent to 5.0 percent in the same period. Except for the Medford area, the housing market in our Avista Utilities service area continues to experience foreclosure rates in line with the national average. The December 2015 national rate was 0.08 percent, compared to 0.08 percent in Spokane County, Washington; 0.04 percent in Kootenai County (Coeur d’Alene), Idaho; and 0.1 percent in Jackson County (Medford), Oregon. Our AEL&P service area is centered in Juneau. Although Juneau is Alaska’s state capital, it is not a metropolitan statistical area. This means breadth and frequency of economic data is more limited. Therefore, the dates of Juneau’s economic data may significantly lag the period of this filing. The Quarterly Census of Employment and Wages for Juneau shows employment increased 0.5 percent between second quarter 2014 and second quarter 2015. The modest growth in employment was largely due to gains in construction; manufacturing; trade, transportation, and utilities; information; professional and business services; and leisure and hospitality, mostly offset by a contraction in government employment, which is Juneau’s largest single sector. Government (including active duty military personnel) accounts for approximately 37 percent of total employment. Employment declines also occurred in natural resources and mining; financial activities; education and health services; and other services. Between December 2014 and December 2015 the non-seasonally adjusted unemployment rate decreased from 5.0 percent to 4.7 percent. The Juneau foreclosure rate is below the U.S. rate. The December 2015 rate was 0.02 percent compared to 0.08 percent for the U.S. Based on our forecast for 2016 through 2019 for Avista Utilities’ service area, we expect annual electric customer growth to average 1.0 percent, within a forecast range of 0.6 percent to 1.4 percent. We expect annual natural gas customer growth to average 1.1 percent, within a forecast range of 0.6 percent to 1.6 percent. We anticipate retail electric load growth to average 0.7 percent, within a forecast range of 0.4 percent and 1.0 percent. We expect natural gas load growth to average 1.1 percent, within a forecast range of 0.6 percent and 1.6 percent. The forecast ranges reflect (1) the inherent uncertainty associated with the economic assumptions on which forecasts are based and (2) natural gas customer and load growth has been historically volatile. Staff_DR_063 Attachment B Page 75 of 160 55 AVISTA In AEL&P’s service area, we expect annual residential customer growth to be in a narrow range around 0.4 percent for 2016 through 2019. We expect no significant growth in commercial and government customers over the same period. We anticipate that average annual total load growth will be in a narrow range around 0.6 percent, with residential load growth averaging 0.6 percent; commercial 0.8 percent; and government 0 percent (no load growth). The forward-looking statements set forth above regarding retail load growth are based, in part, upon purchased economic forecasts and publicly available population and demographic studies. The expectations regarding retail load growth are also based upon various assumptions, including: • assumptions relating to weather and economic and competitive conditions, • internal analysis of company-specific data, such as energy consumption patterns, • internal business plans, • an assumption that we will incur no material loss of retail customers due to self-generation or retail wheeling, and • an assumption that demand for electricity and natural gas as a fuel for mobility will for now be immaterial. Changes in actual experience can vary significantly from our projections. ENVIRONMENTAL ISSUES AND CONTINGENCIES We are subject to environmental regulation by federal, state and local authorities. The generation, transmission, distribution, service and storage facilities in which we have ownership interests are designed and operated in compliance with applicable environmental laws. Furthermore, we conduct periodic reviews and audits of pertinent facilities and operations to ensure compliance and to respond to or anticipate emerging environmental issues. The Company’s Board of Directors has established a committee to oversee environmental issues. We monitor legislative and regulatory developments at all levels of government for environmental issues, particularly those with the potential to impact the operation and productivity of our generating plants and other assets. Environmental laws and regulations may: • increase the operating costs of generating plants; • increase the lead time and capital costs for the construction of new generating plants; • require modification of our existing generating plants; • require existing generating plant operations to be curtailed or shut down; • reduce the amount of energy available from our generating plants; • restrict the types of generating plants that can be built or contracted with; and • require construction of specific types of generation plants at higher cost. Compliance with environmental laws and regulations could result in increases to capital expenditures and operating expenses. We intend to seek recovery of any such costs through the ratemaking process. Clean Air Act We must comply with the requirements under the Clean Air Act (CAA) in operating our thermal generating plants. The CAA currently requires a Title V operating permit for Colstrip (expires in 2017), Coyote Springs 2 (expires in 2018), the Kettle Falls GS (application has been made for a new permit), and the Rathdrum CT (application has been made for a new permit). Boulder Park GS, Northeast CT, and other activities only require minor source operating or registration permits based on their limited operation and emissions. The Title V operating permits are renewed every five years and updated to include newly applicable CAA requirements. We actively monitor legislative, regulatory and program developments within the CAA that may impact our facilities. On March 6, 2013, the Sierra Club and Montana Environmental Information Center, filed a Complaint (Complaint) in the United States District Court for the District of Montana, Billings Division, against the owners of Colstrip. The Complaint alleges certain violations of the CAA. See “Sierra Club and Montana Environmental Information Center Complaint Against the Owners of Colstrip” in “Note 19 of the Notes to Consolidated Financial Statements” for further information on this matter. Hazardous Air Pollutants (HAPs) The EPA regulates hazardous air pollutants from a published list of industrial sources referred to as “source categories” which must meet control technology requirements if they emit one or more of the pollutants in significant quantities. In 2012, the EPA finalized the Mercury Air Toxic Standards (MATS) for the coal and oil-fired source category. At the time of issuance in 2012, we examined the existing emission control systems of Colstrip Units 3 & 4, the only units in which we are a minority owner, and concluded that the existing emission control systems should be sufficient to meet mercury limits. For the remaining portion of the rule that utilized Particulate Matter as a surrogate for air toxics (including metals and acid gases), the Colstrip owners reviewed recent stack testing data and expected that no additional emission control systems would be needed for Units 3 & 4 MATS compliance. On June 29, 2015, the Supreme Court held that the EPA’s interpretation of MATS was unreasonable when it deemed cost irrelevant for MATS regulation. The EPA’s interpretation of MATS has been reversed and remanded. Regional Haze Program The EPA set a national goal of eliminating man-made visibility degradation in Class I areas by the year 2064. States are expected to take actions to make “reasonable progress” through 10-year plans, including application of Best Available Retrofit Technology (BART) requirements. BART is a retrofit program applied to large emission sources, including electric generating units built between 1962 and 1977. In the case where a State opts out of implementing the Regional Haze program, the EPA may act directly. On September 18, 2012, the EPA finalized the Regional Haze federal implementation plan (FIP) for Montana. The FIP includes both emission limitations and pollution controls for Colstrip Units 1 & 2. Colstrip Units 3 & 4, the only units of which we are a minority owner, are not currently affected, but will be evaluated for Reasonable Progress at the next review period in September 2017. We do not anticipate any material impacts on Units 3 & 4 at this time. Staff_DR_063 Attachment B Page 76 of 160 AVISTA 56 Coal Ash Management/Disposal On April 17, 2015, the EPA published a final rule regarding coal combustion residuals (CCRs), also termed coal combustion byproducts or coal ash in the Federal Register, and this rule became effective on October 15, 2015. Colstrip, of which we are a 15 percent owner of Units 3 & 4, produces this byproduct. The rule establishes technical requirements for CCR landfills and surface impoundments under Subtitle D of the Resource Conservation and Recovery Act, the nation’s primary law for regulating solid waste. We, in conjunction with the other owners, are developing a multi-year compliance plan to strategically address the new CCR requirements and existing state obligations while maintaining operational stability. During the second quarter of 2015, the operator of Colstrip provided an initial cost estimate of the expected retirement costs associated with complying with the new CCR rule and this estimate was subsequently updated during the fourth quarter of 2015. Based on the initial assessments, Avista Corp. recorded an increase to its asset retirement obligations of $12.5 million with a corresponding increase in the cost basis of the utility plant. In addition to an increase to our ARO, there are expected to be significant compliance costs at Colstrip in the future, both operating and capital costs, due to a series of incremental infrastructure improvements which are separate from any retirement obligations. Due to the preliminary nature of available data, we cannot reasonably estimate the future compliance costs; however, we will update our ARO and compliance cost estimates when data becomes available. The actual asset retirement costs and future compliance costs related to the CCR Rule requirements may vary substantially from the estimates used to record the increased obligation due to uncertainty about the compliance strategies that will be used and the preliminary nature of available data used to estimate costs, such as the quantity of coal ash present at certain sites and the volume of fill that will be needed to cap and cover certain impoundments. We will coordinate with the plant operators and continue to gather additional data in future periods to make decisions about compliance strategies and the timing of closure activities. As additional information becomes available, we will update the ARO and future nonretirement compliance costs for these changes in estimates, which could be material. We expect to seek recovery of any increased costs related to complying with the new rule through customer rates. Climate Change Concerns about long-term global climate changes could have a significant effect on our business. Our operations could also be affected by changes in laws and regulations intended to mitigate the risk of or alter global climate changes, including restrictions on the operation of our power generation resources and obligations imposed on the sale of natural gas. Changing temperatures and precipitation, including snowpack conditions, affect the availability and timing of streamflows, which impact hydroelectric generation. Extreme weather events could increase service interruptions, outages and maintenance costs. Changing temperatures could also increase or decrease customer demand. Our Climate Policy Council (an interdisciplinary team of management and other employees): • facilitates internal and external communications regarding climate change issues, • analyzes policy effects, anticipates opportunities and evaluates strategies for Avista Corp., and • develops recommendations on climate related policy positions and action plans. Climate Change—Federal Regulatory Actions The EPA released the final rules for the Clean Power Plan (Final CPP) and the Carbon Pollution Standards (Final CPS) on August 3, 2015. The Final CPP and the Final CPS are both intended to reduce the carbon dioxide (CO2) emissions from certain coal-fired and natural gas electric generating units (EGUs). These rules were published in the Federal Register on October 23, 2015 and were immediately challenged via lawsuits by other parties. The Final CPP was promulgated pursuant to Section 111(d) of the CAA and applies to CO2 emissions from existing EGUs. The Final CPP is intended to reduce national CO2 emissions by approximately 32 percent below 2005 levels by 2030. The Final CPS rule was issued pursuant to Section 111(b) of the CAA and applies to the emissions of new, modified and reconstructed EGUs. The two rules are the first rules ever adopted by the U.S. federal government to comprehensively control and reduce CO2 emissions from the power sector. The EPA also issued a proposed Federal Implementation Plan (Proposed FIP) for the Final CPP. The Final FIP that the EPA adopts could be imposed on states by the EPA, should a state decide not to develop its own plan. The Final CPP establishes individual state emission reduction goals based upon the assumed potential for (1) heat rate improvements at coal-fired units, (2) increased utilization of natural gas-fired combined cycle plants, and (3) increased utilization of low or zero carbon emitting generation resources. As expressed in the final rule, states have until September 2016 to submit state compliance plans, with a potential for two-year extensions. Avista Corp. owns two EGUs that are subject to the Final CPP: its portion (15 percent of Units 3 & 4) of Colstrip in Montana and Coyote Springs 2 in Oregon. States may adopt rate-based or mass-based plans, and may choose to focus compliance on specific EGUs or adopt broader measures to reduce carbon emissions from this sector. The states in which Avista Utilities generates or delivers electricity, Washington, Idaho, Montana and Oregon, are all evaluating options for developing state plans, which will define compliance approaches and obligations. Alaska was exempted in the Final CPP. The EPA may consider rulemaking for Alaska and Hawaii, both states which lack regional grid connections, in the future. In a separate but related rulemaking, the EPA finalized CO2 new source performance standards (NSPS) for new, modified and reconstructed fossil fuel-fired EGUs under CAA section 111(b). These EGUs fall into the same two categories of sources regulated by the Final CPP: steam generating units (also known as “utility boilers and IGCC units”), which primarily burn coal, and stationary combustion turbines, which primarily burn natural gas. GHG emission standards could result in significant compliance costs. Such standards could also preclude us from developing, operating or contracting with certain types of generating plants. Additionally, the Climate Action Plan requirements related to preparing the U.S. for the impacts of climate change could affect us and others in the industry as transmission system modifications to improve resiliency Staff_DR_063 Attachment B Page 77 of 160 57 AVISTA may be needed in order to meet those requirements. The promulgated and proposed GHG rulemakings mentioned above have been legally challenged in multiple venues. On February 9, 2016, the U.S. Supreme Court granted a request for stay, halting implementation of the CPP. Given this development and the ongoing legal challenges, we cannot fully predict the outcome or estimate the extent to which our facilities may be impacted by these regulations at this time. We intend to seek recovery of any costs related to compliance with these requirements through the ratemaking process. Climate Change—State Legislation and State Regulatory Activities The states of Washington and Oregon have adopted non-binding targets to reduce GHG emissions. Both states enacted their targets with an expectation of reaching the targets through a combination of renewable energy standards, and assorted “complementary policies,” but no specific reductions are mandated. Washington and Oregon apply a GHG emissions performance standard (EPS) to electric generation facilities used to serve retail loads in their jurisdictions. The EPS prevents utilities from constructing or purchasing generation facilities, or entering into power purchase agreements of five years or longer duration, to purchase energy produced by plants that have emission levels higher than 1,100 pounds of GHG per MWh. The Washington State Department of Commerce (Commerce) initiated a process to adopt a lower emissions performance standard in 2012, any new standard will be applicable until at least 2017. Commerce published a supplemental notice of proposed rulemaking on January 16, 2013 with a new EPS of 970 pounds of GHG per MWh. We will engage in the next process to revise the EPS, which should occur in 2017. The Energy Independence Act (EIA) in Washington requires electric utilities with over 25,000 customers to acquire qualified renewable energy resources and/or renewable energy credits equal to 15 percent of the utility’s total retail load in 2020. I-937 also requires these utilities to meet biennial energy conservation targets beginning in 2012. The renewable energy standard increases from three percent in 2012 to nine percent in 2016. Failure to comply with renewable energy and efficiency standards could result in penalties of $50 per MWh or greater assessed against a utility for each MWh it is deficient in meeting a standard. We have met, and will continue to meet, the requirements of EIA through a variety of renewable energy generating means, including, but not limited to, some combination of hydro upgrades, wind and biomass. In 2012, EIA was amended in such a way that our Kettle Falls GS and certain other biomass energy facilities, which commenced operation before March 31, 1999, are considered resources that may be used to meet the renewable energy standards beginning in 2016. The Washington State Department of Ecology (Ecology) has commenced rulemaking, using its existing authorities, to cap and reduce carbon emissions across the State of Washington in pursuit of the State’s carbon goals, which were enacted in 2008 by the Washington State Legislature (Legislature). The rule applies to sources of annual greenhouse emissions in excess of 100,000 tons for the first compliance period of 2017 through 2019; this threshold incrementally decreases to 70,000 metric tons beginning in 2035. The rule affects stationary sources and transportation fuel suppliers, as well as natural gas distribution companies. Ecology has identified approximately 30 entities responsible for 60 percent of the state’s emission sources that would be regulated under the proposed rule. The proposed rule would only apply to Avista Corp. as a natural gas distribution company, for the emissions associated with the use of the gas we provide our customers. The Governor of Washington ordered Ecology to finalize the rule by June 2016. An Initiative to the Legislature (I-732), which would impose a carbon tax on fossil-fueled generation and natural gas distribution, as well as on transportation fuels, has qualified for submittal to the Legislature. The Legislature may enact the measure into law, pass an alternative, in which case the original initiative and the alternative will be referred to the voters in November, or allow the measure to go onto the ballot in its original form. In addition, a coalition of environmental and labor groups in Washington announced its intent to file an initiative at the start of 2016 that would apply cap and trade regulation to sources of greenhouse gas emissions, with proceeds from the State’s sale of compliance instruments (allowances) dedicated to clean-energy investments and other government programs. If filed and if it gains sufficient signatures, this initiative would go on the general ballot in 2016. While we cannot predict the eventual outcome of actions arising out of initiatives, proposed legislation and regulatory actions at this time nor estimate the effect thereof, we will continue to seek recovery, through the ratemaking process, of all operating and capitalized costs related to our utility operations. On February 6, 2014, the UTC issued a letter finding that Puget Sound Energy’s (PSE’s) 2013 Electric Integrated Resource Plan meets the requirements of the Revised Code of Washington and the Washington Administrative Code. In its letter, however, the UTC expressed concern regarding the continued operation of the Colstrip plant as a resource to serve retail customers. Although the UTC recognized that the results of the analyses presented by PSE “differed significantly between [Colstrip] Units 1 & 2 and Units 3 & 4,” the UTC did not limit its concerns solely to Colstrip Units 1 & 2. The UTC recommended that PSE “consult with UTC staff to consider a Colstrip Proceeding to determine the prudency of any new investment in Colstrip before it is made or, in the alternative, a closure or partial-closure plan.” As a 15 percent owner of Colstrip Units 3 & 4, we cannot estimate the effect of such proceeding, should it occur, on the future ownership and operation of our share of Colstrip Units 3 & 4. Our remaining investment in Colstrip Units 3 & 4 as of December 31, 2015 was $118.8 million. In Oregon, legislation has been introduced which would require Portland General Electric and Pacificorp to remove coal-fired generation from their rate-base by 2030. Because these two utilities, along with Avista Utilities, hold minority interests in Colstrip, the legislation could indirectly impact Avista Utilities, though specific impacts cannot be identified at this time. While the legislation requires the two utilities to eliminate Colstrip from their rates, they would be permitted to sell the output of their shares of Colstrip into the wholesale market or, as is the case with Pacificorp, reallocate the plant to other states. We cannot predict the eventual outcome of actions arising from this legislation at this time or estimate the effect thereof; however, we will continue to seek recovery, through the ratemaking process, of all operating and capitalized costs related to our generation assets. Threatened and Endangered Species and Wildlife A number of species of fish in the Northwest are listed as threatened or endangered under the Federal Endangered Species Act (ESA). Efforts to protect these and other species have not significantly impacted generation levels at any of our hydroelectric facilities. We are implementing fish protection measures at our hydroelectric project on the Clark Fork River under a 45-year FERC operating license for Cabinet Staff_DR_063 Attachment B Page 78 of 160 AVISTA 58 Gorge and Noxon Rapids (issued March 2001) that incorporates a comprehensive settlement agreement. The restoration of native salmonid fish, including bull trout, is a key part of the agreement. The result is a collaborative native salmonid restoration program with the U.S. Fish and Wildlife Service, Native American tribes and the states of Idaho and Montana on the lower Clark Fork River, consistent with requirements of the FERC license. The U.S. Fish & Wildlife Service issued an updated Critical Habitat Designation for bull trout in 2010 that includes the lower Clark Fork River, as well as portions of the Coeur d’Alene basin within our Spokane River Project area, and issued a final Bull Trout Recovery Plan under the ESA. Issues related to these activities are expected to be resolved through the ongoing collaborative effort of our Clark Fork and Spokane River FERC licenses. See “Fish Passage at Cabinet Gorge and Noxon Rapids” in “Note 19 of the Notes to Consolidated Financial Statements” for further information. Various statutory authorities, including the Migratory Bird Treaty Act, have established penalties for the unauthorized take of migratory birds. Because we operate facilities that can pose risks to a variety of such birds, we have developed and follow an avian protection plan. Other For other environmental issues and other contingencies see “Note 19 of the Notes to Consolidated Financial Statements.” ENTERPRISE RISK MANAGEMENT The material risks to our businesses are discussed in “Item 1A. Risk Factors,” “Forward-Looking Statements,” as well as “Environmental Issues and Contingencies.” The following discussion focuses on our mitigation processes and procedures to address these risks. We consider the management of these risks an integral part of managing our core businesses and a key element of our approach to corporate governance. Risk management includes identifying and measuring various forms of risk that may affect the Company. We have an enterprise risk management process for managing risks throughout our organization. Our Board of Directors and its Committees take an active role in the oversight of risk affecting the Company. Our risk management department facilitates the collection of risk information across the Company, providing senior management with a consolidated view of the Company’s major risks and risk mitigation measures. Each area identifies risks and implements the related mitigation measures. The enterprise risk process supports management in identifying, assessing, quantifying, managing and mitigating the risks. Despite all risk mitigation measures, however, risks are not eliminated. Our primary identified categories of risk exposure are: • Financial • Utility regulatory • Energy commodity • Operational • Compliance • Technology • Strategic • External Mandates Financial Risk Financial risk is any risk that could have a direct material impact on the financial performance or financial viability of the Company. Broadly, financial risks involve variation of earnings and liquidity. Underlying risks include, but are not limited to, those described in “Item 1A. Risk Factors.” We mitigate financial risk in a variety of ways including through oversight from the Finance Committee of our Board of Directors and from senior management. Our Regulatory department is also critical in risk mitigation as they have regular communications with state commission regulators and staff and they monitor and develop rate strategies for the Company. Rate strategies, such as decoupling, help mitigate the impacts of revenue fluctuations due to weather, conservation or the economy. We also have a Treasury department that monitors our daily cash position and future cash flow needs, as well as monitoring market conditions to determine the appropriate course of action for capital financing and/or hedging strategies. Weather Risk To partially mitigate the risk of financial underperformance due to weather-related factors, we developed decoupling rate mechanisms that were approved by the Washington and Idaho commissions. Decoupling mechanisms are designed to break the link between a utility’s revenues and consumers’ energy usage and instead provide revenue based on the number of customers, thus mitigating a large portion of the risk associated with lower customer loads. See “Regulatory Matters” for further discussion of our decoupling mechanisms. Access to Capital Markets Our capital requirements rely to a significant degree on regular access to capital markets. We actively engage with rating agencies, banks, investors and state public utility commissions to understand and address the factors that support access to capital markets on reasonable terms. We manage our capital structure to maintain a financial risk profile that these parties will deem prudent. We forecast cash requirements to determine liquidity needs, including sources and variability of cash flows that may arise from our spending plans or from external forces, such as changes in energy prices or interest rates. Our financial and operating forecasts consider various metrics that affect credit ratings. Our regulatory strategies include working with state public utility commissions and filing for rate changes as appropriate to meet financial performance expectations. Interest Rate Risk Uncertainty about future interest rates causes risk related to a portion of our existing debt, our future borrowing requirements, and our pension and other postretirement benefit obligations. We manage debt interest rate exposure by limiting our variable rate debt to a percentage of total capitalization of the Company. We hedge a portion of our interest rate risk on forecasted debt issuances with financial derivative instruments, which may include interest rate swaps and U.S. Treasury lock agreements. The Finance Committee of our Board of Directors periodically reviews and discusses interest rate risk management processes and the steps management has undertaken to control interest rate risk. Our Risk Management Committee, which is comprised of certain officers and other management personnel, also reviews our interest rate risk management plan. Additionally, interest rate risk is Staff_DR_063 Attachment B Page 79 of 160 59 AVISTA managed by monitoring market conditions when timing the issuance of long-term debt and optional debt redemptions and establishing fixed rate long-term debt with varying maturities. Our interest rate swap agreements are considered economic hedges against fluctuations in future cash flows associated with anticipated debt issuances. Interest rates on our long-term debt are generally set based on underlying U.S. Treasury rates plus credit spreads, which are based on our credit ratings and prevailing market prices for debt. The swap agreements hedge against changes in the U.S. Treasury rates but do not hedge the credit spread. Even though we work to manage our exposure to interest rate risk by locking in certain long-term interest rates through interest rate swap agreements, if market interest rates decrease below the interest rates we have locked in, this will result in a liability related to our interest rate swap agreements, which can be significant. However, through our regulatory accounting practices similar to our energy commodity derivatives, any interim mark-to-market gains or losses are offset by regulatory assets and liabilities. Upon settlement of interest rate swaps, the regulatory asset or liability (included as part of long-term debt) is amortized as a component of interest expense over the term of the associated debt. The following table summarizes our interest rate swap agreements outstanding as of December 31, 2015 and December 31, 2014 (dollars in thousands): December 31, December 31, 2015 2014 Number of agreements 23 22 Notional amount $ 455,000 $ 420,000 Mandatory cash settlement dates 2016 to 2022 2015 to 2018 Short-term derivative assets (1) $ — $ 460 Long-term derivative assets (1) 23 — Short-term derivative liability (1) (19,264) (7,325) Long-term derivative liability (1) (2) (30,679) (40,857) (1) There are offsetting regulatory assets and liabilities for these items on the Consolidated Balance Sheets in accordance with regulatory accounting practices. (2) The balance as of December 31, 2015 and December 31, 2014 reflects the offsetting of $34.0 million and $28.9 million, respectively of cash collateral against the net derivative positions where a legal right of offset exists. In anticipation of issuing long-term debt in future years, we entered into three interest rate swap agreements in January 2016, hedging an aggregate notional amount of $30.0 million with mandatory cash settlement dates in 2018 and 2022. The following table shows our outstanding interest rate swaps as of February 23, 2016 (dollars in thousands): Mandatory Cash Number of Notional Settlement As of Date Contracts Amount Date February 23, 2016 6 115,000 2016 4 55,000 2017 13 265,000 2018 3 40,000 2019 4 50,000 2022 We estimate that a 10-basis-point increase in forward LIBOR interest rates as of December 31, 2015 would decrease the interest rate swap derivative net liability by $9.8 million, while a 10-basis- point decrease would increase the interest rate swap net liability by $10.1 million. We estimated that a 10-basis-point increase in forward LIBOR interest rates as of December 31, 2014 would have decreased the interest rate swap derivative net liability by $9.0 million, while a 10-basis-point decrease would increase the interest rate swap net liability by $9.3 million. The interest rate on $51.5 million of long-term debt to affiliated trusts is adjusted quarterly, reflecting current market rates. Amounts borrowed under our committed line of credit agreements have variable interest rates. Historically, during years where we have long-term debt that is maturing, we have to issue long-term debt to replace the maturing debt. To hedge our interest rate risk associated with these expected long-term debt issuances, we enter into interest rate swap agreements (discussed above). The following table shows our long-term debt (including current portion) and related weighted-average interest rates, by expected maturity dates as of December 31, 2015 (dollars in thousands): 2016 2017 2018 2019 2020 Thereafter Total Fair Value Fixed rate long-term debt (1) $ 90,000 $ — $ 272,500 $ 105,000 $ 52,000 $ 1,023,500 $ 1,543,000 $ 1,650,815 Weighted-average interest rate 0.84% — 6.07% 5.22% 3.89% 5.15% 5.02% Variable rate long-term debt to affiliated trusts — — — — — $ 51,547 $ 51,547 $ 36,083 Weighted-average interest rate — — — — — 1.29% 1.29% (1) These balances include the fixed rate long-term debt of Avista Corp., AEL&P and AERC. Staff_DR_063 Attachment B Page 80 of 160 AVISTA 60 Our pension plan is exposed to interest rate risk because the value of pension obligations and other postretirement obligations vary directly with changes in the discount rates, which are derived from end-of-year market interest rates. In addition, the value of pension investments and potential income on pension investments is partially affected by interest rates because a significant portion of pension investments are in fixed income securities. The Finance Committee of the Board of Directors approves investment policies, objectives and strategies that seek an appropriate return for the pension plan and it reviews and approves changes to the investment and funding policies. We manage interest rate risk associated with our pension and other postretirement benefit plans by investing a targeted amount of pension plan assets in fixed income investments that have maturities with similar profiles to future projected benefit obligations. We have implemented a liability-driven investment process for the pension plan with the objective of enhancing the match between changes in pension investments and changes in pension obligations and reducing volatility of annual pension expense arising from changes in interest rates. Credit Risk Counterparty non-performance risk relates to potential losses that we would incur as a result of non-performance of contractual obligations by counterparties to deliver energy or make financial settlements. Changes in market prices may dramatically alter the size of credit risk with counterparties, even when we establish conservative credit limits. Should a counterparty fail to perform, we may be required to honor the underlying commitment or to replace existing contracts with contracts at then-current market prices. We enter into bilateral transactions with various counterparties. We also trade energy and related derivative instruments through clearinghouse exchanges. We seek to mitigate credit risk by: • transacting through clearinghouse exchanges, • entering into bilateral contracts that specify credit terms and protections against default, • applying credit limits and duration criteria to existing and prospective counterparties, • actively monitoring current credit exposures, • asserting our collateral rights with counterparties, and • carrying out transaction settlements timely and effectively. The extent of transactions conducted through exchanges has increased as many market participants have shown a preference toward exchange trading and have reduced bilateral transactions. We actively monitor the collateral required by such exchanges to effectively manage our capital requirements. To address the impact on our operations of energy market price volatility, our hedging practices for electricity (including fuel for generation) and natural gas extend beyond the current operating year. Executing this extended hedging program may increase credit risk and demands for collateral. Our credit risk management process is designed to mitigate such credit risks through limit setting, contract protections and counterparty diversification, among other practices. Credit risk affects demands on our capital. We are subject to limits and credit terms that counterparties may assert to allow us to enter into transactions with them and maintain acceptable credit exposures. Many of our counterparties allow unsecured credit at limits prescribed by agreements or their discretion. Capital requirements for certain transaction types involve a combination of initial margin and market value margins without any unsecured credit threshold. Counterparties may seek assurances of performance from us in the form of letters of credit, prepayment or cash deposits. Credit exposure can change significantly in periods of commodity price and interest rate volatility. As a result, sudden and significant demands may be made against our credit facilities and cash. We actively monitor the exposure to possible collateral calls and take steps to minimize capital requirements. Counterparties’ credit exposure to us is dynamic in normal markets and may change significantly in more volatile markets. The amount of potential default risk to us from each counterparty depends on the extent of forward contracts, unsettled transactions, interest rates and market prices. There is a risk that we do not obtain sufficient additional collateral from counterparties that are unable or unwilling to provide it. As of December 31, 2015, we had cash deposited as collateral of $28.7 million and letters of credit of $28.2 million outstanding related to our energy derivative contracts. Price movements and/or a downgrade in our credit ratings could impact further the amount of collateral required. See “Credit Ratings” for further information. For example, in addition to limiting our ability to conduct transactions, if our credit ratings were lowered to below “investment grade” based on our positions outstanding at December 31, 2015, we would potentially be required to post additional collateral of up to $9.0 million. This amount is different from the amount disclosed in “Note 6 of the Notes to Consolidated Financial Statements” because, while this analysis includes contracts that are not considered derivatives in addition to the contracts considered in Note 6, this analysis also takes into account contractual threshold limits that are not considered in Note 6. Without contractual threshold limits, we would potentially be required to post additional collateral of $18.4 million. Under the terms of interest rate swap agreements that we enter into periodically, we may be required to post cash or letters of credit as collateral depending on fluctuations in the fair value of the instrument. As of December 31, 2015, we had interest rate swap agreements outstanding with a notional amount totaling $455.0 million and we had deposited cash in the amount of $34.0 million and letters of credit of $9.6 million as collateral for these interest rate swap derivative contracts. If our credit ratings were lowered to below “investment grade” based on our interest rate swap agreements outstanding at December 31, 2015, we would have to post $18.8 million of additional collateral. Foreign Currency Risk A significant portion of our utility natural gas supply (including fuel for electric generation) is obtained from Canadian sources. Most of those transactions are executed in U.S. dollars, which avoids foreign currency risk. A portion of our short-term natural gas transactions and long-term Canadian transportation contracts are committed based on Canadian currency prices. The short-term natural gas transactions are typically settled within sixty days with U.S. dollars. We economically hedge a portion of the foreign currency risk by purchasing Canadian currency exchange contracts when such commodity transactions are initiated. This risk has not had a material effect on our financial condition, results of operations or cash flows and these differences in cost related to currency fluctuations are included with natural gas supply costs for ratemaking. Staff_DR_063 Attachment B Page 81 of 160 61 AVISTA Further information for derivatives and fair values is disclosed at “Note 6 of the Notes to Consolidated Financial Statements” and “Note 16 of the Notes to Consolidated Financial Statements.” Utility Regulatory Risk Because we are primarily a regulated utility, we face the risk that regulators may not grant rates that provide timely or sufficient recovery of our costs or allow a reasonable rate of return for our shareholders. This includes costs associated with our investment in rate base, as well as commodity costs and other operating and financing expenses. We mitigate regulatory risk through oversight from our Board of Directors and from senior management. We have a separate regulatory group which communicates with commission regulators and staff regarding the Company’s business plans and concerns. The regulatory group also considers the regulator’s priorities and rate policies and makes recommendations to senior management on regulatory strategy for the Company. See “Regulatory Matters” for further discussion of regulatory matters affecting our Company. Energy Commodity Risk Energy commodity risks are associated with fulfilling our obligation to serve customers, managing variability of energy facilities, rights and obligations and fulfilling the terms of our energy commodity agreements with counterparties. These risks include, among other things, those described in “Item 1A. Risk Factors.” We mitigate energy commodity risk primarily through our energy resources risk policy, which includes oversight from the Risk Management Committee, which is comprised of certain officers and other management and oversight from the Audit Committee and the Environmental, Technology and Operations Committee of our Board of Directors. In conjunction with the oversight committees, our management team develops hedging strategies, detailed resource procurement plans, resource optimization strategies and long-term integrated resource planning to mitigate some of the risk associated with energy commodities. The various plans and strategies are monitored daily and developed with quantitative methods. Our energy resources risk policy, which includes our wholesale energy markets credit policy and control procedures to manage energy commodity price and credit risks. Nonetheless, adverse changes in commodity prices, generating capacity, customer loads, regulation and other factors may result in losses of earnings, cash flows and/or fair values. We measure the volume of monthly, quarterly and annual energy imbalances between projected power loads and resources. The measurement process is based on expected loads at fixed prices (including those subject to retail rates) and expected resources to the extent that costs are essentially fixed by virtue of known fuel supply costs or projected hydroelectric conditions. To the extent that expected costs are not fixed, either because of volume mismatches between loads and resources or because fuel cost is not locked in through fixed price contracts or derivative instruments, our risk policy guides the process to manage this open forward position over a period of time. Normal operations result in seasonal mismatches between power loads and available resources. We are able to vary the operation of generating resources to match parts of intra-hour, hourly, daily and weekly load fluctuations. We use the wholesale power markets, including the natural gas market as it relates to power generation fuel, to sell projected resource surpluses and obtain resources when deficits are projected. We buy and sell fuel for thermal generation facilities based on comparative power market prices and marginal costs of fueling and operating available generating facilities and the relative economics of substitute market purchases for generating plant operation. To address the impact on our operations of energy market price volatility, our hedging practices for electricity (including fuel for generation) and natural gas extend beyond the current operating year. Executing this extended hedging program may increase our credit risks. Our credit risk management process is designed to mitigate such credit risks through limit setting, contract protections and counterparty diversification, among other practices. Our projected retail natural gas loads and resources are regularly reviewed by operating management and the Risk Management Committee. To manage the impacts of volatile natural gas prices, we seek to procure natural gas through a diversified mix of spot market purchases and forward fixed price purchases from various supply basins and time periods. We have an active hedging program that extends several years into the future with the goal of reducing price volatility in our natural gas supply costs. We use natural gas storage capacity to support high demand periods and to procure natural gas when prices are likely to be seasonally lower. Securing prices throughout the year and even into subsequent years mitigates potential adverse impacts of significant purchase requirements in a volatile price environment. Staff_DR_063 Attachment B Page 82 of 160 AVISTA 62 The following table presents energy commodity derivative fair values as a net asset or (liability) as of December 31, 2015 that are expected to settle in each respective year (dollars in thousands): Purchases Sales Electric Derivatives Gas Derivatives Electric Derivatives Gas Derivatives Year Physical (1) Financial (1) Physical (1) Financial (1) Physical (1) Financial (1) Physical (1) Financial (1) 2016 $ (6,928) $ (14,988) $ (5,895) $ (41,006) $ 82 $ 28,857 $ 173 $ 22,445 2017 (6,403) 36 (1,050) (9,473) (23) 3,971 (1,125) 313 2018 (5,614) — — (3,554) (50) — (1,172) (162) 2019 (3,072) — (22) (1,964) (44) — (1,220) — 2020 — — 35 (18) — — (1,130) — Thereafter — — — — — — (679) — The following table presents energy commodity derivative fair values as a net asset or (liability) as of December 31, 2014 that are expected to settle in each respective year (dollars in thousands): Purchases Sales Electric Derivatives Gas Derivatives Electric Derivatives Gas Derivatives Year Physical (1) Financial (1) Physical (1) Financial (1) Physical (1) Financial (1) Physical (1) Financial (1) 2015 $ (6,053) $ (27,664) $ (10,607) $ (50,852) $ 17 $ 32,629 $ 1,228 $ 31,661 2016 (5,978) (5,124) (2,970) (19,381) (80) 13,126 (853) 10,170 2017 (4,657) — (355) (2,428) (117) 1,151 — 119 2018 (4,173) — — (389) (120) — — — 2019 (2,191) — — (147) (85) — — — Thereafter — — — — — — — — (1) Physical transactions represent commodity transactions where we will take delivery of either electricity or natural gas and financial transactions represent derivative instruments with no physical delivery, such as futures, swaps, options, or forward contracts. The above electric and natural gas derivative contracts will be included in either power supply costs or natural gas supply costs during the period they are delivered and will be included in the various recovery mechanisms (ERM, PCA, and PGAs), or in the general rate case process, and are expected to eventually be collected through retail rates from customers. See “Item 1. Business—Electric Operations,” “Item 1. Business— Natural Gas Operations,” and “Item 1A. Risk Factors” for additional discussion of the risks associated with Energy Commodities. Operational Risk Operational risk involves potential disruption, losses, or excess costs arising from external events or inadequate or failed internal processes, people and systems. Our operations are subject to operational and event risks that include, but are not limited to, those described in “Item 1A. Risk Factors.” To manage operational and event risks, we maintain emergency operating plans, business continuity and disaster recovery plans, maintain insurance coverage against some, but not all, potential losses and seek to negotiate indemnification arrangements with contractors for certain event risks. In addition, we design and follow detailed vegetation management and asset management inspection plans, which help mitigate wildfire and storm event risks, as well as identify utility assets which may be failing and in need of repair or replacement. We also have an Emergency Operating Center, which is a team of employees that plan for and train to deal with potential emergencies or unplanned outages at our facilities, resulting from natural disasters or other events. To prevent unauthorized access to our facilities, we have both physical and cyber security in place. To address the risk related to fuel cost, availability and delivery restraints, we have an energy resources risk policy, which includes our wholesale energy markets credit policy and control procedures to manage energy commodity price and credit risks. Development of the energy resources risk policy includes planning for sufficient capacity to meet our customer and wholesale energy delivery obligations. See further discussion of the energy resources risk policy above. Oversight of the operational risk management process is performed by the Environmental, Technology and Operations Committee of our Board of Directors and from senior management with input from each operating department. Compliance Risk Compliance risk is the potential consequences of legal or regulatory sanctions or penalties arising from the failure of the Company to comply with requirements of applicable laws, rules and regulations. We have extensive compliance obligations. Our primary compliance risks and obligations include, among others, those described in “Item 1A. Risk Factors.” We mitigate compliance risk through oversight from the Environmental, Technology and Operations Committee and the Audit Committee of our Board of Directors and from senior management. We also have separate Regulatory and Environmental Compliance departments that monitor legislation, regulatory orders and actions to determine the overall potential impact to our Company and develop strategies for complying with the various rules and regulations. We also engage outside attorneys, and consultants, when necessary, to help ensure compliance with laws and regulations. Staff_DR_063 Attachment B Page 83 of 160 63 AVISTA See “Item 1. Business, Regulatory Issues” through “Item 1. Business, Reliability Standards” and “Environmental Issues and Contingencies” for further discussion of compliance issues that impact our Company. Technology Risk Our primary technology risks are described in “Item 1A. Risk Factors.” We mitigate technology risk through trainings and exercises at all levels of the Company. The Environmental, Technology and Operations Committee of our Board of Directors along with senior management are regularly briefed on security policy, programs and incidents. Annual cyber and physical training and testing of employees are included in our enterprise security program as is business continuity testing and a data breach response exercises. Technology governance is led by senior management, which includes new technology strategy, risk planning and major project planning and approval. The technology project management office and enterprise capital planning group provide project cost, timeline and schedule oversight. In addition, there are independent third party audits of our critical infrastructure security program and our business risk security controls. We have a Technology department dedicated to securing, maintaining, evaluating and developing our information technology systems. There is regular training of the technology and security team. This group also evaluates the Company’s technology for obsolescence and makes recommendations for upgrading or replacing systems as necessary. This group also monitors for intrusion and security events that may include a data breach. Strategic Risk Strategic risk relates to the potential impacts resulting from incorrect assumptions about external and internal factors, inappropriate business plans, ineffective business strategy execution, or the failure to respond in a timely manner to changes in the regulatory, macroeconomic or competitive environments. Our primary strategic risks include, among others, those described in “Item 1A. Risk Factors.” We mitigate strategic risk through detailed oversight from the Board of Directors and from senior management. We also have a Chief Strategy Officer that heads a Strategic Initiatives department, to search for and evaluate opportunities for the Company and makes recommendations to senior management. The Strategic Initiatives department not only focuses on whether opportunities are financially viable, but also considers whether these opportunities fall within our core policies and our core business strategies. We mitigate our reputational risk primarily through a focus on adherence to our core policies, including our Code of Conduct, maintaining an appropriate Company culture and tone at the top, and through communication and engagement of our external stakeholders. External Mandates Risk External mandate risk involves forces outside the Company, which may include significant changes in customer expectations, disruptive technologies that result in obsolescence of our business model and government action that could impact the Company. See “Environmental Issues and Contingencies” and “Forward-Looking Statements” for a discussion of or reference to our external mandates risks. We mitigate external mandate risk through detailed oversight from the Environmental, Technology and Operations Committee of our Board of Directors and from senior management. We have a Climate Council which meets internally to assess the potential impacts of climate policy to our business and to identify strategies to plan for change. We also have employees dedicated to actively engage and monitor federal, state and local government positions and legislative actions that may affect us or our customers. To prevent the threat of municipalization, we work to build strong relationships with the communities we serve through, among other things: • communication and involvement with local business leaders and community organizations, • providing customers with a multitude of limited income initiatives, including energy fairs, senior outreach and low income workshops, mobile outreach strategy and a Low Income Rate Assistance Plan, • tailoring our internal company initiatives to focus on choices for our customers, to increase their overall satisfaction with the Company, and • engaging in the legislative process in a manner that fosters the interests of our customers and the communities we serve. ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK The information required by this item is set forth in the Enterprise Risk Management section of “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and is incorporated herein by reference. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA The Report of Independent Registered Public Accounting Firm and Financial Statements begin on the next page. Staff_DR_063 Attachment B Page 84 of 160 AVISTA 64 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors and Shareholders of Avista Corporation Spokane, Washington We have audited the accompanying consolidated balance sheets of Avista Corporation and subsidiaries (the “Company”) as of December 31, 2015 and 2014, and the related consolidated statements of income, comprehensive income, equity and redeemable noncontrolling interests, and cash flows for each of the three years in the period ended December 31, 2015. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Avista Corporation and subsidiaries at December 31, 2015 and 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015, in conformity with accounting principles generally accepted in the United States of America. We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2015, based on the criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report, dated February 23, 2016 expressed an unqualified opinion on the Company’s internal control over financial reporting. /s/ Deloitte & Touche LLP Seattle, Washington February 23, 2016 Staff_DR_063 Attachment B Page 85 of 160 65 AVISTA CONSOLIDATED STATEMENTS OF INCOME Avista Corporation For the Years Ended December 31, Dollars in thousands, except per share amounts 2015 2014 2013 Operating Revenues: Utility revenues $ 1,456,091 $ 1,433,343 $ 1,402,195 Non-utility revenues 28,685 39,219 39,549 Total operating revenues 1,484,776 1,472,562 1,441,744 Operating Expenses: Utility operating expenses: Resource costs 656,964 678,244 689,586 Other operating expenses 303,221 286,832 276,228 Depreciation and amortization 143,499 129,570 117,174 Taxes other than income taxes 97,657 94,300 88,435 Non-utility operating expenses: Other operating expenses 29,526 30,418 38,651 Depreciation and amortization 695 610 581 Total operating expenses 1,231,562 1,219,974 1,210,655 Income from operations 253,214 252,588 231,089 Interest expense 79,968 75,302 77,118 Interest expense to affiliated trusts 473 450 467 Capitalized interest (3,546) (3,924) (3,676) Other income-net (9,300) (11,346) (5,167) Income from continuing operations before income taxes 185,619 192,106 162,347 Income tax expense 67,449 72,240 58,014 Net income from continuing operations 118,170 119,866 104,333 Net income from discontinued operations (Note 5) 5,147 72,411 7,961 Net income 123,317 192,277 112,294 Net income attributable to noncontrolling interests (90) (236) (1,217) Net income attributable to Avista Corp. shareholders $ 123,227 $ 192,041 $ 111,077 Amounts attributable to Avista Corp. shareholders: Net income from continuing operations $ 118,080 $ 119,817 $ 104,273 Net income from discontinued operations 5,147 72,224 6,804 Net income attributable to Avista Corp. shareholders $ 123,227 $ 192,041 $ 111,077 Weighted-average common shares outstanding (thousands)—basic 62,301 61,632 59,960 Weighted-average common shares outstanding (thousands)—diluted 62,708 61,887 59,997 Earnings per common share attributable to Avista Corp. shareholders—basic: Earnings per common share from continuing operations $ 1.90 $ 1.94 $ 1.74 Earnings per common share from discontinued operations 0.08 1.18 0.11 Total earnings per common share attributable to Avista Corp. shareholders—basic $ 1.98 $ 3.12 $ 1.85 Earnings per common share attributable to Avista Corp. shareholders—diluted: Earnings per common share from continuing operations $ 1.89 $ 1.93 $ 1.74 Earnings per common share from discontinued operations 0.08 1.17 0.11 Total earnings per common share attributable to Avista Corp. shareholders—diluted $ 1.97 $ 3.10 $ 1.85 The Accompanying Notes are an Integral Part of These Statements. Staff_DR_063 Attachment B Page 86 of 160 AVISTA 66 CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME Avista Corporation For the Years Ended December 31, Dollars in thousands 2015 2014 2013 Net income $ 123,317 $ 192,277 $ 112,294 Other Comprehensive Income (Loss): Unrealized investment gains/(losses)—net of taxes of $0, $664 and $(1,026), respectively — 1,126 (1,741) Reclassification adjustment for realized gains on investment securities included in net income—net of taxes of $0, $(1) and $(7), respectively — (2) (12) Reclassification adjustment for realized losses on investment securities included in net income from discontinued operations—net of taxes of $0, $273 and $0, respectively — 462 — Change in unfunded benefit obligation for pension and other postretirement benefit plans—net of taxes of $667, $(1,967) and $1,418, respectively 1,238 (3,655) 2,634 Total other comprehensive income (loss) 1,238 (2,069) 881 Comprehensive income 124,555 190,208 113,175 Comprehensive income attributable to noncontrolling interests (90) (236) (1,217) Comprehensive income attributable to Avista Corporation shareholders $ 124,465 $ 189,972 $ 111,958 The Accompanying Notes are an Integral Part of These Statements. Staff_DR_063 Attachment B Page 87 of 160 67 AVISTA CONSOLIDATED BALANCE SHEETS Avista Corporation As of December 31, Dollars in thousands 2015 2014 Assets: Current Assets: Cash and cash equivalents $ 10,484 $ 22,143 Accounts and notes receivable-less allowances of $4,530 and $4,888, respectively 169,413 171,925 Utility energy commodity derivative assets 683 1,525 Regulatory asset for utility derivatives 17,260 29,640 Materials and supplies, fuel stock and stored natural gas 54,148 66,356 Deferred income taxes — 14,794 Income taxes receivable 24,121 43,893 Other current assets 29,937 45,071 Total current assets 306,046 395,347 Net Utility Property: Utility plant in service 5,129,192 4,718,062 Construction work in progress 202,683 227,758 Total 5,331,875 4,945,820 Less: Accumulated depreciation and amortization 1,433,286 1,325,858 Total net utility property 3,898,589 3,619,962 Other Non-current Assets: Investment in exchange power—net 8,983 11,433 Investment in affiliated trusts 11,547 11,547 Goodwill 57,672 57,976 Long-term energy contract receivable 14,694 28,202 Other property and investments—net 50,750 42,016 Total other non-current assets 143,646 151,174 Deferred Charges: Regulatory assets for deferred income tax 101,240 100,412 Regulatory assets for pensions and other postretirement benefits 235,009 235,758 Other regulatory assets 99,798 91,920 Regulatory asset for unsettled interest rate swaps 83,973 77,063 Non-current regulatory asset for utility derivatives 32,420 24,483 Other deferred charges 5,928 4,852 Total deferred charges 558,368 534,488 Total assets $ 4,906,649 $ 4,700,971 The Accompanying Notes are an Integral Part of These Statements. Staff_DR_063 Attachment B Page 88 of 160 AVISTA 68 CONSOLIDATED BALANCE SHEETS (CONTINUED) Avista Corporation As of December 31, Dollars in thousands 2015 2014 Liabilities and Equity: Current Liabilities: Accounts payable $ 114,349 $ 112,974 Current portion of long-term debt and capital leases 93,167 6,424 Current portion of nonrecourse long-term debt of Spokane Energy — 1,431 Short-term borrowings 105,000 105,000 Utility energy commodity derivative liabilities 14,268 18,045 Other current liabilities 147,896 141,395 Total current liabilities 474,680 385,269 Long-term debt and capital leases 1,480,111 1,480,702 Long-term debt to affiliated trusts 51,547 51,547 Regulatory liability for utility plant retirement costs 261,594 254,140 Pensions and other postretirement benefits 201,453 189,489 Deferred income taxes 747,477 710,342 Other non-current liabilities and deferred credits 161,500 146,240 Total liabilities 3,378,362 3,217,729 Commitments and Contingencies (See Notes to Consolidated Financial Statements) Equity: Avista Corporation Shareholders’ Equity: Common stock, no par value; 200,000,000 shares authorized; 62,312,651 and 62,243,374 shares issued and outstanding as of December 31, 2015 and December 31, 2014, respectively 1,004,336 999,960 Accumulated other comprehensive loss (6,650) (7,888) Retained earnings 530,940 491,599 Total Avista Corporation shareholders’ equity 1,528,626 1,483,671 Noncontrolling Interests (339) (429) Total equity 1,528,287 1,483,242 Total liabilities and equity $ 4,906,649 $ 4,700,971 The Accompanying Notes are an Integral Part of These Statements. Staff_DR_063 Attachment B Page 89 of 160 69 AVISTA CONSOLIDATED STATEMENTS OF CASH FLOWS Avista Corporation For the Years Ended December 31, Dollars in thousands 2015 2014 2013 Operating Activities: Net income $ 123,317 $ 192,277 $ 112,294 Non-cash items included in net income: Depreciation and amortization 147,835 138,337 133,189 Provision for deferred income taxes 51,801 144,269 23,532 Power and natural gas cost amortizations (deferrals)—net 21,358 (14,821) (9,408) Amortization of debt expense 3,526 3,692 3,813 Amortization of investment in exchange power 2,450 2,450 2,450 Stock-based compensation expense 6,914 8,114 6,218 Equity-related AFUDC (8,331) (8,808) (6,066) Pension and other postretirement benefit expense 37,050 22,943 42,067 Amortization of Spokane Energy contract 13,508 12,417 11,414 Write-off of wind generation capitalized costs — — 2,534 Gain on sale of Ecova (777) (160,612) — Other (6,881) 9,009 12,982 Contributions to defined benefit pension plan (12,000) (32,000) (44,263) Changes in certain current assets and liabilities: Accounts and notes receivable (10,538) 16,425 (32,675) Materials and supplies, fuel stock and stored natural gas 12,208 (19,394) 2,509 Increase in collateral posted for derivative instruments (13,301) (23,301) (16,073) Income taxes receivable 19,772 (36,110) (5,006) Other current assets 2,338 (7,117) 2,608 Accounts payable (8,138) (12,562) (8,389) Other current liabilities (6,471) 32,060 8,827 Net cash provided by operating activities 375,640 267,268 242,557 Investing Activities: Utility property capital expenditures (excluding equity-related AFUDC) (393,425) (325,516) (294,363) Other capital expenditures (885) (6,427) (8,750) Federal and state grant payments received 2,730 2,530 3,409 Cash received (paid) in acquisition—net (95) 15,007 — Decrease (increase) in funds held for clients — (18,931) 1,815 Purchase of securities available for sale — (12,267) (35,949) Sale and maturity of securities available for sale — 14,612 22,960 Proceeds from sale of Ecova, net of cash sold 13,856 229,903 — Other (10,008) (2,647) (1,339) Net cash used in investing activities $ (387,827) $ (103,736) $ (312,217) The Accompanying Notes are an Integral Part of These Statements. Staff_DR_063 Attachment B Page 90 of 160 AVISTA 70 CONSOLIDATED STATEMENTS OF CASH FLOWS (CONTINUED) Avista Corporation For the Years Ended December 31, Dollars in thousands 2015 2014 2013 Financing Activities: Net increase (decrease) in short-term borrowings $ — $ (66,000) $ 119,000 Borrowings from Ecova line of credit — — 3,000 Repayment of borrowings from Ecova line of credit — (46,000) (11,000) Proceeds from issuance of long-term debt 100,000 150,000 90,000 Redemption and maturity of long-term debt and capital leases (2,905) (39,971) (50,462) Maturity of nonrecourse long-term debt of Spokane Energy (1,431) (16,407) (14,965) Cash received (paid) for settlement of interest rate swap agreements (9,326) 5,429 2,901 Issuance of common stock—net of issuance costs 1,560 4,060 4,609 Repurchase of common stock (2,920) (79,856) — Cash dividends paid (82,397) (78,314) (73,276) Increase in client fund obligations — 16,216 11,278 Payment to noncontrolling interests for sale of Ecova — (54,179) — Payment to option holders and redeemable noncontrolling interests for sale of Ecova — (20,871) — Other (2,053) 1,930 (4,315) Net cash provided by (used in) financing activities 528 (223,963) 76,770 Net increase (decrease) in cash and cash equivalents (11,659) (60,431) 7,110 Cash and cash equivalents at beginning of year 22,143 82,574 75,464 Cash and cash equivalents at end of year $ 10,484 $ 22,143 $ 82,574 Supplemental Cash Flow Information: Cash paid (received) during the year: Interest $ 79,673 $ 73,526 $ 75,411 Income taxes (net of total refunds of $37,200, $35,573 and $123, respectively) (9,961) 45,416 44,772 Non-cash financing and investing activities: Accounts payable for capital expenditures 35,248 26,959 12,723 Valuation adjustment for redeemable noncontrolling interests — (15,873) 10,704 Receivable for escrow amounts associated with the sale of Ecova — 13,079 — Non-cash stock issuance for acquisition of AERC — 150,119 — The Accompanying Notes are an Integral Part of These Statements. Staff_DR_063 Attachment B Page 91 of 160 71 AVISTA CONSOLIDATED STATEMENTS OF EQUITY AND REDEEMABLE NONCONTROLLING INTERESTS Avista Corporation For the Years Ended December 31, Dollars in thousands 2015 2014 2013 Common Stock, Shares: Shares outstanding at beginning of year 62,243,374 60,076,752 59,812,796 Shares issued through equity compensation plans 125,620 51,127 58,002 Shares issued through Employee Investment Plan (401-K) 33,057 33,168 42,073 Shares issued through Dividend Reinvestment Plan — 110,501 163,881 Shares issued for acquisition — 4,501,441 — Shares repurchased (89,400) (2,529,615) — Shares outstanding at end of year 62,312,651 62,243,374 60,076,752 Common Stock, Amount: Balance at beginning of year $ 999,960 $ 896,993 $ 889,237 Equity compensation expense 6,035 7,676 6,002 Issuance of common stock through equity compensation plans 462 108 (1,342) Issuance of common stock through Employee Investment Plan (401-K) 1,099 1,005 1,127 Issuance of common stock through Dividend Reinvestment Plan — 3,441 4,360 Issuance of common stock for acquisition—net of issuance costs — 149,625 — Payment of minimum tax withholdings for share-based payment awards (1,832) — — Repurchase of common stock (1,431) (40,486) — Equity transactions of consolidated subsidiaries — (1,062) (3,007) Payment to option holders and redeemable noncontrolling interests for sale of Ecova — (20,871) — Excess tax benefits 43 3,531 616 Balance at end of year 1,004,336 999,960 896,993 Accumulated Other Comprehensive Loss: Balance at beginning of year (7,888) (5,819) (6,700) Other comprehensive income (loss) 1,238 (2,069) 881 Balance at end of year (6,650) (7,888) (5,819) Retained Earnings: Balance at beginning of year 491,599 407,092 376,940 Net income attributable to Avista Corporation shareholders 123,227 192,041 111,077 Cash dividends paid (common stock) (82,397) (78,314) (73,276) Repurchase of common stock (1,489) (39,370) — Valuation adjustments and other noncontrolling interests activity — 10,150 (7,649) Balance at end of year 530,940 491,599 407,092 Total Avista Corporation shareholders’ equity $ 1,528,626 $ 1,483,671 $ 1,298,266 The Accompanying Notes are an Integral Part of These Statements. Staff_DR_063 Attachment B Page 92 of 160 AVISTA 72 CONSOLIDATED STATEMENTS OF EQUITY AND REDEEMABLE NONCONTROLLING INTERESTS (CONTINUED) Avista Corporation For the Years Ended December 31, Dollars in thousands 2015 2014 2013 Noncontrolling Interests: Balance at beginning of year $ (429) $ 20,001 $ 17,658 Net income attributable to noncontrolling interests 90 240 1,066 Issuance of subsidiary noncontrolling interests — — 480 Purchase of subsidiary noncontrolling interests — — (4,182) Deconsolidation of noncontrolling interests related to sale of Ecova — (23,612) — Other — 2,942 4,979 Balance at end of year (339) (429) 20,001 Total equity $ 1,528,287 $ 1,483,242 $ 1,318,267 Redeemable Noncontrolling Interests: Balance at beginning of year $ — $ 15,889 $ 4,938 Net income attributable to noncontrolling interests — (4) 151 Purchase of subsidiary noncontrolling interests — (12) (405) Valuation adjustments and other noncontrolling interests activity — (15,873) 11,205 Balance at end of year $ — $ — $ 15,889 The Accompanying Notes are an Integral Part of These Statements. Staff_DR_063 Attachment B Page 93 of 160 73 AVISTA NOTES TO CONSOLIDATED FINANCIAL STATEMENTS NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Nature of Business Avista Corp. is primarily an electric and natural gas utility with certain other business ventures. Avista Utilities is an operating division of Avista Corp., comprising the regulated utility operations in the Pacific Northwest. Avista Utilities provides electric distribution and transmission, and natural gas distribution services in parts of eastern Washington and northern Idaho. Avista Utilities also provides natural gas distribution service in parts of northeastern and southwestern Oregon. Avista Utilities has electric generating facilities in Washington, Idaho, Oregon and Montana. Avista Utilities also supplies electricity to a small number of customers in Montana, most of whom are employees who operate Avista Utilities’ Noxon Rapids generating facility. On July 1, 2014, Avista Corp. acquired AERC, and as of that date, AERC became a wholly-owned subsidiary of Avista Corp. The primary subsidiary of AERC is AEL&P, comprising regulated electric utility operations in Juneau, Alaska. There are no AERC earnings included in the overall results of Avista Corp. prior to July 1, 2014. See Note 4 for information regarding the acquisition of AERC. Avista Capital, a wholly owned subsidiary of Avista Corp., is the parent company of all of the subsidiary companies in the non-utility businesses. During the first half of 2014 and prior, Avista Capital’s subsidiaries included Ecova, which was an 80.2 percent owned subsidiary prior to its disposition on June 30, 2014. Ecova was a provider of energy efficiency and other facility information and cost management programs and services for multi-site customers and utilities throughout North America. See Note 5 for information regarding the disposition of Ecova and Note 21 for business segment information. Basis of Reporting The consolidated financial statements include the assets, liabilities, revenues and expenses of the Company and its subsidiaries and other majority owned subsidiaries and variable interest entities for which the Company or its subsidiaries are the primary beneficiaries. Ecova’s revenues and expenses are included in the Consolidated Statements of Income in discontinued operations; however, as of June 30, 2014 and for all subsequent reporting periods there are no balance sheet amounts included for Ecova. All tables throughout the Notes to Consolidated Financial Statements that present Consolidated Statements of Income information were revised to include only the amounts from continuing operations. Intercompany balances were eliminated in consolidation. The accompanying consolidated financial statements include the Company’s proportionate share of utility plant and related operations resulting from its interests in jointly owned plants (see Note 7). Use of Estimates The preparation of the consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported for assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Significant estimates include: • determining the market value of energy commodity derivative assets and liabilities, • pension and other postretirement benefit plan obligations, • contingent liabilities, • goodwill impairment testing, • recoverability of regulatory assets, and • unbilled revenues. Changes in these estimates and assumptions are considered reasonably possible and may have a material effect on the consolidated financial statements and thus actual results could differ from the amounts reported and disclosed herein. System of Accounts The accounting records of the Company’s utility operations are maintained in accordance with the uniform system of accounts prescribed by the FERC and adopted by the state regulatory commissions in Washington, Idaho, Montana, Oregon and Alaska. Regulation The Company is subject to state regulation in Washington, Idaho, Montana, Oregon and Alaska. The Company is also subject to federal regulation primarily by the FERC, as well as various other federal agencies with regulatory oversight of particular aspects of its operations. Utility Revenues Utility revenues related to the sale of energy are recorded when service is rendered or energy is delivered to customers. Revenues and resource costs from Avista Utilities’ settled energy contracts that are “booked out” (not physically delivered) are reported on a net basis as part of utility revenues. AEL&P does not have booked out transactions. The determination of the energy sales to individual customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each calendar month, the amount of energy delivered to customers since the date of the last meter reading is estimated and the corresponding unbilled revenue is estimated and recorded. Our estimate of unbilled revenue is based on: • the number of customers, • current rates, • meter reading dates, • actual native load for electricity, • actual throughput for natural gas, and • electric line losses and natural gas system losses. Any difference between actual and estimated revenue is automatically corrected in the following month when the actual meter reading and customer billing occurs. Accounts receivable includes unbilled energy revenues of the following amounts as of December 31 (dollars in thousands): 2015 2014 Unbilled accounts receivable $ 62,003 $ 80,718 Staff_DR_063 Attachment B Page 94 of 160 AVISTA 74 Other Non-Utility Revenues Revenues from the other businesses are primarily derived from the operations of AM&D, doing business as METALfx, and are recognized when the risk of loss transfers to the customer, which occurs when products are shipped. In addition, prior to Spokane Energy’s dissolution in 2015, there were revenues at Spokane Energy related to a long-term fixed rate electric capacity contract. This contract was transferred to Avista Corp. during the second quarter of 2015 and the revenues from this contract are now included in utility revenues. Depreciation For utility operations, depreciation expense is estimated by a method of depreciation accounting utilizing composite rates for utility plant. Such rates are designed to provide for retirements of properties at the expiration of their service lives. For utility operations, the ratio of depreciation provisions to average depreciable property was as follows for the years ended December 31: 2015 2014 2013 Avista Utilities Ratio of depreciation to average depreciable property 3.09% 2.97% 2.90% Alaska Electric Light and Power Company Ratio of depreciation to average depreciable property 2.42% 2.43% N/A The average service lives for the following broad categories of utility plant in service are (in years): Alaska Electric Light Avista Utilities and Power Company Electric thermal/other production 40 36 Hydroelectric production 79 45 Electric transmission 57 39 Electric distribution 36 38 Natural gas distribution property 45 N/A Taxes Other Than Income Taxes Taxes other than income taxes include state excise taxes, city occupational and franchise taxes, real and personal property taxes and certain other taxes not based on net income. These taxes are generally based on revenues or the value of property. Utility related taxes collected from customers (primarily state excise taxes and city utility taxes) are recorded as operating revenue and expense and totaled the following amounts for the years ended December 31 (dollars in thousands): 2015 2014 2013 Utility taxes $ 59,173 $ 58,250 $ 55,565 Allowance for Funds Used During Construction The AFUDC represents the cost of both the debt and equity funds used to finance utility plant additions during the construction period. As prescribed by regulatory authorities, AFUDC is capitalized as a part of the cost of utility plant and the debt component is credited against total interest expense in the Consolidated Statements of Income in the line item “capitalized interest.” The equity component of AFUDC is included in the Consolidated Statement of Income in the line item “other income—net.” The Company is permitted, under established regulatory rate practices, to recover the capitalized AFUDC, and a reasonable return thereon, through its inclusion in rate base and the provision for depreciation after the related utility plant is placed in service. Cash inflow related to AFUDC does not occur until the related utility plant is placed in service and included in rate base. The effective AFUDC rate was the following for the years ended December 31: 2015 2014 2013 Avista Utilities Effective AFUDC rate 7.32% 7.64% 7.64% Alaska Electric Light and Power Company Effective AFUDC rate 9.31% 10.37% N/A Income Taxes A deferred income tax asset or liability is determined based on the enacted tax rates that will be in effect when the differences between the financial statement carrying amounts and tax basis of existing assets and liabilities are expected to be reported in the Company’s consolidated income tax returns. The deferred income tax expense for the period is equal to the net change in the deferred income tax asset and liability accounts from the beginning to the end of the period. The effect on deferred income taxes from a change in tax rates is recognized in income in the period that includes the enactment date. Deferred income tax liabilities and regulatory assets are established for income tax benefits flowed through to customers. The Company recognizes the effect of state tax credits, which are generated from utility plant, as they are utilized. The Company did not incur any penalties on income tax Staff_DR_063 Attachment B Page 95 of 160 75 AVISTA positions in 2015, 2014 or 2013. The Company would recognize interest accrued related to income tax positions as interest expense and any penalties incurred as other operating expense. Stock-Based Compensation The Company currently issues three types of stock-based compensation awards—restricted shares, market-based awards and performance-based awards. Historically, these stock compensation awards have not been material to the Company’s overall financial results. Compensation cost relating to share-based payment transactions is recognized in the Company’s financial statements based on the fair value of the equity or liability instruments issued and recorded over the requisite service period. The Company recorded stock-based compensation expense (included in other operating expenses) and income tax benefits in the Consolidated Statements of Income of the following amounts for the years ended December 31 (dollars in thousands): 2015 2014 2013 Stock-based compensation expense $ 6,914 $ 6,007 $ 5,037 Income tax benefits 2,420 2,102 1,763 Restricted share awards vest in equal thirds each year over a three-year period and are payable in Avista Corp. common stock at the end of each year if the service condition is met. In addition to the service condition, the Company must meet a return on equity target in order for the CEO’s restricted shares to vest. Restricted stock is valued at the close of market of the Company’s common stock on the grant date. Total Shareholder Return (TSR) awards are market-based awards and Cumulative Earnings Per Share (CEPS) awards are performance awards. CEPS awards were first granted in 2014. Both types of awards vest after a period of three years and are payable in cash or Avista Corp. common stock at the end of the three-year period. The method of settlement is at the discretion of the Company and historically the Company has settled these awards through issuance of Avista Corp. common stock and intends to continue this practice. Both types of awards entitle the recipients to dividend equivalent rights, are subject to forfeiture under certain circumstances, and are subject to meeting specific market or performance conditions. Based on the level of attainment of the market or performance conditions, the amount of cash paid or common stock issued will range from 0 to 200 percent of the initial awards granted. Dividend equivalent rights are accumulated and paid out only on shares that eventually vest and have met the market and performance conditions. For both the TSR awards and the CEPS awards, the Company accounts for them as equity awards and compensation cost for these awards is recognized over the requisite service period, provided that the requisite service period is rendered. For TSR awards, if the market-condition is not met at the end of the three-year service period, there will be no change in the cumulative amount of compensation cost recognized, since the awards are still considered vested even though the market metric was not met. For CEPS awards, at the end of the three-year service period, if the internal performance metric of cumulative earnings per share is not met, all compensation cost for these awards is reversed as these awards are not considered vested. The fair value of each TSR award is estimated on the date of grant using a statistical model that incorporates the probability of meeting the market targets based on historical returns relative to a peer group. The estimated fair value of the equity component of CEPS awards was estimated on the date of grant as the share price of Avista Corp. common stock on the date of grant, less the net present value of the estimated dividends over the three-year period. The following table summarizes the number of grants, vested and unvested shares, earned shares (based on market metrics), and other pertinent information related to the Company’s stock compensation awards for the years ended December 31: 2015 2014 2013 Restricted Shares Shares granted during the year 58,302 62,075 44,556 Shares vested during the year (60,379) (52,899) (55,456) Unvested shares at end of year 106,091 112,042 104,416 Unrecognized compensation expense at end of year (in thousands) $ 1,705 $ 1,349 $ 1,199 TSR Awards TSR shares granted during the year 116,435 117,550 175,000 TSR shares vested during the year (171,334) (167,584) (176,718) TSR shares earned based on market metrics 222,734 97,199 — Unvested TSR shares at end of year 223,697 287,834 344,684 Unrecognized compensation expense (in thousands) $ 3,219 $ 2,833 $ 3,651 CEPS Awards CEPS shares granted during the year 58,259 59,025 — Unvested CEPS shares at end of year 111,887 58,017 — Unrecognized compensation expense (in thousands) $ 1,840 $ 1,577 $ — Staff_DR_063 Attachment B Page 96 of 160 AVISTA 76 Outstanding TSR and CEPS share awards include a dividend component that is paid in cash. This component of the share grants is accounted for as a liability award. These liability awards are revalued on a quarterly basis taking into account the number of awards outstanding, historical dividend rate, the change in the value of the Company’s common stock relative to an external benchmark (TSR awards only) and the amount of CEPS earned to-date compared to estimated CEPS over the performance period (CEPS awards only). Over the life of these awards, the cumulative amount of compensation expense recognized will match the actual cash paid. As of December 31, 2015 and 2014, the Company had recognized cumulative compensation expense and a liability of $1.5 million and $1.3 million, respectively, related to the dividend component on the outstanding and unvested share grants. Other Income—Net Other Income—net consisted of the following items for the years ended December 31 (dollars in thousands): 2015 2014 2013 Interest income $ 653 $ 987 $ 754 Interest on regulatory deferrals 48 220 126 Equity-related AFUDC 8,331 8,808 6,066 Net gain (loss) on investments (637) 276 (3,378) Other income 905 1,055 1,599 Total $ 9,300 $ 11,346 $ 5,167 Earnings per Common Share Attributable to Avista Corporation Shareholders Basic earnings per common share attributable to Avista Corp. shareholders is computed by dividing net income attributable to Avista Corp. shareholders by the weighted-average number of common shares outstanding for the period. Diluted earnings per common share attributable to Avista Corp. shareholders is calculated by dividing net income attributable to Avista Corp. shareholders (adjusted for the effect of potentially dilutive securities issued to noncontrolling interests by the Company’s subsidiaries) by diluted weighted-average common shares outstanding during the period, including common stock equivalent shares outstanding using the treasury stock method, unless such shares are anti-dilutive. Common stock equivalent shares include shares issuable upon exercise of stock options and contingent stock awards. See Note 18 for earnings per common share calculations. Cash and Cash Equivalents For the purposes of the Consolidated Statements of Cash Flows, the Company considers all temporary investments with a maturity of three months or less when purchased to be cash equivalents. Allowance for Doubtful Accounts The Company maintains an allowance for doubtful accounts to provide for estimated and potential losses on accounts receivable. The Company determines the allowance for utility and other customer accounts receivable based on historical write-offs as compared to accounts receivable and operating revenues. Additionally, the Company establishes specific allowances for certain individual accounts. The following table presents the activity in the allowance for doubtful accounts during the years ended December 31 (dollars in thousands): 2015 2014 2013 Allowance as of the beginning of the year $ 4,888 $ 44,309 $ 44,155 Additions expensed during the year 5,802 5,296 5,099 Net deductions (1) (6,160) (44,717) (4,945) Allowance as of the end of the year $ 4,530 $ 4,888 $ 44,309 (1) During the second quarter of 2014, the Company received $15.0 million in gross proceeds related to the settlement of its California wholesale power markets litigation. The gross proceeds effectively settled all outstanding receivables and payables at Avista Energy (which had been fully reserved against since 2001). As a result of the settlement, the Company reversed $15.0 million of the allowance, which was recorded as a reduction to non-utility other operating expenses on the Consolidated Statements of Income, and the remainder of the receivables, payables and allowance of $24.5 million were removed from the Consolidated Balance Sheets (and had no effect on net income). Materials and Supplies, Fuel Stock and Stored Natural Gas Inventories of materials and supplies, fuel stock and stored natural gas are recorded at average cost for our regulated operations and the lower of cost or market for our non-regulated operations and consisted of the following as of December 31 (dollars in thousands): 2015 2014 Materials and supplies $ 37,101 $ 32,483 Fuel stock 4,273 5,142 Stored natural gas 12,774 28,731 Total $ 54,148 $ 66,356 Staff_DR_063 Attachment B Page 97 of 160 77 AVISTA Utility Plant in Service The cost of additions to utility plant in service, including an allowance for funds used during construction and replacements of units of property and improvements, is capitalized. The cost of depreciable units of property retired plus the cost of removal less salvage is charged to accumulated depreciation. Asset Retirement Obligations The Company records the fair value of a liability for an asset retirement obligation (ARO) in the period in which it is incurred. When the liability is initially recorded, the associated costs of the ARO are capitalized as part of the carrying amount of the related long-lived asset. The liability is accreted to its present value each period and the related capitalized costs are depreciated over the useful life of the related asset. In addition, if there are changes in the estimated timing or estimated costs of the AROs, adjustments are recorded during the period new information becomes available as an increase or decrease to the liability, with the offset recorded to the related long-lived asset. Upon retirement of the asset, the Company either settles the ARO for its recorded amount or incurs a gain or loss. The Company records regulatory assets and liabilities for the difference between asset retirement costs currently recovered in rates and AROs recorded since asset retirement costs are recovered through rates charged to customers (see Note 9 for further discussion of the Company’s asset retirement obligations). The Company recovers certain asset retirement costs through rates charged to customers as a portion of its depreciation expense for which the Company has not recorded asset retirement obligations. The Company has recorded the amount of estimated retirement costs collected from customers (that do not represent legal or contractual obligations) and included them as a regulatory liability on the Consolidated Balance Sheets in the following amounts as of December 31 (dollars in thousands): 2015 2014 Regulatory liability for utility plant retirement costs $ 261,594 $ 254,140 Goodwill Goodwill arising from acquisitions represents the excess of the purchase price over the estimated fair value of net assets acquired. The Company evaluates goodwill for impairment using a combination of discounted cash flow models and a market approach on at least an annual basis or more frequently if impairment indicators arise. The Company completed its annual evaluation of goodwill for potential impairment as of November 30, 2015 and determined that goodwill was not impaired at that time. The changes in the carrying amount of goodwill are as follows (dollars in thousands): Accumulated Impairment Ecova AEL&P Other Losses Total Balance as of January 1, 2014 $ 71,011 $ — $ 12,979 $ (7,733) $ 76,257 Adjustments 112 — — — 112 Goodwill sold during the year (71,123) — — — (71,123) Goodwill acquired during the year — 52,730 — — 52,730 Balance as of the December 31, 2014 — 52,730 12,979 (7,733) 57,976 Adjustments — (304) — — (304) Balance as of the December 31, 2015 $ — $ 52,426 $ 12,979 $ (7,733) $ 57,672 Accumulated impairment losses are attributable to the other businesses. The goodwill sold during 2014 relates to the Ecova disposition, which occurred on June 30, 2014. See Note 5 for information regarding this sales transaction. The goodwill acquired during 2014 relates to the acquisition of AERC and the goodwill associated with this acquisition is not deductible for tax purposes. See Note 4 for information regarding this business acquisition and Note 21 regarding the Company’s reportable segments. Derivative Assets and Liabilities Derivatives are recorded as either assets or liabilities on the Consolidated Balance Sheets measured at estimated fair value. In certain defined conditions, a derivative may be specifically designated as a hedge for a particular exposure. The accounting for a derivative depends on the intended use of such derivative and the resulting designation. The UTC and the IPUC issued accounting orders authorizing Avista Utilities to offset energy commodity derivative assets or liabilities with a regulatory asset or liability. This accounting treatment is intended to defer the recognition of mark-to-market gains and losses on energy commodity transactions until the period of delivery. The orders provide for Avista Utilities to not recognize the unrealized gain or loss on utility derivative commodity instruments in the Consolidated Statements of Income. Realized gains or losses are recognized in the periods of delivery, subject to approval for recovery through retail rates. Realized gains and losses, subject to regulatory approval, result in adjustments to retail rates through purchased gas cost adjustments, the ERM in Washington, the PCA mechanism in Idaho, and periodic general rates cases. Regulatory assets are assessed regularly and are probable for recovery through future rates. Substantially all forward contracts to purchase or sell power and natural gas are recorded as derivative assets or liabilities at estimated Staff_DR_063 Attachment B Page 98 of 160 AVISTA 78 fair value with an offsetting regulatory asset or liability. Contracts that are not considered derivatives are accounted for on the accrual basis until they are settled or realized, unless there is a decline in the fair value of the contract that is determined to be other-than-temporary. For interest rate swap agreements, each period Avista Utilities records all mark-to-market gains and losses as assets and liabilities and records offsetting regulatory assets and liabilities, such that there is no income statement impact. Upon settlement of interest rate swaps, the regulatory asset or liability (included as part of long-term debt) is amortized as a component of interest expense over the term of the associated debt. While the Company has not received any formal accounting orders from the various state commissions allowing for the offset of interest rate swap assets and liabilities with regulatory assets and liabilities, the Company has deemed this accounting treatment appropriate and future recovery probable due to the regulatory precedents set in prior general rate cases and the fact that the state commissions view interest rate swap derivatives as risk management tools similar to energy commodity derivatives. As of December 31, 2015, the Company has multiple master netting agreements with a variety of entities that allow for cross-commodity netting of derivative agreements with the same counterparty (i.e. power derivatives can be netted with natural gas derivatives) under ASC 815-10-45. The Company does not have any agreements which allow for cross-affiliate netting among multiple affiliated legal entities. The Company nets all derivative instruments when allowed by the agreement for presentation in the Consolidated Balance Sheets. Fair Value Measurements Fair value represents the price that would be received when selling an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. Energy commodity derivative assets and liabilities, deferred compensation assets, as well as derivatives related to interest rate swap agreements and foreign currency exchange contracts, are reported at estimated fair value on the Consolidated Balance Sheets. See Note 16 for the Company’s fair value disclosures. Regulatory Deferred Charges and Credits The Company prepares its consolidated financial statements in accordance with regulatory accounting practices because: • rates for regulated services are established by or subject to approval by independent third-party regulators, • the regulated rates are designed to recover the cost of providing the regulated services, and • in view of demand for the regulated services and the level of competition, it is reasonable to assume that rates can be charged to and collected from customers at levels that will recover costs. Regulatory accounting practices require that certain costs and/or obligations (such as incurred power and natural gas costs not currently included in rates, but expected to be recovered or refunded in the future), are reflected as deferred charges or credits on the Consolidated Balance Sheets. These costs and/or obligations are not reflected in the Consolidated Statements of Income until the period during which matching revenues are recognized. The Company also has decoupling revenue deferrals. As opposed to cost deferrals which are not recognized in the Consolidated Statements of Income until they are included in rates, decoupling revenue is recognized in the Consolidated Statements of Income during the period it occurs (i.e. during the period of revenue shortfall or excess due to fluctuations in customer usage), subject to certain limitations, and a regulatory asset/liability is established which will be surcharged or rebated to customers in future periods. GAAP requires that for any alternative regulatory revenue program, like decoupling, the revenue must be collected from customers within 24 months of the deferral to qualify for recognition in the current period Consolidated Statement of Income. Any amounts included in the Company’s decoupling program that won’t be collected from customers within 24 months are not recorded in the financial statements until the period in which revenue recognition criteria are met. This could ultimately result in more decoupling revenue being collected from customers over the life of the decoupling program than what is deferred and recognized in the current period financial statements. If at some point in the future the Company determines that it no longer meets the criteria for continued application of regulatory accounting practices for all or a portion of its regulated operations, the Company could be: • required to write off its regulatory assets, and • precluded from the future deferral of costs or decoupled revenues not recovered through rates at the time such amounts are incurred, even if the Company expected to recover these amounts from customers in the future. See Note 20 for further details of regulatory assets and liabilities. Investment in Exchange Power-Net The investment in exchange power represents the Company’s previous investment in Washington Public Power Supply System Project 3 (WNP-3), a nuclear project that was terminated prior to completion. Under a settlement agreement with the Bonneville Power Administration in 1985, Avista Utilities began receiving power in 1987, for a 32.5-year period, related to its investment in WNP-3. Through a settlement agreement with the UTC in the Washington jurisdiction, Avista Utilities is amortizing the recoverable portion of its investment in WNP-3 (recorded as investment in exchange power) over a 32.5-year period that began in 1987. For the Idaho jurisdiction, Avista Utilities fully amortized the recoverable portion of its investment in exchange power. Unamortized Debt Expense Unamortized debt expense includes debt issuance costs that are amortized over the life of the related debt. See further discussion related to the Consolidated Balance Sheet classification of these costs below under reclassifications. Unamortized Debt Repurchase Costs For the Company’s Washington regulatory jurisdiction and for any debt repurchases beginning in 2007 in all jurisdictions, premiums paid to repurchase debt are amortized over the remaining life of the original debt that was repurchased or, if new debt is issued in connection with the repurchase, these costs are amortized over the life of the new debt. In the Company’s other regulatory jurisdictions, premiums paid to repurchase debt prior to 2007 are being amortized over the average remaining maturity of outstanding debt when no new debt was issued in connection with the debt repurchase. These costs are recovered through retail rates as a component of interest expense. Staff_DR_063 Attachment B Page 99 of 160 79 AVISTA Accumulated Other Comprehensive Loss Accumulated other comprehensive loss, net of tax, consisted of the following as of December 31 (dollars in thousands): 2015 2014 Unfunded benefit obligation for pensions and other postretirement benefit plans—net of taxes of $3,580 and $4,247, respectively $ 6,650 $ 7,888 The following table details the reclassifications out of accumulated other comprehensive loss by component for the years ended December 31 (dollars in thousands): Amounts Reclassified from Accumulated Other Affected Line Comprehensive Loss Item in Statement Details About Accumulated Other Comprehensive Loss Components 2015 2014 of Income Realized gains on investment securities $ — $ 3 (a) Realized losses on investment securities — (735) (a) — (732) Total before tax — 272 Tax benefit (a) $ — $ (460) Net of tax Amortization of defined benefit pension items Amortization of net prior service cost $ (31) $ 1,094 (b) Amortization of net loss (2,623) 83,301 (b) Adjustment due to effects of regulation 749 (78,773) (b) (1,905) 5,622 Total before tax 667 (1,967) Tax expense (benefit) $ (1,238) $ 3,655 Net of tax (a) These amounts were included as part of net income from discontinued operations for all periods presented (see Note 5 for additional details). (b) These accumulated other comprehensive loss components are included in the computation of net periodic pension cost (see Note 10 for additional details). Appropriated Retained Earnings In accordance with the hydroelectric licensing requirements of section 10(d) of the Federal Power Act (FPA), the Company maintains an appropriated retained earnings account for any earnings in excess of the specified rate of return on the Company’s investment in the licenses for its various hydroelectric projects. Per section 10(d) of the FPA, the Company must maintain these excess earnings in an appropriated retained earnings account until the termination of the licensing agreements or apply them to reduce the net investment in the licenses of the hydroelectric projects at the discretion of the FERC. The Company typically calculates the earnings in excess of the specified rate of return on an annual basis, usually during the second quarter. In addition to the hydroelectric project licenses identified above for Avista Utilities, the requirements of section 10(d) of the FPA also apply to the AEL&P licenses for Lake Dorothy and Annex Creek/Salmon Creek (combined). The appropriated retained earnings amounts included in retained earnings were as follows as of December 31 (dollars in thousands): 2015 2014 Appropriated retained earnings $ 21,030 $ 14,270 Operating Leases The Company has multiple lease arrangements involving various assets, with minimum terms ranging from 1 to 45 years. Future minimum lease payments required under operating leases having initial or remaining noncancelable lease terms in excess of one year were not material as of December 31, 2015. Contingencies The Company has unresolved regulatory, legal and tax issues which have inherently uncertain outcomes. The Company accrues a loss contingency if it is probable that a liability has been incurred and the amount of the loss or impairment can be reasonably estimated. The Company also discloses losses that do not meet these conditions for accrual, if there is a reasonable possibility that a material loss may be incurred. As of December 31, 2015, the Company has not recorded any significant amounts related to unresolved contingencies. See Note 19 for further discussion of the Company’s commitments and contingencies. Reclassifications Certain prior year amounts on the Company’s Consolidated Balance Sheets were reclassified to conform to the current year presentation. The reclassifications related the presentation of debt issuance costs due to the retrospective adoption of FASB ASU No. 2015-03, “Interest—Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs” as of December 31, 2015. This resulted in a decrease to Other Deferred Staff_DR_063 Attachment B Page 100 of 160 AVISTA 80 Charges and a decrease to Long-Term Debt and Capital Leases of $11.4 million as of December 31, 2014. There was no other impact on the Company’s financial statements or results of operations. Also, the Company adopted FASB ASU 2015-17 “Income Taxes (Topic 740)—Balance Sheet Classification of Deferred Taxes,” as of December 31, 2015 on a prospective basis, which resulted in all 2015 deferred income taxes being classified as noncurrent liabilities on the Consolidated Balance Sheet, compared to 2014 under the previous guidance, which required entities to separately present Deferred Tax Assets (DTAs) and Deferred Tax Liabilities (DTLs) as current and noncurrent in a classified balance sheet. This makes the 2015 presentation of deferred income taxes incomparable to the 2014 presentation of deferred income taxes. See Note 2 of the Notes to Consolidated Financial Statements for further discussion of the adoption of both of these ASUs. NOTE 2. NEW ACCOUNTING STANDARDS In April 2014, the FASB issued ASU No. 2014-08, “Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity.” This ASU amends the definition of a discontinued operation and requires entities to provide additional disclosures about discontinued operations as well as disposal transactions that do not meet the discontinued-operations criteria. ASU 2014-08 makes it more difficult for a disposal transaction to qualify as a discontinued operation. In addition, the ASU requires entities to reclassify assets and liabilities of a discontinued operation for all comparative periods presented in the Balance Sheet rather than just the current period, and it requires additional disclosures on the face of the Statement of Cash Flows regarding discontinued operations. This ASU became effective for periods beginning on or after December 15, 2014; however, early adoption was permitted. The Company evaluated this standard and determined that it would not early adopt this standard. Since the disposition of Ecova occurred before the effective date of this standard, and the Company did not early adopt this standard, there is no impact on the Company’s financial condition, results of operations and cash flows in the current year. In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606),” which outlines a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. The core principle of the revenue model is that an entity identifies the various performance obligations in a contract, allocates the transaction price among the performance obligations and recognizes revenue as the entity satisfies the performance obligations. This ASU was originally effective for periods beginning after December 15, 2016 and early adoption is not permitted. In August 2015, the FASB issued ASU 2015-14, “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date,” which deferred the effective date of ASU 2014-09 for one year, with adoption as of the original date permitted. However, while this ASU is not effective until 2018, it will require retroactive application to all periods presented in the financial statements. As such, at adoption in 2018, amounts in 2016 and 2017 may have to be revised or a cumulative adjustment to opening retained earnings may have to be recorded. The Company is evaluating this standard and cannot, at this time, estimate the potential impact on its future financial condition, results of operations and cash flows. In February 2015, the FASB issued ASU No. 2015-02, “Consolidation (Topic 810): Amendments to the Consolidation Analysis.” This ASU significantly changes the consolidation analysis required under GAAP, including the identification of variable interest entities (VIE). The ASU also removes the deferral of the VIE analysis related to investments in certain investment funds, which will result in a different consolidation evaluation for these types of investments. This ASU is effective for periods beginning on or after December 15, 2015; however, early adoption is permitted. The Company evaluated this standard and determined that it will not early adopt this standard. The Company is evaluating this standard and cannot, at this time, estimate the potential impact on its future financial condition, results of operations and cash flows. In April 2015, the FASB issued ASU No. 2015-03, “Interest— Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs.” This ASU amends the presentation of debt issuance costs in the financial statements such that an entity presents such costs in the balance sheet as a direct deduction from the related debt liability rather than as a deferred asset. Amortization of the costs will continue to be reported as interest expense. ASU No. 2015-03 is effective for periods beginning on or after December 15, 2015; however, early adoption is permitted. Upon adoption, entities will apply the new guidance retrospectively to all comparable prior periods presented in the financial statements. The Company evaluated this standard and determined that it will early adopt this standard as of December 31, 2015. As such, the Company revised its presentation of debt issuance costs for long-term debt in the Consolidated Balance Sheets for both periods presented. See Note 1 of the Notes to Consolidated Financial Statements—Reclassifications for the quantification of the impact on the prior year Consolidated Balance Sheet. ASU No. 2015-03 did not address the presentation of debt issuance costs associated with line of credit arrangements. Accordingly, in August 2015, the FASB issued ASU No. 2015-15, “Interest—Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements.” This ASU incorporates guidance from the Securities and Exchange Commission which states that it would not object to an entity deferring and presenting debt issuance costs as an asset and subsequently amortizing the deferred debt issuance costs ratably over the term of the line of credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. This ASU was effective upon issuance. The presentation outlined in ASU No. 2015-15 is consistent with the Company’s historical presentation of line of credit issuance costs; therefore, there is no impact on the Company’s financial statements as a result of adopting this accounting standard in 2015. In April 2015, the FASB issued ASU No. 2015-05, “Intangibles— Goodwill and Other—Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Fees Paid in a Cloud Computing Arrangement.” This ASU provides guidance on how organizations should account for fees paid in a cloud computing arrangement, including helping organizations understand whether their arrangement includes a software license. If the arrangement includes a software license, the software license would be accounted for in a manner consistent with internal-use software. If a cloud-computing arrangement does not include a software license, the customer is Staff_DR_063 Attachment B Page 101 of 160 81 AVISTA required to account for the arrangement as a service contract. This ASU is effective for periods beginning on or after December 15, 2015; however, early adoption is permitted. The Company evaluated this standard and determined that it will not early adopt this standard. Upon adoption, an entity can elect to apply this ASU prospectively or retroactively and disclose the method selected. The Company is evaluating this standard and cannot, at this time, estimate the potential impact on its future financial condition, results of operations and cash flows. In May 2015, the FASB issued ASU No. 2015-07, “Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent).” This ASU removes, from the fair value hierarchy, investments for which the practical expedient is used to measure fair value at net asset value (NAV). Instead, an entity is required to include those investments as a reconciling line item so that the total fair value amount of investments in the disclosure is consistent with the amount on the balance sheet. Further, entities must provide certain disclosures for investments for which they elect to use the NAV practical expedient to determine fair value. This ASU is effective for periods beginning on or after December 15, 2015 and early adoption is permitted. The Company evaluated this standard and determined that it will early adopt this standard as of December 31, 2015. As required, this ASU is being applied retrospectively to all periods presented. The adoption of this standard did not affect the Company’s future financial condition, results of operations and cash flows; however, it did affect the Company’s disclosures. See Note 10 and 16 for the expanded disclosures surrounding the adoption of this ASU. In November 2015, the FASB issued ASU 2015-17 “Income Taxes (Topic 740)—Balance Sheet Classification of Deferred Taxes,” which requires entities to present DTAs and DTLs as noncurrent in a classified balance sheet. The ASU simplifies the current guidance, which requires entities to separately present DTAs and DTLs as current and noncurrent in a classified balance sheet. This ASU is effective for annual periods beginning after December 15, 2016, and interim periods within those years and early adoption is permitted. In addition, upon adoption, entities are permitted to apply the amendments either prospectively or retrospectively. The Company has evaluated this standard and determined that it will early adopt this standard as of December 31, 2015 and it will apply this ASU on a prospective basis. As such, the Consolidated Balance Sheet as of December 31, 2014 was not adjusted to reflect the new ASU. The Company early adopted this ASU to ease the burden of preparing its financial statements and eliminate the need to evaluate deferred taxes for current and noncurrent presentation. NOTE 3. VARIABLE INTEREST ENTITIES Lancaster Power Purchase Agreement The Company has a PPA for the purchase of all the output of the Lancaster Plant, a 270 MW natural gas-fired combined cycle combustion turbine plant located in Kootenai County, Idaho, owned by an unrelated third-party (Rathdrum Power LLC), through 2026. Avista Corp. has a variable interest in the PPA. Accordingly, Avista Corp. made an evaluation of which interest holders have the power to direct the activities that most significantly impact the economic performance of the entity and which interest holders have the obligation to absorb losses or receive benefits that could be significant to the entity. Avista Corp. pays a fixed capacity and operations and maintenance payment and certain monthly variable costs under the PPA. Under the terms of the PPA, Avista Corp. makes the dispatch decisions, provides all natural gas fuel and receives all of the electric energy output from the Lancaster Plant. However, Rathdrum Power LLC (the owner) controls the daily operation of the Lancaster Plant and makes operating and maintenance decisions. Rathdrum Power LLC controls all of the rights and obligations of the Lancaster Plant after the expiration of the PPA in 2026. It is estimated that the plant will have 15 to 25 years of useful life after that time. Rathdrum Power LLC bears the maintenance risk of the plant and will receive the residual value of the Lancaster Plant. Avista Corp. has no debt or equity investments in the Lancaster Plant and does not provide financial support through liquidity arrangements or other commitments (other than the PPA). Based on its analysis, Avista Corp. does not consider itself to be the primary beneficiary of the Lancaster Plant. Accordingly, neither the Lancaster Plant nor Rathdrum Power LLC is included in Avista Corp.’s consolidated financial statements. The Company has a future contractual obligation of approximately $296.5 million under the PPA (representing the fixed capacity and operations and maintenance payments through 2026) and believes this would be its maximum exposure to loss. However, the Company believes that such costs will be recovered through retail rates. NOTE 4. BUSINESS ACQUISITIONS Alaska Energy and Resources Company On July 1, 2014, the Company acquired AERC, based in Juneau, Alaska, and as of that date, AERC became a wholly-owned subsidiary of Avista Corp. The primary subsidiary of AERC is AEL&P, a regulated utility which provides electric services to approximately 17,000 customers in the City and Borough of Juneau (Juneau), Alaska as of December 31, 2015. In addition to the regulated utility, AERC owns AJT Mining, which is an inactive mining company holding certain properties. The purpose of the acquisition was to expand and diversify Avista Corp.’s energy assets and deliver long-term value to its customers, communities and investors. In connection with the closing, on July 1, 2014 Avista Corp. issued 4,500,014 new shares of common stock to the shareholders of AERC based on a contractual formula that resulted in a price of $32.46 per share, reflecting a purchase price of $170.0 million, plus acquired cash, less outstanding debt and other closing adjustments. The $32.46 price per share of Avista Corp. common stock was determined based on the average closing stock price of Avista Corp. common stock for the 10 consecutive trading days immediately preceding, but not including, the trading day prior to July 1, 2014. This value was used solely for determining the number of shares to issue based on the adjusted contract closing price (see reconciliation below). The fair value of the consideration transferred at the closing date was based on the closing stock price of Avista Corp. common stock on July 1, 2014, which was $33.35 per share. On October 1, 2014, a working capital adjustment was made in accordance with the agreement and plan of merger which resulted in Avista Corp. issuing an additional 1,427 shares of common stock to the shareholders of AERC. The number of shares issued on October 1, 2014 was based on the same contractual formula described above. The fair value of the new shares issued in October was $30.71 per share, which was the closing stock price of Avista Corp. common stock on that date. Staff_DR_063 Attachment B Page 102 of 160 AVISTA 82 The contract acquisition price and the fair value of consideration transferred for AERC were as follows (in thousands, except “per share” and number of shares data): Contract acquisition price (using the calculated $32.46 per share common stock price) Gross contract price $ 170,000 Acquired cash 19,704 Acquired debt (excluding capital lease obligation) (38,832) Other closing adjustments (including the working capital adjustment) 37 Total adjusted contract price $ 150,909 Fair value of consideration transferred Avista Corp. common stock (4,500,014 shares at $33.35 per share) $ 150,075 Avista Corp. common stock (1,427 shares at $30.71 per share) 44 Cash 4,792 Fair value of total consideration transferred $ 154,911 The fair value of assets acquired and liabilities assumed as of July 1, 2014 (after consideration of the working capital adjustment and the income tax true-ups during the second quarter of 2015) were as follows (in thousands): July 1, 2014 Assets Acquired: Current Assets: Cash $ 19,704 Accounts receivable—gross totals $3,928 3,851 Materials and supplies 2,017 Other current assets 999 Total current assets 26,571 Utility Property: Utility plant in service 113,964 Utility property under long-term capital lease 71,007 Construction work in progress 3,440 Total utility property 188,411 Other Non-current Assets: Non-utility property 6,660 Electric plant held for future use 3,711 Goodwill (1) 52,426 Other deferred charges and non-current assets 5,368 Total other non-current assets 68,165 Total assets $ 283,147 Liabilities Assumed: Current Liabilities: Accounts payable $ 700 Current portion of long-term debt and capital lease obligations 3,773 Other current liabilities (1) 2,807 Total current liabilities 7,280 Long-term debt 37,227 Capital lease obligations 68,840 Other non-current liabilities and deferred credits (1) 14,889 Total liabilities $ 128,236 Total net assets acquired $ 154,911 (1) During the second quarter of 2015, the Company recorded a reduction to goodwill of approximately $0.3 million due to income tax-related adjustments. After consideration of the goodwill adjustment in the second quarter of 2015, the transaction resulted in a total amount of goodwill of $52.4 million. The goodwill associated with this acquisition is not deductible for tax purposes. Staff_DR_063 Attachment B Page 103 of 160 83 AVISTA The majority of AERC’s operations are subject to the rate-setting authority of the RCA and are accounted for pursuant to GAAP, including the accounting guidance for regulated operations. The rate-setting and cost recovery provisions currently in place for AERC’s regulated operations provide revenues derived from costs, including a return on investment, of assets and liabilities included in rate base. Due to this regulation, the fair values of AERC’s assets and liabilities subject to these rate-setting provisions are assumed to approximate their carrying values. There were not any identifiable intangible assets associated with this acquisition. The excess of the purchase consideration over the estimated fair values of the assets acquired and liabilities assumed was recognized as goodwill at the acquisition date. The goodwill reflects the value paid for the expected continued growth of a rate-regulated business located in a defined service area with a constructive regulatory environment, the attractiveness of stable, growing cash flows, as well as providing a platform for potential future growth outside of the rate-regulated electric utility in Alaska and potential additional utility investment. The following table summarizes the supplemental pro forma information for the years ended December 31 related to the acquisition of AERC as if the acquisition had occurred on January 1, 2013 (dollars in thousands—unaudited): 2015 2014 2013 Actual Avista Corp. revenues from continuing operations (excluding AERC) $ 1,439,807 $ 1,450,918 $ 1,441,744 Supplemental pro forma AERC revenues (1) 44,969 46,467 41,594 Total pro forma revenues 1,484,776 1,497,385 1,483,338 Actual AERC revenues included in Avista Corp. revenues (1) 44,969 21,644 — Actual Avista Corp. net income from continuing operations attributable to Avista Corp. shareholders (excluding AERC) 111,772 116,665 104,273 Actual Avista Corp. net income from discontinued operations attributable to Avista Corp. shareholders 5,147 72,224 6,804 Adjustment to Avista Corp.’s net income for acquisition costs (net of tax) (2) 22 870 (892) Supplemental pro forma AERC net income (1) 6,308 8,806 9,328 Total pro forma net income 123,249 198,565 119,513 Actual AERC net income included in Avista Corp. net income (1) $ 6,308 $ 3,152 $ — (1) AERC was acquired on July 1, 2014; therefore, all the revenues and net income for the second half of 2014 and all of 2015 are actual amounts that are included in Avista Corp.’s overall results. All revenue and net income amounts prior to July 1, 2014 are supplemental pro forma amounts and are excluded from Avista Corp.’s overall results. (2) This adjustment is to treat all transaction costs as if they occurred on January 1, 2013 and to remove them from the periods in which they actually occurred. The transaction costs were expensed and presented in the Consolidated Statements of Income in other operating expenses within utility operating expenses. Since the start of the transaction through December 31, 2015, Avista Corp. has expensed $3.0 million (pre-tax) in total transaction fees. In addition to the amounts expensed, through December 31, 2015, Avista Corp. has included $0.4 million in fees associated with the issuance of common stock for the transaction as a reduction to common stock. These fees do not impact the supplemental pro forma information above. NOTE 5. DISCONTINUED OPERATIONS On June 30, 2014, Avista Capital completed the sale of its interest in Ecova to Cofely USA Inc., an indirect subsidiary of GDF SUEZ, a French multinational utility company, and an unrelated party to Avista Corp. The sales price was $335.0 million in cash, less the payment of debt and other customary closing adjustments. At the closing of the transaction on June 30, 2014, Ecova became a wholly-owned subsidiary of Cofely USA Inc. and the Company has not had and will not have any further involvement with Ecova after such date. The purchase price of $335.0 million, as adjusted, was divided among the security holders of Ecova, including minority shareholders, option holders and a warrant holder, pro rata based on ownership. Approximately $16.8 million (5 percent of the purchase price) was held in escrow for 15 months from the closing of the transaction to satisfy certain indemnification obligations under the merger agreement (Escrow). An additional $1.0 million was held in escrow pending resolution of adjustments to working capital. The indemnification escrow and the working capital adjustment escrow amounts above represent the full amounts to be divided among all security holders pro rata based on ownership. As expected, no claims were made against the Escrow as of September 30, 2015 (the end of the claims period) and accordingly, all Escrow amounts were released in October 2015 and the Company received its full portion of the Escrow proceeds together with the remainder of the working capital adjustment escrow for a total amount of $13.8 million. After consideration of the escrow amounts received, the sales transaction provided cash proceeds to Avista Corp., net of debt, payment to option and minority holders, income taxes and transaction expenses, of $143.7 million and resulted in a net gain of $74.8 million. Almost all of the net gain was recognized in 2014 with some true-ups during 2015. Staff_DR_063 Attachment B Page 104 of 160 AVISTA 84 The summary of cash proceeds associated with the sales transaction are as follows (in thousands): Reconciliation to Statement of Cash Flows Contract price $ 335,000 Closing adjustments 4,103 Litigation settlement at Ecova 588 Gross proceeds from sale (1) 339,691 Cash sold in the transaction (95,932) Gross proceeds from sale of Ecova—net of cash sold (per Statement of Cash Flows) (2) $ 243,759 Reconciliation of Total Net Proceeds Gross proceeds from sale (1) $ 339,691 Repayment of long-term borrowings under committed line of credit (40,000) Payment to option holders and redeemable noncontrolling interests (20,871) Payment to noncontrolling interests (54,179) Transaction expenses withheld from proceeds (5,461) Net proceeds to Avista Capital (prior to tax payments) (2) 219,180 Tax payments made in 2014 (74,842) Tax payments made in 2015 (590) Total net proceeds related to sales transaction $ 143,748 (1) Of this total amount, approximately $16.8 million was held in escrow for 15 months from the transaction closing date for any indemnity claims and an additional $1.0 million was held in escrow pending resolution of adjustments to working capital. Both of these escrow accounts were resolved during 2015. (2) Of the total gross proceeds and total net proceeds received, approximately $229.9 million and $205.4 million was received in 2014, respectively, with the remainder being received in 2015. Prior to the completion of the sales transaction, Ecova was a reportable business segment. The major classes of assets and liabilities and their carrying amounts immediately prior to the completion of the sales transaction were as follows: June 30, 2014 Assets: Current Assets: Cash and cash equivalents $ 95,932 Accounts and notes receivable—less allowances of $410 32,070 Investments and funds held for clients 114,598 Income taxes receivable 2,548 Other current assets 8,908 Total current assets 254,056 Other Non-current Assets: Goodwill 71,123 Intangible assets—net of accumulated amortization of $42,266 37,185 Other property and investments—net 4,656 Total other non-current assets 112,964 Total assets $ 367,020 Liabilities: Current Liabilities: Accounts payable $ 72,453 Client fund obligations 115,333 Current portion of long-term debt 67 Other current liabilities 35,329 Total current liabilities 223,182 Long-term borrowings under committed line of credit 40,000 Other non-current liabilities 2,117 Total liabilities $ 265,299 Staff_DR_063 Attachment B Page 105 of 160 85 AVISTA Amounts reported in discontinued operations for 2013 through 2015 relate solely to the Ecova business segment. The following table presents amounts that were included in discontinued operations for the years ended December 31 (dollars in thousands): 2015 2014 2013 Revenues $ — $ 87,534 $ 176,761 Gain on sale of Ecova (1) 777 160,612 — Transaction expenses and accelerated employee benefits (2) 71 9,062 — Gain on sale of Ecova, net of transaction expenses 706 151,550 — Income before income taxes 706 156,025 13,177 Income tax expense (benefit) (3) (4,441) 83,614 5,216 Net income from discontinued operations 5,147 72,411 7,961 Net income attributable to noncontrolling interests — (187) (1,157) Net income from discontinued operations attributable to Avista Corp. shareholders $ 5,147 $ 72,224 $ 6,804 (1) This represents the gross gain recorded to discontinued operations. The total gain net of taxes and transactions expenses is $74.8 million, of which $69.7 million was recognized during 2014. (2) Avista Corp.’s portion of the total transaction expenses was $9.1 million (including amounts which were withheld from the transaction net proceeds) and this was recognized during the second and third quarters of 2014 and the third and fourth quarters of 2015. All transaction expenses paid on the Ecova sale (including Avista Corp.’s portion and the portion attributable to the minority interest holders of Ecova) were $11.1 million, of which $5.5 million was withheld from the net proceeds and the remainder was paid during the second and third quarters of 2014. The transaction expenses were for legal, accounting and other consulting fees, and the accelerated employee benefits related to employee stock options which were settled in accordance with the Ecova equity plan. (3) The tax benefit during 2015 primarily resulted from the reversal of a valuation allowance against net operating losses at Ecova because the net operating losses were deemed realizable under the current tax code. NOTE 6. DERIVATIVES AND RISK MANAGEMENT The disclosures below in Note 6 apply only to Avista Corp. and Avista Utilities; AERC and its primary subsidiary AEL&P do not enter into derivative instruments. Energy Commodity Derivatives Avista Utilities is exposed to market risks relating to changes in electricity and natural gas commodity prices and certain other fuel prices. Market risk is, in general, the risk of fluctuation in the market price of the commodity being traded and is influenced primarily by supply and demand. Market risk includes the fluctuation in the market price of associated derivative commodity instruments. Avista Utilities utilizes derivative instruments, such as forwards, futures, swaps and options in order to manage the various risks relating to these commodity price exposures. The Company has an energy resources risk policy and control procedures to manage these risks. As part of the Company’s resource procurement and management operations in the electric business, the Company engages in an ongoing process of resource optimization, which involves the economic selection from available energy resources to serve the Company’s load obligations and the use of these resources to capture available economic value. The Company transacts in wholesale markets by selling and purchasing electric capacity and energy, fuel for electric generation, and derivative contracts related to capacity, energy and fuel. Such transactions are part of the process of matching resources with load obligations and hedging the related financial risks. These transactions range from terms of intra-hour up to multiple years. As part of its resource procurement and management of its natural gas business, Avista Utilities makes continuing projections of its natural gas loads and assesses available natural gas resources including natural gas storage availability. Natural gas resource planning typically includes peak requirements, low and average monthly requirements and delivery constraints from natural gas supply locations to Avista Utilities’ distribution system. However, daily variations in natural gas demand can be significantly different than monthly demand projections. On the basis of these projections, Avista Utilities plans and executes a series of transactions to hedge a portion of its projected natural gas requirements through forward market transactions and derivative instruments. These transactions may extend as much as four natural gas operating years (November through October) into the future. Avista Utilities also leaves a significant portion of its natural gas supply requirements unhedged for purchase in short-term and spot markets. Staff_DR_063 Attachment B Page 106 of 160 AVISTA 86 The following table presents the underlying energy commodity derivative volumes as of December 31, 2015 that are expected to be settled in each respective year (in thousands of MWhs and mmBTUs): Purchases Sales Electric Derivatives Gas Derivatives Electric Derivatives Gas Derivatives Physical (1) Financial (1) Physical (1) Financial (1) Physical (1) Financial (1) Physical (1) Financial (1) Year MWh MWh mmBTUs mmBTUs MWh MWh mmBTUs mmBTUs 2016 407 1,954 17,252 142,693 280 2,656 3,182 112,233 2017 397 97 675 49,200 255 483 1,360 26,965 2018 397 — — 15,118 286 — 1,360 2,738 2019 235 — 305 6,935 158 — 1,345 — 2020 — — 455 905 — — 1,430 — Thereafter — — — — — — 1,060 — (1) Physical transactions represent commodity transactions in which Avista Utilities will take or make delivery of either electricity or natural gas; financial transactions represent derivative instruments with delivery of cash in the amount of gain or loss but with no physical delivery of the commodity, such as futures, swaps, options, or forward contracts. The electric and natural gas derivative contracts above will be included in either power supply costs or natural gas supply costs during the period they are settled and will be included in the various recovery mechanisms (ERM, PCA, and PGAs), or in the general rate case process, and are expected to be collected through retail rates from customers. Foreign Currency Exchange Contracts A significant portion of Avista Utilities’ natural gas supply (including fuel for power generation) is obtained from Canadian sources. Most of those transactions are executed in U.S. dollars, which avoids foreign currency risk. A portion of Avista Utilities’ short-term natural gas transactions and long-term Canadian transportation contracts are committed based on Canadian currency prices and settled within 60 days with U.S. dollars. Avista Utilities hedges a portion of the foreign currency risk by purchasing Canadian currency exchange contracts when such commodity transactions are initiated. This risk has not had a material effect on the Company’s financial condition, results of operations or cash flows and these differences in cost related to currency fluctuations were included with natural gas supply costs for ratemaking. The following table summarizes the foreign currency hedges that the Company has entered into as of December 31 (dollars in thousands): 2015 2014 Number of contracts 24 18 Notional amount (in United States dollars) $ 1,463 $ 5,474 Notional amount (in Canadian dollars) 2,002 6,198 Interest Rate Swap Agreements Avista Corp. is affected by fluctuating interest rates related to a portion of its existing debt, and future borrowing requirements. The Company hedges a portion of its interest rate risk with financial derivative instruments, which may include interest rate swaps and U.S. Treasury lock agreements. These interest rate swaps and U.S. Treasury lock agreements are considered economic hedges against fluctuations in future cash flows associated with anticipated debt issuances. The following table summarizes the interest rate swaps that the Company has outstanding as of the balance sheet date indicated below (dollars in thousands): Mandatory Cash Number of Notional Settlement Balance Sheet Date Contracts Amount Date December 31, 2015 6 115,000 2016 3 45,000 2017 11 245,000 2018 2 30,000 2019 1 20,000 2022 December 31, 2014 5 75,000 2015 5 95,000 2016 3 45,000 2017 9 205,000 2018 Staff_DR_063 Attachment B Page 107 of 160 87 AVISTA During the third quarter 2015, in connection with the execution of a purchase agreement for bonds that the Company issued in December 2015, the Company cash-settled five interest rate swap contracts (notional aggregate amount of $75.0 million) and paid a total of $9.3 million. The interest rate swap contracts were settled in connection with the pricing of $100.0 million of Avista Corp. first mortgage bonds that were issued in December 2015 (see Note 14). Upon settlement of interest rate swaps, the regulatory asset or liability (included as part of long-term debt) is amortized as a component of interest expense over the term of the associated debt. The fair value of outstanding interest rate swaps can vary significantly from period to period depending on the total notional amount of swaps outstanding and fluctuations in market interest rates compared to the interest rates fixed by the swaps. The Company would be required to make cash payments to settle the interest rate swaps if the fixed rates are higher than prevailing market rates at the date of settlement. Conversely, the Company receives cash to settle its interest rate swaps when prevailing market rates at the time of settlement exceed the fixed swap rates. Summary of Outstanding Derivative Instruments The amounts recorded on the Consolidated Balance Sheet as of December 31, 2015 and December 31, 2014 reflect the offsetting of derivative assets and liabilities where a legal right of offset exists. The following table presents the fair values and locations of derivative instruments recorded on the Consolidated Balance Sheet as of December 31, 2015 (in thousands): Fair Value Net Asset (Liability) Gross Gross Collateral in Balance Derivative Balance Sheet Location Asset Liability Netting Sheet Foreign currency contracts Other current liabilities $ 2 $ (19) $ — $ (17) Interest rate contracts Other property and investments—net 23 — — 23 Interest rate contracts Other current liabilities 118 (23,262) 3,880 (19,264) Interest rate contracts Other non-current liabilities and deferred credits 1,407 (62,236) 30,150 (30,679) Commodity contracts Current utility energy commodity derivative assets 1,236 (553) — 683 Commodity contracts Current utility energy commodity derivative liabilities 67,466 (85,409) 3,675 (14,268) Commodity contracts Other non-current liabilities and deferred credits 6,613 (39,033) 10,851 (21,569) Total derivative instruments recorded on the balance sheet $ 76,865 $ (210,512) $ 48,556 $ (85,091) The following table presents the fair values and locations of derivative instruments recorded on the Consolidated Balance Sheet as of December 31, 2014 (in thousands): Fair Value Net Asset (Liability) Gross Gross Collateral in Balance Derivative Balance Sheet Location Asset Liability Netting Sheet Foreign currency contracts Other current liabilities $ 1 $ (21) $ — $ (20) Interest rate contracts Other current assets 966 (506) — 460 Interest rate contracts Other current liabilities — (7,325) — (7,325) Interest rate contracts Other non-current liabilities and deferred credits — (69,737) 28,880 (40,857) Commodity contracts Current utility energy commodity derivative assets 2,063 (538) — 1,525 Commodity contracts Current utility energy commodity derivative liabilities 66,421 (97,586) 13,120 (18,045) Commodity contracts Other non-current liabilities and deferred credits 29,594 (54,077) 2,390 (22,093) Total derivative instruments recorded on the balance sheet $ 99,045 $ (229,790) $ 44,390 $ (86,355) Exposure to Demands for Collateral The Company’s derivative contracts often require collateral (in the form of cash or letters of credit) or other credit enhancements, or reductions or terminations of a portion of the contract through cash settlement, in the event of a downgrade in the Company’s credit ratings or changes in market prices. In periods of price volatility, the level of exposure can change significantly. As a result, sudden and significant demands may be made against the Company’s credit facilities and cash. The Company actively monitors the exposure to possible collateral calls and takes steps to mitigate capital requirements. Staff_DR_063 Attachment B Page 108 of 160 AVISTA 88 The following table presents the Company’s collateral outstanding related to its derivative instruments as of as of December 31 (in thousands): 2015 2014 Energy Commodity Derivatives Cash collateral posted $ 28,716 $ 20,565 Letters of credit outstanding 28,200 14,500 Balance sheet offsetting (cash collateral against net derivative positions) 14,526 15,510 Interest Rate Swaps Cash collateral posted 34,030 28,880 Letters of credit outstanding 9,600 10,900 Balance sheet offsetting (cash collateral against net derivative positions) 34,030 28,880 Certain of the Company’s derivative instruments contain provisions that require the Company to maintain an “investment grade” credit rating from the major credit rating agencies. If the Company’s credit ratings were to fall below “investment grade,” it would be in violation of these provisions, and the counterparties to the derivative instruments could request immediate payment or demand immediate and ongoing collateralization on derivative instruments in net liability positions. The following table presents the aggregate fair value of all derivative instruments with credit-risk-related contingent features that are in a liability position and the amount of additional collateral the Company could be required to post as of December 31 (in thousands): 2015 2014 Energy Commodity Derivatives Liabilities with credit-risk-related contingent features $ 7,090 $ 12,911 Additional collateral to post 6,980 16,227 Interest Rate Swaps Liabilities with credit-risk-related contingent features 85,498 77,568 Additional collateral to post 18,750 19,404 Credit Risk Credit risk relates to the potential losses that the Company would incur as a result of non-performance by counterparties of their contractual obligations to deliver energy or make financial settlements. The Company often extends credit to counterparties and customers and is exposed to the risk that it may not be able to collect amounts owed to the Company. Credit risk includes potential counterparty default due to circumstances: • relating directly to it, • caused by market price changes, and • relating to other market participants that have a direct or indirect relationship with such counterparty. Changes in market prices may dramatically alter the size of credit risk with counterparties, even when conservative credit limits are established. Should a counterparty fail to perform, the Company may be required to honor the underlying commitment or to replace existing contracts with contracts at then-current market prices. The Company enters into bilateral transactions with various counterparties. The Company also transacts in energy and related derivative instruments through clearinghouse exchanges. In addition, the Company has concentrations of credit risk related to geographic location as it operates in the western United States and western Canada. These concentrations of counterparties and concentrations of geographic location may impact the Company’s overall exposure to credit risk because the counterparties may be similarly affected by changes in conditions. The Company maintains credit support agreements with certain counterparties and margin calls are periodically made and/or received. Margin calls are triggered when exposures exceed contractual limits or when there are changes in a counterparty’s creditworthiness. Price movements in electricity and natural gas can generate exposure levels in excess of these contractual limits. Negotiating for collateral in the form of cash, letters of credit, or performance guarantees is common industry practice. NOTE 7. JOINTLY OWNED ELECTRIC FACILITIES The Company has a 15 percent ownership interest in a twin-unit coal-fired generating facility, Colstrip, located in southeastern Montana, and provides financing for its ownership interest in the project. The Company’s share of related fuel costs as well as operating expenses for plant in service are included in the corresponding accounts in the Consolidated Statements of Income. The Company’s share of utility plant in service for Colstrip and accumulated depreciation were as follows as of December 31 (dollars in thousands): 2015 2014 Utility plant in service $ 362,199 $ 350,518 Accumulated depreciation (243,363) (239,845) Staff_DR_063 Attachment B Page 109 of 160 89 AVISTA NOTE 8. PROPERTY, PLANT AND EQUIPMENT The balances of the major classifications of property, plant and equipment are detailed in the following table as of December 31 (dollars in thousands): 2015 2014 Avista Utilities: Electric production $ 1,217,179 $ 1,171,002 Electric transmission 640,586 603,909 Electric distribution 1,468,157 1,360,185 Electric construction work-in-progress (CWIP) and other 358,846 311,807 Electric total 3,684,768 3,446,903 Natural gas underground storage 43,080 41,963 Natural gas distribution 878,982 810,487 Natural gas CWIP and other 62,024 57,088 Natural gas total 984,086 909,538 Common plant (including CWIP) 456,796 394,027 Total Avista Utilities 5,125,650 4,750,468 AEL&P: Electric production 72,292 71,969 Electric transmission 18,817 18,392 Electric distribution 19,005 17,936 Electric production held under long-term capital lease 71,007 71,007 Electric CWIP and other 16,971 7,893 Electric total 198,092 187,197 Common plant 8,133 8,155 Total AEL&P 206,225 195,352 Other (1) 25,709 25,803 Total $ 5,357,584 $ 4,971,623 (1) Included in other property and investments—net on the Consolidated Balance Sheets. Accumulated depreciation was $10.6 million as of December 31, 2015 and $10.8 million as of December 31, 2014 for the other businesses. The decrease in accumulated depreciation for the other businesses was due to the sale of certain assets which were nearing the end of their useful lives. NOTE 9. ASSET RETIREMENT OBLIGATIONS See Note 1 for a discussion of the Company’s accounting policy associated with AROs. Specifically, the Company has recorded liabilities for future AROs to: • restore coal ash containment ponds at Colstrip, • cap a landfill at the Kettle Falls Plant, • remove plant and restore the land at the Coyote Springs 2 site at the termination of the land lease, and • dispose of PCBs in certain transformers. Due to an inability to estimate a range of settlement dates, the Company cannot estimate a liability for the: • removal and disposal of certain transmission and distribution assets, and • abandonment and decommissioning of certain hydroelectric generation and natural gas storage facilities. On April 17, 2015, the EPA published a final rule regarding CCRs, also termed coal combustion byproducts or coal ash in the Federal Register and this rule became effective on October 15, 2015. Colstrip, of which Avista Corp. is a 15 percent owner of units 3 and 4, produces this byproduct. The rule establishes technical requirements for CCR landfills and surface impoundments under Subtitle D of the Resource Conservation and Recovery Act, the nation’s primary law for regulating solid waste. The Company, in conjunction with the other Colstrip owners, is developing a multi-year compliance plan to strategically address the new CCR requirements and existing State obligations while maintaining operational stability. During the second quarter of 2015, the operator of Colstrip provided an initial cost estimate of the expected retirement costs associated with complying with the new CCR rule and this estimate was subsequently updated during the fourth quarter of 2015. Based on the initial assessments, Avista Corp. recorded an increase to its ARO of $12.5 million during 2015 with a corresponding increase in the cost basis of the utility plant. The actual asset retirement costs related to the new CCR rule requirements may vary substantially from the estimates used to record the increased obligation due to uncertainty about the compliance strategies that will be used and the preliminary nature of available data used to estimate costs, such as the quantity of coal ash present at certain sites and the volume of fill that will be needed to cap and cover certain impoundments. Avista Corp. will coordinate with the plant operator and continue to gather additional data in future periods to Staff_DR_063 Attachment B Page 110 of 160 AVISTA 90 make decisions about compliance strategies and the timing of closure activities. As additional information becomes available, Avista Corp. will update the ARO for these changes in estimates, which could be material. The Company expects to seek recovery of any increased costs related to complying with the new rule through customer rates. The following table documents the changes in the Company’s asset retirement obligation during the years ended December 31 (dollars in thousands): 2015 2014 2013 Asset retirement obligation at beginning of year $ 3,028 $ 2,859 $ 3,168 Liabilities incurred 12,539 — — Liabilities settled (29) (41) (263) Accretion expense (income) 459 210 (46) Asset retirement obligation at end of year $ 15,997 $ 3,028 $ 2,859 NOTE 10. PENSION PLANS AND OTHER POSTRETIREMENT BENEFIT PLANS The pension and other postretirement benefit plans described below only relate to Avista Utilities. AEL&P (not discussed below) participates in a defined contribution multiemployer plan for its union workers and a defined contribution money purchase pension plan for its non-union workers. METALfx (not discussed below) has a defined contribution 401(k) savings plan. None of the subsidiary retirement plans, individually or in the aggregate, are significant to Avista Corp. Avista Utilities The Company has a defined benefit pension plan covering the majority of all regular full-time employees at Avista Utilities that were hired prior to January 1, 2014. Individual benefits under this plan are based upon the employee’s years of service, date of hire and average compensation as specified in the plan. Non-union employees hired on or after January 1, 2014 participate in a defined contribution 401(k) plan in lieu of a defined benefit pension plan. The Company’s funding policy is to contribute at least the minimum amounts that are required to be funded under the Employee Retirement Income Security Act, but not more than the maximum amounts that are currently deductible for income tax purposes. The Company contributed $12.0 million in cash to the pension plan in 2015, $32.0 million in 2014 and $44.3 million in 2013. The Company expects to contribute $12.0 million in cash to the pension plan in 2016. The Company also has a SERP that provides additional pension benefits to executive officers and certain key employees of the Company. The SERP is intended to provide benefits to individuals whose benefits under the defined benefit pension plan are reduced due to the application of Section 415 of the Internal Revenue Code of 1986 and the deferral of salary under deferred compensation plans. The liability and expense for this plan are included as pension benefits in the tables included in this Note. The Company expects that benefit payments under the pension plan and the SERP will total (dollars in thousands): Total 2016 2017 2018 2019 2020 2021-2025 Expected benefit payments $ 29,182 $ 30,260 $ 31,332 $ 32,804 $ 34,430 $ 189,919 The expected long-term rate of return on plan assets is based on past performance and economic forecasts for the types of investments held by the plan. In selecting a discount rate, the Company considers yield rates for highly rated corporate bond portfolios with maturities similar to that of the expected term of pension benefits. The Company provides certain health care and life insurance benefits for eligible retired employees that were hired prior to January 1, 2014. The Company accrues the estimated cost of postretirement benefit obligations during the years that employees provide services. The liability and expense of this plan are included as other postretirement benefits. Non-union employees hired on or after January 1, 2014, will have access to the retiree medical plan upon retirement; however, Avista Corp. will no longer provide a contribution toward their medical premium. The Company has a Health Reimbursement Arrangement (HRA) to provide employees with tax-advantaged funds to pay for allowable medical expenses upon retirement. The amount earned by the employee is fixed on the retirement date based on the employee’s years of service and the ending salary. The liability and expense of the HRA are included as other postretirement benefits. The Company provides death benefits to beneficiaries of executive officers who die during their term of office or after retirement. Under the plan, an executive officer’s designated beneficiary will receive a payment equal to twice the executive officer’s annual base salary at the time of death (or if death occurs after retirement, a payment equal to twice the executive officer’s total annual pension benefit). The liability and expense for this plan are included as other postretirement benefits. The Company expects that benefit payments under other postretirement benefit plans will total (dollars in thousands): Total 2016 2017 2018 2019 2020 2021-2025 Expected benefit payments $ 7,345 $ 7,522 $ 7,713 $ 7,933 $ 6,907 $ 36,560 Staff_DR_063 Attachment B Page 111 of 160 91 AVISTA The Company expects to contribute $7.3 million to other postretirement benefit plans in 2016, representing expected benefit payments to be paid during the year excluding the Medicare Part D subsidy. The Company uses a December 31 measurement date for its pension and other postretirement benefit plans. The following table sets forth the pension and other postretirement benefit plan disclosures as of December 31, 2015 and 2014 and the components of net periodic benefit costs for the years ended December 31, 2015, 2014 and 2013 (dollars in thousands): Other Post- Pension Benefits retirement Benefits 2015 2014 2015 2014 Change in benefit obligation: Benefit obligation as of beginning of year $ 634,674 $ 527,004 $ 127,989 $ 108,249 Service cost 19,791 15,757 2,925 1,844 Interest cost 26,117 26,224 5,158 5,226 Actuarial (gain)/loss (35,790) 97,128 12,668 18,714 Plan change (228) — (1,000) — Transfer of accrued vacation — — — 437 Cumulative adjustment to reclassify liability — — (1,521) — Benefits paid (31,061) (31,439) (7,424) (6,481) Benefit obligation as of end of year $ 613,503 $ 634,674 $ 138,795 $ 127,989 Change in plan assets: Fair value of plan assets as of beginning of year $ 539,311 $ 481,502 $ 31,312 $ 29,732 Actual return on plan assets (4,305) 55,974 (444) 1,580 Employer contributions 12,000 32,000 — — Benefits paid (29,772) (30,165) — — Fair value of plan assets as of end of year $ 517,234 $ 539,311 $ 30,868 $ 31,312 Funded status $ (96,269) $ (95,363) $ (107,927) $ (96,677) Unrecognized net actuarial loss 162,961 175,596 92,433 82,421 Unrecognized prior service cost 25 256 (10,180) (10,379) Prepaid (accrued) benefit cost 66,717 80,489 (25,674) (24,635) Additional liability (162,986) (175,852) (82,253) (72,042) Accrued benefit liability $ (96,269) $ (95,363) $ (107,927) $ (96,677) Accumulated pension benefit obligation $ 542,209 $ 551,615 — — Accumulated postretirement benefit obligation: For retirees $ 65,652 $ 58,276 For fully eligible employees $ 34,498 $ 31,843 For other participants $ 38,645 $ 37,870 Included in accumulated other comprehensive loss (income) (net of tax): Unrecognized prior service cost $ 16 $ 166 $ (6,617) $ (6,747) Unrecognized net actuarial loss 105,925 114,138 60,081 53,574 Total 105,941 114,304 53,464 46,827 Less regulatory asset (99,414) (106,484) (53,341) (46,759) Accumulated other comprehensive loss for unfunded benefit obligation for pensions and other postretirement benefit plans $ 6,527 $ 7,820 $ 123 $ 68 Weighted-average assumptions as of December 31: Discount rate for benefit obligation 4.57% 4.21% 4.57% 4.16% Discount rate for annual expense 4.21% 5.10% 4.16% 5.02% Expected long-term return on plan assets 5.30% 6.60% 6.36% 6.40% Rate of compensation increase 4.87% 4.87% Medical cost trend pre-age 65—initial 7.00% 7.00% Medical cost trend pre-age 65—ultimate 5.00% 5.00% Ultimate medical cost trend year pre-age 65 2022 2021 Medical cost trend post-age 65—initial 7.00% 7.00% Medical cost trend post-age 65—ultimate 5.00% 5.00% Ultimate medical cost trend year post-age 65 2023 2022 Staff_DR_063 Attachment B Page 112 of 160 AVISTA 92 Pension Benefits Other Postretirement Benefits 2015 2014 2013 2015 2014 2013 Components of net periodic benefit cost: Service cost $ 19,791 $ 15,757 $ 19,045 $ 2,925 $ 1,844 $ 4,144 Interest cost 26,117 26,224 23,896 5,158 5,226 5,216 Expected return on plan assets (28,299) (32,131) (27,671) (1,991) (1,903) (1,606) Amortization of prior service cost 2 22 319 (1,199) (1,116) (149) Net loss recognition 9,451 4,731 13,199 5,095 4,289 5,674 Net periodic benefit cost $ 27,062 $ 14,603 $ 28,788 $ 9,988 $ 8,340 $ 13,279 Plan Assets The Finance Committee of the Company’s Board of Directors approves investment policies, objectives and strategies that seek an appropriate return for the pension plan and other postretirement benefit plans and reviews and approves changes to the investment and funding policies. The Company has contracted with investment consultants who are responsible for managing/monitoring the individual investment managers. The investment managers’ performance and related individual fund performance is periodically reviewed by an internal benefits committee and by the Finance Committee to monitor compliance with investment policy objectives and strategies. Pension plan assets are invested in mutual funds, trusts and partnerships that hold marketable debt and equity securities, real estate, absolute return and commodity funds. In seeking to obtain the desired return to fund the pension plan, the investment consultant recommends allocation percentages by asset classes. These recommendations are reviewed by the internal benefits committee, which then recommends their adoption by the Finance Committee. The Finance Committee has established target investment allocation percentages by asset classes and also investment ranges for each asset class. The target investment allocation percentages are typically the midpoint of the established range. The target investment allocation percentages by asset classes are indicated in the table below: 2015 2014 Equity securities 27% 27% Debt securities 58% 58% Real estate 6% 6% Absolute return 9% 9% The fair value of pension plan assets invested in debt and equity securities was based primarily on fair value (market prices). The fair value of investment securities traded on a national securities exchange is determined based on the reported last sales price; securities traded in the over-the-counter market are valued at the last reported bid price. Investment securities for which market prices are not readily available or for which market prices do not represent the value at the time of pricing, the investment manager estimates fair value based upon other inputs (including valuations of securities that are comparable in coupon, rating, maturity and industry). Investments in common/collective trust funds are presented at estimated fair value, which is determined based on the unit value of the fund. Unit value is determined by an independent trustee, which sponsors the fund, by dividing the fund’s net assets by its units outstanding at the valuation date. The Company’s investments in common/collective trusts have redemption limitations that permit quarterly redemptions following notice requirements of 45 to 60 days. The fair values of the closely held investments and partnership interests are based upon the allocated share of the fair value of the underlying assets as well as the allocated share of the undistributed profits and losses, including realized and unrealized gains and losses. Most of the Company’s investments in closely held investments and partnership interests have redemption limitations that range from bi-monthly to semi-annually following redemption notice requirements of 60 to 90 days. One investment in a partnership has a lock-up for redemption currently expiring in 2022 and is subject to extension. The fair value of pension plan assets invested in real estate was determined by the investment manager based on three basic approaches: • properties are externally appraised on an annual basis by independent appraisers, additional appraisals may be performed as warranted by specific asset or market conditions, • property valuations are reviewed quarterly and adjusted as necessary, and • loans are reflected at fair value. The fair value of pension plan assets was determined as of December 31, 2015 and 2014. Effective December 31, 2015, the Company adopted ASU No. 2015-07, “Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent),” which removed from the fair value hierarchy, investments for which the practical expedient is used to measure fair value at net asset value (NAV). In prior years, the Company held investments fair valued using NAV and these amounts were included as level 3 items. This ASU was adopted retrospectively; therefore, the 2014 amounts have been reclassified to conform to the 2015 presentation. Also, since these amounts are no longer included in the fair value hierarchy as level 3 items, the level 3 reconciliations are no longer applicable and have been excluded from this footnote. Staff_DR_063 Attachment B Page 113 of 160 93 AVISTA The following table discloses by level within the fair value hierarchy (see Note 16 for a description of the fair value hierarchy) of the pension plan’s assets measured and reported as of December 31, 2015 at fair value (dollars in thousands): Level 1 Level 2 Level 3 Total Cash equivalents $ 86 $ 10,641 $ — $ 10,727 Fixed income securities: U.S. government issues — 47,845 — 47,845 Corporate issues — 187,308 — 187,308 International issues — 34,458 — 34,458 Municipal issues — 22,416 — 22,416 Mutual funds: U.S. equity securities 87,678 — — 87,678 International equity securities 40,343 — — 40,343 Absolute return (1) 13,996 — — 13,996 Plan assets measured at NAV (not subject to hierarchy disclosure) Common/collective trusts: Real estate — — — 24,147 Partnership/closely held investments: Absolute return (1) — — — 38,302 Private equity funds (2) — — — 73 Real estate — — — 9,941 Total $ 142,103 $ 302,668 $ — $ 517,234 The following table discloses by level within the fair value hierarchy (see Note 16 for a description of the fair value hierarchy) of the pension plan’s assets measured and reported as of December 31, 2014 at fair value (dollars in thousands): Level 1 Level 2 Level 3 Total Cash equivalents $ — $ 3,138 $ — $ 3,138 Fixed income securities: U.S. government issues 19,681 — — 19,681 Corporate issues 104,959 — — 104,959 International issues 19,935 — — 19,935 Municipal issues 2,762 7,788 — 10,550 Mutual funds: Fixed income securities 157,415 8 — 157,423 U.S. equity securities 103,203 — — 103,203 International equity securities 40,838 — — 40,838 Absolute return (1) 15,334 — — 15,334 Plan assets measured at NAV (not subject to hierarchy disclosure) Common/collective trusts: Real estate — — — 21,303 Partnership/closely held investments: Absolute return (1) — — — 36,114 Private equity funds (2) — — — 73 Real estate — — — 6,760 Total $ 464,127 $ 10,934 $ — $ 539,311 (1) This category invests in multiple strategies to diversify risk and reduce volatility. The strategies include: (a) event driven, relative value, convertible, and fixed income arbitrage, (b) distressed investments, (c) long/short equity and fixed income, and (d) market neutral strategies. (2) This category includes private equity funds that invest primarily in U.S. companies. Staff_DR_063 Attachment B Page 114 of 160 AVISTA 94 The fair value of other postretirement plan assets invested in debt and equity securities was based primarily on market prices. The fair value of investment securities traded on a national securities exchange is determined based on the last reported sales price; securities traded in the over-the-counter market are valued at the last reported bid price. Investment securities for which market prices are not readily available or for which market prices do not represent the value at the time of pricing, are fair-valued by the investment manager based upon other inputs (including valuations of securities that are comparable in coupon, rating, maturity and industry). The target asset allocation was 60 percent equity securities and 40 percent debt securities in both 2015 and 2014. The fair value of other postretirement plan assets was determined as of December 31, 2015 and 2014. The following table discloses by level within the fair value hierarchy (see Note 16 for a description of the fair value hierarchy) of other postretirement plan assets measured and reported as of December 31, 2015 at fair value (dollars in thousands): Level 1 Level 2 Level 3 Total Cash equivalents $ — $ 9 $ — $ 9 Mutual funds: Fixed income securities 12,000 — — 12,000 U.S. equity securities 13,224 — — 13,224 International equity securities 5,635 — — 5,635 Total $ 30,859 $ 9 $ — $ 30,868 The following table discloses by level within the fair value hierarchy (see Note 16 for a description of the fair value hierarchy) of other postretirement plan assets measured and reported as of December 31, 2014 at fair value (dollars in thousands): Level 1 Level 2 Level 3 Total Cash equivalents $ — $ 3 $ — $ 3 Mutual funds: Fixed income securities 11,968 — — 11,968 U.S. equity securities 13,210 — — 13,210 International equity securities 6,131 — — 6,131 Total $ 31,309 $ 3 $ — $ 31,312 Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-percentage-point increase in the assumed health care cost trend rate for each year would increase the accumulated postretirement benefit obligation as of December 31, 2015 by $9.7 million and the service and interest cost by $0.5 million. A one-percentage-point decrease in the assumed health care cost trend rate for each year would decrease the accumulated postretirement benefit obligation as of December 31, 2015 by $7.5 million and the service and interest cost by $0.4 million. 401(k) Plans and Executive Deferral Plan Avista Utilities and METALfx have salary deferral 401(k) plans that are defined contribution plans and cover substantially all employees. Employees can make contributions to their respective accounts in the plans on a pre-tax basis up to the maximum amount permitted by law. The respective company matches a portion of the salary deferred by each participant according to the schedule in the respective plan. Employer matching contributions were as follows for the years ended December 31 (dollars in thousands): 2015 2014 2013 Employer 401(k) matching contributions $ 8,011 $ 6,862 $ 6,279 The Company has an Executive Deferral Plan. This plan allows executive officers and other key employees the opportunity to defer until the earlier of their retirement, termination, disability or death, up to 75 percent of their base salary and/or up to 100 percent of their incentive payments. Deferred compensation funds are held by the Company in a Rabbi Trust. There were deferred compensation assets included in other property and investments—net and corresponding deferred compensation liabilities included in other non-current liabilities and deferred credits on the Consolidated Balance Sheets of the following amounts as of December 31 (dollars in thousands): 2015 2014 Deferred compensation assets and liabilities $ 8,093 $ 8,677 Staff_DR_063 Attachment B Page 115 of 160 95 AVISTA NOTE 11. ACCOUNTING FOR INCOME TAXES Income tax expense consisted of the following for the years ended December 31 (dollars in thousands): 2015 2014 2013 Current income tax expense (benefit) $ 12,212 $ (67,059) $ 37,743 Deferred income tax expense 55,237 139,299 20,271 Total income tax expense $ 67,449 $ 72,240 $ 58,014 State income taxes do not represent a significant portion of total income tax expense on the Consolidated Statements of Income for any periods presented. A reconciliation of federal income taxes derived from statutory federal tax rates (35 percent in 2015, 2014 and 2013) applied to income before income taxes as set forth in the accompanying Consolidated Statements of Income is as follows for the years ended December 31 (dollars in thousands): 2015 2014 2013 Federal income taxes at statutory rates $ 64,967 35.0% $ 67,237 35.0% $ 56,821 35.0% Increase (decrease) in tax resulting from: Tax effect of regulatory treatment of utility plant differences 4,358 2.3 4,008 2.1 3,532 2.2 State income tax expense 1,012 0.5 506 0.2 1,553 1.0 Settlement of prior year tax returns and adjustment of tax reserves (992) (0.5) 1,104 0.6 (1,104) (0.7) Manufacturing deduction (1,198) (0.6) (169) (0.1) (2,033) (1.3) Other (698) (0.4) (446) (0.2) (755) (0.5) Total income tax expense $ 67,449 36.3% $ 72,240 37.6% $ 58,014 35.7% Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes and tax credit carryforwards. The total net deferred income tax liability consisted of the following as of December 31 (dollars in thousands): 2015 2014 Deferred income tax assets: Unfunded benefit obligation $ 75,716 $ 72,324 Derivatives 47,009 46,903 Tax credits 15,011 15,080 Power and natural gas deferrals 12,866 3,811 Deferred compensation 10,354 10,796 Other 29,471 20,583 Total gross deferred income tax assets 190,427 169,497 Valuation allowances for deferred tax assets (2,862) (8,145) Total deferred income tax assets after valuation allowances $ 187,565 $ 161,352 Staff_DR_063 Attachment B Page 116 of 160 AVISTA 96 The total net deferred income tax liability consisted of the following as of December 31 (dollars in thousands) (continued): 2015 2014 Deferred income tax liabilities: Differences between book and tax basis of utility plant 723,66 654,321 Regulatory asset on utility, property plant and equipment 36,917 36,504 Regulatory asset for pensions and other postretirement benefits 82,253 82,515 Utility energy commodity derivatives 47,010 46,906 Long-term debt and borrowing costs 14,027 11,484 Settlement with Coeur d’Alene Tribe 12,084 12,458 Other regulatory assets 11,691 9,691 Other 7,399 3,021 Total deferred income tax liabilities 935,042 856,900 Net deferred income tax liability $ 747,477 $ 695,548 Consolidated balance sheet classification of net deferred income taxes: Current deferred income tax asset (1) $ — $ 14,794 Long-term deferred income tax liability (1) 747,477 710,342 Net deferred income tax liability $ 747,477 $ 695,548 (1) Effective December 31, 2015, the Company adopted ASU 2015-17 “Income Taxes (Topic 740)—Balance Sheet Classification of Deferred Taxes,” which requires entities to present DTAs and DTLs as noncurrent in a classified balance sheet versus the previous accounting guidance which required separate presentation of current and noncurrent DTAs and DTLs. The Company has elected to adopt this standard on a prospective basis; therefore, the Consolidated Balance Sheet as of December 31, 2014 has not been adjusted to match the current period presentation. See “Note 2 of the Notes to Consolidated Financial Statements” for further discussion of this ASU. The realization of deferred income tax assets is dependent upon the ability to generate taxable income in future periods. The Company evaluated available evidence supporting the realization of its deferred income tax assets and determined it is more likely than not that deferred income tax assets will be realized. As of December 31, 2015, the Company had $15.3 million of state tax credit carryforwards of which it is expected $2.9 million will expire unused; the Company has reflected the net amount of $12.4 million as an asset at December 31, 2015. State tax credits expire from 2019 to 2028. The Company and its eligible subsidiaries file consolidated federal income tax returns. The Company also files state income tax returns in certain jurisdictions, including Idaho, Oregon and Montana. Subsidiaries are charged or credited with the tax effects of their operations on a stand-alone basis. The Internal Revenue Service (IRS) has completed its examination of all tax years through 2011 and all issues were resolved related to these years. The IRS has not completed an examination of the Company’s 2012 and 2014 federal income tax returns. The Company believes that any open tax years for federal or state income taxes will not result in adjustments that would be significant to the consolidated financial statements. The Company had net regulatory assets related to the probable recovery of certain deferred income tax liabilities from customers through future rates as of December 31 (dollars in thousands): 2015 2014 Regulatory assets for deferred income taxes $ 101,240 $ 100,412 Regulatory liabilities for deferred income taxes 17,609 14,534 NOTE 12. ENERGY PURCHASE CONTRACTS The below discussion only relates to Avista Utilities. The sole energy purchase contract at AEL&P is a PPA for the Snettisham hydroelectric project and it is accounted for as a capital lease. AEL&P does not have any other significant operating agreements or contractual obligations. See Note 14 for further discussion of the Snettisham PPA. Avista Utilities has contracts for the purchase of fuel for thermal generation, natural gas for resale and various agreements for the purchase or exchange of electric energy with other entities. The termination dates of the contracts range from one month to the year 2042. Total expenses for power purchased, natural gas purchased, fuel for generation and other fuel costs, which are included in utility resource costs in the Consolidated Statements of Income, were as follows for the years ended December 31 (dollars in thousands): 2015 2014 2013 Utility power resources $ 511,937 $ 556,915 $ 524,810 Staff_DR_063 Attachment B Page 117 of 160 97 AVISTA The following table details Avista Utilities’ future contractual commitments for power resources (including transmission contracts) and natural gas resources (including transportation contracts) (dollars in thousands): 2016 2017 2018 2019 2020 Thereafter Total Power resources $ 261,560 $ 168,831 $ 149,375 $ 145,074 $ 104,688 $ 838,536 $ 1,668,064 Natural gas resources 79,335 64,400 65,144 57,105 45,446 427,435 738,865 Total $ 340,895 $ 233,231 $ 214,519 $ 202,179 $ 150,134 $ 1,265,971 $ 2,406,929 These energy purchase contracts were entered into as part of Avista Utilities’ obligation to serve its retail electric and natural gas customers’ energy requirements, including contracts entered into for resource optimization. As a result, these costs are recovered either through base retail rates or adjustments to retail rates as part of the power and natural gas cost deferral and recovery mechanisms. The above future contractual commitments for power resources include fixed contractual amounts related to the Company’s contracts with certain PUDs to purchase portions of the output of certain generating facilities. Although Avista Utilities has no investment in the PUD generating facilities, the fixed contracts obligate Avista Utilities to pay certain minimum amounts whether or not the facilities are operating. The cost of power obtained under the contracts, including payments made when a facility is not operating, is included in utility resource costs in the Consolidated Statements of Income. The contractual amounts included above consist of Avista Utilities’ share of existing debt service cost and its proportionate share of the variable operating expenses of these projects. The minimum amounts payable under these contracts are based in part on the proportionate share of the debt service requirements of the PUD’s revenue bonds for which the Company is indirectly responsible. The Company’s total future debt service obligation associated with the revenue bonds outstanding at December 31, 2015 (principal and interest) was $72.0 million. In addition, Avista Utilities has operating agreements, settlements and other contractual obligations related to its generating facilities and transmission and distribution services. The expenses associated with these agreements are reflected as other operating expenses in the Consolidated Statements of Income. The following table details future contractual commitments under these agreements (dollars in thousands): 2016 2017 2018 2019 2020 Thereafter Total Contractual obligations $ 33,694 $ 31,134 $ 26,405 $ 31,117 $ 31,811 $ 192,295 $ 346,456 NOTE 13. COMMITTED LINES OF CREDIT Avista Corp. Avista Corp. has a committed line of credit with various financial institutions in the total amount of $400.0 million that expires in April 2019. The Company has the option to request an extension for an additional one or two years beyond April 2019, provided, 1) that no event of default has occurred and is continuing prior to the requested extension and 2) the remaining term of agreement, including the requested extension period, does not exceed five years. The committed line of credit is secured by non-transferable first mortgage bonds of the Company issued to the agent bank that would only become due and payable in the event, and then only to the extent, that the Company defaults on its obligations under the committed line of credit. The committed line of credit agreement contains customary covenants and default provisions. The credit agreement has a covenant which does not permit the ratio of “consolidated total debt” to “consolidated total capitalization” of Avista Corp. to be greater than 65 percent at any time. As of December 31, 2015, the Company was in compliance with this covenant. Balances outstanding and interest rates of borrowings (excluding letters of credit) under the Company’s revolving committed lines of credit were as follows as of December 31 (dollars in thousands): 2015 2014 Balance outstanding at end of period $ 105,000 $ 105,000 Letters of credit outstanding at end of period $ 44,595 $ 32,579 Average interest rate at end of period 1.18% 0.93% As of December 31, 2015 and 2014, the borrowings outstanding under Avista Corp.’s committed line of credit were classified as short-term borrowings on the Consolidated Balance Sheet. AEL&P AEL&P has a committed line of credit in the amount of $25.0 million that expires in November 2019. As of December 31, 2015, there were no borrowings or letters of credit outstanding under this committed line of credit. The committed line of credit is secured by non-transferable first mortgage bonds of AEL&P issued to the agent bank that would only become due and payable in the event, and then only to the extent, that AEL&P defaults on its obligations under the committed line of credit. The committed line of credit agreement contains customary covenants and default provisions. The credit agreement has a covenant which does not permit the ratio of “consolidated total debt at AEL&P” to “consolidated total capitalization at AEL&P,” including the impact of the Snettisham bonds to be greater than 67.5 percent at any time. As of December 31, 2015, the Company was in compliance with this covenant. Staff_DR_063 Attachment B Page 118 of 160 AVISTA 98 NOTE 14. LONG-TERM DEBT AND CAPITAL LEASES The following details long-term debt outstanding as of December 31 (dollars in thousands): Maturity Interest Year Description Rate 2015 2014 Avista Corp. Secured Long-Term Debt 2016 First Mortgage Bonds 0.84% $ 90,000 $ 90,000 2018 First Mortgage Bonds 5.95% 250,000 250,000 2018 Secured Medium-Term Notes 7.39%–7.45% 22,500 22,500 2019 First Mortgage Bonds 5.45% 90,000 90,000 2020 First Mortgage Bonds 3.89% 52,000 52,000 2022 First Mortgage Bonds 5.13% 250,000 250,000 2023 Secured Medium-Term Notes 7.18%–7.54% 13,500 13,500 2028 Secured Medium-Term Notes 6.37% 25,000 25,000 2032 Secured Pollution Control Bonds (1) (1) 66,700 66,700 2034 Secured Pollution Control Bonds (1) (1) 17,000 17,000 2035 First Mortgage Bonds 6.25% 150,000 150,000 2037 First Mortgage Bonds 5.70% 150,000 150,000 2040 First Mortgage Bonds 5.55% 35,000 35,000 2041 First Mortgage Bonds 4.45% 85,000 85,000 2044 First Mortgage Bonds 4.11% 60,000 60,000 2045 First Mortgage Bonds (2) 4.37% 100,000 — 2047 First Mortgage Bonds 4.23% 80,000 80,000 Total Avista Corp. secured long-term debt 1,536,700 1,436,700 AEL&P Secured Long-Term Debt 2044 First Mortgage Bonds 4.54% 75,000 75,000 Total secured long-term debt 1,611,700 1,511,700 AERC Unsecured Long-Term Debt 2019 Unsecured Term Loan 3.85% 15,000 15,000 Total secured and unsecured long-term debt 1,626,700 1,526,700 Other Long-Term Debt Components Capital lease obligations 68,601 74,149 Settled interest rate swaps (3) (26,515) (17,541) Unamortized debt discount (956) (1,122) Unamortized long-term debt issuance costs (10,852) (11,360) Total 1,656,978 1,570,826 Secured Pollution Control Bonds held by Avista Corporation (1) (83,700) (83,700) Current portion of long-term debt and capital leases (93,167) (6,424) Total long-term debt and capital leases $ 1,480,111 $ 1,480,702 (1) In December 2010, $66.7 million and $17.0 million of the City of Forsyth, Montana Pollution Control Revenue Refunding Bonds (Avista Corporation Colstrip Project) due in 2032 and 2034, respectively, which had been held by Avista Corp. since 2008 and 2009, respectively, were refunded by new bond issues (Series 2010A and Series 2010B). The new bonds were not offered to the public and were purchased by Avista Corp. due to market conditions. The Company expects that at a later date, subject to market conditions, these bonds may be remarketed to unaffiliated investors. So long as Avista Corp. is the holder of these bonds, the bonds will not be reflected as an asset or a liability on Avista Corp.’s Consolidated Balance Sheets. (2) In December 2015, Avista Corp. issued $100.0 million of first mortgage bonds to five institutional investors in a private placement transaction. The first mortgage bonds bear an interest rate of 4.37 percent and mature in 2045. The total net proceeds from the sale of the new bonds were used to repay a portion of the borrowings outstanding under the Company’s $400.0 million committed line of credit and for general corporate purposes. (3) Upon settlement of interest rate swaps, these are recorded as a regulatory asset or liability and included as part of long-term debt above. They are amortized as a component of interest expense over the life of the associated debt and included as a part of the Company’s cost of debt calculation for ratemaking purposes. Staff_DR_063 Attachment B Page 119 of 160 99 AVISTA The following table details future long-term debt maturities including long-term debt to affiliated trusts (see Note 15) (dollars in thousands): 2016 2017 2018 2019 2020 Thereafter Total Debt maturities $ 90,000 $ — $ 272,500 $ 105,000 $ 52,000 $ 1,075,047 $ 1,594,547 Substantially all Avista Utilities’ and AEL&P’s owned properties are subject to the lien of their respective mortgage indentures. Under the Mortgages and Deeds of Trust (Mortgages) securing their first mortgage bonds (including secured medium-term notes), Avista Utilities and AEL&P may each issue additional first mortgage bonds under their specific mortgage in an aggregate principal amount equal to the sum of: 1) 662/3 percent of the cost or fair value (whichever is lower) of property additions at each entity which have not previously been made the basis of any application under the Mortgages, or 2) an equal principal amount of retired first mortgage bonds at each entity which have not previously been made the basis of any application under the Mortgages, or 3) deposit of cash. However, Avista Utilities and AEL&P may not individually issue any additional first mortgage bonds (with certain exceptions in the case of bonds issued on the basis of retired bonds) unless the particular entity issuing the bonds has “net earnings” (as defined in the Mortgages) for any period of 12 consecutive calendar months out of the preceding 18 calendar months that were at least twice the annual interest requirements on all mortgage securities at the time outstanding, including the first mortgage bonds to be issued, and on all indebtedness of prior rank. As of December 31, 2015, property additions and retired bonds would have allowed, and the net earnings test would not have prohibited, the issuance of $1.1 billion in aggregate principal amount of additional first mortgage bonds at Avista Utilities and $5.0 million at AEL&P. See Note 13 for information regarding first mortgage bonds issued to secure the Company’s obligations under its committed line of credit agreement. Snettisham Capital Lease Obligation Included in long-term capital leases above is a power purchase agreement between AEL&P and AIDEA, an agency of the State of Alaska, under which AEL&P has a take-or-pay obligation, expiring in December 2038, to purchase all the output of the 78 MW Snettisham hydroelectric project. For accounting purposes, this power purchase agreement is treated as a capital lease. The balances related to the Snettisham capital lease obligation as of December 31 were as follows (dollars in thousands): 2015 2014 Capital lease obligation (1) $ 64,455 $ 69,955 Capital lease asset (2)71,007 71,007 Accumulated amortization of capital lease asset (2)5,462 1,821 (1) The capital lease obligation amount is equal to the amount of AIDEA’s revenue bonds outstanding. (2) These amounts are included in utility plant in service on the Consolidated Balance Sheet. Interest on the capital lease obligation and amortization of the capital lease asset are included in utility resource costs in the Consolidated Statements of Income and totaled the following amounts for the years ended December 31 (dollars in thousands): 2015 2014 Interest on capital lease obligation $ 3,587 $ 1,908 Amortization of capital lease asset 3,641 1,821 AIDEA issued $100.0 million of revenue bonds in 1998 to finance its acquisition of the project and the payments by AEL&P were designed to be more than sufficient to enable the AIDEA to pay the principal of and interest on its revenue bonds, which bore interest at rates ranging from 4.9 percent to 6.0 percent and were set to mature in January 2034. In August 2015, AIDEA issued $65.7 million of new revenue bonds for the purpose of refunding all of the remaining outstanding revenue bonds for the Snettisham Hydroelectric Project. The new revenue bonds have interest rates ranging from 4.0 percent to 5.0 percent and mature in January 2034. The capital lease obligation on Avista Corp.’s Consolidated Balance Sheet at any given time is equal to the amount of revenue bonds outstanding at that time. AEL&P is scheduled to make its last capital lease payment to AIDEA in December 2033. The payments by AEL&P under the PPA between AEL&P and AIDEA are unconditional, notwithstanding any suspension, reduction or curtailment of the operation of the project. The bonds are payable solely out of AIDEA’s receipts under the power purchase agreement. AEL&P is also obligated to operate, maintain and insure the project. The PPA did not change as a result of the refunding and the lower capital lease payments that resulted from the refunding will be passed through to AEL&P. As a result of the refunding, AEL&P recognized a gain of $3.3 million, which was recorded as a regulatory liability. The benefits from the refunding will eventually be passed through to customers in future periods via lower purchased power costs, after a new general rate case is filed. AEL&P’s new payments for power under the agreement are approximately $10.4 million per year, while the capital lease principal and interest is approximately $5.5 million per year, which is included in the $10.4 million total cost of power. Snettisham Electric Company, a non-operating subsidiary of AERC, has the option to purchase the Snettisham project with certain conditions at any time for the principal amount of the bonds outstanding at that time. While the power purchase agreement is treated as a capital lease for accounting purposes, for ratemaking purposes this agreement is treated as an operating lease with a constant level of annual rental expense (straight line expense). Because of this regulatory treatment, Staff_DR_063 Attachment B Page 120 of 160 AVISTA 100 any difference between the operating lease expense for ratemaking purposes and the expenses recognized under capital lease treatment (interest and depreciation of the capital lease asset) is recorded as a regulatory asset and amortized during the later years of the lease when the capital lease expense is less than the operating lease expense included in base rates. The Company evaluated this agreement to determine if it has a variable interest which must be consolidated. Based on this evaluation, AIDEA will not be consolidated under ASC 810 “Consolidation” because AIDEA is a government agency and ASC 810 has a specific scope exception which does not allow for the consolidation of government organizations. The following table details future capital lease obligations, including interest, under the Snettisham power purchase agreement (dollars in thousands): 2016 2017 2018 2019 2020 Thereafter Total Principal $ 2,295 $ 2,415 $ 2,535 $ 2,660 $ 2,800 $ 51,750 $ 64,455 Interest 3,157 3,042 2,921 2,795 2,662 19,195 33,772 Total $ 5,452 $ 5,457 $ 5,456 $ 5,455 $ 5,462 $ 70,945 $ 98,227 Nonrecourse Long-Term Debt Nonrecourse long-term debt represented the long-term debt of Spokane Energy. To provide funding to acquire a long-term fixed rate electric capacity contract from Avista Corp., Spokane Energy borrowed $145.0 million from a funding trust in December 1998. The long-term debt had scheduled monthly installments and interest at a fixed rate of 8.45 percent and the final payment was made in January 2015. Spokane Energy bore full recourse risk for the debt, which was secured by the fixed rate electric capacity contract and $1.6 million of funds held in a trust account. As of December 31, 2015, there is no obligation remaining. NOTE 15. LONG-TERM DEBT TO AFFILIATED TRUSTS In 1997, the Company issued Floating Rate Junior Subordinated Deferrable Interest Debentures, Series B, with a principal amount of $51.5 million to Avista Capital II, an affiliated business trust formed by the Company. Avista Capital II issued $50.0 million of Preferred Trust Securities with a floating distribution rate of LIBOR plus 0.875 percent, calculated and reset quarterly. The distribution rates paid were as follows during the years ended December 31: 2015 2014 2013 Low distribution rate 1.11% 1.10% 1.11% High distribution rate 1.29% 1.11% 1.19% Distribution rate at the end of the year 1.29% 1.11% 1.11% Concurrent with the issuance of the Preferred Trust Securities, Avista Capital II issued $1.5 million of Common Trust Securities to the Company. These debt securities may be redeemed at the option of Avista Capital II at any time and mature on June 1, 2037. In December 2000, the Company purchased $10.0 million of these Preferred Trust Securities. The Company owns 100 percent of Avista Capital II and has solely and unconditionally guaranteed the payment of distributions on, and redemption price and liquidation amount for, the Preferred Trust Securities to the extent that Avista Capital II has funds available for such payments from the respective debt securities. Upon maturity or prior redemption of such debt securities, the Preferred Trust Securities will be mandatorily redeemed. The Company does not include these capital trusts in its consolidated financial statements as Avista Corp. is not the primary beneficiary. As such, the sole assets of the capital trusts are $51.5 million of junior subordinated deferrable interest debentures of Avista Corp., which are reflected on the Consolidated Balance Sheets. Interest expense to affiliated trusts in the Consolidated Statements of Income represents interest expense on these debentures. Staff_DR_063 Attachment B Page 121 of 160 101 AVISTA NOTE 16. FAIR VALUE The carrying values of cash and cash equivalents, accounts and notes receivable, accounts payable and short-term borrowings are reasonable estimates of their fair values. Long-term debt (including current portion and material capital leases), nonrecourse long-term debt and long-term debt to affiliated trusts are reported at carrying value on the Consolidated Balance Sheets. The fair value hierarchy prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are defined as follows: Level 1—Quoted prices are available in active markets for identical assets or liabilities. Active markets are those in which transactions for the asset or liability occur with sufficient frequency and volume to provide pricing information on an ongoing basis. Level 2—Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Level 3—Pricing inputs include significant inputs that are generally unobservable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. The determination of the fair values incorporates various factors that not only include the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits and letters of credit), but also the impact of Avista Corp.’s nonperformance risk on its liabilities. The following table sets forth the carrying value and estimated fair value of the Company’s financial instruments not reported at estimated fair value on the Consolidated Balance Sheets as of December 31 (dollars in thousands): 2015 2014 Carrying Estimated Carrying Estimated Value Fair Value Value Fair Value Long-term debt (Level 2) $ 951,000 $ 1,055,797 $ 951,000 $ 1,118,972 Long-term debt (Level 3) 592,000 595,018 492,000 527,663 Snettisham capital lease obligation (Level 3) 64,455 63,150 69,955 79,290 Nonrecourse long-term debt (Level 3) — — 1,431 1,440 Long-term debt to affiliated trusts (Level 3) 51,547 36,083 51,547 38,582 These estimates of fair value of long-term debt and long-term debt to affiliated trusts were primarily based on available market information, which generally consists of estimated market prices from third party brokers for debt with similar risk and terms. The price ranges obtained from the third party brokers consisted of par values of 70.00 to 119.70, where a par value of 100.00 represents the carrying value recorded on the Consolidated Balance Sheets. Level 2 long-term debt represents publicly issued bonds with quoted market prices; however, due to their limited trading activity, they are classified as level 2 because brokers must generate quotes and make estimates if there is no trading activity near a period end. Level 3 long-term debt consists of private placement bonds and debt to affiliated trusts, which typically have no secondary trading activity. Fair values in Level 3 are estimated based on market prices from third party brokers using secondary market quotes for debt with similar risk and terms to generate quotes for Avista Corp. bonds. Due to the unique nature of the Snettisham capital lease obligation, the estimated fair value of these items was determined based on a discounted cash flow model using available market information. The Snettisham capital lease obligation was discounted to present value using the Moody’s Aaa Corporate discount rate as published by the Federal Reserve on December 31, 2015. Staff_DR_063 Attachment B Page 122 of 160 AVISTA 102 The following table discloses by level within the fair value hierarchy the Company’s assets and liabilities measured and reported on the Consolidated Balance Sheets as of December 31, 2015 and 2014 at fair value on a recurring basis (dollars in thousands): Counterparty and Cash Collateral Level 1 Level 2 Level 3 Netting (1) Total December 31, 2015 Assets: Energy commodity derivatives $ — $ 74,637 $ — $ (73,954) $ 683 Level 3 energy commodity derivatives: Natural gas exchange agreements — — 678 (678) — Foreign currency derivatives — 2 — (2) — Interest rate swaps — 1,548 — — 1,548 Deferred compensation assets: Fixed income securities (2) 1,727 — — — 1,727 Equity securities (2) 5,761 — — — 5,761 Total $ 7,488 $ 76,187 $ 678 $ (74,634) $ 9,719 Liabilities: Energy commodity derivatives $ — $ 97,193 $ — $ (88,480) $ 8,713 Level 3 energy commodity derivatives: Natural gas exchange agreement — — 5,717 (678) 5,039 Power exchange agreement — — 21,961 — 21,961 Power option agreement — — 124 — 124 Interest rate swaps — 85,498 — — 85,498 Foreign currency derivatives — 19 — (2) 17 Total $ — $ 182,710 $ 27,802 $ (89,160) $ 121,352 December 31, 2014 Assets: Energy commodity derivatives $ — $ 96,729 $ — $ (95,204) $ 1,525 Level 3 energy commodity derivatives: Natural gas exchange agreement — — 1,349 (1,349) — Foreign currency derivatives — 1 — (1) — Interest rate swaps — 966 — (506) 460 Funds held in trust account of Spokane Energy 1,600 — — — 1,600 Deferred compensation assets: Fixed income securities (2) 1,793 — — — 1,793 Equity securities (2) 6,074 — — — 6,074 Total $ 9,467 $ 97,696 $ 1,349 $ (97,060) $ 11,452 Liabilities: Energy commodity derivatives $ — $ 127,094 $ — $ (110,714) $ 16,380 Level 3 energy commodity derivatives: Natural gas exchange agreement — — 1,384 (1,349) 35 Power exchange agreement — — 23,299 — 23,299 Power option agreement — — 424 — 424 Foreign currency derivatives — 21 — (1) 20 Interest rate swaps — 77,568 — (29,386) 48,182 Total $ — $ 204,683 $ 25,107 $ (141,450) $ 88,340 (1) The Company is permitted to net derivative assets and derivative liabilities with the same counterparty when a legally enforceable master netting agreement exists. In addition, the Company nets derivative assets and derivative liabilities against any payables and receivables for cash collateral held or placed with these same counterparties. (2) These assets are trading securities and are included in other property and investments-net on the Consolidated Balance Sheets. Staff_DR_063 Attachment B Page 123 of 160 103 AVISTA Avista Corp. enters into forward contracts to purchase or sell a specified amount of energy at a specified time, or during a specified period, in the future. These contracts are entered into as part of Avista Corp.’s management of loads and resources and certain contracts are considered derivative instruments. The difference between the amount of derivative assets and liabilities disclosed in respective levels and the amount of derivative assets and liabilities disclosed on the Consolidated Balance Sheets is due to netting arrangements with certain counterparties. The Company uses quoted market prices and forward price curves to estimate the fair value of utility derivative commodity instruments included in Level 2. In particular, electric derivative valuations are performed using market quotes, adjusted for periods in between quotable periods. Natural gas derivative valuations are estimated using New York Mercantile Exchange (NYMEX) pricing for similar instruments, adjusted for basin differences, using market quotes. Where observable inputs are available for substantially the full term of the contract, the derivative asset or liability is included in Level 2. To establish fair values for interest rate swaps, the Company uses forward market curves for interest rates for the term of the swaps and discounts the cash flows back to present value using an appropriate discount rate. The discount rate is calculated by third party brokers according to the terms of the swap agreements and evaluated by the Company for reasonableness, with consideration given to the potential non-performance risk by the Company. Future cash flows of the interest rate swaps are equal to the fixed interest rate in the swap compared to the floating market interest rate multiplied by the notional amount for each period. To establish fair value for foreign currency derivatives, the Company uses forward market curves for Canadian dollars against the US dollar and multiplies the difference between the locked-in price and the market price by the notional amount of the derivative. Forward foreign currency market curves are provided by third-party brokers. The Company’s credit spread is factored into the locked-in price of the foreign exchange contracts. Deferred compensation assets and liabilities represent funds held by the Company in a Rabbi Trust for an executive deferral plan. These funds consist of actively traded equity and bond funds with quoted prices in active markets. The balance disclosed in the table above excludes cash and cash equivalents of $0.6 million as of December 31, 2015 and $0.8 million as of December 31, 2014. Level 3 Fair Value Under the power exchange agreement the Company purchases power at a price that is based on the on the average operating and maintenance (O&M) charges from three surrogate nuclear power plants around the country. To estimate the fair value of this agreement the Company estimates the difference between the purchase price based on the future O&M charges and forward prices for energy. The Company compares the Level 2 brokered quotes and forward price curves described above to an internally developed forward price which is based on the average O&M charges from the three surrogate nuclear power plants for the current year. Because the nuclear power plant O&M charges are only known for one year, all forward years are estimated assuming an annual escalation. In addition to the forward price being estimated using unobservable inputs, the Company also estimates the volumes of the transactions that will take place in the future based on historical average transaction volumes per delivery year (November to April). Significant increases or decreases in any of these inputs in isolation would result in a significantly higher or lower fair value measurement. Generally, a change in the current year O&M charges for the surrogate plants is accompanied by a directionally similar change in O&M charges in future years. There is generally not a correlation between external market prices and the O&M charges used to develop the internal forward price. For the power commodity option agreement, the Company uses the Black-Scholes-Merton valuation model to estimate the fair value, and this model includes significant inputs not observable or corroborated in the market. These inputs include: 1) the strike price (which is an internally derived price based on a combination of generation plant heat rate factors, natural gas market pricing, delivery and other O&M charges), 2) estimated delivery volumes, and 3) volatility rates for periods beyond January 2018. Significant increases or decreases in any of these inputs in isolation would result in a significantly higher or lower fair value measurement. Generally, changes in overall commodity market prices and volatility rates are accompanied by directionally similar changes in the strike price and volatility assumptions used in the calculation. For the natural gas commodity exchange agreement, the Company uses the same Level 2 brokered quotes described above; however, the Company also estimates the purchase and sales volumes (within contractual limits) as well as the timing of those transactions. Changing the timing of volume estimates changes the timing of purchases and sales, impacting which brokered quote is used. Because the brokered quotes can vary significantly from period to period, the unobservable estimates of the timing and volume of transactions can have a significant impact on the calculated fair value. The Company currently estimates volumes and timing of transactions based on a most likely scenario using historical data. Historically, the timing and volume of transactions have not been highly correlated with market prices and market volatility. Staff_DR_063 Attachment B Page 124 of 160 AVISTA 104 The following table presents the quantitative information which was used to estimate the fair values of the Level 3 assets and liabilities above as of December 31, 2015 (dollars in thousands): Fair Value (Net) at Valuation Unobservable December 31, 2015 Technique Input Range Power exchange agreement $ (21,961) Surrogate facility O&M charges $33.52–$43.65/MWh (1) pricing Escalation factor 3%—2016 to 2019 Transaction volumes 233,054–397,030 MWhs Power option agreement (124) Black-Scholes- Strike price $35.43/MWh—2016 Merton $48.78/MWh—2019 Delivery volumes 157,517–285,979 MWhs Volatility rates 0.20 (2) Natural gas exchange agreement (5,039) Internally derived Forward purchase prices $1.67–$2.84/mmBTU weighted-average Forward sales prices $1.88–$3.68/mmBTU cost of gas Purchase volumes 115,000–310,000 mmBTUs Sales volumes 30,000–310,000 mmBTUs (1) The average O&M charges for the delivery year beginning in November 2015 were $39.27 per MWh. For ratemaking purposes the average O&M charges to be included for recovery in retail rates vary slightly between regulatory jurisdictions. The average O&M charges for the delivery year beginning in 2015 are $43.52 for Washington and $39.27 for Idaho. (2) The estimated volatility rate of 0.20 is compared to actual quoted volatility rates of 0.37 for 2016 to 0.24 in January 2018. Avista Corp.’s risk management department and accounting department are responsible for developing the valuation methods described above and both groups report to the Chief Financial Officer. The valuation methods, significant inputs and resulting fair values described above are reviewed on at least a quarterly basis by the risk management department and the accounting department to ensure they provide a reasonable estimate of fair value each reporting period. The following table presents activity for energy commodity derivative assets (liabilities) measured at fair value using significant unobservable inputs (Level 3) for the years ended December 31 (dollars in thousands): Natural Gas Power Power Exchange Exchange Option Agreement Agreement Agreement Total Year ended December 31, 2015: Balance as of January 1, 2015 $ (35) $ (23,299) $ (424) $ (23,758) Total gains or losses (realized/unrealized): Included in regulatory assets/liabilities (1) (6,008) (6,198) 300 (11,906) Settlements 1,004 7,536 — 8,540 Ending balance as of December 31, 2015 (2) $ (5,039) $ (21,961) $ (124) $ (27,124) Year ended December 31, 2014: Balance as of January 1, 2014 $ (1,219) $ (14,441) $ (775) $ (16,435) Total gains or losses (realized/unrealized): Included in regulatory assets/liabilities (1) 3,873 (10,002) 351 (5,778) Settlements (2,689) 1,144 — (1,545) Ending balance as of December 31, 2014 (2) $ (35) $ (23,299) $ (424) $ (23,758) Year ended December 31, 2013: Balance as of January 1, 2013 $ (2,379) $ (18,692) $ (1,480) $ (22,551) Total gains or losses (realized/unrealized): Included in regulatory assets/liabilities (1) 2,298 1,017 705 4,020 Settlements (1,138) 3,234 — 2,096 Ending balance as of December 31, 2013 (2) $ (1,219) $ (14,441) $ (775) $ (16,435) (1) All gains and losses are included in other regulatory assets and liabilities. There were no gains and losses included in either net income or other comprehensive income during any of the periods presented in the table above. (2) There were no purchases, issuances or transfers from other categories of any derivatives instruments during the periods presented in the table above. Staff_DR_063 Attachment B Page 125 of 160 105 AVISTA NOTE 17. COMMON STOCK The Company had a Direct Stock Purchase and Dividend Reinvestment Plan under which the Company’s shareholders could automatically reinvest their dividends and make optional cash payments for the purchase of the Company’s common stock at current market value. This plan was terminated by the Company in 2014. Shares issued under this plan in 2014 and 2013 are disclosed in the Consolidated Statements of Equity and Redeemable Noncontrolling Interests. The payment of dividends on common stock could be limited by: • certain covenants applicable to preferred stock (when outstanding) contained in the Company’s Restated Articles of Incorporation, as amended (currently there are no preferred shares outstanding), • certain covenants applicable to the Company’s outstanding long-term debt and committed line of credit agreements, • the hydroelectric licensing requirements of section 10(d) of the FPA (see Note 1), and • certain requirements under the Public Utility Commission of Oregon (OPUC) approval of the AERC acquisition. As of July 1, 2015 (one year following the acquisition date), the OPUC does not permit one-time or special dividends from AERC to Avista Corp. and does not permit Avista Utilities’ total equity to total capitalization to be less than 40 percent, without approval from the OPUC. However, the OPUC approval does allow for regular distributions of AERC earnings to Avista Corp. as long as AERC remains sufficiently capitalized and insured. The Company declared the following dividends for the year ended December 31: 2015 2014 2013 Dividends paid per common share $ 1.32 $ 1.27 $ 1.22 Under the covenant applicable to the Company’s committed line of credit agreement, which does not permit the ratio of “consolidated total debt” to “consolidated total capitalization” to be greater than 65 percent at any time, the amount of retained earnings available for dividends at December 31, 2015 was limited to approximately $385.3 million. Under the requirements of the OPUC approval of the AERC acquisition as outlined above, the amount available for dividends at December 31, 2015 was limited to approximately $231.0 million. The Company has 10 million authorized shares of preferred stock. The Company did not have any preferred stock outstanding as of December 31, 2015 and 2014. Stock Repurchase Programs During 2014, Avista Corp.’s Board of Directors approved a program to repurchase up to 4 million shares of the Company’s outstanding common stock (2014 program). Repurchases of common stock under this program began on July 7, 2014 and the program expired on December 31, 2014. Repurchases were made in the open market or in privately negotiated transactions. Under the 2014 program the Company repurchased 2,529,615 shares at a total cost of $79.9 million and an average cost of $31.57 per share. The Company did not make any repurchases under this program subsequent to October 2014. Avista Corp. initiated a second stock repurchase program on January 2, 2015 that expired on March 31, 2015 for the repurchase of up to 800,000 shares of the Company’s outstanding common stock (first quarter 2015 program). The number of shares repurchased through the first quarter 2015 program was in addition to the number of shares repurchased under the 2014 program, which expired on December 31, 2014. Under the first quarter 2015 program, the Company repurchased 89,400 shares at a total cost of $2.9 million and an average cost of $32.66 per share. All repurchased shares under the 2014 program and the first quarter 2015 program reverted to the status of authorized but unissued shares. Staff_DR_063 Attachment B Page 126 of 160 AVISTA 106 NOTE 18. EARNINGS PER COMMON SHARE ATTRIBUTABLE TO AVISTA CORPORATION SHAREHOLDERS The following table presents the computation of basic and diluted earnings per common share attributable to Avista Corp. shareholders for the years ended December 31 (in thousands, except per share amounts): 2015 2014 2013 Numerator: Net income from continuing operations attributable to Avista Corp. shareholders $ 118,080 $ 119,817 $ 104,273 Net income from discontinued operations attributable to Avista Corp. shareholders 5,147 72,224 6,804 Subsidiary earnings adjustment for dilutive securities (discontinued operations) — 5 (229) Adjusted net income from discontinued operations attributable to Avista Corp. shareholders for computation of diluted earnings per common share $ 5,147 $ 72,229 $ 6,575 Denominator: Weighted-average number of common shares outstanding—basic 62,301 61,632 59,960 Effect of dilutive securities: Performance and restricted stock awards 407 255 37 Weighted-average number of common shares outstanding—diluted 62,708 61,887 59,997 Earnings per common share attributable to Avista Corp. shareholders—basic: Earnings per common share from continuing operations $ 1.90 $ 1.94 $ 1.74 Earnings per common share from discontinued operations $ 0.08 $ 1.18 $ 0.11 Total earnings per common share attributable to Avista Corp. shareholders—basic $ 1.98 $ 3.12 $ 1.85 Earnings per common share attributable to Avista Corp. shareholders—diluted: Earnings per common share from continuing operations $ 1.89 $ 1.93 $ 1.74 Earnings per common share from discontinued operations $ 0.08 $ 1.17 $ 0.11 Total earnings per common share attributable to Avista Corp. shareholders—diluted $ 1.97 $ 3.10 $ 1.85 There were no shares excluded from the calculation because they were antidilutive. All stock options had exercise prices which were less than the average market price of Avista Corp. common stock during the respective period. NOTE 19. COMMITMENTS AND CONTINGENCIES In the course of its business, the Company becomes involved in various claims, controversies, disputes and other contingent matters, including the items described in this Note. Some of these claims, controversies, disputes and other contingent matters involve litigation or other contested proceedings. For all such matters, the Company intends to vigorously protect and defend its interests and pursue its rights. However, no assurance can be given as to the ultimate outcome of any particular matter because litigation and other contested proceedings are inherently subject to numerous uncertainties. For matters that affect Avista Utilities’ or AEL&P’s operations, the Company intends to seek, to the extent appropriate, recovery of incurred costs through the ratemaking process. California Refund Proceeding Recently, APX, a market maker in these proceedings in whose markets Avista Energy participated in the summer of 2000, has asserted that Avista Energy and its other customer/participants may be responsible for a share of the disgorgement penalty APX may be found to owe to the California parties. The penalty arises as a result of the FERC finding that APX committed violations in the California market in the summer of 2000. APX is making these assertions despite Avista Energy having been dismissed in FERC Opinion No. 536 from the ongoing administrative proceeding at the FERC regarding potential wrongdoing in the California markets in the summer of 2000. APX has identified Avista Energy’s share of APX’s exposure to be as much as $16.0 million even though no wrongdoing allegations are specifically attributable to Avista Energy. Avista Energy believes its settlement insulates it from any such liability and that as a dismissed party it cannot be drawn back into the litigation. Avista Energy intends to vigorously dispute APX’s assertions of indirect liability, but cannot at this time predict the eventual outcome. Pacific Northwest Refund Proceeding In July 2001, the FERC initiated a preliminary evidentiary hearing to develop a factual record as to whether prices for spot market sales of wholesale energy in the Pacific Northwest between December 25, 2000 and June 20, 2001 were just and reasonable. In June 2003, the FERC terminated the Pacific Northwest refund proceedings, after finding that the equities do not justify the imposition of refunds. In August 2007, the Ninth Circuit found that the FERC had failed to take into account new evidence of market manipulation and that such failure was arbitrary and capricious and, accordingly, remanded the case to the FERC, stating that the FERC’s findings must be reevaluated in light of the new evidence. The Ninth Circuit expressly declined to direct the FERC to grant refunds. On October 3, 2011, the FERC issued an Order on Remand. On April 5, 2013, the FERC issued an Order on Rehearing expanding the temporal scope of the proceeding to permit parties to submit evidence on transactions during the period from January 1, 2000 through and including June 20, 2001. The Order on Remand established an evidentiary, trial-type hearing before an ALJ, and reopened the record to permit parties to present evidence of unlawful market activity. The Order on Remand stated that parties seeking refunds must submit evidence demonstrating that specific unlawful market activity occurred, and must demonstrate that such activity directly affected negotiations with respect to the specific contract rate about which they complain. Simply alleging a general link between the dysfunctional spot market in California and the Pacific Northwest spot market would not be sufficient Staff_DR_063 Attachment B Page 127 of 160 107 AVISTA to establish a causal connection between a particular seller’s alleged unlawful activities and the specific contract negotiations at issue. The hearing was conducted in August through October 2013. On July 11, 2012 and March 28, 2013, Avista Energy and Avista Utilities filed settlements of all issues in this docket with regard to the claims made by the City of Tacoma and the California AG (on behalf of CERS). The FERC has approved the settlements and they are final. The remaining direct claimant against Avista Utilities and Avista Energy in this proceeding is the City of Seattle, Washington (Seattle). With regard to the Seattle claims, on March 28, 2014, the Presiding ALJ issued her Initial Decision finding that: 1) Seattle failed to demonstrate that either Avista Utilities or Avista Energy engaged in unlawful market activity and also failed to identify any specific contracts at issue; 2) Seattle failed to demonstrate that contracts with either Avista Utilities or Avista Energy imposed an excessive burden on consumers or seriously harmed the public interest; and that 3) Seattle failed to demonstrate that either Avista Utilities or Avista Energy engaged in any specific violations of substantive provisions of the FPA or any filed tariffs or rate schedules. Accordingly, the ALJ denied all of Seattle’s claims under both section 206 and section 309 of the FPA. On May 22, 2015, the FERC issued its Order on Initial Decision in which it upheld the ALJ’s Initial Decision denying all of Seattle’s claims against Avista Utilities and Avista Energy. Seattle filed a Request for Rehearing of the FERC’s Order on Initial Decision which was denied on December 31, 2015. The Company does not expect that this matter will have a material adverse effect on its financial condition, results of operations or cash flows. Sierra Club and Montana Environmental Information Center Complaint Against the Owners of Colstrip On March 6, 2013, the Sierra Club and Montana Environmental Information Center (MEIC) (collectively “Plaintiffs”), filed a Complaint in the United States District Court for the District of Montana, Billings Division, against the Owners of the Colstrip Generating Project (“Colstrip”). Avista Corp. owns a 15 percent interest in Units 3 & 4 of Colstrip. The other Colstrip Co-Owners are Talen (formerly PPL Montana), Puget Sound Energy, Portland General Electric Company, NorthWestern Energy and PacifiCorp. The Complaint alleges certain violations of the Clean Air Act, including the New Source Review, Title V and opacity requirements. On September 27, 2013, the Plaintiffs filed an Amended Complaint. The Amended Complaint withdrew from the original Complaint fifteen claims related to seven pre-January 1, 2001 Colstrip maintenance projects, upgrade projects and work projects and claims alleging violations of Title V and opacity requirements. The Amended Complaint alleges certain violations of the Clean Air Act and the New Source Review and adds claims with respect to post-January 1, 2001 Colstrip projects. On August 27, 2014, the Plaintiffs filed a Second Amended Complaint. The Second Amended Complaint withdraws from the Amended Complaint five claims and adds one new claim. The Second Amended Complaint alleges certain violations of the Clean Air Act and the New Source Review. The Plaintiffs request that the Court grant injunctive and declaratory relief, order remediation of alleged environmental damages, impose civil penalties, require a beneficial environmental project in the areas affected by the alleged air pollution and require payment of Plaintiffs’ costs of litigation and attorney fees. The Plaintiffs have since indicated that they do not intend to pursue two of the seven projects, leaving a total of five projects remaining. A number of motions for summary judgment were filed by both the Plaintiffs and the defendants. The Court issued its rulings on these motions and, as a result, only two projects remain for trial. The Plaintiffs have filed objections to the order. The case has been bifurcated into separate liability and remedy trials. The Court has set the liability trial date for May 31, 2016. No date has been set for the remedy trial. Management believes that it is reasonably possible that this matter could result in a loss to the Company. However, due to uncertainties concerning this matter, Avista Corp. cannot predict the outcome or determine whether it would have a material impact on the Company. Cabinet Gorge Total Dissolved Gas Abatement Plan Dissolved atmospheric gas levels (referred to as “TDG”) in the Clark Fork River exceed state of Idaho and federal water quality numeric standards downstream of Cabinet Gorge during periods when excess river flows must be diverted over the spillway. Under the terms of the Clark Fork Settlement Agreement as incorporated in Avista Corp.’s FERC license for the Clark Fork Project, Avista Corp. has worked in consultation with agencies, tribes and other stakeholders to address this issue. Under the terms of a gas supersaturation mitigation plan, Avista is reducing TDG by constructing spill crest modifications on spill gates at the dam, and the Company expects to continue spill crest modifications over the next several years, in ongoing consultation with key stakeholders. Avista Corp. cannot at this time predict the outcome or estimate a range of costs associated with this contingency; however, the Company will continue to seek recovery, through the ratemaking process, of all operating and capitalized costs related to this issue. Fish Passage at Cabinet Gorge and Noxon Rapids In 1999, the United States Fish and Wildlife Service (USFWS) listed bull trout as threatened under the Endangered Species Act. In 2010, the USFWS issued a revised designation of critical habitat for bull trout, which includes the lower Clark Fork River. The USFWS issued a final recovery plan in October 2015. The Clark Fork Settlement Agreement describes programs intended to help restore bull trout populations in the project area. Using the concept of adaptive management and working closely with the USFWS, the Company evaluated the feasibility of fish passage at Cabinet Gorge and Noxon Rapids. The results of these studies led, in part, to the decision to move forward with development of permanent facilities, among other bull trout enhancement efforts. Fishway designs for Cabinet Gorge have been completed, and the Company is developing construction cost estimates currently. The Company believes its ongoing efforts through the Clark Fork Settlement Agreement continue to effectively address issues related to bull trout. Avista Corp. cannot at this time predict the outcome or estimate a range of costs associated with this contingency; however, the Company will continue to seek recovery, through the ratemaking process, of all operating and capitalized costs related to fish passage at Cabinet Gorge and Noxon Rapids. Staff_DR_063 Attachment B Page 128 of 160 AVISTA 108 Collective Bargaining Agreements The Company’s collective bargaining agreements with the IBEW represents approximately 45 percent of all of Avista Utilities’ employees. The agreement with the local union in Washington and Idaho representing the majority (approximately 90 percent) of the Avista Utilities’ bargaining unit employees expires in March 2016. In October 2015, a new collective bargaining agreement concerning wages over the three-year period 2016 through 2018 was approved by the local IBEW in Washington and Idaho. The new collective bargaining agreement will be effective in March 2016. A three-year agreement in Oregon, which covers approximately 50 employees, expires in March 2017. A collective bargaining agreement with the local union of the IBEW in Alaska expires in March 2017. The collective bargaining agreement with the IBEW in Alaska represents approximately 54 percent of all AERC employees. The remainder of AERC’s employees are non-union. There is a risk that if collective bargaining agreements expire and new agreements are not reached in each of our jurisdictions, employees could strike. Given the magnitude of employees that are covered by collective bargaining agreements, this could result in disruptions of our operations. However, the Company believes that the possibility of this occurring is remote. Customer Information and Work Management Systems Project Cost Recovery Over the past four years, Avista Corp. has invested significant capital into Project Compass. Project Compass was completed and went into service during the first quarter of 2015. As part of the Washington electric and natural gas general rate cases filed in February 2015 and the Oregon natural gas general rate case filed in May 2015, Avista Utilities requested the full recovery of the Washington and Oregon share of the costs associated with this project. On July 27, 2015, the UTC Staff in the Company’s electric and natural gas general rate cases filed responsive testimony. Included in their testimony was a recommendation to disallow $12.7 million (Washington’s share) of Project Compass costs primarily related to the delay in the completion of the project. In a UTC order received in January 2016, the UTC approved the full recovery of Washington’s share of Project Compass costs with no disallowances. In October 2015, the OPUC staff filed testimony in the Company’s natural gas general rate case which included a recommendation to disallow $1.2 million (Oregon’s share) of Project Compass costs, similar to the initial recommendation in Washington. In January 2016, following the January 2016 UTC order approving the full recovery of Washington’s share of Project Compass costs, the OPUC staff withdrew its proposal for a disallowance, with the exception of an inconsequential amount which is still open for discussion. Other Contingencies In the normal course of business, the Company has various other legal claims and contingent matters outstanding. The Company believes that any ultimate liability arising from these actions will not have a material impact on its financial condition, results of operations or cash flows. It is possible that a change could occur in the Company’s estimates of the probability or amount of a liability being incurred. Such a change, should it occur, could be significant. The Company routinely assesses, based on studies, expert analyses and legal reviews, its contingencies, obligations and commitments for remediation of contaminated sites, including assessments of ranges and probabilities of recoveries from other responsible parties who either have or have not agreed to a settlement as well as recoveries from insurance carriers. The Company’s policy is to accrue and charge to current expense identified exposures related to environmental remediation sites based on estimates of investigation, cleanup and monitoring costs to be incurred. For matters that affect Avista Utilities’ or AEL&P’s operations, the Company seeks, to the extent appropriate, recovery of incurred costs through the ratemaking process. The Company has potential liabilities under the Endangered Species Act for species of fish, plants and wildlife that have either already been added to the endangered species list, listed as “threatened” or petitioned for listing. Thus far, measures adopted and implemented have had minimal impact on the Company. However, the Company will continue to seek recovery, through the ratemaking process, of all operating and capitalized costs related to these issues. Under the federal licenses for its hydroelectric projects, the Company is obligated to protect its property rights, including water rights. In addition, the company holds additional non-hydro water rights. The state of Montana is examining the status of all water right claims within state boundaries through a general adjudication. Claims within the Clark Fork River basin could adversely affect the energy production of the Company’s Cabinet Gorge and Noxon Rapids hydroelectric facilities. The state of Idaho has initiated adjudication in northern Idaho, which will ultimately include the lower Clark Fork River, the Spokane River and the Coeur d’Alene basin. The Company is and will continue to be a participant in these and any other relevant adjudication processes. The complexity of such adjudications makes each unlikely to be concluded in the foreseeable future. As such, it is not possible for the Company to estimate the impact of any outcome at this time. The Company will continue to seek recovery, through the ratemaking process, of all operating and capitalized costs related to this issue. Staff_DR_063 Attachment B Page 129 of 160 109 AVISTA NOTE 20. REGULATORY MATTERS Regulatory Assets and Liabilities The following table presents the Company’s regulatory assets and liabilities as of December 31, 2015 (dollars in thousands): Receiving Regulatory Treatment Remaining Not Expected Amortization Earning Earning Recovery or Total Total Period a Return (1) a Return Refund (2) 2015 2014 Regulatory Assets: Investment in exchange power—net 2019 $ 8,983 $ — $ — $ 8,983 $ 11,433 Regulatory assets for deferred income tax (3) 101,240 — — 101,240 100,412 Regulatory assets for pensions and other postretirement benefit plans (4) — 235,009 — 235,009 235,758 Current regulatory asset for utility derivatives (5) — 17,260 — 17,260 29,640 Unamortized debt repurchase costs (6) 15,520 — — 15,520 17,357 Regulatory asset for settlement with Coeur d’Alene Tribe 2059 46,576 — — 46,576 47,887 Demand side management programs (3) — 3,168 — 3,168 4,603 Montana lease payments (3) 947 — — 947 1,984 Lancaster Plant 2010 net costs 2015 — — — — 1,247 Deferred maintenance costs 2017 — 4,823 — 4,823 5,804 Decoupling 2017 13,312 — — 13,312 — Power deferrals (3) 933 — — 933 8,291 Regulatory asset for interest rate swaps (7) — 83,973 — 83,973 77,063 Non-current regulatory asset for utility derivatives (5) — 32,420 — 32,420 24,483 Other regulatory assets (3) 3,132 7,412 4,924 15,468 13,038 Total regulatory assets $ 190,643 $ 384,065 $ 4,924 $ 579,632 $ 579,000 Regulatory Liabilities: Natural gas deferrals (3) $ 17,880 $ — $ — $ 17,880 $ 3,921 Power deferrals (3) 18,747 — — 18,747 14,186 Regulatory liability for utility plant retirement costs (8) 261,594 — — 261,594 254,140 Income tax related liabilities (3) — 17,609 — 17,609 14,534 Regulatory liability for Spokane Energy (9) — — — — 29,028 Regulatory liability for rate refunds (3) — 8,814 3,423 12,237 10,131 Decoupling 2017 2,373 — — 2,373 — Other regulatory liabilities (3) 2,395 1,048 — 3,443 7,688 Total regulatory liabilities $ 302,989 $ 27,471 $ 3,423 $ 333,883 $ 333,628 (1) Earning a return includes either interest on the regulatory asset/liability or a return on the investment as a component of rate base at the allowed rate of return. (2) Expected recovery is pending regulatory treatment including regulatory assets and liabilities with prior regulatory precedence. (3) Remaining amortization period varies depending on timing of underlying transactions. (4) As the Company has historically recovered and currently recovers its pension and other postretirement benefit costs related to its regulated operations in retail rates, the Company records a regulatory asset for that portion of its pension and other postretirement benefit funding deficiency. (5) The UTC and the IPUC issued accounting orders authorizing Avista Corp. to offset commodity derivative assets or liabilities with a regulatory asset or liability. This accounting treatment is intended to defer the recognition of mark-to-market gains and losses on energy commodity transactions until the period of settlement. The orders provide for Avista Corp. to not recognize the unrealized gain or loss on utility derivative commodity instruments in the Consolidated Statements of Income. Realized gains or losses are recognized in the period of settlement, subject to approval for recovery through retail rates. Realized gains and losses, subject to regulatory approval, result in adjustments to retail rates through purchased gas cost adjustments, the ERM in Washington, the PCA mechanism in Idaho, and periodic general rates cases. (6) For the Company’s Washington jurisdiction and for any debt repurchases beginning in 2007 in all jurisdictions, premiums paid to repurchase debt are amortized over the remaining life of the original debt that was repurchased or, if new debt is issued in connection with the repurchase, these costs are amortized over the life of the new debt. In the Company’s other regulatory jurisdictions, premiums paid to repurchase debt prior to 2007 are being amortized over the average remaining maturity of outstanding debt when no new debt was issued in connection with the debt repurchase. These costs are recovered through retail rates as a component of interest expense. (7) For interest rate swap agreements, each period Avista Utilities records all mark-to-market gains and losses as assets and liabilities and records offsetting regulatory assets and liabilities, such that there is no income statement impact. This is similar to the treatment of energy commodity derivatives described above. Upon settlement of interest rate swaps, the regulatory asset or liability (included as part of long-term debt) is amortized as a component of interest expense over the term of the associated debt. (8) This amount is dependent upon the cost of removal of underlying utility plant assets and the life of utility plant. (9) Consists of a regulatory liability recorded for the cumulative retained earnings of Spokane Energy that the Company will flow through regulatory accounting mechanisms in future periods. During 2015, Spokane Energy was dissolved and the fixed rate electric capacity contract that was held at Spokane Energy was transferred to Avista Corp. Staff_DR_063 Attachment B Page 130 of 160 AVISTA 110 Power Cost Deferrals and Recovery Mechanisms Deferred power supply costs are recorded as a deferred charge on the Consolidated Balance Sheets for future prudence review and recovery through retail rates. The power supply costs deferred include certain differences between actual net power supply costs incurred by Avista Utilities and the costs included in base retail rates. This difference in net power supply costs primarily results from changes in: • short-term wholesale market prices and sales and purchase volumes, • the level and availability of hydroelectric generation, • the level and availability of thermal generation (including changes in fuel prices), and • retail loads. In Washington, the ERM allows Avista Utilities to periodically increase or decrease electric rates with UTC approval to reflect changes in power supply costs. The ERM is an accounting method used to track certain differences between actual power supply costs, net of wholesale sales and sales of fuel, and the amount included in base retail rates for Washington customers. Total net deferred power costs under the ERM were a liability of $18.0 million as of December 31, 2015 compared to a liability of $14.2 million as of December 31, 2014, and these deferred power cost balances represent amounts due to customers. Avista Utilities has a PCA mechanism in Idaho that allows it to modify electric rates on October 1 of each year with IPUC approval. Under the PCA mechanism, Avista Utilities defers 90 percent of the difference between certain actual net power supply expenses and the amount included in base retail rates for its Idaho customers. These annual October 1 rate adjustments recover or rebate power costs deferred during the preceding July-June twelve-month period. Total net power supply costs deferred under the PCA mechanism were a regulatory asset of $0.2 million as of December 31, 2015 compared to a regulatory asset of $8.3 million as of December 31, 2014. Natural Gas Cost Deferrals and Recovery Mechanisms Avista Utilities files a PGA in all three states it serves to adjust natural gas rates for: 1) estimated commodity and pipeline transportation costs to serve natural gas customers for the coming year, and 2) the difference between actual and estimated commodity and transportation costs for the prior year. Total net deferred natural gas costs to be refunded to customers were a liability of $17.9 million as of December 31, 2015 compared to a liability of $3.9 million as of December 31, 2014. Decoupling and Earnings Sharing Mechanisms Decoupling is a mechanism designed to sever the link between a utility’s revenues and consumers’ energy usage. The Company’s actual revenue, based on kilowatt hour and therm sales will vary, up or down, from the level included in a general rate case, which could be caused by changes in weather, energy conservation or the economy. Generally, the Company’s electric and natural gas revenues will be adjusted each month to be based on the number of customers, rather than kilowatt hour and therm sales. The difference between revenues based on sales and revenues based on the number of customers will be deferred and either surcharged or rebated to customers beginning in the following year. Washington Decoupling and Earnings Sharing In Washington, the UTC approved the Company’s decoupling mechanisms for electric and natural gas for a five-year period that commenced January 1, 2015. Electric and natural gas decoupling surcharge rate adjustments to customers are limited to 3 percent on an annual basis, with any remaining surcharge balance carried forward for recovery in a future period. There is no limit on the level of rebate rate adjustments. The decoupling mechanisms each include an after-the-fact earnings test. At the end of each calendar year, separate electric and natural gas earnings calculations will be made for the prior calendar year. These earnings tests will reflect actual decoupled revenues, normalized power supply costs and other normalizing adjustments. As of December 31, 2015, the Company had a total net decoupling surcharge (asset) of $10.9 million for Washington electric and natural gas customers and a liability (rebate to customers) for earnings sharing of $3.4 million for Washington electric customers. Idaho Fixed Cost Adjustment (FCA) and Earnings Sharing Mechanisms In Idaho, the IPUC approved the implementation of FCAs for electric and natural gas (similar in operation and effect to the Washington decoupling mechanisms) for an initial term of three years, commencing on January 1, 2016. For the period 2013 through 2015, the Company had an after-the- fact earnings test, such that if Avista Corp., on a consolidated basis for electric and natural gas operations in Idaho, earned more than a 9.8 percent ROE, the Company was required to share with customers 50 percent of any earnings above the 9.8 percent. There was no provision for a surcharge to customers if the Company’s ROE was less than 9.8 percent. This after-the-fact earnings test was discontinued as part of the settlement of the Company’s 2015 Idaho electric and natural gas general rates cases. As of December 31, 2015 and December 31, 2014, the Company had total cumulative earnings sharing liabilities (rebates to customers) of $8.8 million and $10.1 million, respectively for electric and natural gas customers. NOTE 21. INFORMATION BY BUSINESS SEGMENTS The business segment presentation reflects the basis used by the Company’s management to analyze performance and determine the allocation of resources. The Company’s management evaluates performance based on income (loss) from operations before income taxes as well as net income (loss) attributable to Avista Corp. shareholders. The accounting policies of the segments are the same as those described in the summary of significant accounting policies. Avista Utilities’ business is managed based on the total regulated utility operation; therefore, it is considered one segment. AEL&P (acquired in the AERC acquisition on July 1, 2014) is a separate reportable business segment as it has separate financial reports that are reviewed in detail by the Chief Operating Decision Maker and its operations and risks are sufficiently different from Avista Utilities and the other businesses at AERC that it cannot be aggregated with any other operating segments. All goodwill associated with the AERC acquisition was assigned to the AEL&P reportable business segment. The Other category, which is not a reportable segment, includes Spokane Energy, which was dissolved during the third quarter of 2015, other investments and operations of various subsidiaries, as well as certain other operations of Avista Capital. Staff_DR_063 Attachment B Page 131 of 160 111 AVISTA Ecova is a provider of facility information and cost management services for multi-site customers throughout North America. The Ecova business segment was disposed of as of June 30, 2014. All income statement amounts were reclassified to discontinued operations on the Consolidated Statements of Income for all periods presented. The following table presents information for each of the Company’s business segments (dollars in thousands): Alaska Electric Light Avista and Power Total Intersegment Utilities Company Utility Other Eliminations (1) Total For the year ended December 31, 2015: Operating revenues $ 1,411,863 $ 44,778 $ 1,456,641 $ 28,685 $ (550) $ 1,484,776 Resource costs 644,991 11,973 656,964 — — 656,964 Other operating expenses 292,096 11,125 303,221 30,076 (550) 332,747 Depreciation and amortization 138,236 5,263 143,499 695 — 144,194 Income (loss) from operations 241,228 14,072 255,300 (2,086) — 253,214 Interest expense (2) 76,405 3,558 79,963 610 (132) 80,441 Income taxes 64,489 4,202 68,691 (1,242) — 67,449 Net income (loss) from continuing operations attributable to Avista Corp. shareholders 113,360 6,641 120,001 (1,921) — 118,080 Capital expenditures (3) 381,174 12,251 393,425 885 — 394,310 For the year ended December 31, 2014: Operating revenues $ 1,413,499 $ 21,644 $ 1,435,143 $ 39,219 $ (1,800) $ 1,472,562 Resource costs 672,344 5,900 678,244 — — 678,244 Other operating expenses 280,964 5,868 286,832 32,218 (1,800) 317,250 Depreciation and amortization 126,987 2,583 129,570 610 — 130,180 Income from operations 239,976 6,221 246,197 6,391 — 252,588 Interest expense (2) 73,750 1,382 75,132 1,004 (384) 75,752 Income taxes 67,634 1,816 69,450 2,790 — 72,240 Net income from continuing operations attributable to Avista Corp. shareholders 113,263 3,152 116,415 3,236 166 119,817 Capital expenditures (3) 323,931 1,585 325,516 406 — 325,922 For the year ended December 31, 2013: Operating revenues $ 1,403,995 $ — $ 1,403,995 $ 39,549 $ (1,800) $ 1,441,744 Resource costs 689,586 — 689,586 — — 689,586 Other operating expenses 276,228 — 276,228 40,451 (1,800) 314,879 Depreciation and amortization 117,174 — 117,174 581 — 117,755 Income (loss) from operations 232,572 — 232,572 (1,483) — 231,089 Interest expense (2) 75,663 — 75,663 2,247 (325) 77,585 Income taxes 60,472 — 60,472 (2,458) — 58,014 Net income (loss) from continuing operations attributable to Avista Corp. shareholders 108,598 — 108,598 (4,650) 325 104,273 Capital expenditures (3) 294,363 — 294,363 371 — 294,734 Total Assets: As of December 31, 2015 $ 4,601,708 $ 265,735 $ 4,867,443 $ 39,206 $ — $ 4,906,649 As of December 31, 2014 (4) $ 4,357,760 $ 263,070 $ 4,620,830 $ 80,141 $ — $ 4,700,971 As of December 31, 2013 (4) (5) $ 3,930,251 $ — $ 3,930,251 $ 81,282 $ — $ 4,011,533 (1) Intersegment eliminations reported as operating revenues and resource costs represent intercompany purchases and sales of electric capacity and energy between Avista Utilities and Spokane Energy (included in other). Intersegment eliminations reported as interest expense and net income (loss) attributable to Avista Corp. shareholders represent intercompany interest. (2) Including interest expense to affiliated trusts. (3) The capital expenditures for the other businesses are included as other capital expenditures on the Consolidated Statements of Cash Flows. The remainder of the balance included in other capital expenditures on the Consolidated Statements of Cash Flows for 2014 and 2013 are related to Ecova. (4) The total assets balances as of December 31, 2014 and December 31, 2013 were updated to reflect the adoption of FASB ASU No. 2015-03, “Interest—Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs” as of December 31, 2015, which resulted in the reclassification of long-term debt issuance costs from an asset to a reduction of long-term debt. See Note 2 of the Notes to Consolidated Financial Statements for further discussion of the adoption of this ASU. (5) The total assets as of December 31, 2013 exclude the total assets associated with Ecova of $339.6 million. Staff_DR_063 Attachment B Page 132 of 160 AVISTA 112 NOTE 22. SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED) The Company’s energy operations are significantly affected by weather conditions. Consequently, there can be large variances in revenues, expenses and net income between quarters based on seasonal factors such as, but not limited to, temperatures and streamflow conditions. During the second quarter of 2014, Avista Corp. reported Ecova as discontinued operations (see Note 5). Accordingly, periods prior to the second quarter of 2014 were restated to reflect Ecova as discontinued operations. A summary of quarterly operations (in thousands, except per share amounts) for 2015 and 2014 follows: Three Months Ended March 31 June 30 September 30 December 31 2015 Operating revenues from continuing operations $ 446,490 $ 337,332 $ 313,649 $ 387,305 Operating expenses from continuing operations 356,915 279,972 277,737 316,938 Income from continuing operations $ 89,575 $ 57,360 $ 35,912 $ 70,367 Net income from continuing operations $ 46,462 $ 25,078 $ 12,754 $ 33,876 Net income from discontinued operations — 196 289 4,662 Net income 46,462 25,274 13,043 38,538 Net income attributable to noncontrolling interests (13) (28) (32) (17) Net income attributable to Avista Corporation shareholders $ 46,449 $ 25,246 $ 13,011 $ 38,521 Amounts attributable to Avista Corp. shareholders: Net income from continuing operations attributable to Avista Corp. shareholders $ 46,449 $ 25,050 $ 12,722 $ 33,859 Net income from discontinued operations attributable to Avista Corp. shareholders — 196 289 4,662 Net income attributable to Avista Corp. shareholders $ 46,449 $ 25,246 $ 13,011 $ 38,521 Outstanding common stock: Weighted-average—basic 62,318 62,281 62,299 62,308 Weighted-average—diluted 62,889 62,600 62,688 62,758 Earnings per common share attributable to Avista Corp. shareholders, diluted: Earnings per common share from continuing operations $ 0.74 $ 0.40 $ 0.21 $ 0.54 Earnings per common share from discontinued operations — — — 0.07 Total earnings per common share attributable to Avista Corp. shareholders, diluted $ 0.74 $ 0.40 $ 0.21 $ 0.61 2014 Operating revenues from continuing operations $ 446,578 $ 312,580 $ 301,558 $ 411,846 Operating expenses from continuing operations 356,236 249,849 268,796 345,093 Income from continuing operations $ 90,342 $ 62,731 $ 32,762 $ 66,753 Net income from continuing operations $ 47,466 $ 31,270 $ 10,526 $ 30,604 Net income (loss) from discontinued operations 1,515 69,312 (55) 1,639 Net income 48,981 100,582 10,471 32,243 Net loss (income) attributable to noncontrolling interests (482) 289 (20) (23) Net income attributable to Avista Corporation shareholders $ 48,499 $ 100,871 $ 10,451 $ 32,220 Amounts attributable to Avista Corp. shareholders: Net income from continuing operations attributable to Avista Corp. shareholders $ 47,476 $ 31,254 $ 10,506 $ 30,581 Net income (loss) from discontinued operations attributable to Avista Corp. shareholders 1,023 69,617 (55) 1,639 Net income attributable to Avista Corp. shareholders $ 48,499 $ 100,871 $ 10,451 $ 32,220 Outstanding common stock: Weighted-average—basic 60,122 60,184 63,934 62,290 Weighted-average—diluted 60,168 60,463 64,244 62,671 Earnings per common share attributable to Avista Corp. shareholders, diluted: Earnings per common share from continuing operations $ 0.79 $ 0.52 $ 0.16 $ 0.48 Earnings per common share from discontinued operations 0.02 1.15 — 0.03 Total earnings per common share attributable to Avista Corp. shareholders, diluted $ 0.81 $ 1.67 $ 0.16 $ 0.51 Staff_DR_063 Attachment B Page 133 of 160 113 AVISTA ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE Not applicable. ITEM 9A. CONTROLS AND PROCEDURES Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures The Company has disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (Act) that are designed to ensure that information required to be disclosed in the reports it files or submits under the Act is recorded, processed, summarized and reported on a timely basis. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by the Company in the reports that it files or submits under the Act is accumulated and communicated to the Company’s management, including its principal executive and principal financial officers, as appropriate, to allow timely decisions regarding required disclosure. With the participation of the Company’s principal executive officer and principal financial officer, the Company’s management evaluated its disclosure controls and procedures as of the end of the period covered by this report. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives. Based upon this evaluation, the Company’s principal executive officer and principal financial officer have concluded that the Company’s disclosure controls and procedures are effective at a reasonable assurance level as of December 31, 2015. Management’s Report on Internal Control Over Financial Reporting The Company’s management, together with its consolidated subsidiaries, is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934). The Company’s internal control over financial reporting is a process designed under the supervision of the Company’s principal executive officer and principal financial officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Company’s financial statements for external reporting purposes in accordance with accounting principles generally accepted in the United States of America. The Company’s internal control over financial reporting includes policies and procedures that pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect transactions and dispositions of assets; provide reasonable assurances that transactions are recorded as necessary to permit preparation of financial statements in accordance with accounting principles generally accepted in the United States of America, and that receipts and expenditures are being made only in accordance with authorizations of management and the directors of the Company; and provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the Company’s financial statements. Under the supervision and with the participation of the Company’s management, including the Company’s principal executive officer and principal financial officer, the Company conducted an assessment of the effectiveness of the Company’s internal control over financial reporting based on the framework established in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, management determined that the Company’s internal control over financial reporting as of December 31, 2015 is effective at a reasonable assurance level. The Company’s independent registered public accounting firm, Deloitte & Touche LLP, has issued an attest report on the Company’s internal control over financial reporting as of December 31, 2015. Changes in Internal Control Over Financial Reporting There have been no changes in the Company’s internal control over financial reporting that occurred during the Company’s last fiscal quarter that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting. Staff_DR_063 Attachment B Page 134 of 160 AVISTA 114 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors and Shareholders of Avista Corporation Spokane, Washington We have audited the internal control over financial reporting of Avista Corporation and subsidiaries (the “Company”) as of December 31, 2015, based on criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2015, based on the criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2015 of the Company and our report dated February 23, 2016 expressed an unqualified opinion on those financial statements. /s/ Deloitte & Touche LLP Seattle, Washington February 23, 2016 Staff_DR_063 Attachment B Page 135 of 160 115 AVISTA ITEM 9B. OTHER INFORMATION None. PART III ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE The information required by this Item (other than the information regarding executive officers and the Company’s Code of Business Conduct and Ethics set forth below) is omitted pursuant to General Instruction G to Form 10-K. Such information is incorporated herein by reference as follows: • on and after the date of filing with the SEC the Registrant’s definitive Proxy Statement relating to its Annual Meeting of Shareholders scheduled to be held on May 12, 2016, from such Proxy Statement; and • prior to such date, from the Registrant’s definitive Proxy Statement, dated March 27, 2015, relating to its Annual Meeting of Shareholders held on May 7, 2015. Executive Officers of the Registrant Name Age Business Experience Scott L. Morris 58 Chairman, President and Chief Executive Officer effective January 1, 2008. Director since February 9, 2007; President and Chief Operating Officer May 2006–December 2007; Senior Vice President February 2002–May 2006; Vice President November 2000–February 2002; President—Avista Utilities August 2000–December 2008; General Manager—Avista Utilities for the Oregon and California operations October 1991–August 2000; various other management and staff positions with the Company since 1981. Mark T. Thies 52 Treasurer since January 2013; Senior Vice President and Chief Financial Officer (Principal Financial Officer) since September 2008; prior to employment with the Company held the following positions with Black Hills Corporation: Executive Vice President and Chief Financial Officer March 2003–January 2008; Senior Vice President and Chief Financial Officer March 2000–March 2003; Controller May 1997–March 2000. Marian M. Durkin 62 Senior Vice President, General Counsel and Chief Compliance Officer since November 2005; Senior Vice President and General Counsel August 2005–November 2005; prior to employment with the Company: held several legal positions with United Air Lines, Inc. from 1995–August 2005, most recently served as Vice President Deputy General Counsel and Assistant Secretary. Karen S. Feltes 60 Senior Vice President of Human Resources and Corporate Secretary since November 2005; Vice President of Human Resources and Corporate Secretary March 2003–November 2005; Vice President of Human Resources and Corporate Services February 2002–March 2003; various human resources positions with the Company April 1998–February 2002. Dennis P. Vermillion 54 Senior Vice President since January 2010; Vice President July 2007–December 2009; President—Avista Utilities since January 2009; Vice President of Energy Resources and Optimization—Avista Utilities July 2007–December 2008; President and Chief Operating Officer of Avista Energy February 2001–July 2007; various other management and staff positions with the Company since 1985. Jason R. Thackston 45 Senior Vice President since January 2014; Vice President of Energy Resources since December 2012; Vice President of Customer Solutions—Avista Utilities June 2012– December 2012; Vice President of Energy Delivery April 2011–December 2012; Vice President of Finance June 2009–April 2011; various other management and staff positions with the Company since 1996. Ryan L. Krasselt 46 Vice President, Controller and Principal Accounting Officer since October 2015; various other management and staff positions with the Company since 2001. Kevin J. Christie 48 Vice President of Customer Solutions since February 2015; various other management and staff positions with the Company since 2005. Staff_DR_063 Attachment B Page 136 of 160 AVISTA 116 James M. Kensok 57 Vice President and Chief Information Officer since January 2007; Chief Information Officer February 2001–December 2006; various other management and staff positions with the Company since 1996. David J. Meyer 62 Vice President and Chief Counsel for Regulatory and Governmental Affairs since February 2004; Senior Vice President and General Counsel September 1998–February 2004. Kelly O. Norwood 57 Vice President since November 2000; Vice President of State and Federal Regulation— Avista Utilities since March 2002; Vice President and General Manager of Energy Resources—Avista Utilities August 2000–March 2002; various other management and staff positions with the Company since 1981. Heather L. Rosentrater 38 Vice President of Energy Delivery and Customer Service since December 2015; various other management and staff positions with the Company since 1996. Ed D. Schlect 55 Vice President and Chief Strategy Officer since September 2015; prior to employment with the Company was the Executive Vice President of Corporate Development at Ecova, Inc. Roger D. Woodworth 59 President of Avista Development since December 2015; Vice President November 1998– November 2015; Vice President and Chief Strategy Officer April 2011–September 2015; Vice President, Sustainable Energy Solutions Avista Utilities February 2007–April 2011; Vice President, Customer Solutions for Avista Utilities March 2003–February 2007; Vice President of Utility Operations of Avista Utilities September 2001–March 2003; Vice President— Corporate Development November 1998–September 2001; various other management and staff positions with the Company since 1979. All of the Company’s executive officers, with the exception of James M. Kensok, David J. Meyer, Kelly O. Norwood, Kevin J. Christie and Heather L. Rosentrater were officers or directors of one or more of the Company’s subsidiaries in 2015. The Company’s executive officers are elected annually by the Board of Directors. The Company has adopted a Code of Conduct for directors, officers (including the principal executive officer, principal financial officer and principal accounting officer), and employees. The Code of Conduct is available on the Company’s website at www.avistacorp.com and will also be provided to any shareholder without charge upon written request to: Avista Corp. General Counsel P.O. Box 3727 MSC-12 Spokane, Washington 99220-3727 Any changes to or waivers for executive officers and directors of the Company’s Code of Conduct will be posted on the Company’s website. ITEM 11. EXECUTIVE COMPENSATION The information required by this Item is omitted pursuant to General Instruction G to Form 10-K. Such information is incorporated herein by reference as follows: • on and after the date of filing with the SEC the Registrant’s definitive Proxy Statement relating to its Annual Meeting of Shareholders scheduled to be held on May 12, 2016, from such Proxy Statement; and • prior to such date, from the Registrant’s definitive Proxy Statement, dated March 27, 2015, relating to its Annual Meeting of Shareholders held on May 7, 2015. Staff_DR_063 Attachment B Page 137 of 160 117 AVISTA ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS (a) Security ownership of certain beneficial owners (owning 5 percent or more of Registrant’s voting securities): Information regarding security ownership of certain beneficial owners (owning 5 percent or more of Registrant’s voting securities) has been omitted pursuant to General Instruction G to Form 10-K. Such information is incorporated herein by reference as follows: • on and after the date of filing with the SEC the Registrant’s definitive Proxy Statement relating to its Annual Meeting of Shareholders scheduled to be held on May 12, 2016, from such Proxy Statement; and • prior to such date, from the Registrant’s definitive Proxy Statement, dated March 27, 2015, relating to its Annual Meeting of Shareholders held on May 7, 2015; reference also being made to Schedules 13G, as amended, in file with the SEC with respect to the Registrant’s voting securities (the information contained in such schedules 13G, as amended, not being incorporated herein by reference). (b) Security ownership of management: The information required by this Item regarding the security ownership of management is omitted pursuant to General Instruction G to Form 10-K. Such information is incorporated herein by reference as follows: • on and after the date of filing with the SEC the Registrant’s definitive Proxy Statement relating to its Annual Meeting of Shareholders scheduled to be held on May 12, 2016, from such Proxy Statement; and • prior to such date, from the Registrant’s definitive Proxy Statement, dated March 27, 2015, relating to its Annual Meeting of Shareholders held on May 7, 2015. (c) Changes in control: None. (d) Securities authorized for issuance under equity compensation plans as of December 31, 2015: (a) (b) (c) Number of securities to be Weighted-average Number of securities remaining issued upon exercise of exercise price of available for future issuance under outstanding options, outstanding options, equity compensation plans (excluding Plan category warrants and rights (1) warrants and rights securities reflected in column (a)) Equity compensation plans approved by security holders (2) — $ — 398,571 (1) Excludes unvested restricted shares and performance share awards granted under Avista Corp.’s Long Term Incentive Plan. At December 31, 2015, 106,091 Restricted Share awards were outstanding. Performance and market-based share awards may be paid out at zero shares at a minimum achievement level; 335,584 shares at target level; or 671,168 shares at a maximum level. Because there is no exercise price associated with restricted shares or performance and market-based share awards, such shares are not included in the weighted-average price calculation. (2) Includes the Long-Term Incentive Plan approved by shareholders in 1998 and the Non-Employee Director Stock Plan approved by shareholders in 1996. In February 2005, the Board of Directors elected to terminate the Non-Employee Director Stock Plan. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE The information required by this Item is omitted pursuant to General Instruction G to Form 10-K. Such information is incorporated herein by reference as follows: • on and after the date of filing with the SEC the Registrant’s definitive Proxy Statement relating to its Annual Meeting of Shareholders scheduled to be held on May 12, 2016, from such Proxy Statement; and • prior to such date, from the Registrant’s definitive Proxy Statement, dated March 27, 2015, relating to its Annual Meeting of Shareholders held on May 7, 2015. ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES The information required by this Item is omitted pursuant to General Instruction G to Form 10-K. Such information is incorporated herein by reference as follows: • on and after the date of filing with the SEC the Registrant’s definitive Proxy Statement relating to its Annual Meeting of Shareholders scheduled to be held on May 12, 2016, from such Proxy Statement; and • prior to such date, from the Registrant’s definitive Proxy Statement, dated March 27, 2015, relating to its Annual Meeting of Shareholders held on May 7, 2015. Staff_DR_063 Attachment B Page 138 of 160 AVISTA 118 PART IV ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES (a)1. Financial Statements (Included in Part II of this report): Report of Independent Registered Public Accounting Firm Consolidated Statements of Income for the Years Ended December 31, 2015, 2014 and 2013 Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2015, 2014 and 2013 Consolidated Balance Sheets as of December 31, 2015 and 2014 Consolidated Statements of Cash Flows for the Years Ended December 31, 2015, 2014 and 2013 Consolidated Statements of Equity and Redeemable Noncontrolling Interests for the Years Ended December 31, 2015, 2014 and 2013 Notes to Consolidated Financial Statements (a)2. Financial Statement Schedules: None (a)3. Exhibits: Reference is made to the Exhibit Index commencing on page 120. The Exhibits include the management contracts and compensatory plans or arrangements required to be filed as exhibits to this Form 10-K pursuant to Item 15(b). Staff_DR_063 Attachment B Page 139 of 160 119 AVISTA SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. AVISTA CORPORATION February 23, 2016 By /s/ Scott L. Morris Date Scott L. Morris Chairman of the Board, President and Chief Executive Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated. Signature /s/ Scott L. Morris Principal Executive Officer February 23, 2016 Scott L. Morris Chairman of the Board, President and Chief Executive Officer /s/ Mark T. Thies Principal Financial Officer February 23, 2016 Mark T. Thies Senior Vice President, Chief Financial Officer, and Treasurer /s/ Ryan L. Krasselt Principal Accounting Officer February 23, 2016 Ryan L. Krasselt Vice President, Controller and Principal Accounting Officer /s/ Erik J. Anderson Director February 23, 2016 Erik J. Anderson /s/ Kristianne Blake Director February 23, 2016 Kristianne Blake /s/ Donald C. Burke Director February 23, 2016 Donald C. Burke /s/ John F. Kelly Director February 23, 2016 John F. Kelly /s/ Rebecca A. Klein Director February 23, 2016 Rebecca A. Klein /s/ Marc F. Racicot Director February 23, 2016 Marc F. Racicot /s/ Heidi B. Stanley Director February 23, 2016 Heidi B. Stanley /s/ R. John Taylor Director February 23, 2016 R. John Taylor /s/ Janet D. Widmann Director February 23, 2016 Janet D. Widmann Staff_DR_063 Attachment B Page 140 of 160 AVISTA 120 EXHIBIT INDEX Previously Filed(1) Exhibit With Registration Number As Exhibit 3.1 (with June 30, 2012 Form 10-Q) 3.1 Restated Articles of Incorporation of Avista Corporation, as amended and restated June 6, 2012. 3.2 (with Form 8-K filed 3.2 Bylaws of Avista Corporation, as amended November 14, 2014. as of November 14, 2014) 4.1 2-4077 B-3 Mortgage and Deed of Trust, dated as of June 1, 1939. 4.2 2-9812 4(c) First Supplemental Indenture, dated as of October 1, 1952. 4.3 2-60728 2(b)-2 Second Supplemental Indenture, dated as of May 1, 1953. 4.4 2-13421 4(b)-3 Third Supplemental Indenture, dated as of December 1, 1955. 4.5 2-13421 4(b)-4 Fourth Supplemental Indenture, dated as of March 15, 1967. 4.6 2-60728 2(b)-5 Fifth Supplemental Indenture, dated as of July 1, 1957. 4.7 2-60728 2(b)-6 Sixth Supplemental Indenture, dated as of January 1, 1958. 4.8 2-60728 2(b)-7 Seventh Supplemental Indenture, dated as of August 1, 1958. 4.9 2-60728 2(b)-8 Eighth Supplemental Indenture, dated as of January 1, 1959. 4.10 2-60728 2(b)-9 Ninth Supplemental Indenture, dated as of January 1, 1960. 4.11 2-60728 2(b)-10 Tenth Supplemental Indenture, dated as of April 1, 1964. 4.12 2-60728 2(b)-11 Eleventh Supplemental Indenture, dated as of March 1, 1965. 4.13 2-60728 2(b)-12 Twelfth Supplemental Indenture, dated as of May 1, 1966. 4.14 2-60728 2(b)-13 Thirteenth Supplemental Indenture, dated as of August 1, 1966. 4.15 2-60728 2(b)-14 Fourteenth Supplemental Indenture, dated as of April 1, 1970. 4.16 2-60728 2(b)-15 Fifteenth Supplemental Indenture, dated as of May 1, 1973. 4.17 2-60728 2(b)-16 Sixteenth Supplemental Indenture, dated as of February 1, 1975. 4.18 2-60728 2(b)-17 Seventeenth Supplemental Indenture, dated as of November 1, 1976. 4.19 2-69080 2(b)-18 Eighteenth Supplemental Indenture, dated as of June 1, 1980. 4.20 (with 1980 Form 10-K) 4(a)-20 Nineteenth Supplemental Indenture, dated as of January 1, 1981. 4.21 2-79571 4(a)-21 Twentieth Supplemental Indenture, dated as of August 1, 1982. 4.22 (with Form 8-K dated 4(a)-22 Twenty-First Supplemental Indenture, dated as of September 1, 1983. September 20, 1983) 4.23 2-94816 4(a)-23 Twenty-Second Supplemental Indenture, dated as of March 1, 1984. Staff_DR_063 Attachment B Page 141 of 160 121 AVISTA EXHIBIT INDEX (CONTINUED) Previously Filed(1) Exhibit With Registration Number As Exhibit 4.24 (with 1986 Form 10-K) 4(a)-24 Twenty-Third Supplemental Indenture, dated as of December 1, 1986. 4.25 (with 1987 Form 10-K) 4(a)-25 Twenty-Fourth Supplemental Indenture, dated as of January 1, 1988. 4.26 (with 1989 Form 10-K) 4(a)-26 Twenty-Fifth Supplemental Indenture, dated as of October 1, 1989. 4.27 33-51669 4(a)-27 Twenty-Sixth Supplemental Indenture, dated as of April 1, 1993. 4.28 (with 1993 Form 10-K) 4(a)-28 Twenty-Seventh Supplemental Indenture, dated as of January 1, 1994. 4.29 (with 2001 Form 10-K) 4(a)-29 Twenty-Eighth Supplemental Indenture, dated as of September 1, 2001. 4.30 333-82502 4(b) Twenty-Ninth Supplemental Indenture, dated as of December 1, 2001. 4.31 (with June 30, 2002 Form 10-Q) 4(f) Thirtieth Supplemental Indenture, dated as of May 1, 2002. 4.32 333-39551 4(b) Thirty-First Supplemental Indenture, dated as of May 1, 2003. 4.33 (with September 30, 2003 4(f) Thirty-Second Supplemental Indenture, dated as of September 1, 2003. Form 10-Q) 4.34 333-64652 4(a)33 Thirty-Third Supplemental Indenture, dated as of May 1, 2004. 4.35 (with Form 8-K dated 4.1 Thirty-Fourth Supplemental Indenture, dated as of November 1, 2004. as of December 15, 2004) 4.36 (with Form 8-K dated 4.2 Thirty-Fifth Supplemental Indenture, dated as of December 1, 2004. as of December 15, 2004) 4.37 (with Form 8-K dated 4.3 Thirty-Sixth Supplemental Indenture, dated as of December 1, 2004. as of December 15, 2004) 4.38 (with Form 8-K dated 4.4 Thirty-Seventh Supplemental Indenture, dated as of December 1, 2004. as of December 15, 2004) 4.39 (with Form 8-K dated 4.1 Thirty-Eighth Supplemental Indenture, dated as of May 1, 2005. as of May 12, 2005) 4.40 (with Form 8-K dated 4.1 Thirty-Ninth Supplemental Indenture, dated as of November 1, 2005. as of November 17, 2005) 4.41 (with Form 8-K dated 4.1 Fortieth Supplemental Indenture, dated as of April 1, 2006. as of April 6, 2006) 4.42 (with Form 8-K dated 4.1 Forty-First Supplemental Indenture, dated as of December 1, 2006. as of December 15, 2006) 4.43 (with Form 8-K dated 4.1 Forty-Second Supplemental Indenture, dated as of April 1, 2008. as of April 3, 2008) 4.44 (with Form 8-K dated 4.1 Forty-Third Supplemental Indenture, dated as of November 1, 2008. as of November 26, 2008) Staff_DR_063 Attachment B Page 142 of 160 AVISTA 122 EXHIBIT INDEX (CONTINUED) Previously Filed(1) Exhibit With Registration Number As Exhibit 4.45 (with Form 8-K dated 4.1 Forty-Fourth Supplemental Indenture, dated as of December 1, 2008. as of December 16, 2008) 4.46 (with Form 8-K dated 4.3 Forty-Fifth Supplemental Indenture, dated as of December 1, 2008. as of December 30, 2008) 4.47 (with Form 8-K dated 4.1 Forty-Sixth Supplemental Indenture, dated as of September 1, 2009. as of September 15, 2009) 4.48 (with Form 8-K dated 4.1 Forty-Seventh Supplemental Indenture, dated as of November 1, 2009. as of November 25, 2009) 4.49 (with Form 8-K dated 4.5 Forty-Eighth Supplemental Indenture, dated as of December 1, 2010. as of December 15, 2010) 4.50 (with Form 8-K dated 4.1 Forty-Ninth Supplemental Indenture, dated as of December 1, 2010. as of December 20, 2010) 4.51 (with Form 8-K dated 4.1 Fiftieth Supplemental Indenture, dated as of December 1, 2010. as of December 30, 2010) 4.52 (with Form 8-K dated 4.1 Fifty-First Supplemental Indenture, dated as of February 1, 2011. as of February 11, 2011) 4.53 (with Form 8-K dated 4.1 Fifty-Second Supplemental Indenture, dated as of August 1, 2011. as of August 16, 2011) 4.54 (with Form 8-K dated 4.1 Fifty-Third Supplemental Indenture, dated as of December 1, 2011. as of December 14, 2011) 4.55 (with Form 8-K dated 4.1 Fifty-Fourth Supplemental Indenture, dated as of November 1, 2012. as of November 30, 2012) 4.56 (with Form 8-K dated 4.1 Fifty-Fifth Supplemental Indenture, dated as of August 1, 2013. as of August 14, 2013) 4.57 (with Form 8-K dated 4.1 Fifty-Sixth Supplemental Indenture, dated as of April 1, 2014. as of April 18, 2014) 4.58 (with Form 8-K dated 4.1 Fifty-Seventh Supplemental Indenture, dated as of December 1, 2014. as of December 18, 2014) 4.59 (with Form 8-K dated 4.1 Fifty-Eighth Supplemental Indenture, dated as of December 1, 2015. as of December 16, 2015) 4.60 (with Form 8-K dated 4.5 Supplemental Indenture No. 1, dated as of December 1, 2004 to the Indenture as of December 15, 2004) dated as of April 1, 1998 between Avista Corporation and JPMorgan Chase Bank, N.A. 4.61 333-82165 4(a) Indenture dated as of April 1, 1998 between Avista Corporation and The Bank of New York, as Successor Trustee. Staff_DR_063 Attachment B Page 143 of 160 123 AVISTA EXHIBIT INDEX (CONTINUED) Previously Filed(1) Exhibit With Registration Number As Exhibit 4.62 (with Form 8-K dated 4.1 Loan Agreement between City of Forsyth, Montana and Avista Corporation as of December 15, 2010) $66,700,000 City of Forsyth, Montana Pollution Control Revenue Refunding Bonds (Avista Corporation Colstrip Project) Series 2010A dated as of December 1, 2010. 4.63 (with Form 8-K dated 4.3 Trust Indenture between City of Forsyth, and the Bank of New York Mellon as of December 15, 2010) Trust Company, N.A., as Trustee, $66,700,000 City of Forsyth, Montana Pollution Control Revenue Refunding Bonds (Avista Corporation Colstrip Project) Series 2010A, dated as of December 1, 2010. 4.64 (with Form 8-K dated 4.2 Loan Agreement between City of Forsyth, Montana and Avista Corporation as of December 15, 2010) $17,000,000 City of Forsyth, Montana Pollution Control Revenue Refunding Bonds (Avista Corporation Colstrip Project) Series 2010B dated as of December 1, 2010. 4.65 (with Form 8-K dated 4.4 Trust Indenture between City of Forsyth, and the Bank of New York Mellon as of December 15, 2010) Trust Company, N.A., as Trustee, $17,000,000 City of Forsyth, Montana Pollution Control Revenue Refunding Bonds (Avista Corporation Colstrip Project) Series 2010B, dated as of December 1, 2010. 4.66 (with June 30, 2012 Form 10-Q) 3.1 Restated Articles of Incorporation of Avista Corporation, as amended and restated June 6, 2012 (see Exhibit 3.1 herein). 4.67 (with Form 8-K filed 3.2 Bylaws of Avista Corporation, as amended November 14, 2014 as of November 14, 2014) (see Exhibit 3.2 herein). 4.68 (Form 10/A) N/A Post-Effective Amendment No. 1 on Form 10/A, filed February 26, 2015, to Registration Statement on Form 10, filed September 1952. 10.1 (with Form 8-K dated 10.1 Credit Agreement, dated as of February 11, 2011, among Avista Corporation, as of February 11, 2011) the Banks Party hereto, The Bank of New York Mellon, Keybank National Association, and U.S. Bank National Association, as Co-Documentation Agents, Wells Fargo Bank National Association as Syndication Agent and an Issuing Bank, and Union Bank N.A. as Administrative Agent and an Issuing Bank. 10.2 (with Form 8-K dated 10.2 Bond Delivery Agreement, dated as of February 11, 2011, between Avista as of February 11, 2011) Corporation and Union Bank, N.A. 10.3 (with Form 8-K dated 10.1 Second Amendment to Credit Agreement, dated as of April 18, 2014, among as of April 18, 2014) Avista Corporation, Wells Fargo Bank, National Association, as an Issuing Bank, Union Bank, N.A. as Administrative Agent and an Issuing Bank, and the financial institutions identified hereof as Continuing Lenders and Exiting Lender. 10.4 (with Form 8-K dated 10.2 Bond Delivery Agreement, dated as of April 18, 2014, between Avista as of April 18, 2014) Corporation and Union Bank, N.A. 10.5 (with Form 8-K dated 10.1 Term Loan Agreement, dated as of August 14, 2013, among Avista as of August 14, 2013) Corporation, the Lenders Party hereto and Union Bank N.A. as Administrative Agent. Staff_DR_063 Attachment B Page 144 of 160 AVISTA 124 EXHIBIT INDEX (CONTINUED) Previously Filed(1) Exhibit With Registration Number As Exhibit 10.6 (with Form 8-K dated 10.2 Bond Delivery Agreement, dated as of August 14, 2013, between Avista as of August 14, 2013) Corporation and Union Bank, N.A. 10.7 (with Form 8-K dated 10.1 First Amendment and Waiver Thereunder, dated as of December 14, 2011, to as of December 14, 2011) the Credit Agreement dated as of February 11, 2011, among Avista Corporation, the Banks Party hereto, Wells Fargo Bank National Association as an Issuing Bank, and Union Bank N.A. as Administrative Agent and an Issuing Bank. 10.8 (with 2002 Form 10-K) 10(b)-3 Priest Rapids Project Product Sales Contract executed by Public Utility District No. 2 of Grant County, Washington and Avista Corporation dated December 12, 2001 (effective November 1, 2005 for the Priest Rapids Development and November 1, 2009 for the Wanapum Development). 10.9 (with 2002 Form 10-K) 10(b)-4 Priest Rapids Project Reasonable Portion Power Sales Contract executed by Public Utility District No. 2 of Grant County, Washington and Avista Corporation dated December 12, 2001 (effective November 1, 2005 for the Priest Rapids Development and November 1, 2009 for the Wanapum Development). 10.10 (with 2002 Form 10-K) 10(b)-5 Additional Product Sales Agreement (Priest Rapids Project) executed by Public Utility District No. 2 of Grant County, Washington and Avista Corporation dated December 12, 2001 (effective November 1, 2005 for the Priest Rapids Development and November 1, 2009 for the Wanapum Development). 10.11 2-60728 5(g) Power Sales Contract (Wells Project) with Public Utility District No. 1 of Douglas County, Washington, dated as of September 18, 1963. 10.12 2-60728 5(g)-1 Amendment to Power Sales Contract (Wells Project) with Public Utility District No. 1 of Douglas County, Washington, dated as of February 9, 1965. 10.13 2-60728 5(h) Reserved Share Power Sales Contract (Wells Project) with Public Utility District No. 1 of Douglas County, Washington, dated as of September 18, 1963. 10.14 2-60728 5(h)-1 Amendment to Reserved Share Power Sales Contract (Wells Project) with Public Utility District No. 1 of Douglas County, Washington, dated as of February 9, 1965. 10.15 (with September 30, 1985 1 Settlement Agreement and Covenant Not to Sue executed by the United Form 10-Q) States Department of Energy acting by and through the Bonneville Power Administration and the Company, dated as of September 17, 1985, describing the settlement of Project 3 litigation. 10.16 (with 1981 Form 10-K) 10(s)-7 Ownership and Operation Agreement for Colstrip Units No. 3 & 4, dated as of May 6, 1981. 10.17 (with 1992 Form 10-K) 10(s)-1 Agreements for Purchase and Sale of Firm Capacity between the Company and Portland General Electric Company dated March and June 1992. 10.18 (with 2011 Form 10-K) 10.15 Avista Corporation Executive Deferral Plan. (3) Staff_DR_063 Attachment B Page 145 of 160 125 AVISTA EXHIBIT INDEX (CONTINUED) Previously Filed(1) Exhibit With Registration Number As Exhibit 10.19 (with 2011 Form 10-K) 10.16 Avista Corporation Executive Deferral Plan. (3)(8) 10.20 (with 2011 Form 10-K) 10.17 Avista Corporation Supplemental Executive Retirement Plan. (3)(8) 10.21 (with 2011 Form 10-K) 10.18 Avista Corporation Supplemental Executive Retirement Plan. (3)(8) 10.22 (with 1992 Form 10-K) 10(t)-11 The Company’s Unfunded Supplemental Executive Disability Plan. (3) 10.23 (with 2007 Form 10-K) 10.34 Income Continuation Plan of the Company. (3) 10.24 (with 2010 Definitive Proxy Appendix A Avista Corporation Long-Term Incentive Plan. (3) Statement filed March 31, 2010) 10.25 (with 2010 Form 10-K) 10.23 Avista Corporation Performance Award Plan Summary. (3) 10.26 (with 2010 Form 10-K) 10.24 Avista Corporation Performance Award Agreement 2010. (3) 10.27 (with 2011 Form 10-K) 10.24 Avista Corporation Performance Award Agreement 2011. (3) 10.28 (with 2012 Form 10-K) 10.25 Avista Corporation Performance Award Agreement 2012. (3) 10.29 (with 2013 Form 10-K) 10.27 Avista Corporation Performance Award Agreement 2013. (3) 10.30 (with 2014 Form 10-K) 10.30 Avista Corporation Performance Award Agreement 2014. (3) 10.31 (2) Avista Corporation Performance Award Agreement 2015. (3) 10.32 (with Form 8-K 10.1 Employment Agreement between the Company and Marian Durkin dated June 21, 2005) in the form of a Letter of Employment. (3) 10.33 (with Form 8-K 10.1 Employment Agreement between the Company and Mark T. Thies dated August 13, 2008) in the form of a Letter of Employment. (3) 10.34 333-47290 99.1 Non-Officer Employee Long-Term Incentive Plan. 10.35 (with 2010 Form 10-K) Form of Change of Control Agreement between the Company and its Executive Officers. (3)(5) 10.36 (with 2010 Form 10-K) Form of Change of Control Agreement between the Company and its Executive Officers. (3)(6) 10.37 (with 2010 Form 10-K) Form of Change of Control Agreement between the Company and its Executive Officers. (3)(7) 10.38 (with 2010 Form 10-K) Form of Change of Control Agreement between the Company and its Executive Officers. (3)(7) 10.39 (2) Avista Corporation Non-Employee Director Compensation. 12 (2) Statement Re: computation of ratio of earnings to fixed charges. 21 (2) Subsidiaries of Registrant. Staff_DR_063 Attachment B Page 146 of 160 AVISTA 126 EXHIBIT INDEX (CONTINUED) Previously Filed(1) Exhibit With Registration Number As Exhibit 23 (2) Consent of Independent Registered Public Accounting Firm. 31.1 (2) Certification of Chief Executive Officer (Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002). 31.2 (2) Certification of Chief Financial Officer (Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002). 32 (4) Certification of Corporate Officers (Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002). 101 (2) The following financial information from the Annual Report on Form 10-K for the period ended December 31, 2015, formatted in XBRL (Extensible Business Reporting Language) and filed electronically herewith: (i) the Consolidated Statements of Income; (ii) Consolidated Statements of Comprehensive Income; (iii) the Consolidated Balance Sheets; (iv) the Consolidated Statements of Cash Flows; (v) the Consolidated Statements of Equity and Redeemable Noncontrolling Interests; and (vi) the Notes to Consolidated Financial Statements. (1) Incorporated herein by reference. (2) Filed herewith. (3) Management contracts or compensatory plans filed as exhibits to this Form 10-K pursuant to Item 15(b). (4) Furnished herewith. (5) Applies to James M. Kensok, David J. Meyer, Kelly O. Norwood, Jason R. Thackston, Dennis P. Vermillion and Roger D. Woodworth. (6) Applies to Marian M. Durkin, Karen S. Feltes, Scott L. Morris, and Mark T. Thies. (7) Applies to executive officers appointed after October 1, 2010. This applies to Kevin J. Christie, Ryan L. Krasselt, Ed D. Schlect and Heather L. Rosentrater. (8) Applies to executive officers appointed after February 4, 2011. This applies to Kevin J. Christie, Ryan L. Krasselt, Ed D. Schlect and Heather L. Rosentrater. Staff_DR_063 Attachment B Page 147 of 160 127 AVISTA EXHIBIT 12 Avista Corporation Computation of Ratio of Earnings to Fixed Charges Consolidated (thousands of dollars) Years Ended December 31, 2015 2014 2013 2012 2011 Fixed charges, as defined: Interest charges $ 80,613 $ 74,025 $ 73,772 $ 71,843 $ 69,536 Amortization of debt expense and premium—net 3,415 3,635 3,813 3,803 4,617 Interest portion of rentals 1,287 1,187 1,146 1,294 1,139 Total fixed charges $ 85,315 $ 78,847 $ 78,731 $ 76,940 $ 75,292 Earnings, as defined: Pre-tax income from continuing operations $ 185,619 $ 192,106 $ 162,347 $ 116,567 $ 139,438 Add (deduct): Capitalized interest (3,546) (3,924) (3,676) (2,401) (2,942) Total fixed charges above 85,315 78,847 78,731 76,940 75,292 Total earnings $ 267,388 $ 267,029 $ 237,402 $ 191,106 $ 211,788 Ratio of earnings to fixed charges 3.13 3.39 3.02 2.48 2.81 Staff_DR_063 Attachment B Page 148 of 160 AVISTA 128 EXHIBIT 21 Avista Corporation Subsidiaries of Registrant State or Country Subsidiary of Incorporation Avista Capital, Inc. Washington Avista Development, Inc. Washington Avista Energy, Inc. Washington Avista Northwest Resources, LLC Washington Pentzer Corporation Washington Pentzer Venture Holding II, Inc. Washington Bay Area Manufacturing, Inc. Washington Advanced Manufacturing and Development, Inc. California Avista Capital II Delaware Steam Plant Square, LLC Washington Steam Plant Brew Pub, LLC Washington Courtyard Office Center, LLC Washington Alaska Energy and Resources Company Alaska Alaska Electric Light and Power Company Alaska AJT Mining Properties, Inc. Alaska Snettisham Electric Company Alaska Salix, Inc. Washington Staff_DR_063 Attachment B Page 149 of 160 129 AVISTA EXHIBIT 23 Consent of Independent Registered Accounting Firm We consent to the incorporation by reference in Registration Statement Nos. 333-33790, 333-126577 and 333-179042 on Form S8 and in Registration Statement No. 333-187306 on Form S-3, relating to the consolidated financial statements of Avista Corporation and subsidiaries, and the effectiveness of Avista Corporation’s internal control over financial reporting, appearing in this Annual Report on Form 10K of Avista Corporation for the year ended December 31, 2015. /s/ Deloitte & Touche LLP Seattle, Washington February 23, 2016 Staff_DR_063 Attachment B Page 150 of 160 AVISTA 130 EXHIBIT 31.1 Certification I, Scott L. Morris, certify that: 1. I have reviewed this report on Form 10-K of Avista Corporation; 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and 5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions): a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. Date: February 23, 2016 /s/ Scott L. Morris Scott L. Morris Chairman of the Board, President and Chief Executive Officer (Principal Executive Officer) Staff_DR_063 Attachment B Page 151 of 160 131 AVISTA EXHIBIT 31.2 Certification I, Mark T. Thies, certify that: 1. I have reviewed this report on Form 10-K of Avista Corporation; 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and 5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions): a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. Date: February 23, 2016 /s/ Mark T. Thies Mark T. Thies Senior Vice President, Chief Financial Officer, and Treasurer (Principal Financial Officer) Staff_DR_063 Attachment B Page 152 of 160 AVISTA 132 EXHIBIT 32 Avista Corporation Certification of Corporate Officers (Furnished Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002) Each of the undersigned, Scott L. Morris, Chairman of the Board, President and Chief Executive Officer of Avista Corporation (the “Company”), and Mark T. Thies, Senior Vice President and Chief Financial Officer of the Company, hereby certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that the Company’s Annual Report on Form 10-K for the year ended December 31, 2015 fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934, as amended, and that the information contained therein fairly presents, in all material respects, the financial condition and results of operations of the Company. Date: February 23, 2016 /s/ Scott L. Morris Scott L. Morris Chairman of the Board, President and Chief Executive Officer /s/ Mark T. Thies Mark T. Thies Senior Vice President, Chief Financial Officer, and Treasurer Staff_DR_063 Attachment B Page 153 of 160 133 AVISTA SELECTED FINANCIAL DATA Avista Corporation As of and for the years ended December 31, Dollars in thousands, except per share data and ratios 2015 2014 2013 2012 2011 2005 Financial Results Operating revenues $ 1,484,776 $ 1,472,562 $ 1,441,744 $ 1,391,338 $ 1,481,932 $ 1,327,859 Operating expenses 1,231,562 1,219,974 1,210,655 1,204,240 1,274,845 1,183,085 Income from operations 253,214 252,588 231,089 187,098 207,087 144,774 Interest expense 80,441 75,752 77,585 75,645 73,903 91,802 Income taxes 67,449 72,240 58,014 39,764 48,780 23,617 Net income from continuing operations 118,170 119,866 104,333 76,803 90,658 41,066 Net income from discontinued operations 5,147 72,411 7,961 1,997 12,881 3,922 Net income 123,317 192,277 112,294 78,800 103,539 44,988 Net income attributable to noncontrolling interests (90) (236) (1,217) (590) (3,315) — Net income attributable to Avista Corp. shareholders: Net income from continuing operations attributable to Avista Corp. shareholders $ 118,080 $ 119,817 $ 104,273 $ 76,719 $ 90,553 $ 41,066 Net income from discontinued operations attributable to Avista Corp. shareholders $ 5,147 $ 72,224 $ 6,804 $ 1,491 $ 9,671 $ 3,922 Net income attributable to Avista Corp. shareholders $ 123,227 $ 192,041 $ 111,077 $ 78,210 $ 100,224 $ 44,988 Earnings per common share attributable to Avista Corp. shareholders—diluted: Earnings from continuing operations $ 1.89 $ 1.93 $ 1.74 $ 1.30 $ 1.56 $ 0.84 Earnings from discontinued operations 0.08 1.17 0.11 0.02 0.16 0.08 Total $ 1.97 $ 3.10 $ 1.85 $ 1.32 $ 1.72 $ 0.92 Earnings per common share attributable to Avista Corp. shareholders—basic: $ 1.98 $ 3.12 $ 1.85 $ 1.32 $ 1.73 $ 0.93 Common Stock Statistics Dividends paid per common share $ 1.32 $ 1.27 $ 1.22 $ 1.16 $ 1.10 $ 0.545 Book value per common share $ 24.53 $ 23.84 $ 21.61 $ 21.06 $ 20.30 $ 15.82 Shares of common stock: Outstanding at year-end 62,313 62,243 60,077 59,813 58,423 48,593 Average—basic 62,301 61,632 59,960 59,028 57,872 48,523 Average—diluted 62,708 61,887 59,997 59,201 58,092 48,979 Return on average Avista Corp. stockholders’ equity: Total company 8.2% 13.7% 8.7% 6.4% 8.7% 5.9% Utility only 8.4% 9.0% 9.3% 7.3% 8.4% 10.2% Non-utility only 6.5% 54.4% 2.2% (3.7)% 12.4% (3.0)% Common stock price: High $ 38.30 $ 37.37 $ 29.26 $ 28.05 $ 26.53 $ 20.20 Low $ 29.93 $ 27.71 $ 24.10 $ 22.78 $ 21.13 $ 16.31 Year-end close $ 35.37 $ 35.35 $ 28.19 $ 24.11 $ 25.75 $ 17.71 Debt and Preferred Stock Statistics Pretax interest coverage: Including AFUDC/AFUCE 3.46(x) 4.52(x) 3.27(x) 2.68(x) 3.16(x) 1.84(x) Excluding AFUDC/AFUCE 3.31(x) 4.35(x) 3.14(x) 2.59(x) 3.09(x) 1.80(x) Embedded cost of long-term debt 5.31% 5.37% 5.53% 5.79% 5.76% 8.09% Embedded cost of preferred stock — — — — — 7.39% Staff_DR_063 Attachment B Page 154 of 160 AVISTA 134 SELECTED FINANCIAL DATA (CONTINUED) Avista Corporation As of and for the years ended December 31, Dollars in thousands, except per share data and ratios 2015 2014 2013 2012 2011 2005 Financial Condition Total assets (1) (2) $ 4,906,649 $ 4,700,971 $ 4,011,533 $ 3,979,240 $ 3,909,305 $ 4,888,262 Total net Avista Utilities property 3,702,691 3,427,641 3,202,425 3,023,716 2,860,776 2,126,417 Avista Utilities property capital expenditures (excluding equity-related AFUDC) 381,174 323,931 294,363 271,187 239,782 215,341 Long-term debt and capital leases (including current portion) (2) 1,573,278 1,487,126 1,262,036 1,217,520 1,165,014 1,015,376 Nonrecourse long-term debt of Spokane Energy (including current portion) — 1,431 17,838 32,803 46,471 — Long-term debt to affiliated trusts 51,547 51,547 51,547 51,547 51,547 113,403 Preferred stock subject to mandatory redemption (3) — — — — — 28,000 Avista Corporation stockholders’ equity $ 1,528,626 $ 1,483,671 $ 1,298,266 $ 1,259,477 $ 1,185,701 $ 768,849 (1) The total assets at year-end for the years 2013 to 2011 and 2005 exclude the total assets associated with Ecova of $ 339.6 million, $ 322.7 million, $ 292.9 million and $46.1 million, respectively. (2) The total assets and total long-term debt and capital leases for 2014 to 2011 and 2005 were adjusted in accordance with a change in accounting standards. (3) Preferred stock was reclassified from equity to liabilities in 2003 in accordance with a change in accounting standards. Accordingly, preferred stock dividend requirements were reclassified to interest expense effective July 1, 2003. Balance includes current portion. Staff_DR_063 Attachment B Page 155 of 160 135 AVISTA SELECTED FINANCIAL DATA (CONTINUED) Avista Corporation As of and for the years ended December 31, Dollars in thousands, except per share data and ratios 2015 2014 2013 2012 2011 2005 Avista Utilities Electric Operations Electric operating revenues (millions of dollars): Residential $ 335.5 $ 338.7 $ 331.9 $ 315.1 $ 324.9 $ 211.9 Commercial 308.2 300.1 289.6 286.6 280.1 203.5 Industrial 111.8 110.8 113.6 119.6 122.6 91.6 Public street and highway lighting 7.3 7.5 7.3 7.2 6.9 4.9 Total retail 762.8 757.1 742.4 728.5 734.5 511.9 Wholesale 127.3 138.2 127.5 102.7 78.3 151.4 Sales of fuel 82.9 83.7 126.7 115.8 153.5 41.8 Other 25.8 27.5 36.0 21.1 21.9 18.0 Decoupling 4.7 — — — — — Provision for refunds (5.6) (7.5) (2.0) — — — Total electric operating revenues $ 997.9 $ 999.0 $ 1,030.6 $ 968.1 $ 988.2 $ 723.1 Electric energy sales (millions of kWhs): Residential 3,571 3,694 3,745 3,608 3,728 3,420 Commercial 3,197 3,189 3,147 3,127 3,122 2,994 Industrial 1,812 1,868 1,979 2,100 2,147 2,091 Public street and highway lighting 23 25 26 26 26 25 Total retail 8,603 8,776 8,897 8,861 9,023 8,530 Wholesale 3,145 3,686 3,874 3,733 2,796 2,508 Total electric energy sales 11,748 12,462 12,771 12,594 11,819 11,038 Retail electric customers (average per year): Residential 327,057 324,188 321,098 318,692 316,762 294,036 Commercial 41,296 40,988 40,202 39,869 39,618 37,282 Industrial 1,353 1,385 1,386 1,395 1,380 1,408 Public street and highway lighting 529 531 527 503 455 421 Total retail electric customers 370,235 367,092 363,213 360,459 358,215 333,147 Retail electric customers (at year-end): Residential 330,749 326,917 323,801 320,434 318,694 298,961 Commercial 42,182 41,264 40,492 40,024 39,826 37,587 Industrial 1,362 1,378 1,382 1,389 1,385 1,393 Public street and highway lighting 555 527 531 522 456 428 Total retail electric customers 374,848 370,086 366,206 362,369 360,361 338,369 Revenue per residential kWh (cents) 9.40 9.17 8.86 8.73 8.71 6.20 Use per residential customer (kWh) 10,827 11,394 11,664 11,323 11,769 11,630 Revenue per commercial kWh (cents) 9.64 9.41 9.20 9.16 8.97 6.80 Use per commercial customer (kWh) 76,638 77,814 78,276 78,436 78,804 80,314 Electric energy resources (millions of kWhs): Hydro generation (from Company facilities) 3,434 4,143 3,646 4,088 4,534 3,611 Thermal generation (from Company facilities) 3,983 3,252 3,383 2,864 2,447 3,666 Purchased power 4,899 5,615 6,375 6,286 5,435 4,383 Power exchanges (2) (25) (20) (10) (24) 10 Total power resources 12,314 12,985 13,384 13,228 12,392 11,670 Staff_DR_063 Attachment B Page 156 of 160 AVISTA 136 SELECTED FINANCIAL DATA (CONTINUED) Avista Corporation As of and for the years ended December 31, Dollars in thousands, except per share data and ratios 2015 2014 2013 2012 2011 2005 Electric Operations (continued) Energy losses and company use (566) (523) (613) (634) (573) (632) Total electric energy resources 11,748 12,462 12,771 12,594 11,819 11,038 Retail Native Load at time of system peak (MW): Winter 1,529 1,715 1,669 1,554 1,669 1,660 Summer 1,638 1,606 1,577 1,579 1,535 1,498 Natural Gas Operations Natural gas operating revenues (millions of dollars): Residential $ 193.8 $ 203.4 $ 206.3 $ 196.7 $ 219.6 $ 229.7 Commercial 96.8 103.2 102.2 99.0 111.9 126.6 Industrial and interruptible 6.5 6.9 6.3 5.9 6.7 11.9 Total retail 297.1 313.5 314.8 301.6 338.2 368.2 Wholesale 204.3 228.2 194.7 158.6 195.9 58.1 Transportation 8.0 7.7 7.6 7.0 6.7 7.6 Other 5.6 7.5 8.6 6.9 7.4 4.3 Decoupling 6.0 — — — — — Provision for refunds — (0.2) (0.4) — — — Total natural gas operating revenues $ 521.0 $ 556.7 $ 525.3 $ 474.1 $ 548.2 $ 438.2 Natural gas therms delivered (millions of therms): Residential 176.6 190.2 204.7 189.2 207.2 199.4 Commercial 107.9 116.7 122.2 115.1 125.3 123.0 Industrial and interruptible 9.8 10.7 10.9 9.4 10.2 13.5 Total retail 294.3 317.6 337.8 313.7 342.7 335.9 Wholesale 809.1 545.6 524.8 586.2 510.8 72.9 Transportation and other 165.0 162.7 160.4 155.1 152.9 153.5 Total natural gas therms delivered 1,268.4 1,025.9 1,023.0 1,055.0 1,006.4 562.3 Retail natural gas customers (average per year): Residential 296,005 291,928 288,708 286,522 284,504 265,294 Commercial 34,229 34,047 33,932 33,763 33,540 31,652 Industrial and interruptible 296 301 297 301 293 307 Total retail natural gas customers 330,530 326,276 322,937 320,586 318,337 297,253 Retail natural gas customers (at year-end): Residential 299,509 294,993 291,386 288,484 286,567 265,502 Commercial 34,775 34,267 34,084 33,908 33,730 31,476 Industrial and interruptible 289 304 287 308 295 299 Total retail natural gas customers 334,573 329,564 325,757 322,700 320,592 297,277 Revenue per residential therm (in dollars) 1.10 1.07 1.01 1.04 1.06 1.15 Use per residential customer (therms) 593 651 709 660 728 752 Revenue per commercial therm (in dollars) 0.90 0.88 0.84 0.86 0.89 1.03 Staff_DR_063 Attachment B Page 157 of 160 137 AVISTA SELECTED FINANCIAL DATA (CONTINUED) Avista Corporation As of and for the years ended December 31, Dollars in thousands, except per share data and ratios 2015 2014 2013 2012 2011 2005 Natural Gas Operations (continued) Use per commercial customer (therms) 3,128 3,429 3,603 3,409 3,737 3,885 Heating degree days (at Spokane, Washington): Actual 5,614 6,215 6,683 6,256 6,861 6,538 30-year average 6,491 6,820 6,780 6,676 6,647 6,820 Actual as a percent of average 86% 91% 99% 94% 103% 96% Alaska Electric Light and Power Company Revenues (millions of dollars) 44.8 21.6 — — — — Total assets (millions of dollars) 265.7 263.1 — — — — Ecova Revenues (millions of dollars) $ — $ 87.5 $ 176.8 $ 155.7 $ 137.8 $ 31.7 Total assets (millions of dollars) $ — $ — $ 339.6 $ 322.7 $ 292.9 $ 46.1 Other Revenues (millions of dollars) $ 28.7 $ 39.2 $ 39.5 $ 39.0 $ 40.4 $ 185.9 Total assets (millions of dollars) $ 39.2 $ 80.1 $ 81.3 $ 95.6 $ 112.1 $ 2,064.3 Staff_DR_063 Attachment B Page 158 of 160 WE HAVE ENERGY FOR THAT CORPORATE INFORMATION COMPANY HEADQUARTERS Spokane, Washington AVISTA ON THE INTERNET Financial results, stock quotes, news releases and documents filed with the Securities and Exchange Commission (SEC), and information on the company’s products and services are available on Avista’s website at www.avistacorp.com. DIRECT STOCK PURCHASE AND DIVIDEND REINVESTMENT PLAN Computershare sponsors and administers the Computershare Investment Plan (CIP) for Avista Corp. common stock. To invest, obtain forms or for information about your holdings, please contact the transfer agent using the information below. TRANSFER AGENT Computershare P.O. Box 30170 College Station, TX 77842-3170 800.642.7365 www.computershare.com/investor INVESTOR INFORMATION A copy of the company’s financial reports, including the reports on Forms 10-K and 10-Q filed with the SEC, will be provided without charge upon request to: Avista Corp. Investor Relations P.O. Box 3727 MSC-19 Spokane, WA 99220-3727 800.222.4931 ANNUAL MEETING OF SHAREHOLDERS Shareholders are invited to attend the company’s annual meeting to be held at 8:15 a.m. PDT on Thursday, May 12, 2016, at Avista Corp. headquarters, 1411 East Mission Avenue, Spokane, Washington. The annual meeting will be webcast. Please go to www.avistacorp.com to preregister for the webcast and to listen to the live webcast. The webcast will be archived at www.avistacorp.com for one year to allow shareholders to listen at their convenience. EXCHANGE LISTING Ticker Symbol: AVA New York Stock Exchange CERTIFICATIONS On June 2, 2015, the Chief Executive Officer (CEO) of Avista Corp. filed a Section 303A.12(a) Annual CEO Certification with the New York Stock Exchange. The CEO Certification attests that the CEO is not aware of any violations by the company of NYSE’s Corporate Governance Listing Standards. Avista Corp. has included as exhibits to its annual report on Form 10-K for the year 2015, filed with the SEC, certifications of Avista’s Chief Executive Officer and Chief Financial Officer regarding the quality of Avista’s public disclosure in compliance with Section 302 of the Sarbanes-Oxley Act of 2002. This annual report contains forward-looking statements regarding the company’s current expectations. These statements are subject to a variety of risks and uncertainties that could cause actual results to differ materially from the expectations. These risks and uncertainties include, in addition to those discussed herein, all factors discussed in the company’s annual report on Form 10-K for the year 2015. Our 2015 annual report is provided for shareholders. It is not intended for use in connection with any sale or purchase of or any solicitation of others to buy or sell securities. © 2016, Avista Corp. All rights reserved. ACKNOWLEDGEMENTS The 2015 annual report is produced through a partnership of Avista employees and companies within Avista’s service area. Design and Production: Klündt | Hosmer Photography: Dean Davis Photography and Mike Janes, AEL&P Printing: Lawton Printing Services HELP US HELP THE ENVIRONMENT Managing costs is a primary goal for Avista. You can help us meet this goal by agreeing to receive future annual reports and proxy statements electronically. This service saves on the costs of printing and mailing, provides timely delivery of information, and helps protect our environment by saving energy and decreasing the need for paper, printing and mailing materials. FOR MORE INFORMATION, PLEASE VISIT www.avistacorp.com Staff_DR_063 Attachment B Page 159 of 160 BRINGINGENERGYTO LIFE 1411 EAST MISSION AVENUE | SPOKANE, WASHINGTON 99202 | 509.489.0500 | AVISTACORP.COM 2015 ANNUAL REPORT ON THE COVER AVISTA GENERATES AND DELIVERS SAFE, RELIABLE ENERGY. IT’S WHAT OUR CUSTOMERS EXPECT FROM US. BUT WE DELIVER EVEN MORE. EVERYTHING WE DO IS GUIDED BY THE PURPOSE OF BRINGING ENERGY TO LIFE. THE ENERGY WE DELIVER HEATS, COOLS AND LIGHTS HOMES AND BUSINESSES, POWERS MANUFACTURING AND ENABLES THE FUNCTION OF MODERN COMMUNITIES. BEYOND THAT, OUR RESOURCES AND THE PEOPLE BEHIND THEM IMPROVE LIVES IN MANY WAYS — FROM HELPING A REGION RECOVER FROM A WIND STORM, TO FUNDING COLLEGE SCHOLARSHIPS OR FOSTERING THE NEXT GENERATION OF BASEBALL FANS, AVISTA BRINGS ENERGY TO LIFE. Staff_DR_063 Attachment B Page 160 of 160 Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/17/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Mark Thies REQUESTER: UTC Staff - Parcell RESPONDER: Paul Kimball TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff - 063 TELEPHONE: (509) 495-4584 EMAIL: paul.kimball@avistacorp.com REQUEST: Please provide a copy of the following documents: a. 2015 Form 10-K of Avista Corp. b. 2015 Annual Report of Avista Corp. RESPONSE: a. Please see Staff_DR_063 Attachment A b. Please see Staff_DR_063 Attachment B. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/17/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Mark Thies REQUESTER: UTC Staff - Parcell RESPONDER: Paul Kimball TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff - 063 TELEPHONE: (509) 495-4584 EMAIL: paul.kimball@avistacorp.com REQUEST: Please provide a copy of the following documents: a. 2015 Form 10-K of Avista Corp. b. 2015 Annual Report of Avista Corp. RESPONSE: a. Please see Staff_DR_063 Attachment A b. Please see Staff_DR_063 Attachment B. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/17/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Mark Thies REQUESTER: UTC Staff - Parcell RESPONDER: Paul Kimball TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff - 064 TELEPHONE: (509) 495-4584 EMAIL: paul.kimball@avistacorp.com REQUEST: Please provide an organizational chart that describes the various divisions and subsidiaries of Avista Corp. RESPONSE: Please see the Company’s Annual Affiliated Interest and Subsidiary Transactions Report for 2015, pursuant to WAC 480-100-264 filed with the Commission under UE-160447. The report provides an organizational chart and describes Avista’s subsidiaries. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/17/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Mark Thies REQUESTER: UTC Staff - Parcell RESPONDER: Paul Kimball TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff - 064 TELEPHONE: (509) 495-4584 EMAIL: paul.kimball@avistacorp.com REQUEST: Please provide an organizational chart that describes the various divisions and subsidiaries of Avista Corp. RESPONSE: Please see the Company’s Annual Affiliated Interest and Subsidiary Transactions Report for 2015, pursuant to WAC 480-100-264 filed with the Commission under UE-160447. The report provides an organizational chart and describes Avista’s subsidiaries. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/23/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Mark Thies REQUESTER: UTC Staff - Parcell RESPONDER: L. Pendergraft/C. Hulbert TYPE: Data Request DEPT: Finance REQUEST NO.: Staff - 065 TELEPHONE: (509) 495-2998 EMAIL: lauren.pendergraft@avistacorp.com REQUEST: Please provide a schedule that shows the capital structure ratios (in dollars and percentages, including short-term debt, long-term debt, preferred stock, and common equity) for each year 2011– 2015 for the following entities: a. Avista Corp. b. Avista Utilities c. Alaska Light and Power RESPONSE: a. & b. See Staff_DR_065 Attachment A for the capital structure ratios (in dollars and percentages), for each year 2011-2015 for Avista Corp. See Staff_DR_065 Attachment B for the capital structure ratios (in dollars and percentages), for each year 2011-2015 for Avista’s regulatory capital structure which is consistent with prior regulatory filings made by the Company. (Note: For Company regulatory filing capital structures the Company excludes affiliate debt. Prior to July 1, 2014 and the sale of Ecova, the Company included affiliate equity, less Ecova debt. After July 1, 2014 and the purchase of AERC/AEL&P, the Company included affiliate equity less the equity investment in AERC/AEL&P.) c. Please see Staff_DR_065 Attachment C. Page 1 of 3 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/23/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Mark Thies REQUESTER: UTC Staff - Parcell RESPONDER: L. Pendergraft/C. Hulbert TYPE: Data Request DEPT: Finance REQUEST NO.: Staff - 066 TELEPHONE: (509) 495-2998 EMAIL: lauren.pendergraft@avistacorp.com REQUEST: Please provide a schedule that shows the securities ratings (by Fitch, Moody’s and Standard & Poor’s) for each year 2010 to the present for: a. Avista Corp. b. Avista Utilities c. Alaska Light and Power Co. RESPONSE: a. & b. See tables below for securities ratings for 2010 to the present for Avista Corp (note: there are not separate ratings for Avista Utilities as it is an operating division of Avista Corp (not a subsidiary). January 2014- present AAA Aaa AA+Aa1 AA Aa2 AA-Aa3 A+A1 A A2 First Mortgage Bonds / Secured Debt A-First Mortgage Bonds / Secured Debt A3 BBB+Baa1 Issuer rating BBB Corporate credit rating Baa2 Trust-Originated Preferred Securities BBB-Baa3 BB+Trust-Originated Preferred Securities Ba1 BB Ba2 BB-Ba3 Credit Outlook Stable Stable In v e s t m e n t G r a d e No n - in v e s t m e n t Gr a d e Standard & Poor's Moody's Page 2 of 3 August 2011- January 2014 March 2011- August 2011 AAA Aaa AA+Aa1 AA Aa2 AA-Aa3 A+A1 A A2 A-First Mortgage Bonds / Secured Debt A3 First Mortgage Bonds / Secured Debt BBB+Baa1 BBB Corporate credit rating Baa2 Issuer rating BBB-Baa3 Trust-Originated Preferred Securities BB+Trust-Originated Preferred Securities Ba1 BB Ba2 BB-Ba3 Credit Outlook Stable Stable In v e s t m e n t G r a d e No n - in v e s t m e n t Gr a d e Standard & Poor's Moody's AAA Aaa AA+Aa1 AA Aa2 AA-Aa3 A+A1 A A2 A-A3 First Mortgage Bonds / Secured Debt BBB+First Mortgage Bonds / Secured Debt Baa1 BBB Corporate credit rating Baa2 Issuer rating BBB-Baa3 Trust-Originated Preferred Securities BB+Trust-Originated Preferred Securities Ba1 BB Ba2 BB-Ba3 Credit Outlook Stable Stable In v e s t m e n t G r a d e No n - in v e s t m e n t Gr a d e Standard & Poor's Moody's Page 3 of 3 2010- March 2011 c. Please see Avista’s CONFIDENTIAL response to data request Staff_DR_066C. Please note that Avista’s response to Staff_DR_066C is Confidential per Protective Order in UTC Dockets UE- 160228 and UG-160229. Please see Staff_DR_066C Confidential Attachment A. AAA Aaa AA+Aa1 AA Aa2 AA-Aa3 A+A1 A A2 A-A3 BBB+First Mortgage Bonds / Secured Debt Baa1 First Mortgage Bonds / Secured Debt BBB Baa2 BBB-Corporate credit rating Baa3 Issuer rating BB+Ba1 BB Trust-Originated Preferred Securities Ba2 Trust-Originated Preferred Securities BB-Ba3 Credit Outlook Positive Positive In v e s t m e n t G r a d e No n - in v e s t m e n t Gr a d e Standard & Poor's Moody's Page 1 of 3 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/23/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Mark Thies REQUESTER: UTC Staff - Parcell RESPONDER: L. Pendergraft/C. Hulbert TYPE: Data Request DEPT: Finance REQUEST NO.: Staff - 066 TELEPHONE: (509) 495-2998 EMAIL: lauren.pendergraft@avistacorp.com REQUEST: Please provide a schedule that shows the securities ratings (by Fitch, Moody’s and Standard & Poor’s) for each year 2010 to the present for: a. Avista Corp. b. Avista Utilities c. Alaska Light and Power Co. RESPONSE: a. & b. See tables below for securities ratings for 2010 to the present for Avista Corp (note: there are not separate ratings for Avista Utilities as it is an operating division of Avista Corp (not a subsidiary). January 2014- present AAA Aaa AA+Aa1 AA Aa2 AA-Aa3 A+A1 A A2 First Mortgage Bonds / Secured Debt A-First Mortgage Bonds / Secured Debt A3 BBB+Baa1 Issuer rating BBB Corporate credit rating Baa2 Trust-Originated Preferred Securities BBB-Baa3 BB+Trust-Originated Preferred Securities Ba1 BB Ba2 BB-Ba3 Credit Outlook Stable Stable In v e s t m e n t G r a d e No n - in v e s t m e n t Gr a d e Standard & Poor's Moody's Page 2 of 3 August 2011- January 2014 March 2011- August 2011 AAA Aaa AA+Aa1 AA Aa2 AA-Aa3 A+A1 A A2 A-First Mortgage Bonds / Secured Debt A3 First Mortgage Bonds / Secured Debt BBB+Baa1 BBB Corporate credit rating Baa2 Issuer rating BBB-Baa3 Trust-Originated Preferred Securities BB+Trust-Originated Preferred Securities Ba1 BB Ba2 BB-Ba3 Credit Outlook Stable Stable In v e s t m e n t G r a d e No n - in v e s t m e n t Gr a d e Standard & Poor's Moody's AAA Aaa AA+Aa1 AA Aa2 AA-Aa3 A+A1 A A2 A-A3 First Mortgage Bonds / Secured Debt BBB+First Mortgage Bonds / Secured Debt Baa1 BBB Corporate credit rating Baa2 Issuer rating BBB-Baa3 Trust-Originated Preferred Securities BB+Trust-Originated Preferred Securities Ba1 BB Ba2 BB-Ba3 Credit Outlook Stable Stable In v e s t m e n t G r a d e No n - in v e s t m e n t Gr a d e Standard & Poor's Moody's Page 3 of 3 2010- March 2011 c. Please see Avista’s CONFIDENTIAL response to data request Staff_DR_066C. Please note that Avista’s response to Staff_DR_066C is Confidential per Protective Order in UTC Dockets UE- 160228 and UG-160229. Please see Staff_DR_066C Confidential Attachment A. AAA Aaa AA+Aa1 AA Aa2 AA-Aa3 A+A1 A A2 A-A3 BBB+First Mortgage Bonds / Secured Debt Baa1 First Mortgage Bonds / Secured Debt BBB Baa2 BBB-Corporate credit rating Baa3 Issuer rating BB+Ba1 BB Trust-Originated Preferred Securities Ba2 Trust-Originated Preferred Securities BB-Ba3 Credit Outlook Positive Positive In v e s t m e n t G r a d e No n - in v e s t m e n t Gr a d e Standard & Poor's Moody's Summary: Avista Corp. Primary Credit Analyst: Gerrit W Jepsen, CFA, New York (1) 212-438-2529; gerrit.jepsen@standardandpoors.com Secondary Contact: Matthew L O'Neill, New York (1) 212-438-4295; matthew.oneill@standardandpoors.com Table Of Contents Rationale Outlook Standard & Poor's Base-Case Scenario Business Risk Financial Risk Liquidity Other Credit Considerations Group Influence Ratings Score Snapshot Recovery Analysis Issue Ratings Related Criteria And Research WWW.STANDARDANDPOORS.COM/RATINGSDIRECT MAY 19, 2015 1 THIS WAS PREPARED EXCLUSIVELY FOR USER PAT GORTON. NOT FOR REDISTRIBUTION UNLESS OTHERWISE PERMITTED. 1399426 | 302321598 Staff_DR_067 Attachment A Page 1 of 7 WWW.STANDARDANDPOORS.COM/RATINGSDIRECT THIS WAS PREPARED EXCLUSIVELY FOR USER PAT GORTON. NOT FOR REDISTRIBUTION UNLESS OTHERWISE PERMITTED. MAY 19, 2015 2 1399426 | 302321598 Summary: Avista Corp. Rationale Business Risk: Strong Financial Risk: Significant  Regulated vertically integrated electric and natural gas distribution utility.  Geographic and operational diversity but largely Washington focus.  Higher hydroelectric power use.  Regulatory mechanisms provide cash flow stability when purchasing power during low water periods.  Elevated capital spending over the next few years.  Negatively discretionary cash flow after dividends.  Consistent access to capital markets to fund capital spending.  A "strong" liquidity position that provides the utility a cushion due to its hydroelectric power use. Business Risk: STRONG CORPORATE CREDIT RATING Vulnerable Excellent bbb bbb bbb Financial Risk: SIGNIFICANT BBB/Stable/A-2 Highly leveraged Minimal Anchor Modifiers Group/Gov't Staff_DR_067 Attachment A Page 2 of 7 WWW.STANDARDANDPOORS.COM/RATINGSDIRECT THIS WAS PREPARED EXCLUSIVELY FOR USER PAT GORTON. NOT FOR REDISTRIBUTION UNLESS OTHERWISE PERMITTED. MAY 19, 2015 3 1399426 | 302321598 Summary: Avista Corp. Standard & Poor's Base-Case Scenario Assumptions Key Metrics  Average capital spending of $360 million in 2015 and declining to $350 million for 2016.  Dividends of roughly $85 million per year over the forecasted period.  Regular recovery of electric and gas rates through respective surcharges.  Average operation and maintenance expenses consistent with historical levels.  Negative discretionary cash flow indicating external funding needs. 2014A 2015E 2016E FFO/total debt (%) 20.8 14.2-15.5 15.7-16.5 Debt/EBITDA (x) 4.5 4.2-4.6 3.8-4.2 OCF/total debt (%) 24 17-18.5 17-18.5 Note: Standard & Poor's adjusted figures. A--Actual. E--Estimate. FFO--Funds from operations. OCF--Operating cash flow. Business Risk: Strong In our assessment, Avista's business risk profile is "strong" based on what we consider the utility's "satisfactory" competitive position, "very low" industry risk of the regulated utility industry, and "very low" country risk of the U.S. where the company operates. The company's competitive position incorporates its vertically integrated electric and natural gas distribution utility operations in Washington and Idaho, electric operations in Alaska, and gas distribution Outlook: Stable Downside scenario Upside scenario Staff_DR_067 Attachment A Page 3 of 7 WWW.STANDARDANDPOORS.COM/RATINGSDIRECT THIS WAS PREPARED EXCLUSIVELY FOR USER PAT GORTON. NOT FOR REDISTRIBUTION UNLESS OTHERWISE PERMITTED. MAY 19, 2015 4 1399426 | 302321598 Summary: Avista Corp. in Oregon. Although the company operates in four states, it has fewer than 400,000 electric and about 330,000 natural gas customers with no meaningful industrial concentration. When needed, the utility requests through the regulatory process to recover costs. Since the utility has hydroelectric power exposure, recovery mechanisms are important to mitigate the need to purchase power for customers when the hydro power is unavailable. The company has some flexibility in implementing incremental rate changes through its energy recovery mechanism in Washington and the power cost adjustment in Idaho, but the recovery of excess power costs in Washington is more restrictive with minimum thresholds and deferral bands. Purchased gas adjustments for gas distribution units in all three gas jurisdictions, along with hedging, mitigate gas supply risk. We view these as important in averting large cost adjustment requests and support the business risk profile. Financial Risk: Significant We base our financial risk profile assessment of "significant" on the medial volatility financial ratio benchmarks. Our assessment takes into consideration the mostly steady cash flows from the utility business. Our base case indicates that capital spending along with dividend payments will lead to negative discretionary cash flow over the next few years. External funding will be needed to cover the deficit since internally generated cash flow is insufficient. Our base-case scenario suggests mostly steady key credit measures for the next several years, including FFO to debt from about 14% to 16%. Our base case indicates that the supplemental ratio of operating cash flow to debt is expected to range from about 17% to about 18.5%, bolstering the "significant" financial risk profile assessment. Liquidity: Strong Avista has "strong" liquidity as our criteria define the term. We believe the company's liquidity sources are likely to cover its uses by more than 1.5x over the next 12 months and remain above 1x over the subsequent 12 months. We expect the company to meet cash outflows even with a 30% decline in EBITDA. Principal Liquidity Sources Principal Liquidity Uses  We estimate FFO of about $280 million in 2015 and $310 million in 2016.  Revolving credit facility of $425 million in 2015 and 2016.  Capital spending of about $360 million in 2015 and $350 million in 2016.  Dividends of roughly $85 million per year in 2015 and 2016. Other Credit Considerations Other modifiers have no impact on the rating outcome. Staff_DR_067 Attachment A Page 4 of 7 WWW.STANDARDANDPOORS.COM/RATINGSDIRECT THIS WAS PREPARED EXCLUSIVELY FOR USER PAT GORTON. NOT FOR REDISTRIBUTION UNLESS OTHERWISE PERMITTED. MAY 19, 2015 5 1399426 | 302321598 Summary: Avista Corp. Group Influence Avista is subject to the group rating methodology criteria. We view Avista as the parent that is also the driver of the group credit profile. As a result, Avista's group and stand-alone credit profiles are the same at 'bbb'. Ratings Score Snapshot Corporate Credit Rating BBB/Stable/A-2 Business risk: Strong  Country risk: Very low  Industry risk: Very low  Competitive position: Satisfactory Financial risk: Significant  Cash flow/Leverage: Significant Anchor: bbb Modifiers  Diversification/Portfolio effect: Neutral (no impact)  Capital structure: Neutral (no impact)  Financial policy: Neutral (no impact)  Liquidity: Strong (no impact)  Management and governance: Satisfactory (no impact)  Comparable rating analysis: Neutral (no impact) Stand-alone credit profile : bbb  Group credit profile: bbb Recovery Analysis  Avista's first mortgage bonds benefit from a first-priority lien on substantially all of the utility's real property owned or subsequently acquired. Collateral coverage of more than 1.5x supports a recovery rating of '1+' and an issue rating two notches above the issuer credit rating. Issue Ratings  We rate the preferred stock two notches below the issuer credit rating to reflect the discretionary nature of the dividend and the deeply subordinated claim if a bankruptcy occurs. Staff_DR_067 Attachment A Page 5 of 7 WWW.STANDARDANDPOORS.COM/RATINGSDIRECT THIS WAS PREPARED EXCLUSIVELY FOR USER PAT GORTON. NOT FOR REDISTRIBUTION UNLESS OTHERWISE PERMITTED. MAY 19, 2015 6 1399426 | 302321598 Summary: Avista Corp.  The short-term rating on Avista is 'A-2' based on the issuer credit rating and our assessment of its liquidity as at least adequate. Related Criteria And Research Related Criteria  Criteria - Corporates - General: Methodology And Assumptions: Liquidity Descriptors For Global Corporate Issuers, Dec. 16, 2014  Criteria - Corporates - Utilities: Key Credit Factors For The Regulated Utilities Industry, Nov. 19, 2013  Criteria - Corporates - General: Corporate Methodology: Ratios And Adjustments, Nov. 19, 2013  General Criteria: Methodology: Industry Risk, Nov. 19, 2013  Criteria - Corporates - General: Corporate Methodology, Nov. 19, 2013  General Criteria: Methodology For Linking Short-Term And Long-Term Ratings For Corporate, Insurance, And Sovereign Issuers, May 7, 2013  Criteria - Corporates - Utilities: Collateral Coverage And Issue Notching Rules For ‘1+’ And ‘1’ Recovery Ratings On Senior Bonds Secured By Utility Real Property, Feb. 14, 2013  General Criteria: Methodology: Management And Governance Credit Factors For Corporate Entities And Insurers, Nov. 13, 2012  Criteria - Corporates - General: 2008 Corporate Criteria: Rating Each Issue, April 15, 2008 b- Business And Financial Risk Matrix Business Risk Profile Financial Risk Profile Significant Strong bbb Staff_DR_067 Attachment A Page 6 of 7 WWW.STANDARDANDPOORS.COM/RATINGSDIRECT THIS WAS PREPARED EXCLUSIVELY FOR USER PAT GORTON. 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S&P Parties disclaim any duty whatsoever arising out of the assignment, withdrawal, or suspension of an acknowledgment as well as any liability for any damage alleged to have been suffered on account thereof. S&P keeps certain activities of its business units separate from each other in order to preserve the independence and objectivity of their respective activities. As a result, certain business units of S&P may have information that is not available to other S&P business units. S&P has established policies and procedures to maintain the confidentiality of certain nonpublic information received in connection with each analytical process. S&P may receive compensation for its ratings and certain analyses, normally from issuers or underwriters of securities or from obligors. S&P reserves the right to disseminate its opinions and analyses. S&P's public ratings and analyses are made available on its Web sites, www.standardandpoors.com (free of charge), and www.ratingsdirect.com and www.globalcreditportal.com (subscription) and www.spcapitaliq.com (subscription) and may be distributed through other means, including via S&P publications and third-party redistributors. Additional information about our ratings fees is available at www.standardandpoors.com/usratingsfees. Staff_DR_067 Attachment A Page 7 of 7 Credit Opinion: Avista Corp. Global Credit Research - 11 Mar 2015 Spokane, Washington, United States Ratings Category Moody's Rating Outlook Stable Issuer Rating Baa1 First Mortgage Bonds A2 Senior Secured A2 Senior Unsecured MTN (P)Baa1 Avista Corp. Capital II Outlook Stable BACKED Pref. Stock Baa2 Contacts Analyst Phone Ryan Wobbrock/New York City 212.553.7104 William L. Hess/New York City 212.553.3837 Key Indicators [1]Avista Corp. 12/31/2014 12/31/2013 12/31/2012 12/31/2011 CFO pre-WC + Interest / Interest 5.2x 4.8x 4.4x 4.8x CFO pre-WC / Debt 18.8%19.4%17.4%19.1% CFO pre-WC - Dividends / Debt 14.3%15.0%13.3%15.1% Debt / Capitalization 44.4%46.9%47.7%47.5% [1] All ratios are based on 'Adjusted' financial data and incorporate Moody's Global Standard Adjustments for Non- Financial Corporations. Source: Moody's Financial Metrics Note: For definitions of Moody's most common ratio terms please see the accompanying User's Guide. Opinion Rating Drivers Low-risk utility in supportive regulatory jurisdictions Core utility business in Washington provides stable cash flow Elevated capex, dividend payout and share buybacks are credit negatives Corporate Profile Avista Corp. is primarily a regulated electric and gas utility servicing around 367,000 electric and 326,000 gas customers in Washington, Idaho and Oregon. Avista also owns Alaska Energy and Resources Company (AERC; Staff_DR_067 Attachment B Page 1 of 7 not rated), parent of Alaska Electric Light and Power Company (AEL&P; not rated) which serves around 16,000 electric customers in Juneau, Alaska. Avista's utility operations are primarily regulated by the Washington Utilities and Transportation Commission (WUTC), Idaho Public Utilities Commission (IPUC) and the Oregon Public Utility Commission (OPUC). AEL&P's rates are regulated by the Regulatory Commission of Alaska (RCA). SUMMARY RATING RATIONALE Avista's Baa1 issuer rating reflects its primary business as a low-risk vertically integrated electric and gas utility in supportive regulatory jurisdictions. The rating also incorporates a steady financial profile that should remain as such with a newly implemented decoupling mechanism in Washington, and a business risk profile that has been enhanced by the 2014 sale of its unregulated energy management services subsidiary in mid-2014. The addition of a small utility in Alaska has added marginal regulatory, operational and cash flow diversity, but remains ratings neutral for the company. Avista has initiated, and partly executed, a share repurchase program and increasing dividend during a time of heightened capital expenditures, which tempers some of the positive ratings trends. Furthermore, management team has identified areas of intended growth which could be unregulated in nature, but we view this as more long- term and is not incorporated in the Baa1 rating. DETAILED RATING CONSIDERATIONS SUPPORTIVE REGULATION PROVIDES RATINGS BALLAST The primary credit driver for Avista is the degree of regulatory support and cost recovery allowed by its regulatory authorities, and particularly via the WUTC, which regulates roughly 60% of the company's revenue. In December 2014, the WUTC authorized approximately $12.3 million of electric, and $8.5 million gas, revenue increases, effective January 1, 2015. More importantly, the WUTC rate order allowed Avista to implement a revenue decoupling mechanism for both electric and gas customers. The mechanism will be in place for five years, but reviewed after three years and will include an earnings test and demand reduction targets for determining collections/rebates. Avista's annual decoupling charges will be capped at 3% of rates, with unrecovered balances carried forward to future years. We view the implementation of full electric and gas decoupling mechanisms as a significant credit positive for the company, since it will enhance the recovery of fixed costs for the utility and provide for stable and predictable gross margin and cash flow over the next several years. While the company's cash flow has been very stable, historically, the decoupling mechanism should help to reduce some regulatory lag. While we've seen improvement in the Washington jurisdiction, we note that Avista's recent all-party (and OPUC staff approved) settlement in Oregon was rejected by the OPUC. Avista had filed for over $9.1 million of revenue increases in Oregon, in which the OPUC took exception to three areas: early adoption of a customer credit related to pipe replacement expenditures; rate allocation between customers; and an accounting mechanism which could defer margin based on actual-to-stipulated customer count (i.e., "customer count tracking mechanism"). While we maintain our view that the Oregon regulatory framework is ultimately supportive, the rejection of an all-party settlement is rare and adds an element of unpredictability to the ultimate decision and rate structure of the case. Oregon rates typically provide roughly 10% of Avista's annual revenue, so while it is a credit negative from a predictability standpoint, it is not a material ratings driver. We note that the company and settling parties issued a new stipulation, to address the OPUC concerns, on March 6th. Idaho, Avista's third primary regulatory jurisdiction, is viewed as the most supportive of Avista's state regulatory environments. The IPUC allows for a wide variety of interim rate making mechanisms (trackers) and has a track record of credit supportive rate decisions. This allows for a high degree of predictability to roughly 25% of Avista's consolidated revenue. FINANCIAL METRICS COULD BE PRESSURED AMIDST SHARE BUYBACKS, HIGH CAPEX AND INCREASING DIVIDEND Avista's key financial metrics, such as cash flow from operations before the changes in working capital (CFO pre- WC) to debt, have been very stable over the past five years, at around 17%. The company consistently produces around $275 million of CFO pre-WC, which excludes the impact of one-time cash flow benefits from tax accounting allowances (the most significant benefit occurring in 2014, where both capital repairs and bonus depreciation boosted CFO through deferred taxes). This compares to roughly $1.6 billion of debt, on average over the past five years. Staff_DR_067 Attachment B Page 2 of 7 The primary challenges to Avista's financial metrics will come via a heightened capital spend and high dividend payout. The company's capital expenditures have been on a steady rise since 2010 ($205 million) and is expected to peak at $390 million this year (including $15 million at AEL&P), while maintaining a relatively high $365 million in both 2016 and 2017. Financing these expenditures will require additional debt issuances, especially in light of a share buyback program (approximately 2.5 million shares were repurchased in 2014 for nearly $80 million; the company also has board authorization to repurchase 800,000 more through 1Q15) and an increasing dividend, targeted at a growth of 4% to 5% annually. We note that the company is expecting to keep the dividend within its earnings growth rate, but at a negative free cash flow level of $180 million in 2015, Avista is financing the dividend through debt - a credit negative. Our expectations for Avista to produce $275 million of CFO, have $390 million in capital expenditures and over $80 million of expected dividends, will leave the company with a significant free cash flow deficit (i.e., about $195 million) in the coming months. The company will make use of the cash flow generated from tax benefits to help fund these expenditures, which may lessen the debt financing required (we expect Avista to capitalize operations in-line with its WUTC allowed capital structure of 47% / 53% equity / debt). Absent the one-time tax boosts to CFO, and considering higher debt levels, Avista could produce at or near 15% CFO pre-WC to debt, which is more reflective of a Baa2 vertically integrated electric and gas utility. Avista's greatest capital requirements are primarily related to bolstering its transmission and distribution assets, as well as upgrading its hydroelectric generation facilities. The nature of these investments is more basic when compared to many other integrated utilities across the nation who are in the midst of constructing new generation facilities or making significant environmental upgrades. Avista's long power supply position is beneficial to its credit profile as the company is not currently required to make investments in higher-cost, higher-risk assets, like many of its regional peers. APPETITE FOR GROWTH MAY INTRODUCE GREATER RISK OVER THE LONG-TERM Avista's business risk profile improved in 2014, through the sale of Avista's primary unregulated business (Ecova, not rated) and through the acquisition of rate regulated utility assets in Alaska. We view both developments as credit positive since it increased the overall contribution and diversity of regulated cash flow to consolidated operations. However, we view both as ratings neutral given the small size of each subsidiary. Furthermore, the addition of AERC offers no real synergies to speak of, along with a new regulatory relationship to maintain, which requires a share of management attention. As described above, the nature of Avista's capital plan is viewed positively, since it is focused on basic system improvements; however, we continue to caution that should the "plain vanilla" type investment profile cause management to look for growth opportunities in non-traditional areas, this could have the potential to raise the risk profile of Avista's investments, which could overshadow the regulated bias of M&A activity in 2014. Along these lines, we note that management has identified and drawn attention to creating new growth platforms through a non-utility subsidiary, Salix, Inc. (not rated), a subsidiary of Avista Capital, Incl. (not rated, a wholly- owned subsidiary of Avista). Salix was formed to explore opportunities to extend natural gas use beyond traditional pipeline supplied markets, via expansion of liquefied natural gas (LNG) services throughout the region. Avista's strategy is premised on the low-price and abundant supply of natural gas, which could give LNG an economic advantage over other competing fuels. We view Salix much in the same way we did the development of Ecova, from its nascent stages in the mid-to-late 2000's. We expect that management will take small, measured approaches to the development of its unregulated business, with Salix's overall contribution to the consolidated entity remaining around 10% - 15% of earnings and cash flow. Should Salix grow to be a larger portion of earnings and cash flow, or exhibit more business risk (e.g., as a commodity-based business, unlike the operations of Ecova), we would view this as negative to Avista's credit profile. Currently, Salix and Avista's plans to explore LNG delivery throughout the Pacific Northwest is not impacting the company's ratings. Liquidity Avista's external liquidity source consists of a $400 million senior secured revolving credit facility, which expires in April 2019. As of December 31, 2014, there were $105 million of cash borrowings and nearly $33 million in letters of credit outstanding, leaving $262 million of available liquidity under the line of credit. Since Avista currently has unsecured investment grade ratings from two nationally recognized rating agencies, the company has the option to request the banks to relinquish the existing First Mortgage Bond collateral position, but it has chosen not to do so for economic reasons. Despite the collateral staying in place at Avista's discretion, the secured nature of the credit Staff_DR_067 Attachment B Page 3 of 7 facilities somewhat constrains Avista's liquidity flexibility, in our opinion, since the typical investment grade issuer (having an unsecured facility) can use collateral as an option to improve bank credit access during periods of unforeseen liquidity stress. The facility has a $100 million accordion feature and is subject to grid pricing. The $400 million facility does not contain any material adverse change language for borrowings but does so to access the $100 million accordion feature. The facility also includes a debt to capitalization covenant not to exceed 65%. As of December 2014, the company had sufficient headroom available under the debt to capitalization covenant. AEL&P has a $25 million line of credit which expires in November 2019 and has a consolidated debt to capitalization covenant of 67.5%. As of December 31, 2014, the full amount was available for borrowing and AEL&P was in compliance with its covenant. Avista's next material debt maturities occur in August 2016 when $90 million of first mortgage bonds is due. AERC's next maturity is in 2019 when its $15 million term loan is scheduled to expire. Rating Outlook The stable outlook incorporates our view that Avista's financial profile will maintain CFO pre-WC to debt in the high-teens range and that it will ultimately continue to receive supportive cost recovery from its regulators. The stable outlook also incorporates a view that unregulated operations will remain below 15% of consolidated earnings and cash flow, and that the company's financial policy will maintain a relatively even mix of debt and equity in its capital structure. What Could Change the Rating - Up The ratings for Avista could be upgraded if the company were able to produce CFO pre-WC to debt above 20% on a sustainable basis, without the benefits from one-time tax policy adjustments. What Could Change the Rating - Down Avista's ratings could be negatively impacted if the level of regulatory support wanes, if the contribution of its unregulated business were to increase disproportionately to those of its regulated operations, or if CFO pre-WC to debt were to fall to 15% for a sustainable period. Rating Factors Avista Corp. Regulated Electric and Gas Utilities Industry Grid [1][2] Current LTM 12/31/2014 [3]Moody's 12-18 Month Forward ViewAs of Date Published Factor 1 : Regulatory Framework (25%)Measure Score Measure Score a) Legislative and Judicial Underpinnings of the Regulatory Framework A A A A b) Consistency and Predictability of Regulation A A A A Factor 2 : Ability to Recover Costs and Earn Returns (25%) a) Timeliness of Recovery of Operating and Capital Costs Baa Baa Baa Baa b) Sufficiency of Rates and Returns Baa Baa Baa Baa Factor 3 : Diversification (10%) a) Market Position Baa Baa Baa Baa b) Generation and Fuel Diversity A A A A Factor 4 : Financial Strength (40%) a) CFO pre-WC + Interest / Interest (3 Year Avg) 4.8x A 4.5x - 4.9x A b) CFO pre-WC / Debt (3 Year Avg)18.6%Baa 15% - 19%Baa Staff_DR_067 Attachment B Page 4 of 7 c) CFO pre-WC - Dividends / Debt (3 Year Avg) 14.2%Baa 11% - 15%Baa d) Debt / Capitalization (3 Year Avg)46.4%Baa 45% - 50%Baa Rating: Grid-Indicated Rating Before Notching Adjustment Baa1 Baa1 HoldCo Structural Subordination Notching n/a n/a n/a a) Indicated Rating from Grid Baa1 Baa1 b) Actual Rating Assigned Baa1 Baa1 [1] All ratios are based on 'Adjusted' financial data and incorporate Moody's Global Standard Adjustments for Non- Financial Corporations. 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MJKK or MSFJ (as applicable) hereby disclose that most issuers of debt securities (including corporate and municipal bonds, debentures, notes and commercial paper) and preferred stock rated by MJKK or MSFJ (as applicable) have, prior to assignment of any rating, agreed to pay to MJKK or MSFJ (as applicable) for appraisal and rating services rendered by it fees ranging from JPY200,000 to approximately JPY350,000,000. MJKK and MSFJ also maintain policies and procedures to address Japanese regulatory requirements. Staff_DR_067 Attachment B Page 7 of 7 INFRASTRUCTURE AND PROJECT FINANCE CREDIT OPINION 11 March 2016 Update RATINGS AVISTA CORP. Domicile Spokane, Washington,United States Long Term Rating Baa1 Type LT Issuer Rating Date 30 Jan 2014 Outlook Stable Date 30 Jan 2014 Please see the ratings section at the end of this reportfor more information. Contacts Ryan Wobbrock 212-553-7104 AVP-Analyst ryan.wobbrock@moodys.com Richa N Patel 212-553-9475 Associate Analyst richa.patel@moodys.com William L. Hess 212-553-3837 MD-Utilities william.hess@moodys.com Avista Corp. A Vertically Integrated Electric and Gas Utility Summary Rating Rationale Avista's Baa1 issuer rating reflects its primary business as a low-risk vertically integrated electric and gas utility with strong financial metrics. The rating is underpinned by supportive regulatory jurisdictions, which provide important cost recovery mechanisms such as electric and gas revenue decoupling. Avista has some unregulated exposure in addition to its ownership of regulated utility Alaska Electric Light and Power (AELP, Baa3 stable), which provide marginal operational and cash flow diversity, but remain neutral in terms of affecting the ratings of Avista. Exhibit 1 Avista's CFO pre-WC to debt is consistently in the high-teens. Source: Moody's Investors Service Staff_DR_067 Attachment C Page 1 of 6 MOODY'S INVESTORS SERVICE INFRASTRUCTURE AND PROJECT FINANCE This publication does not announce a credit rating action. For any credit ratings referenced in this publication, please see the ratings tab on the issuer/entity page on www.moodys.com for the most updated credit rating action information and rating history. 2 11 March 2016 Avista Corp.: A Vertically Integrated Electric and Gas Utility Credit Strengths » Low-risk utility in supportive regulatory jurisdictions » Core utility business in Washington provides stable cash flow Credit Challenges » High dividend payout ratio » Eying long-term growth potential outside of rate-regulated, core business Rating Outlook The stable outlook incorporates our view that Avista's financial profile will maintain CFO pre-WC to debt in the high-teens range and that it will continue to receive supportive cost recovery from its regulators. The stable outlook also incorporates a view that unregulated operations will remain below 15% of consolidated earnings and cash flow, and that the company's financial policy will maintain a relatively even mix of debt and equity in its capital structure. Factors that Could Lead to an Upgrade The ratings for Avista could be upgraded if the company were able to produce CFO pre-WC to debt above 20% on a sustainable basis, without the benefits from one-time adjustments. Factors that Could Lead to a Downgrade Avista's ratings could be negatively impacted if the level of regulatory support wanes, if the contribution of its unregulated business were to increase disproportionately to those of its regulated operations, or if CFO pre-WC to debt were to fall to 15% for a sustainable period. Key Indicators Exhibit 2 [1] All ratios are based on 'Adjusted' financial data and incorporate Moody's Global Standard Adjustments for Non-Financial Corporations.Source: Moody's Investors Service Staff_DR_067 Attachment C Page 2 of 6 MOODY'S INVESTORS SERVICE INFRASTRUCTURE AND PROJECT FINANCE 3 11 March 2016 Avista Corp.: A Vertically Integrated Electric and Gas Utility Detailed Rating Considerations RECENT REGULATORY DECISIONS ARE CREDIT POSITIVE The primary credit driver for Avista is the degree of regulatory support and cost recovery allowed by its regulatory authorities, and particularly via the Washington Utilities and Transportation Commission (WUTC), which regulates roughly 60% of the company's revenue. We view the WUTC to be generally supportive to credit, while having improved cost recovery provisions in the last few years. For example, in December 2014, the WUTC allowed Avista to implement electric and gas decoupling mechanisms which enhances the timely recovery of fixed costs for the utility and provides for stable and predictable gross margin and cash flow in the face of declining use, in addition to attrition adjustments for ongoing rates. This has been particularly helpful for Avista, since energy delivery to customers has fallen in both electric and gas segments for 2015. More recently, the WUTC allowed a $10.8 million gas revenue increase in January; however, the commission also ordered the company to reduce electric rates by $8.1 million. The rate reduction was mainly driven by lower commodity and power prices compared to the time when Avista made its original filing. As such, we view the WUTC order as immaterial to Avista’s credit profile, since fuel and power costs do not generate margin and the rate reduction is not a result of unsupportive regulatory treatment. Following the electric rate decrease, Avista filed a rate case with a two–step electric and gas rate increase proposal through the 18 months ending June 2018. Avista’s request includes around $50 million of electric and approaching $6 million of gas annual rate increases. Avista will also be offsetting some of the customer rate impacts through energy recovery mechanism (ERM) rebates. The filing is primarily driven by capital investments for maintaining and upgrading its system. In Oregon, the Oregon Public Utilities Commission (OPUC) approved a $4.5 million gas rate increase on March 3, 2016, based on a 9.4% return on equity. While relatively minor in terms of scale, the decision is credit positive since Avista is now allowed to implement a revenue-per-customer decoupling mechanism. In Idaho, the Idaho Public Utilities Commission (IPUC) authorized Avista just under $2 million of electric and just over $2 million of gas rate increases, effective January 1, 2016, with an allowed ROE of 9.5%. In addition to the settlement, the company was authorized electric and gas decoupling mechanisms, as well. STRONG CASH FLOW METRICS OFFSET HIGH PAYOUT AND SHARE REPURCHASES MADE IN 2014 Avista's key financial metrics, such as cash flow from operations before the changes in working capital (CFO pre-WC) to debt, have been very stable over the past five years, at around 19%. The strength and consistency of Avista’s financial metrics provides an offset to a dividend payout ratio that is close to 70% and the repurchase of $80 million worth of common stock in 2014. Despite these credit negative financial policies, Avista continues to maintain a financial profile in-line with Baa1 integrated peers, who have averaged just over 20% CFO pre-WC to debt and 15% CFO pre-WC less dividends to debt over the past five years; both are consistent with the levels produced by Avista over this time. Avista’s $376 million of CFO in 2015 is significantly higher than historical periods, partly due to: higher depreciation and amortization from additional plant-in-service and a full year of AELP on Avista’s consolidated books; non-cash pension expense exceeding cash plan contributions by around $25 million; and a $35 million swing in power and natural gas cost deferrals. While the asset additions will continue to boost depreciation and amortization, we expect the pension and deferrals for power and fuel costs to reverse over time, as the company’s recovery mechanisms true-up the temporary mismatch between the costs Avista incurred and rates charged to customers. We expect for Avista’s ongoing margin and cash flow to remain around $300 million due to margin-stabilizing decoupling mechanisms in Washington, Idaho and Oregon. This would result in about 17% of Avista’s total adjusted debt at December 2015. APPETITE FOR GROWTH MAY INTRODUCE GREATER RISK OVER THE LONG-TERM Avista management has indicated an interest in creating new growth platforms through a non-utility subsidiary, Salix, Inc. (not rated), a subsidiary of Avista Capital, Inc. (not rated, a wholly-owned subsidiary of Avista). Salix was formed to explore opportunities to extend natural gas use beyond traditional pipeline supplied markets, via expansion of liquefied natural gas (LNG) services throughout Staff_DR_067 Attachment C Page 3 of 6 MOODY'S INVESTORS SERVICE INFRASTRUCTURE AND PROJECT FINANCE 4 11 March 2016 Avista Corp.: A Vertically Integrated Electric and Gas Utility the region. Avista's strategy is premised on the low-price and abundant supply of natural gas, which could give LNG an economic advantage over other competing fuels. However, this strategy has slowed given the steep declines in oil prices over the last 18 months. For now, we expect that the management will take small, measured approaches to the development of its unregulated business. Currently, we do not view Salix as a negative to Avista's credit profile; however, if Salix grows to be a larger portion of earnings and cash flow, or exhibit more business risk, it has the potential of negatively hurting the credit profile for Avista. The current nature of Avista's capital plan is viewed positively, since the company is long power and primarily focused on basic system improvements; but, if other non-traditional areas are targeted for growth opportunities, this could have the potential to raise the risk profile of the company. Liquidity Analysis Avista's external liquidity source consists of a $400 million senior secured revolving credit facility, which expires in April 2019. As of December 31, 2015, there were $149 million of cash borrowings, leaving $250.4 million of available liquidity under the line of credit. Since Avista currently has unsecured investment grade ratings from two nationally recognized rating agencies, the company has the option to request the banks to relinquish the existing First Mortgage Bond collateral position, but it has chosen not to do so for economic reasons. Despite the collateral staying in place at Avista's discretion, the secured nature of the credit facilities somewhat constrains Avista's liquidity flexibility, in our opinion, since the typical investment grade issuer (having an unsecured facility) can use collateral as an option to improve bank credit access during periods of unforeseen liquidity stress. The facility has a $100 million accordion feature and is subject to grid pricing. The $400 million facility does not contain any material adverse change language for borrowings but does so to access the $100 million accordion feature. The facility also includes a debt to capitalization covenant not to exceed 65%. As of December 2015, the company had sufficient headroom available under the debt to capitalization covenant. AEL&P has a $25 million line of credit which expires in November 2019 and has a consolidated debt to capitalization covenant of 67.5%. As of December 31, 2015, the full amount was available for borrowing and AEL&P was in compliance with its covenant. Avista's next material debt maturities occur in August 2016 when $90 million of first mortgage bonds is due. AERC's next maturity is in 2019 when its $15 million term loan is scheduled to expire. Profile Avista Corp. is primarily a regulated electric and gas utility servicing around 375,000 electric and 335,000 gas customers in Washington, Idaho and Oregon. Avista also owns Alaska Energy and Resources Company (AERC; not rated), parent of Alaska Electric Light and Power Company (AELP; Baa3) which serves around 17,000 electric customers in Juneau, Alaska. Avista's utility operations are primarily regulated by the Washington Utilities and Transportation Commission (WUTC), Idaho Public Utilities Commission (IPUC) and the Oregon Public Utility Commission (OPUC). AELP's rates are regulated by the Regulatory Commission of Alaska (RCA). Staff_DR_067 Attachment C Page 4 of 6 MOODY'S INVESTORS SERVICE INFRASTRUCTURE AND PROJECT FINANCE 5 11 March 2016 Avista Corp.: A Vertically Integrated Electric and Gas Utility Rating Methodology and Scorecard Factors Exhibit 3 [1] All ratios are based on 'Adjusted' financial data and incorporate Moody's Global Standard Adjustments for Non-Financial Corporations.[2] As of 12/31/2015;[3] This represents Moody's forward view; not the view of the issuer; and unless noted in the text, does not incorporate significant acquisitions and divestitures.Source: Moody's Investors Service Ratings Exhibit 4 Category Moody's Rating AVISTA CORP. Outlook Stable Issuer Rating Baa1 First Mortgage Bonds A2 Senior Secured A2 Senior Unsecured MTN (P)Baa1 ALASKA ELECTRIC LIGHT AND POWER COMPANY(AELP) Outlook Stable Issuer Rating Baa3 AVISTA CORP. CAPITAL II Outlook Stable BACKED Pref. Stock Baa2 Source: Moody's Investors Service Staff_DR_067 Attachment C Page 5 of 6 MOODY'S INVESTORS SERVICE INFRASTRUCTURE AND PROJECT FINANCE 6 11 March 2016 Avista Corp.: A Vertically Integrated Electric and Gas Utility © 2016 Moody's Corporation, Moody's Investors Service, Inc., Moody's Analytics, Inc. and/or their licensors and affiliates (collectively, "MOODY'S"). All rights reserved. CREDIT RATINGS ISSUED BY MOODY'S INVESTORS SERVICE, INC. AND ITS RATINGS AFFILIATES ("MIS") ARE MOODY'S CURRENT OPINIONS OF THE RELATIVE FUTURE CREDIT RISK OF ENTITIES, CREDIT COMMITMENTS, OR DEBT OR DEBT-LIKE SECURITIES, AND CREDIT RATINGS AND RESEARCH PUBLICATIONS PUBLISHED BY MOODY'S ("MOODY'S PUBLICATIONS") MAY INCLUDE MOODY'S CURRENT OPINIONS OF THE RELATIVE FUTURE CREDIT RISK OF ENTITIES, CREDIT COMMITMENTS, OR DEBT OR DEBT-LIKE SECURITIES. 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Information regarding certain affiliations that may exist between directors of MCO and rated entities, and between entities who hold ratings from MIS and have also publicly reported to the SEC an ownership interest in MCO of more than 5%, is posted annually at www.moodys.com under the heading "Investor Relations — Corporate Governance — Director and Shareholder Affiliation Policy." Additional terms for Australia only: Any publication into Australia of this document is pursuant to the Australian Financial Services License of MOODY'S affiliate, Moody's Investors Service Pty Limited ABN 61 003 399 657AFSL 336969 and/or Moody's Analytics Australia Pty Ltd ABN 94 105 136 972 AFSL 383569 (as applicable). This document is intended to be provided only to "wholesale clients" within the meaning of section 761G of the Corporations Act 2001. By continuing to access this document from within Australia, you represent to MOODY'S that you are, or are accessing the document as a representative of, a "wholesale client" and that neither you nor the entity you represent will directly or indirectly disseminate this document or its contents to "retail clients" within the meaning of section 761G of the Corporations Act 2001. MOODY'S credit rating is an opinion as to the creditworthiness of a debt obligation of the issuer, not on the equity securities of the issuer or any form of security that is available to retail investors. It would be reckless and inappropriate for retail investors to use MOODY'S credit ratings or publications when making an investment decision. If in doubt you should contact your financial or other professional adviser. Additional terms for Japan only: Moody's Japan K.K. ("MJKK") is a wholly-owned credit rating agency subsidiary of Moody's Group Japan G.K., which is wholly-owned by Moody's Overseas Holdings Inc., a wholly-owned subsidiary of MCO. Moody's SF Japan K.K. ("MSFJ") is a wholly-owned credit rating agency subsidiary of MJKK. MSFJ is not a Nationally Recognized Statistical Rating Organization ("NRSRO"). Therefore, credit ratings assigned by MSFJ are Non-NRSRO Credit Ratings. Non-NRSRO Credit Ratings are assigned by an entity that is not a NRSRO and, consequently, the rated obligation will not qualify for certain types of treatment under U.S. laws. MJKK and MSFJ are credit rating agencies registered with the Japan Financial Services Agency and their registration numbers are FSA Commissioner (Ratings) No. 2 and 3 respectively. MJKK or MSFJ (as applicable) hereby disclose that most issuers of debt securities (including corporate and municipal bonds, debentures, notes and commercial paper) and preferred stock rated by MJKK or MSFJ (as applicable) have, prior to assignment of any rating, agreed to pay to MJKK or MSFJ (as applicable) for appraisal and rating services rendered by it fees ranging from JPY200,000 to approximately JPY350,000,000. MJKK and MSFJ also maintain policies and procedures to address Japanese regulatory requirements. REPORT NUMBER 1018613 Staff_DR_067 Attachment C Page 6 of 6 Credit Opinion: Alaska Electric Light and Power Company (AELP) Global Credit Research - 28 Jul 2015 Alaska, United States Ratings Category Moody's Rating Outlook Stable Issuer Rating Baa3 Ult Parent: Avista Corp. Outlook Stable Issuer Rating Baa1 First Mortgage Bonds A2 Senior Secured A2 Senior Unsecured MTN (P)Baa1 Contacts Analyst Phone Ryan Wobbrock/New York City 212.553.7104 William L. Hess/New York City 212.553.3837 Key Indicators [1]Alaska Electric Light and Power Company (AELP) -Private [2]12/31/2014 12/31/2013 12/31/2012 12/31/2011 CFO pre-WC + Interest / Interest 7.6x 8.0x 7.6x 4.5x CFO pre-WC / Debt 11.1%13.1%16.0%8.6% CFO pre-WC - Dividends / Debt -25.1%11.4%14.9%8.4% Debt / Capitalization 57.3%53.3%55.5%60.7% [1] All ratios are based on 'Adjusted' financial data and incorporate Moody's Global Standard Adjustments for Non- Financial Corporations. Source: Moody's Financial Metrics [2] 2014 Dividend includes a one-time special dividend to Avista Corp. (Baa1 stable) as part of AELP's recapitalization Note: For definitions of Moody's most common ratio terms please see the accompanying User's Guide. Opinion Rating Drivers Supportive regulatory oversight provides stable cash flow production Small size and weak financial metrics are ongoing challenges Adequate liquidity even in the midst of significant capital expenditures Ownership by Avista is positive Corporate Profile Staff_DR_067 Attachment D Page 1 of 7 Alaska Electric Light and Power Company (AELP; Baa3 stable) is a vertically integrated electric utility that services just under 16,500 customers in Juneau, Alaska. AELP is the primary operating subsidiary of Alaska Energy and Resources Company (AERC, not rated), an intermediate holding company and subsidiary of Avista Corp. (Avista; Baa1 stable). AELP's utility operations are primarily regulated by the Regulatory Commission of Alaska (RCA), with certain of its generation facilities being regulated by the Federal Energy Regulatory Commission (FERC). Two thirds of AELP's generation supply comes from a single plant, the Snettisham Hydroelectric Project (Snettisham; Baa2 stable), a 78 MW hydro facility located 28 miles south of Juneau. Snettisham is owned by the Alaska Industrial Development and Export Authority (AIDEA), but operated by AELP. AELP purchases the entire output of Snettisham under a power purchase agreement whereby AELP is obligated to pay the full project costs on a take-or-pay basis. SUMMARY RATING RATIONALE AELP's Baa3 issuer rating primarily reflects its monopoly status as a rate regulated utility company and the predictable earnings and cash flow derived from a supportive regulatory environment in Alaska. By any measure, AELP is a very small corporate utility, which makes it more vulnerable to adverse events since it is unable to spread increased costs across a sizeable asset or customer base. This exposure is exacerbated by a weak financial profile compared to utility peers, its concentration and isolation in Juneau, and large dependency on a single generating asset. Avista's ownership, while not a direct benefit to AELP's credit profile, is seen as a positive since Avista is a relatively conservative strategic owner and any potential equity support for AELP could be provided (with regulatory approval), without causing financial duress to Avista. At the same time, the existence of a $15 million term loan at AERC adds additional indirect indebtedness for AELP, since AELP is the only operating company to service the intermediate holding company debt. DETAILED RATING CONSIDERATIONS RCA RATE SUPPORT IS PRIMARY RATINGS DRIVER The timely and adequate cost recovery that the RCA provides through general rate cases is the primary ratings driver for AELP. While the Alaskan regulatory environment lacks many of the legislative or single-issue rate making mechanisms we see in other states across the US regulatory landscape, the RCA provides AELP with a high allowed ROE (12.875%) and equity layer (53.8%) upon which to generate earnings and cash flow. The RCA also allows for interim rates to be implemented after 45 days of a general rate case filing, which provides the utility quick cost recovery despite a 15 month review period. While the interim rates are subject to a customer refund, depending on the RCA final order, we see little evidence of cost disallowances in recent history - a credit positive. In addition, the RCA has proven the willingness to allow significant rate increases, in order to support Alaskan utility financial health. For example, in AELP's 2010 rate decision, the RCA approved a revenue increase of over 22% for the company, which allowed the company to recover the costs of its Lake Dorothy generation plant (14.3 MW), while more recently, the RCA approved a 24% rate increase for the Anchorage Municipal Light & Power (not rated). This level of rate increase is rarely seen throughout the US. Furthermore, the RCA has also allowed Chugach Electric Association (Chugach; P-2 stable) to adjust its rate design in order to maintain financial stability and successfully cope with the loss of significant wholesale power demand (see the Chugach credit opinion for more detail). We see this as an example of the RCA's willingness to work with Chugach, in order to meet its financial needs. AELP also benefits from two cost of power adjustments - the Cost of Power Adjustment (COPA) and Emergency Cost of Power Adjustment (E-COPA). The COPA is similar to a traditional fuel and purchased power recovery mechanism that we see with nearly every electric and gas utility company, but is trued-up on a quarterly basis, which is more frequent (and credit positive) than most annual trackers. The E-COPA is unique in that it gets applied in the event that AELP loses the output from its Snettisham facility and must run its higher cost diesel fleet for an extended period of time. This mechanism is triggered after a 14 days of loss of energy from Snettisham and does not require RCA approval for implementation and rate recovery and has been successfully implemented twice for the company. We view these various rate provisions as evidence of the RCA's attention to maintaining utility financial health. This gives us comfort that AELP will continue to achieve sufficient rate relief to maintain a healthy financial profile Staff_DR_067 Attachment D Page 2 of 7 on an ongoing basis, and provides the foundation for an investment grade rating at AELP. SMALL SIZE AND CONCENTRATION RISKS We generally regard smaller sized companies as more vulnerable to single-event costs or cash flow pressures, due to their lack of economies of scale and market position. Should there be an unforeseen event or regulation that causes significant cost increases over a short period of time or reduce sources of cash flow, we feel that smaller companies are more at-risk to negative financial impacts than larger companies that are able to spread the costs across a larger range of asset support or that have greater diversification in sources of cash flow. With around 16,500 customers, about $45 million in annual revenue and under $300 million of total assets, AELP is the smallest vertically integrated investor owned utility in Moody's rated universe. The small size and geographic concentration is partly offset by the strategic importance of the company to Alaska's state capital and government functions; however, its low-cost supply advantage (e.g., Snettisham's production costs are around $0.05/kwh) and operating proficiencies are significantly tied to the Snettisham facility. AELP customers also benefit from rate offsets derived from AELP's interruptible load with Hecla Mining Company (B2 negative) at its Greens Creek mine; these revenues are used to supplant AELP's revenue requirement from firm customer bills. The loss of either the single plant's supply or the mine load demand, for an extended period, would place upward pressure on residential rates and could result in negative ratings implications if a more contentious regulatory environment ensued. AELP is also geographically isolated, since it is not interconnected to any other utility. To address the risk of generation outages, especially in light of roughly two-thirds of its energy being produced by the Snettisham plant, AELP targets to have enough back-up diesel generation to withstand the loss of Snettisham, Lake Dorothy and its largest back-up generator. We view AELP being long generation as a credit positive, but note that it is still highly exposed to a single generation facility, with very expensive diesel generation as its only replacement. WEAK FINANCIAL METRICS Due to the strategic importance of the Snettisham facility, we analyze AELP's financial metrics with the Snettisham obligation fully included in our debt calculations. We also attribute the principal amortization payments that AELP makes for the Snettisham capital lease, as cash flows from financing activities, which helps to improve cash flow from operations and partially offset this debt increase. Over the last three years, AELP has produced CFO pre-WC to debt of around 13%. This level is at the lower end of the range for Baa3 vertically integrated peers, and is reflective of a weakly-positioned Baa3 or strongly- positioned Ba1 rated utility. Following the recapitalization of AELP in 2014, the company's CFO pre-WC to debt ratio fell to 11%, even when including the cash flow benefits from bonus depreciation, which we view as non-core, temporary boosts to cash flow. On a positive note, we observe that AELP was free cash flow positive for each of the last five years, a characteristic not often seen among vertically integrated utilities. Prospectively, we expect AELP to continue to produce cash flow metrics that are weak for an investment grade financial profile, especially as it looks to add additional generation (i.e., a 25MW natural gas unit to provide additional back-up capacity and the potential for a small hydro unit for expected growth) over the next three to four years. We estimate that AELP will continue to generate cash flow to debt metrics around 10% on a standalone basis, and 8% - 9% when including the term loan obligation at AERC. Also, because of this capital spending program, AELP is expected to be free cash flow negative during this period but should be able to fund this program without the help from its parent. Despite the weakness of these metrics over the next several years, we note the expectation for improvement once the added generation units are placed into rate base and meager maintenance capex requirements thereafter (i.e., approximately $5 million). Moreover, given that nearly 50% of the total debt has annual debt amortization, AELP's cash flow to debt metrics will improve as leverage gradually declines. Liquidity As mentioned, AELP has typically been free cash flow positive for each of past five years, a credit positive. AELP's internally generated liquidity consists of around $15 million of cash flow from operations, which will largely be used for its capital expenditures over the next 12 - 18 months, and has $7 million of cash as of July 2015. AELP's external liquidity consists of a $25 million senior secured credit facility, which expires in November 2019 and is provided by CoBank. We view the First Mortgage Bond security provided by AELP as a negative, since it is somewhat constraining to the company's liquidity profile; that's because the typical investment grade issuer (having an unsecured facility) can use collateral as an option to improve bank credit access during periods of Staff_DR_067 Attachment D Page 3 of 7 unforeseen liquidity stress. We view Avista's $400 million secured credit facility as having similar limiting features for an investment grade liquidity profile. AELP's credit facility has a consolidated debt to capitalization covenant of 67.5% and a EBITDA to interest coverage covenant of at least 2.5x. As of July 2015, the full amount was available for borrowing and AEL&P was in compliance with its covenant. Aside from the scheduled amortization on the Snettisham capital lease, AELP has no near-term maturities. We note that the AERC $15 million term loan is due in 2019. Rating Outlook The stable outlook incorporates our view that revenue support from the RCA and strategic nature of the company's operations, to the city of Juneau, will offset a weak financial profile for a small utility with concentration risks. What Could Change the Rating - Up AELP could be upgraded if it were able to produce CFO pre-WC to debt in the mid-teens for a sustained period. What Could Change the Rating - Down Weak financial metrics are expected to persist beyond the next 12 - 18 month rating horizon; however, AELP's rating could be downgraded during its four year construction period if CFO pre-WC to debt remains below 10% on a standalone and prospective basis. Additionally, AELP could be downgraded if regulatory treatment from the RCA becomes less supportive, or if the company experiences a prolonged operational difficulty. Other Considerations AELP is evaluated under the Regulated Electric and Gas Utilities methodology, and, as depicted below, the grid indicated rating is Baa2, one notch above its Baa3 assigned rating, reflecting its very small size and concentration risk both referenced above. Rating Factors Alaska Electric Light and Power Company (AELP) -Private Regulated Electric and Gas Utilities Industry Grid [1][2] Current FY 12/31/2014 [3]Moody's 12-18 Month Forward ViewAs of Date Published Factor 1 : Regulatory Framework (25%)Measure Score Measure Score a) Legislative and Judicial Underpinnings of the Regulatory Framework A A A A b) Consistency and Predictability of Regulation A A A A Factor 2 : Ability to Recover Costs and Earn Returns (25%) a) Timeliness of Recovery of Operating and Capital Costs A A A A b) Sufficiency of Rates and Returns A A A A Factor 3 : Diversification (10%) a) Market Position B B B B b) Generation and Fuel Diversity B B B B Factor 4 : Financial Strength (40%) a) CFO pre-WC + Interest / Interest (3 Year Avg) 7.7x Aa 5.1x - 5.6x A b) CFO pre-WC / Debt (3 Year Avg)13.2%Baa 10% - 13%Ba c) CFO pre-WC - Dividends / Debt (3 Year Avg) -1.7%B 9% - 12%Baa d) Debt / Capitalization (3 Year Avg)55.5%Ba 58% - 65%Ba Staff_DR_067 Attachment D Page 4 of 7 Rating: Grid-Indicated Rating Before Notching Adjustment Baa1 Baa2 HoldCo Structural Subordination Notching 0 0 a) Indicated Rating from Grid Baa1 Baa2 b) Actual Rating Assigned Baa3 [1] All ratios are based on 'Adjusted' financial data and incorporate Moody's Global Standard Adjustments for Non- Financial Corporations. [2] As of 12/31/2014; Source: Moody's Financial Metrics [3] This represents Moody's forward view; not the view of the issuer; and unless noted in the text, does not incorporate significant acquisitions and divestitures. This publication does not announce a credit rating action. For any credit ratings referenced in this publication, please see the ratings tab on the issuer/entity page on http://www.moodys.com for the most updated credit rating action information and rating history. © 2015 Moody’s Corporation, Moody’s Investors Service, Inc., Moody’s Analytics, Inc. and/or their licensors and affiliates (collectively, “MOODY’S”). All rights reserved. CREDIT RATINGS ISSUED BY MOODY'S INVESTORS SERVICE, INC. AND ITS RATINGS AFFILIATES (“MIS”) ARE MOODY’S CURRENT OPINIONS OF THE RELATIVE FUTURE CREDIT RISK OF ENTITIES, CREDIT COMMITMENTS, OR DEBT OR DEBT-LIKE SECURITIES, AND CREDIT RATINGS AND RESEARCH PUBLICATIONS PUBLISHED BY MOODY’S (“MOODY’S PUBLICATIONS”) MAY INCLUDE MOODY’S CURRENT OPINIONS OF THE RELATIVE FUTURE CREDIT RISK OF ENTITIES, CREDIT COMMITMENTS, OR DEBT OR DEBT-LIKE SECURITIES. MOODY’S DEFINES CREDIT RISK AS THE RISK THAT AN ENTITY MAY NOT MEET ITS CONTRACTUAL, FINANCIAL OBLIGATIONS AS THEY COME DUE AND ANY ESTIMATED FINANCIAL LOSS IN THE EVENT OF DEFAULT. CREDIT RATINGS DO NOT ADDRESS ANY OTHER RISK, INCLUDING BUT NOT LIMITED TO: LIQUIDITY RISK, MARKET VALUE RISK, OR PRICE VOLATILITY. CREDIT RATINGS AND MOODY’S OPINIONS INCLUDED IN MOODY’S PUBLICATIONS ARE NOT STATEMENTS OF CURRENT OR HISTORICAL FACT. MOODY’S PUBLICATIONS MAY ALSO INCLUDE QUANTITATIVE MODEL-BASED ESTIMATES OF CREDIT RISK AND RELATED OPINIONS OR COMMENTARY PUBLISHED BY MOODY’S ANALYTICS, INC. CREDIT RATINGS AND MOODY’S PUBLICATIONS DO NOT CONSTITUTE OR PROVIDE INVESTMENT OR FINANCIAL ADVICE, AND CREDIT RATINGS AND MOODY’S PUBLICATIONS ARE NOT AND DO NOT PROVIDE RECOMMENDATIONS TO PURCHASE, SELL, OR HOLD PARTICULAR SECURITIES. NEITHER CREDIT RATINGS NOR MOODY’S PUBLICATIONS COMMENT ON THE SUITABILITY OF AN INVESTMENT FOR ANY PARTICULAR INVESTOR. MOODY’S ISSUES ITS CREDIT RATINGS AND PUBLISHES MOODY’S PUBLICATIONS WITH THE EXPECTATION AND UNDERSTANDING THAT EACH INVESTOR WILL, WITH DUE CARE, MAKE ITS OWN STUDY AND EVALUATION OF EACH SECURITY THAT IS UNDER CONSIDERATION FOR PURCHASE, HOLDING, OR SALE. MOODY’S CREDIT RATINGS AND MOODY’S PUBLICATIONS ARE NOT INTENDED FOR USE BY RETAIL INVESTORS AND IT WOULD BE RECKLESS FOR RETAIL INVESTORS TO CONSIDER MOODY’S CREDIT RATINGS OR MOODY’S PUBLICATIONS IN MAKING ANY INVESTMENT DECISION. IF IN DOUBT YOU SHOULD CONTACT YOUR FINANCIAL OR OTHER PROFESSIONAL ADVISER. ALL INFORMATION CONTAINED HEREIN IS PROTECTED BY LAW, INCLUDING BUT NOT LIMITED TO, COPYRIGHT LAW, AND NONE OF SUCH INFORMATION MAY BE COPIED OR OTHERWISE REPRODUCED, REPACKAGED, FURTHER TRANSMITTED, TRANSFERRED, DISSEMINATED, REDISTRIBUTED OR RESOLD, OR STORED FOR SUBSEQUENT USE FOR ANY SUCH PURPOSE, IN WHOLE OR IN PART, IN ANY FORM OR MANNER OR BY ANY MEANS WHATSOEVER, BY ANY PERSON WITHOUT MOODY’S PRIOR WRITTEN CONSENT. Staff_DR_067 Attachment D Page 5 of 7 All information contained herein is obtained by MOODY’S from sources believed by it to be accurate and reliable. Because of the possibility of human or mechanical error as well as other factors, however, all information contained herein is provided “AS IS” without warranty of any kind. MOODY'S adopts all necessary measures so that the information it uses in assigning a credit rating is of sufficient quality and from sources MOODY'S considers to be reliable including, when appropriate, independent third-party sources. However, MOODY’S is not an auditor and cannot in every instance independently verify or validate information received in the rating process or in preparing the Moody’s Publications. To the extent permitted by law, MOODY’S and its directors, officers, employees, agents, representatives, licensors and suppliers disclaim liability to any person or entity for any indirect, special, consequential, or incidental losses or damages whatsoever arising from or in connection with the information contained herein or the use of or inability to use any such information, even if MOODY’S or any of its directors, officers, employees, agents, representatives, licensors or suppliers is advised in advance of the possibility of such losses or damages, including but not limited to: (a) any loss of present or prospective profits or (b) any loss or damage arising where the relevant financial instrument is not the subject of a particular credit rating assigned by MOODY’S. To the extent permitted by law, MOODY’S and its directors, officers, employees, agents, representatives, licensors and suppliers disclaim liability for any direct or compensatory losses or damages caused to any person or entity, including but not limited to by any negligence (but excluding fraud, willful misconduct or any other type of liability that, for the avoidance of doubt, by law cannot be excluded) on the part of, or any contingency within or beyond the control of, MOODY’S or any of its directors, officers, employees, agents, representatives, licensors or suppliers, arising from or in connection with the information contained herein or the use of or inability to use any such information. NO WARRANTY, EXPRESS OR IMPLIED, AS TO THE ACCURACY, TIMELINESS, COMPLETENESS, MERCHANTABILITY OR FITNESS FOR ANY PARTICULAR PURPOSE OF ANY SUCH RATING OR OTHER OPINION OR INFORMATION IS GIVEN OR MADE BY MOODY’S IN ANY FORM OR MANNER WHATSOEVER. Moody’s Investors Service, Inc., a wholly-owned credit rating agency subsidiary of Moody’s Corporation (“MCO”), hereby discloses that most issuers of debt securities (including corporate and municipal bonds, debentures, notes and commercial paper) and preferred stock rated by Moody’s Investors Service, Inc. have, prior to assignment of any rating, agreed to pay to Moody’s Investors Service, Inc. for appraisal and rating services rendered by it fees ranging from $1,500 to approximately $2,500,000. MCO and MIS also maintain policies and procedures to address the independence of MIS’s ratings and rating processes. Information regarding certain affiliations that may exist between directors of MCO and rated entities, and between entities who hold ratings from MIS and have also publicly reported to the SEC an ownership interest in MCO of more than 5%, is posted annually at www.moodys.com under the heading “Investor Relations — Corporate Governance — Director and Shareholder Affiliation Policy.” For Australia only: Any publication into Australia of this document is pursuant to the Australian Financial Services License of MOODY’S affiliate, Moody’s Investors Service Pty Limited ABN 61 003 399 657AFSL 336969 and/or Moody’s Analytics Australia Pty Ltd ABN 94 105 136 972 AFSL 383569 (as applicable). This document is intended to be provided only to “wholesale clients” within the meaning of section 761G of the Corporations Act 2001. By continuing to access this document from within Australia, you represent to MOODY’S that you are, or are accessing the document as a representative of, a “wholesale client” and that neither you nor the entity you represent will directly or indirectly disseminate this document or its contents to “retail clients” within the meaning of section 761G of the Corporations Act 2001. MOODY’S credit rating is an opinion as to the creditworthiness of a debt obligation of the issuer, not on the equity securities of the issuer or any form of security that is available to retail clients. It would be dangerous for “retail clients” to make any investment decision based on MOODY’S credit rating. If in doubt you should contact your financial or other professional adviser. For Japan only: MOODY'S Japan K.K. (“MJKK”) is a wholly-owned credit rating agency subsidiary of MOODY'S Group Japan G.K., which is wholly-owned by Moody’s Overseas Holdings Inc., a wholly-owned subsidiary of MCO. Moody’s SF Japan K.K. (“MSFJ”) is a wholly-owned credit rating agency subsidiary of MJKK. MSFJ is not a Nationally Recognized Statistical Rating Organization (“NRSRO”). Therefore, credit ratings assigned by MSFJ are Non-NRSRO Credit Ratings. Non-NRSRO Credit Ratings are assigned by an entity that is not a NRSRO and, consequently, the rated obligation will not qualify for certain types of treatment under U.S. laws. MJKK and MSFJ are credit rating agencies registered with the Japan Financial Services Agency and their registration numbers are FSA Commissioner (Ratings) No. 2 and 3 respectively. Staff_DR_067 Attachment D Page 6 of 7 FSA Commissioner (Ratings) No. 2 and 3 respectively. MJKK or MSFJ (as applicable) hereby disclose that most issuers of debt securities (including corporate and municipal bonds, debentures, notes and commercial paper) and preferred stock rated by MJKK or MSFJ (as applicable) have, prior to assignment of any rating, agreed to pay to MJKK or MSFJ (as applicable) for appraisal and rating services rendered by it fees ranging from JPY200,000 to approximately JPY350,000,000. MJKK and MSFJ also maintain policies and procedures to address Japanese regulatory requirements. Staff_DR_067 Attachment D Page 7 of 7 Staff_DR_067 Attachment E Page 1 of 2 Staff_DR_067 Attachment E Page 2 of 2 Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/01/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Mark Thies REQUESTER: UTC Staff - Parcell RESPONDER: L. Pendergraft/C. Hulbert TYPE: Data Request DEPT: Finance REQUEST NO.: Staff – 067 Supplemental TELEPHONE: (509) 495-2998 EMAIL: lauren.pendergraft@avistacorp.com REQUEST: Please provide a copy of all reports by ratings agencies for the period 2015 to the present for the following entities: a. Avista Corp. b. Avista Utilities c. Alaska Light and Power RESPONSE: a.-c. Please see Staff_DR_067 Attachments A-E. SUPPLEMENTAL: a.-c. Please see Staff_DR_067 Supplemental Attachments A. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/01/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Mark Thies REQUESTER: UTC Staff - Parcell RESPONDER: L. Pendergraft/C. Hulbert TYPE: Data Request DEPT: Finance REQUEST NO.: Staff – 067 Supplemental TELEPHONE: (509) 495-2998 EMAIL: lauren.pendergraft@avistacorp.com REQUEST: Please provide a copy of all reports by ratings agencies for the period 2015 to the present for the following entities: a. Avista Corp. b. Avista Utilities c. Alaska Light and Power RESPONSE: a.-c. Please see Staff_DR_067 Attachments A-E. SUPPLEMENTAL: a.-c. Please see Staff_DR_067 Supplemental Attachments A. WWW.STANDARDANDPOORS.COM/RATINGSDIRECT MAY 26, 2016 1 1644562 | 302493718 Research Update: Avista Corp. Rating Affirmed At 'BBB' After Review; Outlook Stable Primary Credit Analyst: Gerrit W Jepsen, CFA, New York (1) 212-438-2529; gerrit.jepsen@spglobal.com Secondary Contact: Safina Ali, CFA, New York (1) 212-438-1877; safina.ali@spglobal.com Table Of Contents Overview Rating Action Rationale Other Credit Considerations Group Influence Outlook Ratings Score Snapshot Recovery Analysis Related Criteria And Research Ratings List Staff_DR_067 Supplemental Attachment A Page 1 of 7 WWW.STANDARDANDPOORS.COM/RATINGSDIRECT MAY 26, 2016 2 1644562 | 302493718 Research Update: Avista Corp. Rating Affirmed At 'BBB' After Review; Outlook Stable Overview  We are affirming our credit ratings on U.S. integrated electric and gas utility Avista Corp. after a review. These include the 'BBB' issuer credit rating, the 'A-' first mortgage bond rating with a recovery rating of '1+', and the 'A-2' short-term rating. We revised the liquidity assessment to adequate from strong based on current estimates of uses such as capital spending, debt maturities, short-term borrowings, and dividend payments. The outlook remains stable.  The stable outlook reflects our expectation that the company will continue to effectively manage regulatory risks, fund capital spending in a manner that does not meaningfully increase leverage, maintain adequate liquidity, and maintain comparable financial performance. We also expect no material increase in business risk through expansion into nonutility operations. Under our base-case scenario, we expect funds from operations to total debt to average about 18%. Rating Action On May 26, 2016, S&P Global Ratings affirmed its ratings on Avista Corp., including the 'BBB' issuer credit rating, the 'A-' first mortgage bond rating with a recovery rating of '1+', and the 'A-2' short term rating. The outlook is stable. In addition, we revised the liquidity assessment to adequate from strong. Rationale In our assessment, Avista's business risk profile is strong, reflecting its lower–risk, vertically integrated electric and natural gas distribution utility operations in Washington and Idaho, electric operations in Alaska, and gas distribution in Oregon. Although the company operates in four states, it has fewer than 400,000 electric and about 330,000 natural gas customers with no meaningful industrial concentration. When needed, the utility requests cost recovery from regulators. Because the utility has hydroelectric power exposure, recovery mechanisms are important to maintain operating cash flow after purchasing power for customers when hydroelectric generation is unavailable. The company has some flexibility in implementing incremental rate changes through its energy-recovery mechanism in Washington and the power cost adjustment in Idaho, but the recovery of excess power costs is subject to minimum thresholds and deferral bands. Purchased gas adjustments for gas distribution units in all three gas jurisdictions, along with hedging, Staff_DR_067 Supplemental Attachment A Page 2 of 7 WWW.STANDARDANDPOORS.COM/RATINGSDIRECT MAY 26, 2016 3 1644562 | 302493718 Research Update: Avista Corp. Rating Affirmed At 'BBB' After Review; Outlook Stable mitigate gas price risk. These help avert large cost-adjustment requests and support the business risk profile. Decoupling mechanisms smooth out operating cash flow in all jurisdictions except Alaska. Our financial risk profile assessment of significant takes into consideration the mostly steady cash flows from the utility business. Our base case indicates that capital spending along with dividend payments will lead to negative discretionary cash flow over the next few years. Avista will need external funding to cover the deficit because internally generated cash flow is insufficient. Our base-case scenario suggests stronger financial measures over the next two years, including funds from operations (FFO) to debt of roughly 18%, mainly benefiting from higher deferred taxes due to bonus depreciation. Our base case indicates an expected supplemental ratio of operating cash flow to debt of about 16% to about 18%, bolstering the significant financial risk profile assessment. Liquidity Avista has an adequate liquidity assessment because in our view its sources are likely to cover uses by more than 1.1x over the next 12 months and to meet cash outflows, even with a 10% decline in EBITDA. The adequate assessment also reflects the company's generally prudent risk management, sound relationships with banks, and a generally satisfactory standing in credit markets. Avista recently extended the maturity of its credit facilities to 2021. Principal liquidity sources:  We estimate FFO of about $360 million for the 12 months ending March 31, 2017.  Revolving credit facility of $425 million.  Cash on hand of roughly $10 million. Principal liquidity uses:  Capital spending of about $350 million for the 12 months ending March 31, 2017.  Dividends of roughly $85 million for the 12 months ending March 31, 2017.  Debt maturities of about $195 million, including short–term borrowings. We rate the preferred securities at Avista Capital II two notches below the issuer credit rating to reflect the discretionary nature of the dividend and the deeply subordinated claim if a bankruptcy occurs. The short-term rating on Avista is 'A-2' based on the issuer credit rating and our assessment of its liquidity as at least adequate. Other Credit Considerations Other modifiers do not affect the rating outcome. Staff_DR_067 Supplemental Attachment A Page 3 of 7 WWW.STANDARDANDPOORS.COM/RATINGSDIRECT MAY 26, 2016 4 1644562 | 302493718 Research Update: Avista Corp. Rating Affirmed At 'BBB' After Review; Outlook Stable Group Influence Avista is subject to the group rating methodology criteria. We view Avista as the parent that drives the group credit profile. As a result, Avista's group and stand-alone credit profiles are the same at 'bbb'. Outlook The stable outlook on Avista reflects our expectation that over the next two years the company will continue to effectively manage regulatory risks, fund capital spending such that leverage does not meaningfully increase, preserve adequate liquidity, and maintain comparable financial performance. We also expect no material increase in business risk through expansion into nonutility operations. Under our base-case scenario, we expect FFO to total debt to average about 18%. Downside scenario We could lower the rating in the next two years if business risk materially rises or credit measures diminish such that FFO to debt would be consistently less than 15%. This could occur due to greater borrowing or increased rate lag, a large deferral, or adverse regulatory decisions. Upside scenario In the next two years, we do not currently contemplate an upgrade given the company's current business mix. Credit quality could strengthen if cash flow measures considerably improve, specifically FFO to debt of more than 20% on a consistent basis. The company could accomplish this by paying down debt with higher internally generated cash flow or increased equity, or by boosting FFO without adding debt. Ratings Score Snapshot Corporate Credit Rating: BBB/Stable/A-2 Business risk: Strong  Country risk: Very low  Industry risk: Very low  Competitive position: Satisfactory Financial risk: Significant  Cash flow/Leverage: Significant Anchor: 'bbb' Modifiers Staff_DR_067 Supplemental Attachment A Page 4 of 7 WWW.STANDARDANDPOORS.COM/RATINGSDIRECT MAY 26, 2016 5 1644562 | 302493718 Research Update: Avista Corp. Rating Affirmed At 'BBB' After Review; Outlook Stable  Diversification/Portfolio effect: Neutral (no impact)  Capital structure: Neutral (no impact)  Financial policy: Neutral (no impact)  Liquidity: Adequate (no impact)  Management and governance: Satisfactory (no impact)  Comparable rating analysis: Neutral (no impact) Stand-alone credit profile: 'bbb'  Group credit profile: 'bbb' Recovery Analysis Avista's first mortgage bonds benefit from a first-priority lien on substantially all of the utility's real property owned or subsequently acquired. Collateral coverage of more than 1.5x supports a recovery rating of '1+' and an issue rating two notches above the issuer credit rating. Related Criteria And Research  Methodology And Assumptions: Liquidity Descriptors For Global Corporate Issuers, Dec. 16, 2014  Country Risk Assessment Methodology And Assumptions, Nov. 19, 2013  Group Rating Methodology, Nov. 19, 2013  Key Credit Factors For The Regulated Utilities Industry, Nov. 19, 2013  Corporate Methodology, Nov. 19, 2013  Corporate Methodology: Ratios And Adjustments, Nov. 19, 2013  Methodology: Industry Risk, Nov. 19, 2013  Methodology For Linking Short-Term And Long-Term Ratings For Corporate, Insurance, And Sovereign Issuers, May 7, 2013  Collateral Coverage And Issue Notching Rules For ‘1+’ And ‘1’ Recovery Ratings On Senior Bonds Secured By Utility Real Property, Feb. 14, 2013  Management And Governance Credit Factors For Corporate Entities And Insurers, Nov. 13, 2012  General Criteria: Use Of CreditWatch And Outlooks, Sept. 14, 2009  Hybrid Capital Handbook: September 2008 Edition, Sept. 15, 2008  2008 Corporate Criteria: Rating Each Issue, April 15, 2008 Ratings List Ratings Affirmed Avista Corp. Corporate Credit Rating BBB/Stable/A-2 Senior Secured Rating A- Recovery Rating 1+ Certain terms used in this report, particularly certain adjectives used to express our view on rating relevant factors, have specific meanings ascribed Staff_DR_067 Supplemental Attachment A Page 5 of 7 WWW.STANDARDANDPOORS.COM/RATINGSDIRECT MAY 26, 2016 6 1644562 | 302493718 Research Update: Avista Corp. Rating Affirmed At 'BBB' After Review; Outlook Stable to them in our criteria, and should therefore be read in conjunction with such criteria. Please see Ratings Criteria at www.standardandpoors.com for further information. Complete ratings information is available to subscribers of RatingsDirect at www.globalcreditportal.com and at www.spcapitaliq.com. All ratings affected by this rating action can be found on the S&P Global Ratings public website at www.standardandpoors.com. Use the Ratings search box located in the left column. 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S&P's public ratings and analyses are made available on its Web sites, www.standardandpoors.com (free of charge), and www.ratingsdirect.com and www.globalcreditportal.com (subscription) and www.spcapitaliq.com (subscription) and may be distributed through other means, including via S&P publications and third-party redistributors. Additional information about our ratings fees is available at www.standardandpoors.com/usratingsfees. STANDARD & POOR'S, S&P and RATINGSDIRECT are registered trademarks of Standard & Poor's Financial Services LLC. Staff_DR_067 Supplemental Attachment A Page 7 of 7 Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/23/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Mark Thies REQUESTER: UTC Staff - Parcell RESPONDER: L. Pendergraft/C. Hulbert TYPE: Data Request DEPT: Finance REQUEST NO.: Staff - 067 TELEPHONE: (509) 495-2998 EMAIL: lauren.pendergraft@avistacorp.com REQUEST: Please provide a copy of all reports by ratings agencies for the period 2015 to the present for the following entities: a. Avista Corp. b. Avista Utilities c. Alaska Light and Power RESPONSE: a.-c. Please see Staff_DR_067 Attachments A-E. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/23/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Mark Thies REQUESTER: UTC Staff - Parcell RESPONDER: L. Pendergraft/C. Hulbert TYPE: Data Request DEPT: Finance REQUEST NO.: Staff - 067 TELEPHONE: (509) 495-2998 EMAIL: lauren.pendergraft@avistacorp.com REQUEST: Please provide a copy of all reports by ratings agencies for the period 2015 to the present for the following entities: a. Avista Corp. b. Avista Utilities c. Alaska Light and Power RESPONSE: a.-c. Please see Staff_DR_067 Attachments A-E. ADRIEN M. MCKENZIE SUMMARY OF TESTIMONY BEFORE REGULATORY AGENCIES * Joint testimony with Dr. William E. Avera 1 No. Utility Case Agency Docket Date Nature of Testimony et al. et al. Staff_DR_068 Attachment A Page 1 of 3 Adrien M. McKenzie Summary of Testimony Before Regulatory Agencies (Continued) * Joint testimony with Dr. William E. Avera 2 No. Utility Case Agency Docket Date Nature of Testimony Staff_DR_068 Attachment A Page 2 of 3 ADRIEN M. MCKENZIE SUMMARY OF TESTIMONY BEFORE REGULATORY AGENCIES 3 No. Utility Case Agency Docket Date Nature of Testimony Staff_DR_068 Attachment A Page 3 of 3 Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/22/2016 CASE NO: UE-160228 & UG-160229 WITNESS: Adrien M. McKenzie REQUESTER: UTC Staff - Parcell RESPONDER: Adrien M. McKenzie TYPE: Data Request DEPT: Consultant REQUEST NO.: Staff – 068 TELEPHONE: (512) 923-2790 EMAIL: fincap3@texas.net REQUEST: Please identify each public utility proceeding in which Mr. McKenzie has provided cost of capital testimony. For each proceeding identified, please provide the following information: a. Date of Testimony b. Name of Utility c. Name of Client d. Name of Commission e. ROE Recommended f. ROE Adopted RESPONSE: Please see Staff_DR_068 Attachment A for a list of past cost of capital testimony sponsored by Mr. McKenzie, which identifies the date, the name of the utility client, and regulatory jurisdiction. Mr. McKenzie does not maintain a record of the ROE recommendations or Commission decisions in each proceeding; however, this information is publicly available from each of the respective regulatory agencies. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/22/2016 CASE NO: UE-160228 & UG-160229 WITNESS: Adrien M. McKenzie REQUESTER: UTC Staff - Parcell RESPONDER: Adrien M. McKenzie TYPE: Data Request DEPT: Consultant REQUEST NO.: Staff – 068 TELEPHONE: (512) 923-2790 EMAIL: fincap3@texas.net REQUEST: Please identify each public utility proceeding in which Mr. McKenzie has provided cost of capital testimony. For each proceeding identified, please provide the following information: a. Date of Testimony b. Name of Utility c. Name of Client d. Name of Commission e. ROE Recommended f. ROE Adopted RESPONSE: Please see Staff_DR_068 Attachment A for a list of past cost of capital testimony sponsored by Mr. McKenzie, which identifies the date, the name of the utility client, and regulatory jurisdiction. Mr. McKenzie does not maintain a record of the ROE recommendations or Commission decisions in each proceeding; however, this information is publicly available from each of the respective regulatory agencies. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/22/2016 CASE NO: UE-160228 & UG-160229 WITNESS: Adrien M. McKenzie REQUESTER: UTC Staff - Parcell RESPONDER: Adrien M. McKenzie TYPE: Data Request DEPT: Consultant REQUEST NO.: Staff – 069 TELEPHONE: (512) 923-2790 EMAIL: fincap3@texas.net REQUEST: Please provide a copy of the source documents identified in each of Mr. McKenzie’s footnotes, to the extent that they have not already been provided in his workpapers. RESPONSE: With the exception of regulatory or court decisions cited in Mr. McKenzie’s testimony, which are publicly available, a copy of all documents identified in Mr. McKenzie’s testimony were previously provided in his workpapers. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/22/2016 CASE NO: UE-160228 & UG-160229 WITNESS: Adrien M. McKenzie REQUESTER: UTC Staff - Parcell RESPONDER: Adrien M. McKenzie TYPE: Data Request DEPT: Consultant REQUEST NO.: Staff – 069 TELEPHONE: (512) 923-2790 EMAIL: fincap3@texas.net REQUEST: Please provide a copy of the source documents identified in each of Mr. McKenzie’s footnotes, to the extent that they have not already been provided in his workpapers. RESPONSE: With the exception of regulatory or court decisions cited in Mr. McKenzie’s testimony, which are publicly available, a copy of all documents identified in Mr. McKenzie’s testimony were previously provided in his workpapers. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/22/2016 CASE NO: UE-160228 & UG-160229 WITNESS: Adrien M. McKenzie REQUESTER: UTC Staff - Parcell RESPONDER: Adrien M. McKenzie TYPE: Data Request DEPT: Consultant REQUEST NO.: Staff – 070 TELEPHONE: (512) 923-2790 EMAIL: fincap3@texas.net REQUEST: Please identify the utility bonds making up the “Baa Utility Bonds” yields shown on Table 3 on page 21 of Exhibit No. AMM-1T. RESPONSE: The Baa bond yields reported in Table 3 correspond to the Baa public utility bond yield average reported by Moody’s Investors Service (“Moody’s”). Moody’s indicates that its yield averages are based on seasoned bonds with remaining maturities of at least 20 years, and are derived from pricing data on a regularly replenished population of seasoned bonds in the U.S. market, each with current outstandings over $100 million and having maturities as close as possible to 30 years. Mr. McKenzie has no information regarding the specific utility bond issues relied on by Moody’s to perform their calculations. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/22/2016 CASE NO: UE-160228 & UG-160229 WITNESS: Adrien M. McKenzie REQUESTER: UTC Staff - Parcell RESPONDER: Adrien M. McKenzie TYPE: Data Request DEPT: Consultant REQUEST NO.: Staff – 070 TELEPHONE: (512) 923-2790 EMAIL: fincap3@texas.net REQUEST: Please identify the utility bonds making up the “Baa Utility Bonds” yields shown on Table 3 on page 21 of Exhibit No. AMM-1T. RESPONSE: The Baa bond yields reported in Table 3 correspond to the Baa public utility bond yield average reported by Moody’s Investors Service (“Moody’s”). Moody’s indicates that its yield averages are based on seasoned bonds with remaining maturities of at least 20 years, and are derived from pricing data on a regularly replenished population of seasoned bonds in the U.S. market, each with current outstandings over $100 million and having maturities as close as possible to 30 years. Mr. McKenzie has no information regarding the specific utility bond issues relied on by Moody’s to perform their calculations. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/22/2016 CASE NO: UE-160228 & UG-160229 WITNESS: Adrien M. McKenzie REQUESTER: UTC Staff - Parcell RESPONDER: Adrien M. McKenzie TYPE: Data Request DEPT: Consultant REQUEST NO.: Staff – 071 TELEPHONE: (512) 923-2790 EMAIL: fincap3@texas.net REQUEST: Please indicate the revenue impact, for both electric and gas operations, of the proposed flotation cost adjustment proposed by Mr. McKenzie. RESPONSE: As shown in Table 1 to Mr. McKenzie’s direct testimony, the 9.9% ROE requested by Avista falls at the low end of the 9.8% to 10.8% cost of equity range, which excludes any allowance for flotation costs, and well below the 10.3% midpoint of this “bare bones” cost of equity range. As a result, the 9.9% ROE requested by Avista does not include the 13 basis point flotation cost adjustment supported in Mr. McKenzie’s testimony. As Mr. McKenzie indicated in his testimony, the fact that Avista’s requested 9.9% ROE falls below 10.43% midpoint of his recommended ROE range (including flotation costs) provides further support for his conclusion that this value represents a conservative ROE for Avista. The revenue impact would be $1,428,000 for electric and $289,000 for natural gas. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/22/2016 CASE NO: UE-160228 & UG-160229 WITNESS: Adrien M. McKenzie REQUESTER: UTC Staff - Parcell RESPONDER: Adrien M. McKenzie TYPE: Data Request DEPT: Consultant REQUEST NO.: Staff – 071 TELEPHONE: (512) 923-2790 EMAIL: fincap3@texas.net REQUEST: Please indicate the revenue impact, for both electric and gas operations, of the proposed flotation cost adjustment proposed by Mr. McKenzie. RESPONSE: As shown in Table 1 to Mr. McKenzie’s direct testimony, the 9.9% ROE requested by Avista falls at the low end of the 9.8% to 10.8% cost of equity range, which excludes any allowance for flotation costs, and well below the 10.3% midpoint of this “bare bones” cost of equity range. As a result, the 9.9% ROE requested by Avista does not include the 13 basis point flotation cost adjustment supported in Mr. McKenzie’s testimony. As Mr. McKenzie indicated in his testimony, the fact that Avista’s requested 9.9% ROE falls below 10.43% midpoint of his recommended ROE range (including flotation costs) provides further support for his conclusion that this value represents a conservative ROE for Avista. The revenue impact would be $1,428,000 for electric and $289,000 for natural gas. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/17/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: UTC Staff – Van Meter RESPONDER: Ryan Finesilver TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff - 072 TELEPHONE: (509) 495-4873 EMAIL: ryan.finesilver@avistacorp.com REQUEST: In Order UE-090134 Order 10 pages 57-59 the Commission determined Directors’ Fees and Meetings costs should be shared equally between shareholders and ratepayers. Please explain why the Company has split Director’s Fees 97/3 Utility/Non-Utility? RESPONSE: Please see the Company’s response to ICNU_DR_083. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/17/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: UTC Staff – Van Meter RESPONDER: Ryan Finesilver TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff - 072 TELEPHONE: (509) 495-4873 EMAIL: ryan.finesilver@avistacorp.com REQUEST: In Order UE-090134 Order 10 pages 57-59 the Commission determined Directors’ Fees and Meetings costs should be shared equally between shareholders and ratepayers. Please explain why the Company has split Director’s Fees 97/3 Utility/Non-Utility? RESPONSE: Please see the Company’s response to ICNU_DR_083. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/17/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: UTC Staff – Van Meter RESPONDER: Ryan Finesilver TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff - 073 TELEPHONE: (509) 495-4873 EMAIL: ryan.finesilver@avistacorp.com REQUEST: In Smiths workpaper 2016 WA GRC – Misc – Plane Reclass, the worksheet labeled “Transaction Detail” There are 4 entries for the purpose of “Washington Roundtable Meeting”. It states on the website for this organization, “The Washington Roundtable is a nonprofit organization comprised of senior executives of major private sector employers in Washington State. Our members work together to effect positive change on public policy issues that they believe are most important to supporting state economic vitality and fostering opportunity for all Washingtonians.” This looks to be a lobbying organization. Why did Avista include these expenses in this Rate Case to be payable by rate payers? Are there any other destination meetings in the “Transaction Detail” for the Plane reclass that are also for meetings with either lobbying organizations or for activities that are not paid for by rate payers? RESPONSE: The Company included expenses related to The Washington Roundtable in its Rate Case as they are incurred as part of the ordinary course of doing business, as the Company remains engaged in policy issues affecting our customers and service territory. Avista remains a member of this organization to stay apprised on emerging public policy issues that may affect our business as a provider of utility service. As per the Company’s Regulatory Accounting Guidelines, lobbying activities and the portion of activities related to lobbying, are charged to Non-Utility operations and are not recovered from ratepayers. There are no lobbying activities in the transaction detail that have been included in utility operations. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/17/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: UTC Staff – Van Meter RESPONDER: Ryan Finesilver TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff - 073 TELEPHONE: (509) 495-4873 EMAIL: ryan.finesilver@avistacorp.com REQUEST: In Smiths workpaper 2016 WA GRC – Misc – Plane Reclass, the worksheet labeled “Transaction Detail” There are 4 entries for the purpose of “Washington Roundtable Meeting”. It states on the website for this organization, “The Washington Roundtable is a nonprofit organization comprised of senior executives of major private sector employers in Washington State. Our members work together to effect positive change on public policy issues that they believe are most important to supporting state economic vitality and fostering opportunity for all Washingtonians.” This looks to be a lobbying organization. Why did Avista include these expenses in this Rate Case to be payable by rate payers? Are there any other destination meetings in the “Transaction Detail” for the Plane reclass that are also for meetings with either lobbying organizations or for activities that are not paid for by rate payers? RESPONSE: The Company included expenses related to The Washington Roundtable in its Rate Case as they are incurred as part of the ordinary course of doing business, as the Company remains engaged in policy issues affecting our customers and service territory. Avista remains a member of this organization to stay apprised on emerging public policy issues that may affect our business as a provider of utility service. As per the Company’s Regulatory Accounting Guidelines, lobbying activities and the portion of activities related to lobbying, are charged to Non-Utility operations and are not recovered from ratepayers. There are no lobbying activities in the transaction detail that have been included in utility operations. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/25/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: UTC Staff - White RESPONDER: Annette Brandon TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff - 074 TELEPHONE: (509) 495-4324 EMAIL: annette.brandon@avistacorp.com REQUEST: Staff has reviewed the detailed account activity provided by the company in the file Uncollectible Exp Adj-Elec.xls, tab C-UE-2. Periodic postings into the accounts 144200, Write-Offs, and 144600, Reinstatements, appear to stop as of 12/2014. Also, there are zero Recoveries (account 144700) for the test year. Please explain. If there a policy change at the end of calendar year 2014, please provide copies of the 2014 and 2015 policies regarding uncollectible accounts. RESPONSE: In February of 2015 the Company’s new Customer Care and Billing system (CC&B), a portion of the overall Compass project, went into effect. Pre-existing customer account write offs in the old system were not converted to CC&B but collection efforts and account reviews were in effect throughout the year. Write-offs were suspended from January through July until the billing and payment functions were working accurately. The write-offs were recorded to G/L account 144200 in August 2015. G/L accounts 144600 and 144700 are no longer used. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/25/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: UTC Staff - White RESPONDER: Annette Brandon TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff - 074 TELEPHONE: (509) 495-4324 EMAIL: annette.brandon@avistacorp.com REQUEST: Staff has reviewed the detailed account activity provided by the company in the file Uncollectible Exp Adj-Elec.xls, tab C-UE-2. Periodic postings into the accounts 144200, Write-Offs, and 144600, Reinstatements, appear to stop as of 12/2014. Also, there are zero Recoveries (account 144700) for the test year. Please explain. If there a policy change at the end of calendar year 2014, please provide copies of the 2014 and 2015 policies regarding uncollectible accounts. RESPONSE: In February of 2015 the Company’s new Customer Care and Billing system (CC&B), a portion of the overall Compass project, went into effect. Pre-existing customer account write offs in the old system were not converted to CC&B but collection efforts and account reviews were in effect throughout the year. Write-offs were suspended from January through July until the billing and payment functions were working accurately. The write-offs were recorded to G/L account 144200 in August 2015. G/L accounts 144600 and 144700 are no longer used. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/25/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: UTC Staff - White RESPONDER: Annette Brandon TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff - 075 TELEPHONE: (509) 495-4324 EMAIL: annette.brandon@avistacorp.com REQUEST: Also in the file Uncollectible Exp Adj-Elec.xls, tab C-UE-2, cells E25 through E44, the company posts the net amount of $2,189,671 in uncollectibles after not posting between 01/2015 and 07/2015. Please provide, in Excel format, the detailed write-offs making up the August 2015 write-offs. RESPONSE: Please see Staff_DR_075 Attachment A for the detail related to the August 2015 write-offs. Information is provided in electronic format as requested. Also see the Company’s response to Staff_DR_074. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/25/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: UTC Staff - White RESPONDER: Annette Brandon TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff - 075 TELEPHONE: (509) 495-4324 EMAIL: annette.brandon@avistacorp.com REQUEST: Also in the file Uncollectible Exp Adj-Elec.xls, tab C-UE-2, cells E25 through E44, the company posts the net amount of $2,189,671 in uncollectibles after not posting between 01/2015 and 07/2015. Please provide, in Excel format, the detailed write-offs making up the August 2015 write-offs. RESPONSE: Please see Staff_DR_075 Attachment A for the detail related to the August 2015 write-offs. Information is provided in electronic format as requested. Also see the Company’s response to Staff_DR_074. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/25/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: UTC Staff - Cheesman RESPONDER: Annette Brandon TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff – 076 TELEPHONE: (509) 495-4324 EMAIL: annette.brandon@avistacorp.com REQUEST: Referring to the company’s electric labor adjustments 3.02, 4.02 and 18.03 (gas labor adjustments 3.00, 4.00 and 18.01), please provide the Board of Directors’ minutes approving the 2016 and 2017 non-union wage increases included in the company’s filing. RESPONSE: Please see Avista’s CONFIDENTIAL response to data request Staff_DR_076C - Supplemental. Please note that Avista’s response to Staff_DR_076C - Supplemental is Confidential per Protective Order in UTC Dockets UE-160228 and UG-160229. Please see Staff_DR_076C Confidential Attachment A for the requested information. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/25/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: UTC Staff - Cheesman RESPONDER: Annette Brandon TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff – 076 TELEPHONE: (509) 495-4324 EMAIL: annette.brandon@avistacorp.com REQUEST: Referring to the company’s electric labor adjustments 3.02, 4.02 and 18.03 (gas labor adjustments 3.00, 4.00 and 18.01), please provide the Board of Directors’ minutes approving the 2016 and 2017 non-union wage increases included in the company’s filing. RESPONSE: Please see Avista’s CONFIDENTIAL response to data request Staff_DR_076C - Supplemental. Please note that Avista’s response to Staff_DR_076C - Supplemental is Confidential per Protective Order in UTC Dockets UE-160228 and UG-160229. Please see Staff_DR_076C Confidential Attachment A for the requested information. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/25/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: UTC Staff - Cheesman RESPONDER: Annette Brandon TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff – 077 TELEPHONE: (509) 495-4324 EMAIL: annette.brandon@avistacorp.com REQUEST: Referring to the company’s electric labor adjustments 3.02, 4.02 and 18.03 (gas labor adjustments 3.00, 4.00 and 18.01), please provide a copy of any market survey(s) conducted during the test year and most recent that relate to non-union wage increases. Please also provide a written summary on how the company utilizes the market survey information to determine the wage increases included in the company’s filing. RESPONSE: Please see Avista’s CONFIDENTIAL response to data request Staff_DR_077C. Please note that Avista’s response to Staff_DR_077C is Confidential per Protective Order in UTC Dockets UE- 160228 and UG-160229. Please see Staff_DR_077C Confidential Attachments for the salary studies the Company has participated in for the test period. Due to the voluminous nature of the documents they are being provided in electronic format only. The Company conducts and participates in numerous salary studies each year to aid in the determination of salary levels as part of the overall compensation package1. These studies are used in various ways depending upon the type of information collected in the study. For instance, some studies provide information regarding overall anticipated salary increases, others provide information on overall regional trends, whereas others are specific to job type by region. The Company compiles the results of these surveys and targets overall compensation levels (base and short-term incentive) to be within +/- 15% of the median. Typically the Company targets the utility industry for merit increases and changes to midpoints. Regional peers are also reviewed in an effort to obtain as much intelligence on trends within the region. Ultimately the goal is to appropriately position the overall compensation package to recruit and retain qualified employees. While benchmarking is an important component of the setting of overall compensation levels, it is not the sole criteria. Pay components may vary higher or lower than the median depending on an individual’s role, responsibilities and performance within the Company. 1Salary planning studies are also periodically utilized in the evaluation of the non-executive officer short term incentive plan. No changes to target opportunities have been made in this plan since 2004. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/25/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: UTC Staff - Cheesman RESPONDER: Annette Brandon TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff – 077 TELEPHONE: (509) 495-4324 EMAIL: annette.brandon@avistacorp.com REQUEST: Referring to the company’s electric labor adjustments 3.02, 4.02 and 18.03 (gas labor adjustments 3.00, 4.00 and 18.01), please provide a copy of any market survey(s) conducted during the test year and most recent that relate to non-union wage increases. Please also provide a written summary on how the company utilizes the market survey information to determine the wage increases included in the company’s filing. RESPONSE: Please see Avista’s CONFIDENTIAL response to data request Staff_DR_077C. Please note that Avista’s response to Staff_DR_077C is Confidential per Protective Order in UTC Dockets UE- 160228 and UG-160229. Please see Staff_DR_077C Confidential Attachments for the salary studies the Company has participated in for the test period. Due to the voluminous nature of the documents they are being provided in electronic format only. The Company conducts and participates in numerous salary studies each year to aid in the determination of salary levels as part of the overall compensation package1. These studies are used in various ways depending upon the type of information collected in the study. For instance, some studies provide information regarding overall anticipated salary increases, others provide information on overall regional trends, whereas others are specific to job type by region. The Company compiles the results of these surveys and targets overall compensation levels (base and short-term incentive) to be within +/- 15% of the median. Typically the Company targets the utility industry for merit increases and changes to midpoints. Regional peers are also reviewed in an effort to obtain as much intelligence on trends within the region. Ultimately the goal is to appropriately position the overall compensation package to recruit and retain qualified employees. While benchmarking is an important component of the setting of overall compensation levels, it is not the sole criteria. Pay components may vary higher or lower than the median depending on an individual’s role, responsibilities and performance within the Company. 1Salary planning studies are also periodically utilized in the evaluation of the non-executive officer short term incentive plan. No changes to target opportunities have been made in this plan since 2004. Staff_DR_078 Attachment A Page 1 of 14 2014-2016 AGREEMENT Between AVISTA UTILITIES and LOCAL UNION NO. 77 of the INTERNATIONAL BROTHERHOOD OF ELECTRICAL WORKERS Staff_DR_078 Attachment A Page 2 of 14 36 Wage Exhibit 3/26/2013 3/26/2014 3/26/2015 3.00% 3.00% 3.00% OVERHEAD, UNDERGROUND AND GENERAL Job No. Classification 2013 2014 2015 6005 Loc Rep-Ele $44.92 $46.27 $47.66 6006 Loc Rep-Ele-2 $43.04 $44.33 $45.66 6007 Loc Rep-Ele-1 $41.48 $42.72 $44.00 6010 Line Frmn $45.13 $46.48 $47.87 6041 Jmn Lnmn Switchman $41.32 $42.56 $43.84 6040 Jmn Lnsvsmn $40.72 $41.94 $43.20 030 Jmn Lnmn $39.53 $40.72 $41.94 6051 App Lnmn-6 % of Jmn - 92 $36.37 $37.46 $38.58 6061 App Lnmn-5 % of Jmn - 86 $34.00 $35.02 $36.07 6071 App Lnmn-4 % of Jmn - 81 $32.02 $32.98 $33.97 6081 App Lnmn-3 % of Jmn - 77 $30.45 $31.35 $32.29 6091 App Lnmn-2 % of Jmn - 73 $28.86 $29.73 $30.62 6101 App Lnmn-1 % of Jmn - 70 $27.67 $28.50 $29.36 6150 Hd Grndmn (See Note 1) $32.40 $33.37 $34.37 6151 Hd Grndmn-2 $30.46 $31.37 $32.31 6152 Hd Grndmn-1 $28.91 $29.78 $30.67 6173 Pre apprentice Grndmn 3 $28.91 $29.78 $30.67 6174 Pre apprentice Grndmn 2 $27.00 $27.81 $28.64 6175 Pre apprentice Grndmn 1 $23.15 $23.84 $24.56 6191 Grndmn-5 $28.91 $29.78 $30.67 6192 Grndmn-4 $27.00 $27.81 $28.64 6193 Grndmn-3 $23.16 $23.85 $24.57 6194 Grndmn-E2 $19.29 $19.87 $20.47 6195 Grndmn-E1 $15.43 $15.89 $16.37 6029 Frmn Test & Treat $39.53 $40.72 $41.94 6210 Frmn Trimmer $40.78 $42.00 $43.26 6230 Jmn Trimmer $36.29 $37.38 $38.50 6270 Trimmer-4 $32.66 $33.64 $34.65 6280 Trimmer-3 $30.84 $31.77 $32.72 6290 Trimmer-2 $28.99 $29.86 $30.76 6300 Trimmer-1 $27.20 $28.02 $28.86 Staff_DR_078 Attachment A Page 3 of 14 37 Job No. Classification 2013 2014 2015 6240 Trimmer Grndmn-5 $28.91 $29.78 $30.67 6241 Trimmer Grndmn-4 $27.00 $27.81 $28.64 6242 Trimmer Grndmn-3 $23.16 $23.85 $24.57 6243 Trimmer Grndmn-E2 $19.29 $19.87 $20.47 6244 Trimmer Grndmn-E1 $15.43 $15.89 $16.37 6305 Lead Frmn Cblmn $49.73 $51.22 $52.76 6310 Frmn Cblmn $46.68 $48.08 $49.52 6330 Jmn Cblmn $41.48 $42.72 $44.00 6351 App Cblmn-6 % of Jmn-92 $38.17 $39.30 $40.48 6361 App Cblmn-5 % of Jmn-86 $35.68 $36.74 $37.84 6371 App Cblmn-4 % of Jmn-81 $33.60 $34.60 $35.64 6381 App Cblmn-3 % of Jmn-77 $31.95 $32.89 $33.88 6391 App Cblmn-2 % of Jmn-73 $30.29 $31.19 $32.12 6401 App Cblmn-1 % of Jmn-70 $29.03 $29.90 $30.80 6821 Crew Ldr Ntwk $35.11 $36.16 $37.24 6520 Supply Handler-4 $27.00 $27.81 $28.64 6521 Supply Handler-3 $23.16 $23.85 $24.57 6522 Supply Handler-2 $19.29 $19.87 $20.47 6523 Supply Handler-1 $15.43 $15.89 $16.37 6559 Shop & Mtlsmn $37.62 $38.75 $39.91 6561 Stkpr-6 $31.62 $32.57 $33.55 6562 Stkpr-5 $28.91 $29.78 $30.67 6563 Stkpr-4 $27.00 $27.81 $28.64 6564 Stkpr-3 $23.16 $23.85 $24.57 6565 Stkpr-E2 $19.29 $19.87 $20.47 6566 Stkpr-E1 $15.43 $15.89 $16.37 6593 Mtrdr-3 $26.43 $27.22 $28.04 6594 Mtrdr-2 $20.40 $21.01 $21.64 6595 Mtrdr-E1 $15.43 $15.89 $16.37 6601 B Frmn Outsvsmn $34.01 $35.03 $36.08 6600 Out Svsmn $31.62 $32.57 $33.55 6630 Jmn Svsmn $35.85 $36.93 $38.04 6635 Shop & Eqpt Worker $34.31 $35.34 $36.40 Staff_DR_078 Attachment A Page 4 of 14 38 Job No. Classification 2013 2014 2015 6640 Genl Mtce Worker $32.03 $32.99 $33.98 6650 Eqpt Opr-Hvy $34.73 $35.77 $36.84 6670 Rd Mtce Worker $30.88 $31.81 $32.76 6680 Design & Display Spec $36.29 $37.38 $38.50 6691 Umn-4 $25.10 $25.85 $26.63 6692 Umn-3 $23.16 $23.85 $24.57 6693 Umn-E2 $19.29 $19.87 $20.47 6694 Umn-E1 $15.43 $15.89 $16.37 6701 Temp Umn-4 $23.16 $23.85 $24.57 6702 Temp Umn-3 $21.21 $21.85 $22.51 6703 Temp Umn-E2 $19.29 $19.87 $20.47 6704 Temp Umn-E1 $15.43 $15.89 $16.37 6841 Eqpt Opr-Elec $32.40 $33.37 $34.37 6917 Loc Rep-Gas $41.50 $42.75 $44.03 6918 Loc Rep-Gas-2 $39.39 $40.57 $41.79 6919 Loc Rep-Gas-1 $37.22 $38.34 $39.49 6799 Gas Foreman Lead $41.57 $42.82 $44.10 6800 Gas Foreman $39.06 $40.23 $41.44 6801 Jmn Gas $34.73 $35.77 $36.84 6802 App Gas-4 % of Jmn - 92 $31.95 $32.91 $33.89 6803 App Gas-3 % of Jmn - 85 $29.53 $30.40 $31.31 6804 App Gas-2 % of Jmn - 80 $27.78 $28.62 $29.47 6805 App Gas-1 % of Jmn - 75 $26.06 $26.83 $27.63 6831 Gas Pr Ctrlmn $43.77 $45.08 $46.43 6830 Gas Pr Ctrlmn-2 $41.50 $42.75 $44.03 6829 Gas Pr Ctrlmn-1 $39.39 $40.57 $41.79 6819 Seasonal Crew Leadman $34.73 $35.77 $36.84 6822 Cnst Svs Repr-2 $34.31 $35.34 $36.40 6823 Cnst Svs Repr-1 $32.40 $33.37 $34.37 Staff_DR_078 Attachment A Page 5 of 14 39 Job No. Classification 2013 2014 2015 6825 Hi Press Welder $33.85 $34.87 $35.92 6832 Welder Gas $28.08 $28.92 $29.79 6840 Eqpt Opr Gas $32.40 $33.37 $34.37 6871 Utm Loc II $30.46 $31.37 $32.31 6872 Utm Loc I $28.91 $29.78 $30.67 6883 Crewman Gas $23.16 $23.85 $24.57 6884 Crewman Gas-E2 $19.29 $19.87 $20.47 6885 Crewman Gas-E1 $15.43 $15.89 $16.37 6901 Mtls Handler-4 $28.90 $29.77 $30.66 6902 Mtls Handler-3 $27.00 $27.81 $28.64 6903 Mtls Handler-E2 $23.18 $23.88 $24.60 6904 Mtls Handler-E1 $19.29 $19.87 $20.47 6920 Svsmn Gas $36.30 $37.37 $38.49 6921 App Svsmn Gas-4 % of Jmn - 92 $33.40 $34.38 $35.41 6922 App Svsmn Gas-3 % of Jmn - 85 $30.86 $31.77 $32.72 6923 App Svsmn Gas-2 % of Jmn - 80 $29.03 $29.90 $30.79 6924 App Svsmn Gas-1 % of Jmn - 75 $27.22 $28.03 $28.87 STORES, TRANSPORTATION AND METER SHOP 6950 Mtr Installer $35.11 $36.16 $37.24 6410 A Frmn Mtrmn $45.13 $46.48 $47.87 6420 B Frmn Mtrmn $42.47 $43.74 $45.05 6430 Jmn Mtrmn $39.53 $40.72 $41.94 6440 Mtrshop Spec $36.37 $37.46 $38.58 6451 App Mtrmn-6 % of Jmn - 92 $36.37 $37.46 $38.58 6461 App Mtrmn-5 % of Jmn - 86 $34.00 $35.02 $36.07 6471 App Mtrmn-4 % of Jmn - 81 $32.02 $32.98 $33.97 6481 App Mtrmn-3 % of Jmn - 77 $30.44 $31.35 $32.29 6491 App Mtrmn-2 % of Jmn - 73 $28.86 $29.73 $30.62 6501 App Mtrmn-1 % of Jmn - 70 $27.67 $28.50 $29.36 6510 Elec Mtr Inst $32.40 $33.37 $34.37 6511 Elec Mtr Inst-2 $30.06 $30.96 $31.89 6512 Elec Mtr Inst-1 $27.77 $28.60 $29.46 Staff_DR_078 Attachment A Page 6 of 14 40 Job No. Classification 2013 2014 2015 6910 Frmn Gas Mtr Tech $40.84 $42.07 $43.33 6941 Gas Mtr Tech $36.29 $37.38 $38.50 6942 App Gas Mtr Tech-4 % of Jmn - 92 $33.40 $34.39 $35.42 6943 App Gas Mtr Tech-3 % of Jmn - 85 $30.86 $31.77 $32.73 6944 App Gas Mtr Tech-2 % of Jmn - 80 $29.03 $29.90 $30.80 6945 App Gas Mtr Tech-1 % of Jmn - 75 $27.22 $28.04 $28.88 6955 Res. Mtr Util Worker $27.66 $28.49 $29.34 6960 Gas Meas & Inst Tech 5 $42.26 $43.53 $44.84 6961 Gas Meas & Inst Tech 4 $40.15 $41.35 $42.59 6962 Gas Meas & Inst Tech 3 $38.03 $39.17 $40.35 6963 Gas Meas & Inst Tech 2 $35.92 $37.00 $38.11 6964 Gas Meas & Inst Tech 1 $33.82 $34.83 $35.87 7310 Frmn Whse $35.54 $36.61 $37.71 7315 Travel Stkpr $32.76 $33.74 $34.75 7320 Recvr-Shpr $31.62 $32.57 $33.55 7356 Toolkeeper $30.88 $31.81 $32.76 7351 Whsemn-5 $29.69 $30.58 $31.50 7352 Whsemn-4 $27.00 $27.81 $28.64 7353 Whsemn-3 $23.16 $23.85 $24.57 7354 Whsemn-E2 $19.29 $19.87 $20.47 7355 Whsemn-E1 $15.43 $15.89 $16.37 7357 Invest Recovery Coord $32.52 $33.50 $34.51 7358 Invest Recovery Coord 2 $31.62 $32.57 $33.55 7359 Invest Recovery Coord 1 $30.69 $31.61 $32.56 7360 Recovery Utm-5 $25.87 $26.65 $27.45 7361 Recovery Utm-4 $23.16 $23.85 $24.57 7362 Recovery Utm-3 $21.21 $21.85 $22.51 7363 Recovery Utm-E2 $19.29 $19.87 $20.47 7364 Recovery Utm-E1 $15.43 $15.89 $16.37 Staff_DR_078 Attachment A Page 7 of 14 41 Job No. Classification 2013 2014 2015 7410 A Frmn Gar $39.91 $41.11 $42.34 7420 B Frmn Gar $38.15 $39.29 $40.47 7425 Jmn Gar/Colville,Clarkston,Pullman $36.82 $37.92 $39.06 7430 Jmn Gar $35.49 $36.55 $37.65 7429 Jmn Gar-Fab $35.49 $36.55 $37.65 7431 App Gar-6 % of Jmn - 92 $32.65 $33.63 $34.64 7432 App Gar-5 % of Jmn - 86 $30.52 $31.43 $32.38 7433 App Gar-4 % of Jmn - 81 $28.75 $29.61 $30.50 7434 App Gar-3 % of Jmn - 77 $27.32 $28.14 $28.99 7435 App Gar-2 % of Jmn - 73 $25.90 $26.68 $27.48 7436 App Gar-1 % of Jmn - 70 $24.82 $25.59 $26.36 7437 Fleet Pool Driver 3 $28.91 $29.78 $30.67 7438 Fleet Pool Driver 2 $27.00 $27.81 $28.64 7439 Fleet Pool Driver E-1 $23.16 $23.85 $24.57 7460 Partsman-4 $31.62 $32.57 $33.55 7461 Partsman-3 $28.91 $29.78 $30.67 7462 Partsman-2 $27.00 $27.81 $28.64 7463 Parstman-1 $25.10 $25.85 $26.63 7481 Svsmn Gar-5 $28.91 $29.78 $30.67 7482 Svsmn Gar-4 $27.00 $27.81 $28.64 7483 Svsmn Gar-3 $23.16 $23.85 $24.57 7484 Svsmn Gar-E2 $19.29 $19.87 $20.47 7485 Svsmn Gar E1 $15.43 $15.89 $16.37 7440 Helper Gar 3 $17.36 $17.88 $18.42 7441 Helper Gar 2 $16.41 $16.90 $17.41 7442 Helper Gar 1 $15.43 $15.89 $16.37 FACILITIES SERVICES 7509 Bldg Ele $38.59 $39.75 $40.94 7525 Int Sys Spec $35.11 $36.16 $37.24 7529 Ch Bldg Tech $41.25 $42.49 $43.76 Staff_DR_078 Attachment A Page 8 of 14 42 Job No. Classification 2013 2014 2015 7528 HVAC Lead Tech $39.35 $40.53 $41.75 7530 HVAC Tech $36.61 $37.71 $38.84 7531 HVAC Tech-5 $34.88 $35.93 $37.01 7532 HVAC Tech-4 $32.96 $33.95 $34.97 7533 HVAC Tech-3 $31.02 $31.95 $32.91 7534 HVAC Tech-2 $29.13 $30.00 $30.90 7535 HVAC Tech-1 $27.20 $28.02 $28.86 7510 Frmn Bldg/Grnds $27.79 $28.62 $29.48 7551 Bldg Utm-5 $25.87 $26.65 $27.45 7552 Bldg Utm-4 $23.16 $23.85 $24.57 7553 Bldg Utm-3 $21.21 $21.85 $22.51 7554 Bldg Utm-E2 $19.29 $19.87 $20.47 7555 Bldg Utm-E1 $15.43 $15.89 $16.37 7590 Fac Painter $32.09 $33.05 $34.04 7592 Bldg Svsmn-3 $20.05 $20.65 $21.27 7593 Bldg Svsmn-E2 $17.36 $17.88 $18.42 7594 Bldg Svsmn-E1 $15.43 $15.89 $16.37 7580 Ld Grndskpr $22.47 $23.14 $23.83 7582 Grndskpr $20.05 $20.65 $21.27 7583 Grndskpr-E2 $17.36 $17.88 $18.42 7584 Grndskpr-E1 $15.43 $15.89 $16.37 Generation Production and Substation Support 7800 Lead Frmn Elec $49.03 $50.50 $52.02 7810 A Frmn Elec $45.58 $46.95 $48.36 7830 Jmn Elec $40.53 $41.75 $43.00 7931 App Elec -8 % of Jmn - 92 92 $37.29 $38.41 $39.56 7941 App Elec -7 % of Jmn - 92 88 $35.67 $36.74 $37.84 7851 App Elec-6 % of Jmn - 85 $37.29 $35.49 $36.55 7861 App Elec-5 % of Jmn - 83 $34.86 $34.65 $35.69 7871 App Elec-4 % of Jmn - 81 $32.83 $33.82 $34.83 7881 App Elec-3 % of Jmn - 77 $31.21 $32.15 $33.11 7891 App Elec-2 % of Jmn - 73 $29.59 $30.48 $31.39 7901 App Elec-1 % of Jmn - 70 $28.38 $29.23 $30.10 Staff_DR_078 Attachment A Page 9 of 14 43 Job No. Classification 2013 2014 2015 7920 Eqpt Spec (See Note 2) $33.93 $34.95 $36.00 7921 Eqpt Spec-3 $32.40 $33.37 $34.37 7922 Eqpt Spec-2 $30.46 $31.37 $32.31 7923 Eqpt Spec-1 $28.91 $29.78 $30.67 7925 Elec Mtlsmn $33.17 $34.17 $35.20 7930 Batteryman $34.73 $35.77 $36.84 7940 Jmn Transfmn $34.73 $35.77 $36.84 7949 Hazardous Waste Tech $35.49 $36.55 $37.65 7950 Hazardous Waste Tech-4 $33.93 $34.95 $36.00 7951 Hazardous Waste Tech-3 $32.40 $33.37 $34.37 7952 Hazardous Waste Tech-2 $30.46 $31.37 $32.31 7953 Hazardous Waste Tech-1 $28.91 $29.78 $30.67 7981 Hlpr Elec-5 $28.91 $29.78 $30.67 7982 Hlpr Elec-4 $27.00 $27.81 $28.64 7983 Hlpr Elec-3 $23.16 $23.85 $24.57 7984 Hlpr Elec-E2 $19.29 $19.87 $20.47 7985 Hlpr Elec-E1 $15.43 $15.89 $16.37 7991 Umn Elec-4 $25.10 $25.85 $26.63 7992 Umn Elec-3 $23.16 $23.85 $24.57 7993 Umn Elec-E2 $19.29 $19.87 $20.47 7994 Umn Elec-E1 $15.43 $15.89 $16.37 8231 Sta Elec $40.53 $41.75 $43.00 8010 A Frmn M/S $46.03 $47.41 $48.83 8030 Jmn M/S $40.90 $42.13 $43.39 8040 App M/S-8 % of Jmn - 92 $37.63 $38.76 $39.92 8045 App M/S-7 % of Jmn - 88 $35.99 $37.07 $38.19 8051 App M/S-6 % of Jmn - 85 $34.77 $35.81 $36.88 8061 App M/S-5 % of Jmn - 83 $33.95 $34.97 $36.01 8071 App M/S-4 % of Jmn - 81 $33.13 $34.13 $35.15 8081 App M/S-3 % of Jmn - 77 $31.49 $32.44 $33.41 8091 App M/S-2 % of Jmn - 73 $29.86 $30.75 $31.67 8101 App M/S-1 % of Jmn - 70 $28.62 $29.49 $30.37 Staff_DR_078 Attachment A Page 10 of 14 44 Job No. Classification 2013 2014 2015 8150 M/S Shop & Mtlsmn $37.62 $38.75 $39.91 8181 Hlpr M/S-5 $28.91 $29.78 $30.67 8182 Hlpr M/S-4 $27.00 $27.81 $28.64 8183 Hlpr M/S-3 $23.16 $23.85 $24.57 8184 Hlpr M/S-2 $19.29 $19.87 $20.47 8185 Hlpr M/S-1 $15.43 $15.89 $16.37 8188 Pre Appr Wrkr GPSS 3 28.914 $29.78 $30.67 8199 Pre Appr Wrkr GPSS 2 $27.00 $27.81 $28.64 8190 Pre Appr Wrkr GPSS 1 $23.15 $23.84 $24.50 8191 Umn M/S-4 $25.10 $25.85 $26.63 8192 Umn M/S-3 $23.16 $23.85 $24.57 8193 Umn M/S-E2 $19.29 $19.87 $20.47 8194 Umn M/S-E1 $15.43 $15.89 $16.37 8230 Sta Mech $40.90 $42.13 $43.39 8400 Frmn P/C Mtr Tech $50.50 $52.02 $53.58 8410 Sr P/C Mtr Tech $46.99 $48.40 $49.85 8419 Jmn P/C Mtr Tech-2 $44.66 $46.00 $47.38 8420 Jmn P/C Mtr Tech-1 $42.33 $43.60 $44.91 8431 App P/C Mtr-8 (See Note 3) % of Jmn - 92 $38.94 $40.11 $41.32 8441 App P/C Mtr-7 % of Jmn - 88 $37.25 $38.37 $39.52 8451 App P/C Mtr-6 % of Jmn - 85 $35.98 $37.06 $38.17 8461 App P/C Mtr-5 % of Jmn - 83 $35.14 $36.19 $37.27 8471 App P/C Mtr-4 % of Jmn - 81 $34.30 $35.32 $36.38 8481 App P/C Mtr-3 % of Jmn - 77 $32.61 $33.57 $34.58 8491 App P/C Mtr-2 % of Jmn - 73 $30.90 $31.83 $32.78 8501 App P/C Mtr-1 % of Jmn - 70 $29.63 $30.52 $31.44 8511 Tech Assistant $27.66 $28.49 $29.34 8519 Frmn Comm $47.85 $49.29 $50.77 8520 Sr Comm Tech $44.49 $45.82 $47.19 8528 Jmn Comm Tech-3 $42.50 $43.78 $45.09 8529 Jmn Comm Tech-2 $41.33 $42.57 $43.85 8530 Jmn Comm Tech-1 $40.08 $41.28 $42.52 Staff_DR_078 Attachment A Page 11 of 14 45 Job No. Classification 2013 2014 2015 8541 App Tech-8 (See Note 3) % of Jmn - 92 $36.87 $37.98 $39.12 8551 App Tech-7 (See Note 3) % of Jmn - 88 $35.26 $36.33 $37.42 8561 App Comm Tech-6 % of Jmn - 85 $34.08 $35.09 $36.14 8571 App Comm Tech-5 % of Jmn - 83 $33.27 $34.26 $35.29 8581 App CommTech-4 % of Jmn - 81 $32.47 $33.44 $34.44 8591 App Comm Tech-3 % of Jmn - 77 $30.88 $31.79 $32.74 8601 App Comm Tech-2 % of Jmn - 73 $29.27 $30.13 $31.04 8611 App Comm Tech-1 % of Jmn - 70 $28.06 $28.90 $29.76 8630 Comm Shop Tech-4 $36.87 $37.98 $39.12 8631 Comm Shop Tech-3 $35.26 $36.32 $37.41 8632 Comm Shop Tech-2 $34.08 $35.10 $36.15 8633 Comm Shop Tech-1 $33.28 $34.28 $35.31 8615 Tele Installer $32.45 $33.42 $34.42 8621 Comm Umn-4 $25.10 $25.85 $26.63 8622 Comm Umn-3 $23.16 $23.85 $24.57 8623 Comm Umn-E2 $19.29 $19.87 $20.47 HYDRO OPERATIONS 8653 Jmn Plant Spec-3 $43.50 $44.81 $46.15 8654 Jmn Plant Spec-2 $42.47 $43.74 $45.05 8655 Jmn Plant Spec-1 $41.48 $42.72 $44.00 8640 Ch Opr $45.58 $46.95 $48.36 8648 Ch Jmn Opr-3 $44.06 $45.38 $46.74 8649 Ch Jmn Opr-2 $43.09 $44.38 $45.71 8650 Ch Jmn Opr-1 $41.89 $43.15 $44.44 8660 Jmn Opr $40.53 $41.75 $43.00 8681 App Opr-6 % of Jmn - 92 $37.29 $38.41 $39.56 8691 App Opr-5 % of Jmn - 86 $34.86 $35.91 $36.98 8701 App Opr-4 % of Jmn - 81 $32.83 $33.82 $34.83 8711 App Opr-3 % of Jmn - 77 $31.21 $32.15 $33.11 8721 App Opr-2 % of Jmn - 73 $29.59 $30.48 $31.39 8731 App Opr-1 % of Jmn - 70 $28.38 $29.23 $30.10 8775 Pre App GPSS $23.16 $23.85 $24.57 Staff_DR_078 Attachment A Page 12 of 14 46 Job No. Classification 2013 2014 2015 8781 Sta Umn-5 $30.88 $31.81 $32.76 8782 Sta Umn-4 $27.00 $27.81 $28.64 8783 Sta Umn-3 $23.16 $23.85 $24.57 8784 Sta Umn-E2 $19.29 $19.87 $20.47 8785 Sta Umn-E1 $15.43 $15.89 $16.37 THERMAL OPERATIONS 9009 Ch Control Opr $45.69 $47.06 $48.47 9010 Control Opr $40.66 $41.88 $43.14 9020 Control Opr-1 $39.11 $40.28 $41.49 9030 Asst Control Opr $37.80 $38.93 $40.10 9110 Axly Opr $37.80 $38.93 $40.10 9115 Axly Opr-6 $37.07 $38.18 $39.33 9120 Axly Opr-5 $36.30 $37.39 $38.51 9130 Axly Opr-4 $35.48 $36.54 $37.64 9140 Axly Opr-3 $33.93 $34.95 $36.00 9150 Axly Opr-2 $32.40 $33.37 $34.37 9160 Axly Opr-1 $30.88 $31.81 $32.76 9310 Fuel Eqpt Opr-4 $31.62 $32.57 $33.55 9320 Fuel Eqpt Opr-3 $28.91 $29.78 $30.67 9330 Fuel Eqpt Opr-2 $27.00 $27.81 $28.64 9340 Fuel Eqpt Opr-1 $23.16 $23.85 $24.57 9405 A Frmn Mech $44.24 $45.57 $46.94 9410 Plant Mech $39.91 $41.11 $42.34 9420 Plant Mech-6 $36.23 $37.32 $38.44 9430 Plant Mech-5 $33.85 $34.87 $35.92 9440 Plant Mech-4 $32.28 $33.25 $34.25 9450 Plant Mech-3 $31.05 $31.98 $32.94 9460 Plant Mech-2 $30.31 $31.22 $32.16 9470 Plant Mech-1 $29.48 $30.36 $31.27 9501 Sr Control & Elec Tech $44.49 $45.82 $47.19 9508 Jmn Control & Elec Tech-3 $42.50 $43.78 $45.09 Staff_DR_078 Attachment A Page 13 of 14 47 Job No. Classification 2013 2014 2015 9509 Jmn Control & Elec Tech-2 $41.33 $42.57 $43.85 9510 Jmn Control & Elec Tech-1 $40.08 $41.28 $42.52 9520 Control & Elec Tech-6 $36.93 $38.04 $39.18 9530 Control & Elec Tech-5 $35.31 $36.37 $37.46 9540 Control & Elec Tech-4 $34.11 $35.13 $36.18 9550 Control & Elec Tech-3 $33.27 $34.27 $35.30 9560 Control & Elec Tech-2 $32.48 $33.45 $34.45 9570 Control & Elec Tech-1 $31.69 $32.64 $33.62 9611 Plant Mtlsmn-4 $33.17 $34.17 $35.20 9612 Plant Mtlsmn-3 $28.91 $29.78 $30.67 9613 Plant Mtlsmn-2 $27.00 $27.81 $28.64 9614 Plant Mtlsmn-1 $23.16 $23.85 $24.57 9711 Plant Umn-5 $28.91 $29.78 $30.67 9712 Plant Umn-4 $27.00 $27.81 $28.64 9713 Plant Umn-3 $23.16 $23.85 $24.57 9714 Plant Umn-E1 $19.29 $19.87 $20.47 9715 Plant Umn-E2 $15.43 $15.89 $16.37 Note 1: Hd Groundman without previous line experience will have steps indicated. Note 2: Eqpt Spec without previous maintenance and equipment experience in substations and generating stations and/or without heavy equipment operating will have steps indicated. Note 3: These two periods will include certain Journeyman Level work to be performed without direct supervision. AGREEMENT: Witnessed and signed this _______ day of ____________, 2015. International Brotherhood of Avista Corporation, doing business Electrical Workers, AFL-CIO as Avista Utilities Local Union #77 __________________________ _________________________ Louis Walter Dennis Vermillion Business Manager/Financial Secretary President, Avista Utilities ___________________________ _________________________ Suzanne Brunner Terry Bushnell Assistant Business Manager Chair, Management Negotiations Committee Staff_DR_078 Attachment A Page 14 of 14 Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/25/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: UTC Staff - Cheesman RESPONDER: Annette Brandon TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff – 078 TELEPHONE: (509) 495-4324 EMAIL: annette.brandon@avistacorp.com REQUEST: Referring to the company’s electric labor adjustments 3.02, 4.02 and 18.03 (gas labor adjustments 3.00, 4.00 and 18.01), please provide a copy of that part of the union contract(s) that supports the union wage increases included in the company’s filing. RESPONSE: Please see Staff_DR_078 Attachment A for the portion of the union contract which supports wage increases included in the Company’s filing. Please note the original contract was for 2014-2016, however, it was amended to include wage increases for 2016, 2017 and 2018. The attachment contains both the wage exhibit from the original contract (pages 2-14) and the contract extension (page 1). Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/25/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: UTC Staff - Cheesman RESPONDER: Annette Brandon TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff – 078 TELEPHONE: (509) 495-4324 EMAIL: annette.brandon@avistacorp.com REQUEST: Referring to the company’s electric labor adjustments 3.02, 4.02 and 18.03 (gas labor adjustments 3.00, 4.00 and 18.01), please provide a copy of that part of the union contract(s) that supports the union wage increases included in the company’s filing. RESPONSE: Please see Staff_DR_078 Attachment A for the portion of the union contract which supports wage increases included in the Company’s filing. Please note the original contract was for 2014-2016, however, it was amended to include wage increases for 2016, 2017 and 2018. The attachment contains both the wage exhibit from the original contract (pages 2-14) and the contract extension (page 1). Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/25/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: UTC Staff - Cheesman RESPONDER: Annette Brandon TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff – 079 TELEPHONE: (509) 495-4324 EMAIL: annette.brandon@avistacorp.com REQUEST: Referring to the company’s electric incentive adjustment 2.16 (gas incentive adjustment 2.14), please provide the past six calendar years (2009 through 2015) of incentive payouts organized by year and by executive verse non-executive employees. RESPONSE: Please see Avista’s CONFIDENTIAL response to data request Staff_DR_079C. Please note that Avista’s response to Staff_DR_079C is Confidential per Protective Order in UTC Dockets UE- 160228 and UG-160229. Please see Staff_DR_079C Confidential Attachment A for the requested information. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/25/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: UTC Staff - Cheesman RESPONDER: Annette Brandon TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff – 079 TELEPHONE: (509) 495-4324 EMAIL: annette.brandon@avistacorp.com REQUEST: Referring to the company’s electric incentive adjustment 2.16 (gas incentive adjustment 2.14), please provide the past six calendar years (2009 through 2015) of incentive payouts organized by year and by executive verse non-executive employees. RESPONSE: Please see Avista’s CONFIDENTIAL response to data request Staff_DR_079C. Please note that Avista’s response to Staff_DR_079C is Confidential per Protective Order in UTC Dockets UE- 160228 and UG-160229. Please see Staff_DR_079C Confidential Attachment A for the requested information. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/25/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: UTC Staff - Cheesman RESPONDER: Annette Brandon TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff – 080 TELEPHONE: (509) 495-4324 EMAIL: annette.brandon@avistacorp.com REQUEST: Referring to Jennifer Smith’s direct testimony, Exhibit _(JSS-1T), page 34, lines 3-5, the company’s electric labor adjustment 3.04 (gas labor adjustment 3.02), please provide a copy of most recent actuarial analysis for the Pension Plan and Post-Retirement Medical expenses. Please also provide a summary of any changes that would affect the company’s “(WA 2016) FLB Retirement and Medical” work papers. RESPONSE: Please see Avista’s CONFIDENTIAL response to data request Staff_DR_080C. Please note that Avista’s response to Staff_DR_080C is Confidential per Protective Order in UTC Dockets UE- 160228 and UG-160229. Please see Staff_DR_080C Confidential Attachment A for the updated actuarial analysis for the updated pension and post-retirement medical estimate for 2016-2020. Please see Staff_DR_080C Confidential Attachment B for the Actuarial Evaluation report for the period ending December 31, 2015. This update results in an increase in Washington Electric expense for approximately $544,000 and Washington Natural Gas expense for approximately $163,000. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/25/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: UTC Staff - Cheesman RESPONDER: Annette Brandon TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff – 080 TELEPHONE: (509) 495-4324 EMAIL: annette.brandon@avistacorp.com REQUEST: Referring to Jennifer Smith’s direct testimony, Exhibit _(JSS-1T), page 34, lines 3-5, the company’s electric labor adjustment 3.04 (gas labor adjustment 3.02), please provide a copy of most recent actuarial analysis for the Pension Plan and Post-Retirement Medical expenses. Please also provide a summary of any changes that would affect the company’s “(WA 2016) FLB Retirement and Medical” work papers. RESPONSE: Please see Avista’s CONFIDENTIAL response to data request Staff_DR_080C. Please note that Avista’s response to Staff_DR_080C is Confidential per Protective Order in UTC Dockets UE- 160228 and UG-160229. Please see Staff_DR_080C Confidential Attachment A for the updated actuarial analysis for the updated pension and post-retirement medical estimate for 2016-2020. Please see Staff_DR_080C Confidential Attachment B for the Actuarial Evaluation report for the period ending December 31, 2015. This update results in an increase in Washington Electric expense for approximately $544,000 and Washington Natural Gas expense for approximately $163,000. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/25/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: UTC Staff - Cheesman RESPONDER: Annette Brandon TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff – 081 TELEPHONE: (509) 495-4324 EMAIL: annette.brandon@avistacorp.com REQUEST: Please provide descriptions of duties and work performed during the test year for all officers included in the company’s work paper “(WA 2016) FLB Forecast labor Executive (historical)”, worksheet “Exec Utility Split.” RESPONSE: Please see Avista’s CONFIDENTIAL response to data request Staff_DR_081C - Supplemental. Please note that Avista’s response to Staff_DR_081C - Supplemental is Confidential per Protective Order in UTC Dockets UE-160228 and UG-160229. Please see Staff_DR_081C Confidential Attachment A for requested job descriptions. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/25/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: UTC Staff - Cheesman RESPONDER: Annette Brandon TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff – 081 TELEPHONE: (509) 495-4324 EMAIL: annette.brandon@avistacorp.com REQUEST: Please provide descriptions of duties and work performed during the test year for all officers included in the company’s work paper “(WA 2016) FLB Forecast labor Executive (historical)”, worksheet “Exec Utility Split.” RESPONSE: Please see Avista’s CONFIDENTIAL response to data request Staff_DR_081C - Supplemental. Please note that Avista’s response to Staff_DR_081C - Supplemental is Confidential per Protective Order in UTC Dockets UE-160228 and UG-160229. Please see Staff_DR_081C Confidential Attachment A for requested job descriptions. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/20/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: UTC Staff - Huang RESPONDER: Ryan Finesilver TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff - 082 TELEPHONE: (509) 495-4873 EMAIL: ryan.finesilver@avistacorp.com REQUEST: Please describe what the Colville warehouse was used for prior to its sale. Please explain the service / jurisdiction allocation of ZZ ZZ to the gain of the warehouse (see file 2016 Net Gains Losses tab NGL-2 cell f10.) RESPONSE: The Colville Warehouse was purchased in 1955 and was used for the housing of stores and equipment related to the Company’s utility operations in the Colville area. In July, 2013, prior to the sale in 2015, the warehouse was no longer used for the benefit of the utility and was moved to non-utility operations. After further inquiries and discussion, it was determined that the gain on sale related to the Colville Warehouse should have been included in the Net Gains and Losses adjustment as a CD.WA item instead of a ZZ.ZZ item as filed. The impact of this change increases the Washington Electric Net Gains and Losses adjustment by $10,298 to a revised adjustment of $89,778. For Natural Gas, the adjustment increases $2,780 to a revised adjustment of $8,974. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/20/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: UTC Staff - Huang RESPONDER: Ryan Finesilver TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff - 082 TELEPHONE: (509) 495-4873 EMAIL: ryan.finesilver@avistacorp.com REQUEST: Please describe what the Colville warehouse was used for prior to its sale. Please explain the service / jurisdiction allocation of ZZ ZZ to the gain of the warehouse (see file 2016 Net Gains Losses tab NGL-2 cell f10.) RESPONSE: The Colville Warehouse was purchased in 1955 and was used for the housing of stores and equipment related to the Company’s utility operations in the Colville area. In July, 2013, prior to the sale in 2015, the warehouse was no longer used for the benefit of the utility and was moved to non-utility operations. After further inquiries and discussion, it was determined that the gain on sale related to the Colville Warehouse should have been included in the Net Gains and Losses adjustment as a CD.WA item instead of a ZZ.ZZ item as filed. The impact of this change increases the Washington Electric Net Gains and Losses adjustment by $10,298 to a revised adjustment of $89,778. For Natural Gas, the adjustment increases $2,780 to a revised adjustment of $8,974. September 2014 Combined Excise Tax Return 328-000-223 AVISTA CORP State Business and Occupation Section Taxes State Sales and Use Section Taxes Local Sales Section State of Washingto Department of RevenuPO Box 4746Olympia, WA 9850 -7464 Line Cod Tax Classificatio Gross Amount Total Deduction Taxable Amount Rat Tax Du 0003 Wholesaling 123,179.96 0.00 123,179.96 0.00484 596.19 0004 Service and Other Activities; Gambling Contests of Chance less than $50,000 a ear 357,338.4 0.0 357,338.4 0.015 5,360.08 0002 Retailin 40,854.7 0.0 40,854.7 0.0047 192.4 521,373.16 0.00 521,373.16 6,148.70 Line Cod Tax Classificatio Gross Amoun Total Deduction Taxable Amount Rat Tax Du 000 Retail Sale 40,854.7 0.0 40,854.7 0.065 2,655.5 000 Use Ta 1,059,394.7 0.0 1,059,394.7 0.065 68,860.6 1,100,249.52 0.00 1,100,249.52 71,516.22 Line Cod Location Cod ocation Nam Taxable Amount Rat Tax Du 004 010 DAMS COUNTY 803.6 0.012 9.64 004 0202 CLARKSTON 169.6 0.012 2.04 004 220 INCOLN COUNTY 749.3 0.012 8.99 004 2204 ARRINGTON 523.9 0.012 6.29 004 220 ODESS 785.8 0.012 9.4 004 320 SPOKANE COUNTY 3,541.1 0.016 56.6 004 320 IRWAY HEIGHT 16.8 0.024 0.4 004 320 EER PARK 324.69 0.016 5.2 004 320 EDICAL LAK 1,416.2 0.022 31.1 004 321 SPOKANE CITY 2,926.7 0.022 64.39 004 3212 IBERTY LAK 844.8 0.022 18.59 004 321 SPOKANE VALLEY 13,879.1 0.022 305.34 Page 1 of 4Combined Excise Tax Retur 5 18 201mhtml:file://C:\Users\Rff9457\Desktop\DR Working Folder\09 September 2014 Combin ... Staff_DR_083 Attachment A Page 1 of 16 Local Use Section Public Utilities Section Taxes Deductions Other Tax Section Natural Gas Use Tax Credit Section 004 3232 SPOKAN -PTB 8,306.3 0.022 182.74 004 330 STEVENS COUNTY 5,066.6 0.011 55.7 004 3304 ARCU 1,500.0 0.011 16.5 40,854.75 773.10 Line Cod Location Cod Location Nam Taxable Amount Rat Tax Du 004 0104 RITZVILL 320.0 0.012 3.84 004 320 SPOKANE COUNTY 2,000.0 0.016 32.0 004 321 SPOKANE CITY 778,217.34 0.022 17,120.78 004 321 SPOKANE VALLEY 95,309.2 0.022 2,096.8 004 330 STEVENS COUNTY 101,781.8 0.011 1,119.6 004 3302 COLVILL 112.9 0.011 1.24 004 380 WHITMAN COUNTY 81,653.5 0.013 1,061.5 1,059,394.77 21,435.7 Line Cod Tax Classificatio Gross Amount Total Deduction Taxable Amount Rat Tax Du 0049 Powe 44,115,868.04 266,209.0 43,849,659.04 0.038734 1,698,472.69 002 Gas Distribution-Telegraph 5,334,935.6 3,967.1 5,330,968.5 0.03852 205,348.9 49,450,803.71 270,176.11 49,180,627.60 1,903,821.60 Deduction Cod Tax Classificatio Deduction Nam Amount 00490 owe Bad Debt 266,209.0 00260 Gas Distribution-Tele ra h Bad Debt 3,967.1 270,176.11 Line Cod Tax Classificatio Taxable Amount Rat Tax Du 012 atural Gas Purchase Pric 102,392.12 0.03852 3,944.14 102,392.12 3,944.14 Code Document Number Credit Amount Page 2 of 4Combined Excise Tax Retur 5 18 201mhtml:file://C:\Users\Rff9457\Desktop\DR Working Folder\09 September 2014 Combin ... Staff_DR_083 Attachment A Page 2 of 16 Summary Section Additional Information This is a copy for your records. Please DO NOT MAIL a copy to the Department of Revenue. 088 898 illing Discounts/Qualified Contributions to a Low Income Home Energy Assistance und Credi (112,294.21) 092 enewable Ener S stem Cost Recover Credi 8,766.39 121,060.60 Amount State Business and Occupation Tax Tota 6,148.7 State Sales and Use Tax Tota 71,516.22 Local and Re ional Tax Tota 22,208.8 Lodging Tax Tota 0.0 Public Utilities Tax Tota 1,903,821.6 E911 Tax Tota 0.0 Other Tax Tota 3,944.14 SubTotal 2,007,639.52 Less Total Credit (121,060.60) Total 1,886,578.92 Amount Pai 1,886,578.92 Balanc 0.00 Confirmation Number 14204842 Date and Time Submitted 10/22/2014 11:36:32 AM Pa ment T pe EFT Credit Total Amount Paid 1,886,578.92 ate Printed 10/22/2014 Tax Re istration umber 28-000-223 Person Completin Return Catherine Cooper Phone Number (509)495-4885 E-Mail Address Catherine.Coo er Avistacor .com To initiate your payment, you must contact your financial institution. Each bank has its own guidelines for ACH transactions. ACH Credit taxpayers are responsible for contacting their own bank to ensure funds are deposited in the State's bank no later than 5:00 PM Pacific Time on October 28 2014. Page 3 of 4Combined Excise Tax Retur 5 18 201mhtml:file://C:\Users\Rff9457\Desktop\DR Working Folder\09 September 2014 Combin ... Staff_DR_083 Attachment A Page 3 of 16 Natural Gas Use Tax Section State Natural Gas Use Tax Local City Natural Gas Use Tax Totals Renewable Energy Credit Volum Volume in therms 287,04 Tax Classificatio Taxable Amount Rat Tax Du Purchase Pric 102,392.12 0.03852 3,944.14 Trans ortation Char 0.0 0.03852 0.00 Total State Tax Due 3,944.14 Code Location Name Taxable Rate City Tax Due Previously Filed Amount Accumulated Threshold Tax Due 3,944.14 Less Credits 0.00 Natural Gas Use Tax Due 3,944.14 Line 1: Solar, Wind, Anaerobic Digester or Community Solar Project Credit Amount (Do Not Include Utility- Owned or Company-Owned Community Solar Projects)8,766.39 Line 2: Company-Owned Community Solar Project Credit Amount 0.00 Line 3: Utility-Owned Community Solar Project Credit Amount 0.00 Total Renewable Energy System Cost Recovery Credit Amount 8,766.39 Page 4 of 4Combined Excise Tax Retur 5 18 201mhtml:file://C:\Users\Rff9457\Desktop\DR Working Folder\09 September 2014 Combin ... Staff_DR_083 Attachment A Page 4 of 16 October 2014 Combined Excise Tax Return 328-000-223 AVISTA CORP State Business and Occupation Section Taxes State Sales and Use Section Taxes Local Sales Section State of Washingto Department of RevenuPO Box 4746Olympia, WA 9850 -7464 Line Cod Tax Classificatio Gross Amount Total Deduction Taxable Amount Rat Tax Du 0003 Wholesaling 321,735.20 0.00 321,735.20 0.00484 1,557.20 0004 Service and Other Activities; Gambling Contests of Chance less than $50,000 a ear 514,786.04 0.0 514,786.04 0.015 7,721.79 0002 Retailin 73,316.6 0.0 73,316.6 0.0047 345.32 909,837.89 0.00 909,837.89 9,624.31 Line Cod Tax Classificatio Gross Amoun Total Deduction Taxable Amount Rat Tax Du 000 Retail Sale 73,316.6 0.0 73,316.6 0.065 4,765.58 000 Use Ta 837,091.5 0.0 837,091.5 0.065 54,410.9 910,408.20 0.00 910,408.20 59,176.53 Line Cod Location Cod ocation Nam Taxable Amount Rat Tax Du 004 100 ERRY COUNTY 2,552.0 0.012 30.62 004 2202 CRESTON 249.7 0.012 3.0 004 220 AVENPORT 249.7 0.012 3.0 004 320 SPOKANE COUNTY 11,161.4 0.016 178.58 004 320 IRWAY HEIGHT 33.6 0.024 0.8 004 320 EER PARK 80.5 0.016 1.29 004 3204 AIRFIELD 248.84 0.016 3.98 004 320 EDICAL LAK 879.48 0.022 19.3 004 321 SPOKANE CITY 24,342.99 0.022 535.5 004 3212 IBERTY LAK 727.6 0.022 16.0 004 321 SPOKANE VALLEY 5,457.5 0.022 120.0 004 3232 SPOKAN -PTB 3,959.39 0.022 87.1 Page 1 of 4Combined Excise Tax Retur 5 18 201mhtml:file://C:\Users\Rff9457\Desktop\DR Working Folder\10 October 2014 Combined ... Staff_DR_083 Attachment A Page 5 of 16 Local Use Section Public Utilities Section Taxes Deductions Other Tax Section Natural Gas Use Tax 004 330 STEVENS COUNTY 16,948.4 0.011 186.4 004 330 CHEWELAH 512.2 0.011 5.6 004 3302 COLVILL 762.2 0.011 8.38 004 3304 ARCU 250.0 0.011 2.7 004 330 ORTHPORT 1,304.4 0.011 14.3 004 380 LBION 303.84 0.013 3.9 004 3802 COLFAX 2,544.0 0.013 33.0 004 381 OAKESDAL 249.54 0.013 3.24 004 381 OSALI 249.54 0.013 3.24 004 381 TEKO 249.54 0.013 3.24 73,316.65 1,263.65 Line Cod Location Cod Location Nam Taxable Amount Rat Tax Du 004 0202 CLARKSTON 308.3 0.012 3.7 004 1309 MOSES LAK 90.0 0.014 1.2 004 220 LINCOLN COUNTY 60,538.3 0.012 726.4 004 320 SPOKANE COUNTY (1,869.70) 0.016 (29.92) 004 320 DEER PARK 41.79 0.016 0.6 004 321 SPOKANE CITY 553,893.7 0.022 12,185.6 0046 3213 SPOKANE VALLEY 57,467.88 0.0220 1,264.29 004 330 STEVENS COUNTY 153,160.7 0.011 1,684.7 004 380 WHITMAN COUNTY 13,460.38 0.013 174.98 837,091.55 16,011.87 Line Cod Tax Classificatio Gross Amount Total Deduction Taxable Amount Rat Tax Du 0049 Powe 38,596,316.02 266,209.0 38,330,107.02 0.038734 1,484,678.3 002 Gas Distribution-Telegraph 6,040,067.1 3,967.1 6,036,100.0 0.03852 232,510.5 44,636,383.13 270,176.11 44,366,207.02 1,717,188.94 Deduction Cod Tax Classificatio Deduction Nam Amount 00490 owe Bad Debt 266,209.0 00260 Gas Distribution-Tele ra h Bad Debt 3,967.1 270,176.11 Line Cod Tax Classificatio Taxable Amount Rat Tax Du Page 2 of 4Combined Excise Tax Retur 5 18 201mhtml:file://C:\Users\Rff9457\Desktop\DR Working Folder\10 October 2014 Combined ... Staff_DR_083 Attachment A Page 6 of 16 Credit Section Summary Section Additional Information 012 atural Gas Purchase Pric 12,720.84 0.03852 490.0 12,720.84 490.01 Cod Document Number Credit Amount 0880 8985 Billing Discounts/Qualified Contributions to a Low Income Home Energy Assistance Fund Credi (62,113.50) 62,113.50 Amount State Business and Occu ation Tax Tota 9,624.3 State Sales and Use Tax Tota 59,176.5 Local and Regional Tax Total 17,275.52 Lodging Tax Tota 0.0 Public Utilities Tax Tota 1,717,188.94 E911 Tax Tota 0.0Other Tax Tota 490.0 SubTotal 1,803,755.31 Less Total Credit 62,113.50 Total 1,741,641.81 Amount Pai 1,741,641.81 Balanc 0.00 Confirmation Number 14371990 Date and Time Submitted 11/20/2014 9:50:00 M Pa ment T pe FT Credit Total Amount Paid 1,741,641.81 Date Printed 11/20/2014 Tax Re istration Number 28-000-223 Person Completin Return Catherine Cooper Phone Number 509 495-4885 E-Mail Address Catherine.Coo er Avistacor .com To initiate your payment, you must contact your financial institution. Each bank has its own guidelines for ACH transactions. ACH Credit taxpayers are responsible for contacting their own bank to ensure funds are deposited in the State's bank no later than 5:00 PM Pacific Time on November 26 2014. Page 3 of 4Combined Excise Tax Retur 5 18 201mhtml:file://C:\Users\Rff9457\Desktop\DR Working Folder\10 October 2014 Combined ... Staff_DR_083 Attachment A Page 7 of 16 This is a copy for your records. Please DO NOT MAIL a copy to the Department of Revenue. Natural Gas Use Tax Section State Natural Gas Use Tax Local City Natural Gas Use Tax Totals Volum Volume (in therms) 33,539 Tax Classificatio Taxable Amount Rat Tax Du Purchase Pric 12,720.84 0.03852 490.01 Transportation Char 0.0 0.03852 0.00 Total State Tax Due 490.01 Code Location Name Taxable Rate City Tax Due Previously Filed Amount Accumulated Threshold Tax Due 490.01 Less Credits 0.00 Natural Gas Use Tax Due 490.01 Page 4 of 4Combined Excise Tax Retur 5 18 201mhtml:file://C:\Users\Rff9457\Desktop\DR Working Folder\10 October 2014 Combined ... Staff_DR_083 Attachment A Page 8 of 16 Washington State Department of Revenu State of Washingto Department of Revenue PO Box 47464 Olympia, WA 98504-7464 July 2015 Combined Excise Tax Return 328-000-223 AVISTA CORP State Business and Occupation Section Taxes Line Code Tax Classification Gross Amount Total Deductions Taxable Amount Rate Tax Due 0003 Wholesaling 55,532.64 0.00 55,532.64 0.00484 268.78 0004 Service and Other Activities; Gambling Contests of Chance (less than $50,000 a year) 2,996.34 1,122,869.57 (1,119,873.23) 0.0150 (16,798.10) 0002 Retailing 31,674.72 0.00 31,674.72 0.00471 149.19 90,203.70 1,122,869.57 (1,032,665.87) (16,380.13) Deductions Deduction Code Tax Classification Deduction Name Amount 000499 Service and Other Activities; Gambling Contests of Chance (less than $50,000 a year) Other 1,122,869.57 1,122,869.57 Explanations for Other Deductions Deduction Code Explanation 000499 Reversing previously reported grant funds, received from the WA. St. Dept of Commerce, as non-taxable services. State Sales and Use Section Taxes Line Code Tax Classification Gross Amount Total Deductions Taxable Amount Rate Tax Due 0001 Retail Sales 31,674.72 0.00 31,674.72 0.0650 2,058.86 0005 Use Tax 1,009,583.80 0.00 1,009,583.80 0.0650 65,622.95 1,041,258.52 0.00 1,041,258.52 67,681.81 Local Sales Section Line Code Location Code Location Name Taxable Amount Rate Tax Due 0045 0202 CLARKSTON 1,793.88 0.0120 21.53 0045 2605 NEWPORT 2,621.96 0.0110 28.84 0045 3200 SPOKANE COUNTY 1,010.80 0.0160 16.17 0045 3203 DEER PARK 12.60 0.0160 0.20 0045 3206 MEDICAL LAKE 125.00 0.0220 2.75 0045 3210 SPOKANE CITY 24,853.08 0.0220 546.77 0045 3212 LIBERTY LAKE 398.20 0.0220 8.76 0045 3213 SPOKANE VALLEY 409.00 0.0220 9.00 0045 3232 SPOKANE-PTBA 450.20 0.0220 9.90 31,674.72 643.92 Page 1 of 4Combined Excise Tax Retur 5 18 201file:///C:/Users/Rff9457/Desktop/DR%20Working%20Folder/07%20July%202015%20C ... Staff_DR_083 Attachment A Page 9 of 16 Local Use Section Line Code Location Code Location Name Taxable Amount Rate Tax Due 0046 2002 GOLDENDALE 9,489.18 0.0100 94.89 0046 2203 DAVENPORT 95.00 0.0120 1.14 0046 3200 SPOKANE COUNTY 679.25 0.0160 10.87 0046 3210 SPOKANE CITY 839,596.47 0.0220 18,471.12 0046 3213 SPOKANE VALLEY 132,537.03 0.0220 2,915.81 0046 3232 SPOKANE-PTBA 66.50 0.0220 1.46 0046 3300 STEVENS COUNTY 25,096.69 0.0110 276.06 0046 3302 COLVILLE 134.02 0.0110 1.47 0046 3800 WHITMAN COUNTY 1,889.66 0.0130 24.57 1,009,583.80 21,797.39 Public Utilities Section Taxes Line Code Tax Classification Gross Amount Total Deductions Taxable Amount Rate Tax Due 0049 Power 45,452,766.92 (29,717.25) 45,482,484.17 0.038734 1,761,718.54 0026 Gas Distribution-Telegraph 5,003,119.58 (386.21)5,003,505.79 0.03852 192,735.04 50,455,886.50 (30,103.46)50,485,989.96 1,954,453.58 Deductions Deduction Code Tax Classification Deduction Name Amount 004901 Power Bad Debts (29,717.25) 002601 Gas Distribution-Telegraph Bad Debts (386.21) (30,103.46) Other Tax Section Natural Gas Use Tax Line Code Tax Classification Taxable Amount Rate Tax Due 0121 Natural Gas Purchase Price 134,431.80 0.03852 5,178.31 134,431.80 5,178.31 Credit Section Code Document Number Credit Amount 0880 9995 Billing Discounts/Qualified Contributions to a Low Income Home Energy Assistance Fund Credit (46,743.99) 0925 Renewable Energy System Cost Recovery Credit (397,422.98) 444,166.97 Summary Section Amount Page 2 of 4Combined Excise Tax Retur 5 18 201file:///C:/Users/Rff9457/Desktop/DR%20Working%20Folder/07%20July%202015%20C ... Staff_DR_083 Attachment A Page 10 of 16 State Business and Occupation Tax Tota (16,380.13) State Sales and Use Tax Total 67,681.81 Local and Regional Tax Total 22,441.31 Lodging Tax Total 0.00 Public Utilities Tax Total 1,954,453.58 E911 Tax Total 0.00 Other Tax Total 5,178.31 SubTotal 2,033,374.88 Less Total Credits (444,166.97) Total 1,589,207.91 Amount Paid 1,589,207.91 Balance 0.00 Additional Information Confirmation Number 16168144 Date and Time Submitted 8/19/2015 2:30:21 PM Payment Type EFT Credit Total Amount Paid 1,589,207.91 Date Printed 8/19/2015 Tax Registration Number 328-000-223 Person Completing Return Catherine Cooper Phone Number (509)495-4885 E-Mail Address Catherine.Cooper@Avistacorp.com To initiate your payment, you must contact your financial institution. Each bank has its own guidelines for ACH transactions. ACH Credit taxpayers are responsible for contacting their own bank to ensure funds are deposited in the State's bank no later than 5:00 PM Pacific Time on August 26 2015. This is a copy for your records. Please DO NOT MAIL a copy to the Department of Revenue. Natural Gas Use Tax Section State Natural Gas Use Tax Volume Volume (in therms) 434,179 Tax Classification Taxable Amount Rate Tax Due Purchase Price 134,431.80 0.03852 5,178.31 Transportation Charge 0.00 0.03852 0.00 Total State Tax Due 5,178.31 Local City Natural Gas Use Tax Code Location Name Taxable Rate City Tax Due Previously Filed Amount Accumulated Threshold Page 3 of 4Combined Excise Tax Retur 5 18 201file:///C:/Users/Rff9457/Desktop/DR%20Working%20Folder/07%20July%202015%20C ... Staff_DR_083 Attachment A Page 11 of 16 Totals Tax Due 5,178.31 Less Credits 0.00 Natural Gas Use Tax Due 5,178.31 Renewable Energy Credit Line 1: Solar, Wind, Anaerobic Digester or Community Solar Project Credit Amount (Do Not Include Utility-Owned or Company-Owned Community Solar Projects)397,422.98 Line 2: Company-Owned Community Solar Project Credit Amount 0.00 Line 3: Utility-Owned Community Solar Project Credit Amount 0.00 Total Renewable Energy System Cost Recovery Credit Amount 397,422.98 Page 4 of 4Combined Excise Tax Retur 5 18 201file:///C:/Users/Rff9457/Desktop/DR%20Working%20Folder/07%20July%202015%20C ... Staff_DR_083 Attachment A Page 12 of 16 Washington State Department of Revenu State of Washingto Department of Revenue PO Box 47464 Olympia, WA 98504-7464 August 2015 Combined Excise Tax Return 328-000-223 AVISTA CORP State Business and Occupation Section Taxes Line Code Tax Classification Gross Amount Total Deductions Taxable Amount Rate Tax Due 0003 Wholesaling 141,065.76 0.00 141,065.76 0.00484 682.76 0004 Service and Other Activities; Gambling Contests of Chance (less than $50,000 a year) 370,129.94 0.00 370,129.94 0.0150 5,551.95 0002 Retailing 57,553.88 0.00 57,553.88 0.00471 271.08 568,749.58 0.00 568,749.58 6,505.79 State Sales and Use Section Taxes Line Code Tax Classification Gross Amount Total Deductions Taxable Amount Rate Tax Due 0001 Retail Sales 57,553.88 0.00 57,553.88 0.0650 3,741.00 0005 Use Tax 1,204,169.89 0.00 1,204,169.89 0.0650 78,271.04 1,261,723.77 0.00 1,261,723.77 82,012.04 Local Sales Section Line Code Location Code Location Name Taxable Amount Rate Tax Due 0045 0200 ASOTIN COUNTY 142.04 0.0120 1.70 0045 0202 CLARKSTON 142.04 0.0120 1.70 0045 3200 SPOKANE COUNTY 1,226.20 0.0160 19.62 0045 3202 CHENEY 110.00 0.0220 2.42 0045 3203 DEER PARK 133.40 0.0160 2.13 0045 3206 MEDICAL LAKE 125.00 0.0220 2.75 0045 3210 SPOKANE CITY 53,422.19 0.0220 1,175.29 0045 3212 LIBERTY LAKE 1,092.10 0.0220 24.03 0045 3213 SPOKANE VALLEY 372.00 0.0220 8.18 0045 3232 SPOKANE-PTBA 420.60 0.0220 9.25 0045 3302 COLVILLE 274.46 0.0110 3.02 0045 3800 WHITMAN COUNTY 93.85 0.0130 1.22 57,553.88 1,251.31 Local Use Section Page 1 of 4Combined Excise Tax Retur 5 18 201file:///C:/Users/Rff9457/Desktop/DR%20Working%20Folder/08%20August%202015%20... Staff_DR_083 Attachment A Page 13 of 16 Line Code Location Code Location Name Taxable Amount Rate Tax Due 0046 0202 CLARKSTON 72.00 0.0120 0.86 0046 2200 LINCOLN COUNTY 949.19 0.0120 11.39 0046 3200 SPOKANE COUNTY 16,055.72 0.0160 256.89 0046 3210 SPOKANE CITY 910,038.50 0.0220 20,020.85 0046 3213 SPOKANE VALLEY 234,674.87 0.0220 5,162.85 0046 3232 SPOKANE-PTBA 12,808.50 0.0220 281.79 0046 3300 STEVENS COUNTY 29,402.33 0.0110 323.43 0046 3800 WHITMAN COUNTY 168.78 0.0130 2.19 1,204,169.89 26,060.25 Public Utilities Section Taxes Line Code Tax Classification Gross Amount Total Deductions Taxable Amount Rate Tax Due 0049 Power 47,037,142.89 1,846,679.49 45,190,463.40 0.038734 1,750,407.41 0026 Gas Distribution-Telegraph 4,990,426.03 313,420.29 4,677,005.74 0.03852 180,158.26 52,027,568.92 2,160,099.78 49,867,469.14 1,930,565.67 Deductions Deduction Code Tax Classification Deduction Name Amount 004901 Power Bad Debts 1,846,679.49 002601 Gas Distribution-Telegraph Bad Debts 313,420.29 2,160,099.78 Other Tax Section Natural Gas Use Tax Line Code Tax Classification Taxable Amount Rate Tax Due 0121 Natural Gas Purchase Price 165,043.83 0.03852 6,357.49 165,043.83 6,357.49 Credit Section Code Document Number Credit Amount 0880 9995 Billing Discounts/Qualified Contributions to a Low Income Home Energy Assistance Fund Credit (303,018.82) 0925 Renewable Energy System Cost Recovery Credit (47,414.92) 350,433.74 Summary Section Amount State Business and Occupation Tax Total 6,505.79 State Sales and Use Tax Total 82,012.04 Local and Regional Tax Total 27,311.56 Lodging Tax Total 0.00 Public Utilities Tax Total 1,930,565.67 E911 Tax Total 0.00 Other Tax Total 6,357.49 SubTotal 2,052,752.55 Page 2 of 4Combined Excise Tax Retur 5 18 201file:///C:/Users/Rff9457/Desktop/DR%20Working%20Folder/08%20August%202015%20... Staff_DR_083 Attachment A Page 14 of 16 Less Total Credit (350,433.74) Total 1,702,318.81 Amount Paid 1,702,318.81 Balance 0.00 Additional Information Confirmation Number 16386162 Date and Time Submitted 9/23/2015 2:10:33 PM Payment Type EFT Credit Total Amount Paid 1,702,318.81 Date Printed 9/23/2015 Tax Registration Number 328-000-223 Person Completing Return Catherine Cooper Phone Number (509)495-4885 E-Mail Address Catherine.Cooper@Avistacorp.com To initiate your payment, you must contact your financial institution. Each bank has its own guidelines for ACH transactions. ACH Credit taxpayers are responsible for contacting their own bank to ensure funds are deposited in the State's bank no later than 5:00 PM Pacific Time on September 28 2015. This is a copy for your records. Please DO NOT MAIL a copy to the Department of Revenue. Natural Gas Use Tax Section State Natural Gas Use Tax Volume Volume (in therms) 528,890 Tax Classification Taxable Amount Rate Tax Due Purchase Price 165,043.83 0.03852 6,357.49 Transportation Charge 0.00 0.03852 0.00 Total State Tax Due 6,357.49 Local City Natural Gas Use Tax Code Location Name Taxable Rate City Tax Due Previously Filed Amount Accumulated Threshold Totals Page 3 of 4Combined Excise Tax Retur 5 18 201file:///C:/Users/Rff9457/Desktop/DR%20Working%20Folder/08%20August%202015%20... Staff_DR_083 Attachment A Page 15 of 16 Tax Due 6,357.4 Less Credits 0.00 Natural Gas Use Tax Due 6,357.49 Renewable Energy Credit Line 1: Solar, Wind, Anaerobic Digester or Community Solar Project Credit Amount (Do Not Include Utility-Owned or Company-Owned Community Solar Projects)47,414.92 Line 2: Company-Owned Community Solar Project Credit Amount 0.00 Line 3: Utility-Owned Community Solar Project Credit Amount 0.00 Total Renewable Energy System Cost Recovery Credit Amount 47,414.92 Page 4 of 4Combined Excise Tax Retur 5 18 201file:///C:/Users/Rff9457/Desktop/DR%20Working%20Folder/08%20August%202015%20... Staff_DR_083 Attachment A Page 16 of 16 Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/18/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: UTC Staff - White RESPONDER: Ryan Finesilver TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff - 083 TELEPHONE: (509) 495-4873 EMAIL: ryan.finesilver@avistacorp.com REQUEST: Please provide a copy of the company’s monthly excise tax returns for Sept. 2014; October 2014; July 2015; and August 2015. RESPONSE: Please see Staff_DR_083 Attachment A. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/18/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: UTC Staff - White RESPONDER: Ryan Finesilver TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff - 083 TELEPHONE: (509) 495-4873 EMAIL: ryan.finesilver@avistacorp.com REQUEST: Please provide a copy of the company’s monthly excise tax returns for Sept. 2014; October 2014; July 2015; and August 2015. RESPONSE: Please see Staff_DR_083 Attachment A. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/20/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: UTC Staff - White RESPONDER: Jeanne Pluth TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff - 084 TELEPHONE: (509) 495-2204 EMAIL: jeanne.pluth@avistacorp.com REQUEST: Re: Adjustment 2.07, Office Space Charges to Non-Utility The file 2016-Office Space Charged to NU, tab OSC-3, includes summed data for “expenditure organizations” ranging from A04 through Z89. Please provide a listing describing these organizations by title. Also, please provide the raw data being summed, in Excel format. Also referring to “expenditure organizations” as mentioned above, please provide the company policy that instructs staff on how to allocate their time to these organizations. RESPONSE: Please see Staff_DR_084-Attachment A for Organization descriptions. The raw data is provided with the electronic file Staff_DR_084 Attachment A. Please see Staff_DR_084-Attachment B for a memo that is sent semi-annually to all employees describing the Company’s policy on recording time to specific projects related to non-utility or to subsidiary activities. This memo directs employees to the Regulatory Accounting Guidelines, Policies, and Expense Coding Training that has been provided as Staff_DR_084-Attachment C. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/20/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: UTC Staff - White RESPONDER: Jeanne Pluth TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff - 084 TELEPHONE: (509) 495-2204 EMAIL: jeanne.pluth@avistacorp.com REQUEST: Re: Adjustment 2.07, Office Space Charges to Non-Utility The file 2016-Office Space Charged to NU, tab OSC-3, includes summed data for “expenditure organizations” ranging from A04 through Z89. Please provide a listing describing these organizations by title. Also, please provide the raw data being summed, in Excel format. Also referring to “expenditure organizations” as mentioned above, please provide the company policy that instructs staff on how to allocate their time to these organizations. RESPONSE: Please see Staff_DR_084-Attachment A for Organization descriptions. The raw data is provided with the electronic file Staff_DR_084 Attachment A. Please see Staff_DR_084-Attachment B for a memo that is sent semi-annually to all employees describing the Company’s policy on recording time to specific projects related to non-utility or to subsidiary activities. This memo directs employees to the Regulatory Accounting Guidelines, Policies, and Expense Coding Training that has been provided as Staff_DR_084-Attachment C. Staff_DR_084 Attachment B Page 1 of 3 Staff_DR_084 Attachment B Page 2 of 3 Staff_DR_084 Attachment B Page 3 of 3 March 25, 2011 Regulatory Accounting Guidelines, Policies, and Expense Coding Training 1 Staff_DR_084 Attachment C Page 1 of 57 Training Purpose: As a regulated utility operating in multiple services and states, it is important the Company maintain its books and records following proper accounting guidelines and policies. Costs should be charged to the appropriate service and jurisdiction, based on which customers benefit from the service provided. It is also necessary to properly account for costs to utility and non-utility accounts. The Company should be using its best efforts to assure that ratepayers are only paying for appropriate costs. Special attention should be paid to items such as: •Allocations / Direct assignment of costs •Political Activities •Advertising •Charitable Contributions, Donations & Sponsorships •Dues •Miscellaneous employee expenses 2 Staff_DR_084 Attachment C Page 2 of 57 Learning Objective: •Understand Regulatory Accounting Guidelines and Policies to accurately record and code expenses by: •Using FERC accounts accurately to identify and track costs •Properly allocating charges for service and jurisdiction •Charges should be directly assigned to a service or jurisdiction whenever possible. •Understanding “Above” vs. “Below the Line” •Understanding “Allowable” vs. “Non-Allowable” costs for rate making •These may be acceptable business expenses, but not allowable for ratemaking purposes, i.e., lobbying, promotional advertising, etc. 3 Staff_DR_084 Attachment C Page 3 of 57 Why does all this matter? It’s how our customer rates are determined! •Avista records its revenues, expenses and capital costs by coding various accounts that are either directly assigned or are allocated between services (electric, gas) and jurisdiction (WA, ID, OR). •The Rates Department then uses this information to determine the rates which are charged to our customers (WA-elec, WA-gas, ID-elec, ID-gas, OR-gas). •Therefore, where you record your costs is ultimately how we determine our customers’ rates. •By recording your costs accurately, Customers are only paying for costs to provide them safe and reliable service at reasonable rates. 4 Staff_DR_084 Attachment C Page 4 of 57 2010 WA Electric & Gas GRCs Dockets UE-100467/UG-100468, Order 07, Page 11 “The testimony supporting the Settlement explained that the Company’s original filing contained costs that were either incorrectly booked to utility accounts or booked to improper accounts.” “These errors were discovered through Public Counsel’s targeted audit. Although Public Counsel’s audit was limited to a small subset of accounting entries, it revealed several instances where ratepayers would have been inappropriately and unlawfully saddled with costs that must be borne by shareholders alone.” “It is not Public Counsel’s function to provide accounting oversight for the Company. Nor should Staff and the other parties be responsible for ensuring that Avista is complying with the law.” 5 Staff_DR_084 Attachment C Page 5 of 57 “We are concerned that a broader investigation will reveal many more such instances . . . ” “We are confident that the Company can, and will, do better.” “Given the attention to these matters, we expect that future filings will be free of blatant errors and accounting adjustments that are unquestionably improper.” 2010 WA Electric & Gas GRCs Dockets UE-100467/UG-100468, Order 07, Page 11 6 Staff_DR_084 Attachment C Page 6 of 57 Spokesman Review Article “Avista rate hikes approved with warning” Annual audits imposed to prevent more incorrect charges By Becky Kramer The Spokesman-Review November 20, 2010 “Washington regulators granted part of Avista’s request for higher rates Friday, but also said the electric and natural gas utility must conduct annual expense audits to make sure that ratepayers aren’t illegally saddled with costs that should be borne by shareholders.” 7 Staff_DR_084 Attachment C Page 7 of 57 Spokesman Review Article, continued : “The action came after an audit by the state attorney general’s office, which found that Avista had billed utility customers for $38,000 in expenses that the company’s shareholders should have paid.” Items included: First-class travel for the board of directors; Employee gifts and entertainment at a sporting event; Dues and fees to civic organizations; Charitable contributions; Advertising to improve Avista’s corporate image 8 Staff_DR_084 Attachment C Page 8 of 57 Regulations and State Administrative Codes and Rules: Avista Utilities as a regulated utility in the states of Washington, Idaho and Oregon must maintain its books and records in accordance with Generally Accepted Accounting Principles (GAAP) and Federal and State regulatory requirements. The Company must follow these principles and requirements to ensure costs for electric and natural gas services are fair, just, reasonable and sufficient for the utility and its customers. 9 Staff_DR_084 Attachment C Page 9 of 57 Regulations and State Administrative Codes and Rules: Use of Uniform System Chart of Accounts -FERC Chart of Accounts Washington -WAC 480-100-203 –Electric / WAC 480-90-203 -Gas Idaho -IDAPA 31.12.01.101 –Electric / IDAPA 31.12.01.102 -Gas Oregon -OAR 860-027-0045 –Electric / OAR 860-027-0055 –Gas Political or legislative activities expenditures Washington -WAC 480-100-213/480-90-213 Promotional/Image Advertising Washington -WAC 480-100-223/480-090-223 Oregon -OAR 860-026-0022 10 Staff_DR_084 Attachment C Page 10 of 57 Regulations and State Administrative Codes and Rules: Affiliated Interest Reporting Washington -RCW 80.16.020 and WAC 480-90-245 Oregon -ORS 757.495 and OAR 860-027-0040 Sale or Transfer of Utility Property Washington -WAC 480-100-248–Electric / WAC 480-090-248 –Gas Washington -WAC 480-143-180 -Disposal and determination of necessary or useful property. Oregon -OAR 860-027-0025 Idaho –IDAPA 31.61.03.328 11 Staff_DR_084 Attachment C Page 11 of 57 Regulations and State Administrative Codes and Rules: Affiliated Interest Reporting Requirements The Company is subject to certain state regulatory reporting requirements relating to the existence of contracts and/or the provision of services between Avista Corp. (the Utility) and any Company Affiliate/Subsidiary. Covered Activities The activities between Avista Corp. (Utility) and any Affiliate/Subsidiary which are covered by the reporting requirements include: Entering into or modification of contracts. Provision of services. Sale, lease or transfer of property (i.e. land, buildings, equipment, etc.) Covered Activities do not include activities between subsidiaries where Avista Corp. (Utility) is not involved. 12 Staff_DR_084 Attachment C Page 12 of 57 Regulations and State Administrative Codes and Rules: Affiliated Interest Reporting Requirements -Washington Regulatory Reporting Requirements Washington Utilities and Transportation Commission (WUTC): 1.File Annual Affiliate or Subsidiary Interest Report (May 30 electric / April 30 natural gas); 2.File contracts or arrangements with affiliates (written or unwritten) prior to the effective date of the contract or arrangement. Modifications or amendments must also be submitted prior to the effective date of the modification or amendment. The WUTC may institute an investigation and disapprove the contract or arrangement if the Commission finds the Utility has failed to prove that the contract or arrangement is reasonable and consistent with the public interest. 3.The Washington Commissions’ reporting requirements provide that all activity, whether written or unwritten, must be included in the annual report regardless of price or activity. 13 Staff_DR_084 Attachment C Page 13 of 57 Regulations and State Administrative Codes and Rules: Affiliated Interest Reporting Requirements –Oregon Regulatory Reporting Requirements Oregon Public Utilities Commission (OPUC): 1.File Annual Affiliated Interest Report (June 1); 2.File contracts between the Utility and any Affiliate / Subsidiary within 90 days of execution. 3.The Oregon Commissions’ reporting requirements provide that all activity, whether written or unwritten, must be included in the annual report regardless of price or activity. To report activities or questions regarding affiliate/subsidiary activities, please contact: Jeanne Pluth, Senior Regulatory Analyst, 509-495-2204, jeanne.pluth@avistacorp.com 14 Staff_DR_084 Attachment C Page 14 of 57 Regulations and State Administrative Codes and Rules: Sale or Transfer of Property –WA, ID, OR Before selling, leasing, or assigning any of its property or facilities which are necessary or useful in the performance of its duties to the public, or before acquiring property or facilities of another public utility, an electric/gas utility must obtain from the commission an order authorizing such transaction. •Avista must file an applications with the Commissions requesting approval for any sale, lease, etc, of Utility property prior to the Sale or Transfer of the property. •A minimum of 60 days notice is necessary in order to file and receive authorization from the commissions. •Note: In the state of Oregon, any net gain from the sale of Utility property is applied against the unamortized Oregon acquisition adjustment. To report activities or questions regarding the Sale or Transfer of Property, please contact: Karen Schuh, Regulatory Analyst, 509-495-2293, Karen.schuh@avistacorp.com 15 Staff_DR_084 Attachment C Page 15 of 57 Commission and Company Approved Guidelines: Company Regulatory Accounting Allocation Guidelines All utility operating costs should be directly assigned to services and jurisdictions whenever possible.For costs that are not directly assigned (common costs), a common service and/or jurisdiction may be used that will then be allocated. Employees serving in corporate functions typically record their labor and expenses to projects that are common to all rate jurisdictions (projects which begin with “099”) if it has been determined that their functions or responsibilities benefit all rate jurisdictions.There are instances when a corporate employee will incur costs (travel for instance) specific to a particular locale.If the employee and their manager deem these costs to be related to service in all jurisdictions, then these costs may be charged to a project which allocates costs to all jurisdictions.If it is deemed that these costs are for the sole benefit of a particular service and/or jurisdiction, then these costs should be directly assigned.16 Staff_DR_084 Attachment C Page 16 of 57 Projects and Tasks 17 Staff_DR_084 Attachment C Page 17 of 57 Understanding where items are charged Project Accumulates Costs First 3 digits equate to service and jurisdiction Task Equivalent to FERC Above the line 920-935 Below the Line 417-426 Sources of Information Budget Manual FERC CFR Corporate Acct Project Acct Rates 18 Staff_DR_084 Attachment C Page 18 of 57 POET -Project, Organization, Expenditure Type, Task •Project Number -divided in two parts; locations and project number. •The first three digits of the project number represent the location of the work or service. •The last five digits are a unique set of numbers assigned to a project. •A service and jurisdiction are automatically assigned via the project code. 19 Staff_DR_084 Attachment C Page 19 of 57 Service When using POET to record expenditures, Service is associated with the Project Number. The service code is intended to mean “method of assignment to electric and/or gas services”. The values that will be used for this code are: Service Code Description ED (Electric Direct)Directly assigned to Electric Service GD (Gas Direct)Directly assigned to Gas Service CD (Common Direct)Common to both Electric and Gas Services ZZ (Non-Utility)Not associated with a Service (Non-Utility) 20 Staff_DR_084 Attachment C Page 20 of 57 Jurisdiction When using POET to record expenditures, Jurisdiction is associated with the Project Number. The first three digits of a project code dictate the service and jurisdiction a project is associated. Below are commonly used Administrative & General location codes: Location Jurisdiction Description Explanation •028 WA Washington Directly assigned to Washington •038 ID Idaho Directly assigned to Idaho •048 MT Montana Directly assigned to Montana •068 OR Oregon Gas Directly assigned to Oregon •098 AN Common WA/ID Common to Washington and Idaho •099 AA Common WA/ID/OR Common to all States •777 ZZ Non Utility Not associated with a Jurisdiction 21 Staff_DR_084 Attachment C Page 21 of 57 Project / Task Examples POET Entry General Ledger Project Org Exp Type Task FERC Service Jurisdiction 09800160 XXX XXX 561010 =561000 ED AN 09800160 XXX XXX 561020 =561000 ED AN 03800510 XXX XXX 588000 =588000 ED ID 03802046 XXX XXX 893010 =893000 GD ID 09900013 XXX XXX 930200 =930200 CD AA 09900542 XXX XXX 813000 =813000 GD AA Selection of Project / Task drive the allocation of charges in the general ledger. 22 Staff_DR_084 Attachment C Page 22 of 57 Service / JurisdictionAllocation Example 1 Project 09900013 09900542 2 Service / Jurisdiction CD / AA GD /AA 3 Invoice Amount $ 100.00 $ 100.00 Allocation for Rate Making: 4 Washington: 5 Electric $ 48.06 $ - 6 Gas 13.35 48.36 7 $ 61.41 $ 48.36 8 Idaho: 9 Electric $ 24.33 $ - 10 Gas 6.13 22.22 11 $ 30.46 $ 22.22 12 Oregon $ 8.13 $ 29.42 NOTE: This is a system allocation, Not to be manually computed by the employee.23 Staff_DR_084 Attachment C Page 23 of 57 Project / Task Data in Discoverer 24 Staff_DR_084 Attachment C Page 24 of 57 Project / Task Data in Discoverer After selecting the Project- Task Setup report you will be prompted with the following screen. You can either type in a specific project number to look up the corresponding Service and Jurisdiction. OR You can type in “%” which will provide you with a listing of all project numbers that currently exist. 25 Staff_DR_084 Attachment C Page 25 of 57 Project / Task Data in Discoverer 26 This screen shot displays the search for project number 09900010. Staff_DR_084 Attachment C Page 26 of 57 Tasks / FERC Account Tasks: Used to break-down costs into further detail Task Breakdown Digits 1-3 (sometimes 4) = FERC Digits 4-6 = Sub accounts Tasks 300XXX (Design & Engineering) is an exception to the rule. It is for common engineering costs and they are assigned directly to Construction Work in Progress, or FERC Account 107000. FERC Accounts: Account codes with the associated meanings are defined by the FERC and used by all regulated utilities for consistency across the utility industry. 27 Staff_DR_084 Attachment C Page 27 of 57 TASK / FERC …. Sub Accounts FERC 903.2 Task 903200 Task 903205 Task 903210 28 Staff_DR_084 Attachment C Page 28 of 57 FERC Accounts •Administrative and General FERC Accounts: (920-935) 920 –A&G Salaries 921 –Office Supplies & exp 923 –Outside services employed 924 –Property Insurance 925 –Injuries & damages 926-Employee Pensions & Benefits 928 –Regulatory commission exp 931 –Rents 930 –Misc. general exp (930.1 –Advertising; 930.2 –Misc.) 935 –Maintenance on general plant •Non -Utility Accounts: 417.1 –Expenses for non-utility 426.1 –Donations 426.3 –Penalties 426.4 –Certain civic, political, & related 426.5 –Other Miscellaneous 29 Staff_DR_084 Attachment C Page 29 of 57 Accurate Invoice and Expense Report Completion and Review Use concise / accurate descriptions of what the invoice / charge is for. Single invoices may have multiple project / task combinations to appropriately allocate charges.30 Staff_DR_084 Attachment C Page 30 of 57 I Expense Report Example 31 Staff_DR_084 Attachment C Page 31 of 57 Utility or Non-Utility •Above the Line •Benefit to Customers •Recovered from RatepayersUtility •Below the Line •Legitimate business expense, with no benefit to customers •NOT recovered from Ratepayers Non- Utility 32 Staff_DR_084 Attachment C Page 32 of 57 Non-Utility Charges Political Activities: WAC 480-90-213/ 480-100-213 Expenditures for political or legislative activities. (1) The commission will not allow either direct or indirect expenditures for political or legislative activities for rate- making purposes. (2) For purposes of this rule, political or legislative activities include, but are not limited to: (a) Encouraging support or opposition to ballot measures, legislation, candidates for a public office, or current public office holders; (b) Soliciting support for or contributing to political action committees; (c) Gathering data for mailing lists that are generated for the purposes of encouraging support for or opposition to ballot measures, legislation, candidates for public office, or current office holders, or encouraging support for or contributions to political action committees; (d) Soliciting contributions or recruiting volunteers to assist in the activities set forth in (a) through (c) of this subsection. (3) Political or legislative activities do not include activities directly related to appearances before regulatory or local governmental bodies necessary for the utility's operations. Note: Lobbying portion of an organization’s dues or memberships should be charged to 77700300 426400 with your ORG. This accounting treatment is used because these costs are not recoverable for ratemaking purposes and are charged as Miscellaneous Income Deductions. FERC Account 426.400 33 Staff_DR_084 Attachment C Page 33 of 57 Advertising WAC 480-90-223/480-100-223 (1) The commission will not allow expenses for promotional or political advertising for rate-making purposes. The term "promotional advertising" means advertising to encourage any person or business to select or use the service or additional services of a gas utility, to select or install any appliance or equipment designed to use the gas utility's service, or to influence consumers' opinions of the gas utility. The term "political advertising" means any advertising for the purpose of influencing public opinion with respect to legislative, administrative, or electoral matters, or with respect to any controversial issue of public importance. (2) As used in this section the terms "promotional advertising" and "political advertising" do not include: (a) Advertising which informs customers how to conserve energy or how to reduce peak demand for energy; (b) Advertising required by law or by regulation, including advertising under Part 1 of Title II, of the National Energy Conservation Policy Act; (c) Advertising regarding service interruptions, safety measures, or emergency conditions; (d) Advertising concerning employment opportunities with the gas utility; (e) Advertising which promotes the use of energy efficient appliances, equipment, or services; (f) Announcements or explanations of existing or proposed tariffs or rate schedules; and (g) Notices of meetings or commission hearings concerning gas utility rates and tariffs. Promotional/Image Advertising –Non-Utility 34 Staff_DR_084 Attachment C Page 34 of 57 Non-Utility Charges Charitable Contributions, Donations & Sponsorships FERC Account 426.1: “This account shall include all payments or donations for charitable, social or community welfare purposes” Corporate contributions provide financial support to organizations and activities benefiting the various communities served by the Company, while supporting business initiatives and fostering relationships with key stakeholders. The costs for these activities are charged “Below the Line”. In order to accurately report the types of contributions made, project numbers have been established for each contribution category, and contributions should be charged to one of the POET (Project, Organization, Expenditure Type, and Task) codes noted below. 35 Staff_DR_084 Attachment C Page 35 of 57 Charitable Contributions and Donations Project Organization Expenditure Type Task Task Description 77700300 825 -Donations 426110 Dues/Donations 77700300 825 -Donations 426115 Arts, Culture, Humanities 77700300 825 -Donations 426120 Economic/Community Development 77700300 825 -Donations 426121 Avista Foundation 77700300 825 -Donations 426122 Project Share 77700300 825 -Donations 426125 Education 77700300 825 -Donations 426130 Environmental 77700300 825 -Donations 426135 Youth Development 77700300 825 -Donations 426140 Health & Human Service 77700300 825 -Donations 426400 Political Expenditures Non-Utility Charges 36 Staff_DR_084 Attachment C Page 36 of 57 Sponsorships The Company provides contributions to organizations in the form of sponsorships. These contributions should be coded in the same manner as cash donations, unless there is a specific benefit to utility customers derived from the cost. Sporting event sponsorships are considered part of marketing and brand identity efforts and should not be coded as a corporate donation. These charges should be charged to the POET (Project, Organization, Expenditure Type, and Task) code noted below: Project Organization Expenditure Type Task Task Description 77700300 826 -Sponsorships 426XXX (any of those listed above) 77700300 826 -Sponsorships 426XXX (any of those listed above) Non-Utility Charges 37 Staff_DR_084 Attachment C Page 37 of 57 Dues and Fees: Corporate Dues Corporate dues / memberships are typically paid to industry organizations that are of a national or regional nature, e.g. Edison Electric Institute (EEI), American Gas Association (AGA), Western Electric Power Institute, etc, which provide benefit to the Utility and its customers because they focus on the issues facing the energy industry. These charges should be coded to the following: Project Organization Expenditure Type Task Task Description 09800310 (Electric)830 -Dues 930200 09900310 (Gas)830 -Dues 930200 Note: Lobbying portion of an organization’s dues or memberships should be charged to 77700300 426400 with your ORG. This accounting treatment is used because these costs are not recoverable for ratemaking purposes and are charged as Miscellaneous Income Deductions.38 Staff_DR_084 Attachment C Page 38 of 57 39 Staff_DR_084 Attachment C Page 39 of 57 Dues and Fees: Other Dues Employees are encouraged to participate in professional and community organizations that are related to utility operations. Dues in such organizations should be charged to Utility expense when participation in these types of activities are considered a part of an employee’s job responsibilities and will provide benefits to the Company’s customers. 40 Staff_DR_084 Attachment C Page 40 of 57 Dues and Fees: Other Dues, continued Professional Organizations: Employee dues for individual memberships in professional organizations should be charged to appropriate expense distributions related to each employee’s job responsibility. If you charge A&G and you support operations, the charges should be charged to one of the following: Project Organization Expenditure Type Task Task Description 02800162 -Admin Activities-WA Common 830 -Dues 921000 03800162 -Gas Ops Admin Activity -Idaho 830 -Dues 921000 06800161 -Gas Oregon Admin Activity 830 -Dues 921000 09800162 -Elect Admin Activity -A and G 830 -Dues 921000 09800163 -Admin Activities-Common WA ID 830 -Dues 921000 09800166 -Gas Ops No Admin Activity-Admin 830 -Dues 921000 09900160 -Gas Ops Admin Activity -Admin 830 -Dues 921000 09900162 -Admin Activities-Common to All 830 -Dues 921000 41 Staff_DR_084 Attachment C Page 41 of 57 Dues and Fees: Other Dues, continued, Community and Civic Organizations: Company or employee dues for memberships in community organizations that provide a benefit to both the Company and to customers should be charged 50% to the Utility (Above the Line) and 50% to Non-Utility (Below the line). Organizations that fall into this category include organizations that provide Avista employees an opportunity to meet with Avista customers that otherwise may be inaccessible to them. These opportunities provide Avista the opportunity to educate its customers on Utility issues such as energy efficiency, customer assistance programs available, rate activity, etc. and to listen to customer concerns. However, this is not the sole purpose of these organizations, and therefore a sharing is appropriate. Examples include Chamber of Commerce, Rotary, Lions Club, etc. 42 Staff_DR_084 Attachment C Page 42 of 57 Dues and Fees: Community and Civic Organizations, continued Dues that are to be allocated Utility/Non-Utility should be charged 50% using one of the POET codes noted above, which are charged to the Utility, and the remaining 50% should be charged to the POET code noted below which is charged to Non-Utility. Project Organization Expenditure Type Task Task Description 77700300 830 -Dues 426120 Econ/Comm Devlp 43 Staff_DR_084 Attachment C Page 43 of 57 Dues and Fees Trade or Industry Dues for Company 100% Charge to Utility FERC Account 930.2* i.e. –EEI, AGA, WEI Trade or Professional Dues for Employee 100% Charged to Utility FERC Account 921* A&G or 500-800** i.e. –AICPA, CPA, WSBA Community / Civic / Other Dues If participation provides an opportunity to educate or interact with customers on utility issues. Record: 50% -Utility -FERC Acct 921000 And 50% -Non Utility -FERC Acct 426120 If participation provides no opportunity to educate or interact with customers on utility issues. Record: 100% -Non Utility -FERC Acct 426120 i.e. –Chamber of Commerce, Rotary, Lions Club 44 In all instances, all charges for these dues must be approved by the appropriate manager. * Lobbying portion of an organization’s dues or memberships should be charged to 77700300 426400 with your ORG. ** Professional certifications for electric and gas technical areas are recorded in operation and maintenance FERC accounts, i.e. 880 gas, 588 electric. Staff_DR_084 Attachment C Page 44 of 57 Invoice Examples –Charitable/Civic Dues 45 50/50 Spokane Chamber Dues Staff_DR_084 Attachment C Page 45 of 57 Below the Line Charges –Non-Utility Related Expenses: Employee Miscellaneous Expenses Employee Gifts awarded to an employee as an award for performance purposes may be charged to the Utility (Above the Line). All other Employee Gifts must be charged to Non Utility (below the line FERC Account 426). Examples include holiday gifts, birthday gifts, floral arrangements, etc. However, in all instances, all charges for Employee Gifts must be approved by the appropriate manager. Project Organization Expenditure Type Task Task Description 77705191 235 –Miscellaneous Employee Expenses 426502 426506 Employee Gifts Employee Parties 46 Staff_DR_084 Attachment C Page 46 of 57 Employee Entertainment/Sporting Events Charges for employee entertainment or attendance at sporting events must be charged to Non Utility (below the line FERC Account 426). In all instances, all charges for employee entertainment or attendance to sporting events must be approved by the appropriate manager. These charges should be charged to the following POET: Project Organization Expenditure Type Task Task Description 77705191 235 –Miscellaneous Employee Expenses 426504 Employee Entertainment/Sporting Events 47 Below the Line Charges –Non-Utility Related Expenses: Staff_DR_084 Attachment C Page 47 of 57 Corporate Logo Apparel and Items Charges for corporate logo apparel and items should be charged to the Utility when the purpose of the item is to identify an employee as a representative of the Company, remind customers or employees of the importance of safety, or educate customers or employees on energy related issues such as energy efficiency or other issues impacting the Utility. These charges would follow the project for which it relates. All other corporate logo apparel and items, i.e. give-away items or gifts, which do not meet the above criteria, must be charged to Non Utility (Below the Line) FERC Account 426 and the following POET:Project Organization Expenditure Type Task Task Description 77705191 235 –Miscellaneous Employee Expenses 426508 Corporate Logo Apparel and Items 48 Below the Line Charges –Non-Utility Related Expenses: Staff_DR_084 Attachment C Page 48 of 57 Community Boards and Volunteering The Company encourages employees to give back to the community and endorses participation on Community Boards and other volunteering activities. Any incremental costs of participation, should be charged “Below the Line”, unless there is a specific benefit to utility customers derived from the cost. All charges must be approved by the appropriate manager. 49 Below the Line Charges –Non-Utility Related Expenses: Staff_DR_084 Attachment C Page 49 of 57 Community Boards and Volunteering, continued In order to accurately report these transactions, project numbers have been established for several types of involvement and should be charged to one of the POET codes noted below. Project Organization Expenditure Type Task Task Description 77700300 235 -Employee Misc Expense 426110 Dues/Donations 77700300 235 -Employee Misc Expense 426115 Arts, Culture, Humanities 77700300 235 -Employee Misc Expense 426120 Economic/Community Development 77700300 235 -Employee Misc Expense 426121 Avista Foundation 77700300 235 -Employee Misc Expense 426122 Project Share 77700300 235 -Employee Misc Expense 426125 Education 77700300 235 -Employee Misc Expense 426130 Environmental 77700300 235 -Employee Misc Expense 426135 Youth Development 77700300 235 -Employee Misc Expense 426140 Health & Human Service Note: In-Kind Contributions –All incremental expenses associated with volunteer activities should be recorded to a Non-Utility POET listed above. Direct labor costs which are more than incidental and on a recurring basis, must also be recorded to a Non-Utility POET. For example, if you are a loaned employee or executive, your time must be recorded Below the Line. For any questions regarding in kind contributions of labor, please contact Adam Munson, Manager Corporate Accounting. 50 Below the Line Charges –Non-Utility Related Expenses: Staff_DR_084 Attachment C Page 50 of 57 References •Code of Federal Regulation Website •Federal Energy Regulatory Commission (FERC) Website •Washington Utilities and Transportation Commission (WUTC) Website •Oregon Public Utilities Commission (OPUC) Website •Idaho Public Utilities Commission (IPUC) Website •AVAnet •Regulatory Accounting Guidelines and Policies •Budget Manual •Travel and Expense Reimbursement Guidelines •Project –Task Listing •Budget Contacts 51 Staff_DR_084 Attachment C Page 51 of 57 For questions regarding Projects: For assistance in determining which project number to record an expense to, please refer to your Budget Contact. A listing of all Budget contacts assigned to specific Orgs, are listed on the Budget website. 52 Staff_DR_084 Attachment C Page 52 of 57 For questions regarding Projects: A listing of all Projects is also available on the Budget website. For assistance in setting up a new project number, please contact: Howard Grimsrud, Operations Analyst, at 509-495-2936 or Howard.grimsrud@avistacorp.com 53 Staff_DR_084 Attachment C Page 53 of 57 Questions? 54 Staff_DR_084 Attachment C Page 54 of 57 For Questions Regarding Policies and Guidelines: For questions regarding Policies and Guidelines, please contact: Adam Munson, Manager Corporate Accounting, at 509-495-2471 or Adam.munson@avistacorp.com Liz Andrews, Manager State and Federal Regulation, at 509-495-8601 or Liz.Andrew@avistacorp.com Jen Smith, State and Federal Regulatory Analyst, at 509-495-2098 or Jennifer.Smith@avistacorp.com 55 Staff_DR_084 Attachment C Page 55 of 57 SUMMARY Main message points we want you to leave with . . . . . •Customers should bear the costs for that from which they receive benefit. •To achieve that, employees must: •Directly assign where appropriate, or allocate when services provided are shared by service, jurisdiction, or both. •Charge costs to Non-Utility when appropriate, based on Company Regulatory Accounting Guidelines and Policies. 56 Staff_DR_084 Attachment C Page 56 of 57 Housekeeping •Sign-in Form •Time Card -project # 09905519 has been assigned to the Training on invoice coding and charging payroll job, use task # 920000 •Expenses -project # 09905519 has been assigned to the Training on invoice coding and charging an expenses, use task # 926100 •The Training presentations and policies will be available on the AVAnet soon! 57 Staff_DR_084 Attachment C Page 57 of 57 Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/20/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: UTC Staff - White RESPONDER: Jeanne Pluth TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff - 085 TELEPHONE: (509) 495-2204 EMAIL: jeanne.pluth@avistacorp.com REQUEST: Re: Adjustment 2.07, Office Space Charges to Non-Utility The file 2016-Office Space Charged to NU, tab OSC-2, cells C13 and C25 contain the following note: “Jen Buss: Per email dated 02/01/2012, from Jason Hunnel”. This email apparently establishes office space square footages for standard and executive office spaces. Please provide a copy of this email. RESPONSE: The email is not readily available and is stored in electronic archives. However, the information that was attached to the email is provided in Staff_DR_085-Attachment A. This attachment also provides data that was requested in Staff_DR_086. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/20/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: UTC Staff - White RESPONDER: Jeanne Pluth TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff - 085 TELEPHONE: (509) 495-2204 EMAIL: jeanne.pluth@avistacorp.com REQUEST: Re: Adjustment 2.07, Office Space Charges to Non-Utility The file 2016-Office Space Charged to NU, tab OSC-2, cells C13 and C25 contain the following note: “Jen Buss: Per email dated 02/01/2012, from Jason Hunnel”. This email apparently establishes office space square footages for standard and executive office spaces. Please provide a copy of this email. RESPONSE: The email is not readily available and is stored in electronic archives. However, the information that was attached to the email is provided in Staff_DR_085-Attachment A. This attachment also provides data that was requested in Staff_DR_086. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/20/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: UTC Staff - White RESPONDER: Jeanne Pluth TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff - 086 TELEPHONE: (509) 495-2204 EMAIL: jeanne.pluth@avistacorp.com REQUEST: Re: Adjustment 2.07, Office Space Charges to Non-Utility The file 2016-Office Space Charged to NU, tab OSC-2, cells C14 and C26 state that Office Space Cost / per sq ft. is $27.99. A footnote on that tab states lists various costs that are included. Please provide the calculation establishing this per-square-foot cost. Also, referring to the file 2016-Office Space Charged to NU, tab OSC-2, cells C15 and C27 establish annual costs per workstation of $3,765 and $5,019 for “standard” and “executive” workstations. A footnote on that tab states that the “approximate annual incremental costs for laptop, phone, cell phone, monitor, mouse and keyboard is $3,765 per workstation.” Which figure is correct, $3,765 or $5,019? Please provide the calculation establishing this annual cost. RESPONSE: Please see the Company’s response to Staff_DR_085-Attachment A. This spreadsheet includes the costs that establishes $27.99 per square foot. The spreadsheet also details the average workstation cost for both non-executive (standard) and executive workstations. Both figures are correct, $3,765 is used for non-executive (standard), and $5,019 is used for executive costs per workstation. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/20/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: UTC Staff - White RESPONDER: Jeanne Pluth TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff - 086 TELEPHONE: (509) 495-2204 EMAIL: jeanne.pluth@avistacorp.com REQUEST: Re: Adjustment 2.07, Office Space Charges to Non-Utility The file 2016-Office Space Charged to NU, tab OSC-2, cells C14 and C26 state that Office Space Cost / per sq ft. is $27.99. A footnote on that tab states lists various costs that are included. Please provide the calculation establishing this per-square-foot cost. Also, referring to the file 2016-Office Space Charged to NU, tab OSC-2, cells C15 and C27 establish annual costs per workstation of $3,765 and $5,019 for “standard” and “executive” workstations. A footnote on that tab states that the “approximate annual incremental costs for laptop, phone, cell phone, monitor, mouse and keyboard is $3,765 per workstation.” Which figure is correct, $3,765 or $5,019? Please provide the calculation establishing this annual cost. RESPONSE: Please see the Company’s response to Staff_DR_085-Attachment A. This spreadsheet includes the costs that establishes $27.99 per square foot. The spreadsheet also details the average workstation cost for both non-executive (standard) and executive workstations. Both figures are correct, $3,765 is used for non-executive (standard), and $5,019 is used for executive costs per workstation. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/20/2016 CASE NO: UE-160228 & UG-160229 WITNESS: Elizabeth Andrews REQUESTER: Staff - Hancock RESPONDER: Joe Miller TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff – 087 TELEPHONE: (509) 495-4546 EMAIL: joe.miller@avistacorp.com REQUEST: In Staff Data Request 32, the Company provided the figures produced by its Load Forecast model for estimated annual customer bills, therms, and kilowatt-hours, as well as the corresponding actual figures, from 2011 through 2015. Please provide explanations for the substantial deviations between estimates and actual results for the following items: • Schedule 131/132 therms for 2012 and 2013; • Schedule 131/132 annual bills for 2013; • Schedule 121/122 therms for 2012 and 2013. RESPONSE: For 2012, the deviation was due to an inaccurate assumption as to how the overall forecasted load should be applied to the individual rate schedules. In particular, the assumption over-allocated usage to Schedules 131/132 and under-allocated usage to Schedule 121/122. As for 2013, actuals came in higher for Schedule 131/132 due to a customer who switched from rate schedule 121 to rate schedule 132 at the end of 2012. This increased the number of customers on Schedule 132 from one customer to two customers and essentially doubled the load on Schedule 132. The schedule shifting occurred after the forecast for 2013 was completed, therefore resulting in a deviation between the forecasted and actual results. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/20/2016 CASE NO: UE-160228 & UG-160229 WITNESS: Elizabeth Andrews REQUESTER: Staff - Hancock RESPONDER: Joe Miller TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff – 087 TELEPHONE: (509) 495-4546 EMAIL: joe.miller@avistacorp.com REQUEST: In Staff Data Request 32, the Company provided the figures produced by its Load Forecast model for estimated annual customer bills, therms, and kilowatt-hours, as well as the corresponding actual figures, from 2011 through 2015. Please provide explanations for the substantial deviations between estimates and actual results for the following items: • Schedule 131/132 therms for 2012 and 2013; • Schedule 131/132 annual bills for 2013; • Schedule 121/122 therms for 2012 and 2013. RESPONSE: For 2012, the deviation was due to an inaccurate assumption as to how the overall forecasted load should be applied to the individual rate schedules. In particular, the assumption over-allocated usage to Schedules 131/132 and under-allocated usage to Schedule 121/122. As for 2013, actuals came in higher for Schedule 131/132 due to a customer who switched from rate schedule 121 to rate schedule 132 at the end of 2012. This increased the number of customers on Schedule 132 from one customer to two customers and essentially doubled the load on Schedule 132. The schedule shifting occurred after the forecast for 2013 was completed, therefore resulting in a deviation between the forecasted and actual results. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/18/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: UTC Staff - Huang RESPONDER: Ryan Finesilver TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff - 088 TELEPHONE: (509) 495-4873 EMAIL: ryan.finesilver@avistacorp.com REQUEST: Referring to Smith’s Workpaper “1) 2016 O&M Offsets E-OFF.xlsx”, only the O & M offsets for two plant additions were provided: $229,000 for Downtown Network New Warehouse/Ops Bldg and $103,000 for COF Long-Term Restructuring Plan. Please provide the O&M Offsets for all other capital additions proposed by Avista in 2016? RESPONSE: The Company included O&M Offset data for projects that were included in its Pro Forma Study and therefore, only those items are proposed in Avista’s request. Of the projects included in the Company’s Pro Forma Capital adjustment, only two items were identified as having offsets to O&M. Those two projects have been included in the Company’s 2016 O&M Offsets-E-OFF.xlsx workpaper. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/18/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: UTC Staff - Huang RESPONDER: Ryan Finesilver TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff - 088 TELEPHONE: (509) 495-4873 EMAIL: ryan.finesilver@avistacorp.com REQUEST: Referring to Smith’s Workpaper “1) 2016 O&M Offsets E-OFF.xlsx”, only the O & M offsets for two plant additions were provided: $229,000 for Downtown Network New Warehouse/Ops Bldg and $103,000 for COF Long-Term Restructuring Plan. Please provide the O&M Offsets for all other capital additions proposed by Avista in 2016? RESPONSE: The Company included O&M Offset data for projects that were included in its Pro Forma Study and therefore, only those items are proposed in Avista’s request. Of the projects included in the Company’s Pro Forma Capital adjustment, only two items were identified as having offsets to O&M. Those two projects have been included in the Company’s 2016 O&M Offsets-E-OFF.xlsx workpaper. 1 Finesilver, Ryan From:Ruppert, Vance Sent:Wednesday, December 30, 2015 4:18 PM To:Finesilver, Ryan Cc:Bowles, Eric Subject:RE: Vance - OM Offsets 2016 Attachments:REVISED Vance - OM Offsets 2016.docx; 15.1230 O-M Calcs (2).docx Hey Ryan, yep definitely some updates for you! See attached revised sheet. Namely, some projects that were meant to finish this year did not, or was pushed by the Capital Budget Group to a different year. Also, we had two new major drop in projects mid‐year that is slated to finish 2016, the Downtown Network Ops Bldg and the Downtown Office Bldg. I also attached my updated calculations for your review, if you want to see the “story behind the numbers.” Thanks, hope this helps! Vance Ruppert AIA ‐ LEED AP O+M Project Manager ‐ Facilities P 509.495.2235 | C 509.315.7056 www.avistautilities.com From: Finesilver, Ryan Sent: Tuesday, December 22, 2015 11:07 AM To: Ruppert, Vance Subject: Vance ‐ OM Offsets 2016 Hi Vance – It’s that time again to look at the offsets. Please take a look at the attached and provide any updates. Thank you, Ryan Finesilver Regulatory Analyst 1411 E Mission MSC-27 Spokane, WA 99202 P 509.495.4873 http://www.avistautilities.com Staff_DR_089 Attcahment A Page 1 of 2 Central Operating Facility (Mission Campus) Long-Term Restructuring Plan Savings are gained due to line trucks and employees not having to travel and off-load waste maters that are recyclable or hazardous. Savings are $43,000 in 2015 on a system level.  Any additional savings increment for 2017 or 2018?  O&M amounts: o 2015 - $24K + $19K = $43K (offsets delayed to 2016 due to project delays) o 2016 - $24K + $19K +$60K = $103K o 2017 and beyond – the same $103K yearly Downtown Network New Warehouse/Ops Bldg This is for the Downtown Network crews that are currently scattered at several different sites around the downtown area (Post St. Substation, Sprague Wire Warehouse, and 3rd & Hatch Storage Yard). This new complex will consolidate their sites into one building, with modern tools and technology to save time and increase employee efficiency. Estimated Used and Useful Dec 2016.  O&M amounts: o 2016 = $77K yearly o 2017 and beyond = the same $77K yearly Downtown Office Building This is a renovation of an existing office building that will be next to the new Downtown Network Ops Bldg. Currently, employees are working out of a leased space at the Mirabeau office park in the Valley. This project moves them closer to the Mission Campus, and eliminates the need to pay ongoing rent. Estimated used and useful April 2016.  O&M amounts: o 2016 = $152K yearly o 2017 and beyond = the same $152K yearly Staff_DR_089 Attcahment A Page 2 of 2 2015  COF Restructuring: Asset Recovery Bldg, and WH Storage Yard Expansion 1 (‐$43,612 yearly) o 30 min. efficiency per employee per day (Xfmr Recovery employee)  3 emp x 0.5/hrs x 260 work days x $30/hr = $11,700/yr o 30 min. efficiency per employee per day (Haz mat employee)  1 emp x 0.5/hrs x 260 work days x $30/hr = $3900/yr o 10 min. efficiency per line truck delivery / drop offs per day (to Xfmr and Hazmat)  2 emp per truck x 0.16/hrs x 4 trucks/day x 260 work days x $40/hr = $13,312/yr o HVAC / insulation increase (Facilities Energy use in new buildings)  Approx $400 utility costs per month  $400/mo x 12 = (+$4800/yr) o Non‐Quantifiable Safety Savings  Practically eliminates possibility of environmental contamination through hazardous materials or PCB‐lace transformer oil due to new features. o 30 min. warehouse employee efficiency due to closer warehouse storage yard  5 emp x 0.5/hrs x 260 work days x $30/hr = $19,500/yr 2016  COF Restructuring:, Spokane Construction Remodel and Investment Recovery Bldg (‐$50,144 yearly) o Gain 8 Add’l cubicles, no need to lease space  Approx. $375/mo x 12 mo = $4500 o Facilities Energy Savings and Maintenance time savings  Approx $6K / yr o 20 min. efficiency per employee per day (IR employee)  10 emp x 0.33/hrs x 260 work days x $15/hr = $12,870/yr o 10 min. efficiency per line truck delivery / drop offs per day  2 emp per truck x 0.16/hrs x 8 trucks/day x 260 work days x $40/hr = $26,624/yr o Gate 5 & 6 reduced use, opens 1 time vs. 3. Maintenance savings and longevity.  Save approximately 5% costs of the yearly $3000 maintenance/repair expenses = $3000 x 5% = $150. o Non‐Quantifiable Safety Savings  Since crew trucks will no longer need to enter gate 5, drop off at IR, exit gate 6, go back out on N. North Center, and re‐enter gate 5, the potential for costly accidents on N. North Center will reduce.  IR crews will no longer work in the main service truck travel path, reducing the risk for a costly accident.  Downtown Office Building (‐$152,920 yearly) o Gain 75 Add’l cubicles, no need to lease office space  Approx. $12,600 /mo x 12 mo = $151,200/yr o Employees have less travel distance back‐forth to Mission than from Mirabeau  TIME: 10 emp x 2 trips/day x 0.13hr/trip x 260 work days x $30/hr = $20,280  CAR REIMBURSE: 10 emp x 2 trips/day x 4 miles x $0.55/mile x 260 wk days= $11,440 o Increase in snow removal and landscaping costs Staff_DR_089 Attachment B Page 1 of 2  Approx (+$15K / yr) o Increase in utility, maintenance costs  Approx (+$15K / yr) 2017  COF Restructuring: GPSS Remodel, Wash Bay, and WH Storage Yard Expansion 2 (‐$10,500 yearly) o Gain 8 Add’l cubicles, no need to lease space  Approx. $375/mo x 12 mo = $4500 o Facilities Energy Savings and Maintenance time savings  Approx $6K / yr o Non‐Quantifiable Safety Savings  Warehouse employees on forklifts will no longer need to cross N. North Center to get materials from storage yard across the street.  Downtown Network New Warehouse/Ops Bldg (‐$77,168 yearly) o Gain 8 Add’l cubicles, no need to lease office space  Approx. $750/mo x 12 mo = $9000 o Facilities Energy Savings and Maintenance time savings vs. existing DT Network facilities  Approx $6K / yr o 20 min. efficiency per employee per day  14 emp x 0.33/hrs x 260 work days x $40/hr = $48,048/yr o 60 min. off‐site trip efficiency to 3rd/Hatch or Wire Warehouse per employee per week  14 emp x 1 hr x 52 weeks/yr x $40/hr = $29,120/yr o Increase in snow removal and landscaping costs  Approx (+$15K / yr) Staff_DR_089 Attachment B Page 2 of 2 Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/18/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: UTC Staff - Liu RESPONDER: Ryan Finesilver TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff - 089 TELEPHONE: (509) 495-4873 EMAIL: ryan.finesilver@avistacorp.com REQUEST: Referring to Smith’s Workpaper “1) 2016 O&M Offsets E-OFF.xlsx,” please provide internal memos or other relevant documents that lead to the determination of system-level O&M offsets, $229,000 (Downtown Network New Warehouse/Ops Bldg) and $103,000 (COF Long-Term Restructuring Plan) for the two plant additions projects, respectively. Please include all steps of the calculation. RESPONSE: Please see Staff_DR_089 Attachment A for a copy of the email requesting O&M Offset information from the Company’s facilities management department received in December 2015. Page 2 of the attachment summarizes the relevant O&M information used in the Company’s direct filed case. For calculations related to these offsets, please see Staff_DR_089 Attachment B. This attachment includes the following updates received in May 2016: 1. The 2016 O&M Offsets related to COF Long-Term Restructuring plan have been revised from $60,000 to $50,144 in 2017. 2. Downtown Network Building work will occur in 2017 and 2018 rather than 2016 and 2017 as indicated in the Company’s O&M Offset Adjustment. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/18/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: UTC Staff - Liu RESPONDER: Ryan Finesilver TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff - 089 TELEPHONE: (509) 495-4873 EMAIL: ryan.finesilver@avistacorp.com REQUEST: Referring to Smith’s Workpaper “1) 2016 O&M Offsets E-OFF.xlsx,” please provide internal memos or other relevant documents that lead to the determination of system-level O&M offsets, $229,000 (Downtown Network New Warehouse/Ops Bldg) and $103,000 (COF Long-Term Restructuring Plan) for the two plant additions projects, respectively. Please include all steps of the calculation. RESPONSE: Please see Staff_DR_089 Attachment A for a copy of the email requesting O&M Offset information from the Company’s facilities management department received in December 2015. Page 2 of the attachment summarizes the relevant O&M information used in the Company’s direct filed case. For calculations related to these offsets, please see Staff_DR_089 Attachment B. This attachment includes the following updates received in May 2016: 1. The 2016 O&M Offsets related to COF Long-Term Restructuring plan have been revised from $60,000 to $50,144 in 2017. 2. Downtown Network Building work will occur in 2017 and 2018 rather than 2016 and 2017 as indicated in the Company’s O&M Offset Adjustment. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/26/2016 CASE NO: UE-160228 & UG-160229 WITNESS: Patrick Ehrbar REQUESTER: Staff - Hancock RESPONDER: Joe Miller TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff – 090 TELEPHONE: (509) 495-4546 EMAIL: joe.miller@avistacorp.com REQUEST: Please provide weather-normalized commodity sales figures for the most recent 10 years, by rate schedule, for both electric and natural gas service. RESPONSE: See the attachment labeled “Staff_DR_090 Attachment A”. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/26/2016 CASE NO: UE-160228 & UG-160229 WITNESS: Patrick Ehrbar REQUESTER: Staff - Hancock RESPONDER: Joe Miller TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff – 090 TELEPHONE: (509) 495-4546 EMAIL: joe.miller@avistacorp.com REQUEST: Please provide weather-normalized commodity sales figures for the most recent 10 years, by rate schedule, for both electric and natural gas service. RESPONSE: See the attachment labeled “Staff_DR_090 Attachment A”. Staff_DR_091 Supplemental Attachment D Page 1 of 54 Staff_DR_091 Supplemental Attachment D Page 2 of 54 Staff_DR_091 Supplemental Attachment D Page 3 of 54 Staff_DR_091 Supplemental Attachment D Page 4 of 54 Staff_DR_091 Supplemental Attachment D Page 5 of 54 Staff_DR_091 Supplemental Attachment D Page 6 of 54 Staff_DR_091 Supplemental Attachment D Page 7 of 54 Staff_DR_091 Supplemental Attachment D Page 8 of 54 Staff_DR_091 Supplemental Attachment D Page 9 of 54 Staff_DR_091 Supplemental Attachment D Page 10 of 54 Staff_DR_091 Supplemental Attachment D Page 11 of 54 Staff_DR_091 Supplemental Attachment D Page 12 of 54 Staff_DR_091 Supplemental Attachment D Page 13 of 54 Staff_DR_091 Supplemental Attachment D Page 14 of 54 Staff_DR_091 Supplemental Attachment D Page 15 of 54 Staff_DR_091 Supplemental Attachment D Page 16 of 54 Staff_DR_091 Supplemental Attachment D Page 17 of 54 Staff_DR_091 Supplemental Attachment D Page 18 of 54 Staff_DR_091 Supplemental Attachment D Page 19 of 54 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of 54 Staff_DR_091 Supplemental Attachment D Page 39 of 54 Staff_DR_091 Supplemental Attachment D Page 40 of 54 Staff_DR_091 Supplemental Attachment D Page 41 of 54 Staff_DR_091 Supplemental Attachment D Page 42 of 54 Staff_DR_091 Supplemental Attachment D Page 43 of 54 Staff_DR_091 Supplemental Attachment D Page 44 of 54 Staff_DR_091 Supplemental Attachment D Page 45 of 54 Staff_DR_091 Supplemental Attachment D Page 46 of 54 Staff_DR_091 Supplemental Attachment D Page 47 of 54 Staff_DR_091 Supplemental Attachment D Page 48 of 54 Staff_DR_091 Supplemental Attachment D Page 49 of 54 Staff_DR_091 Supplemental Attachment D Page 50 of 54 Staff_DR_091 Supplemental Attachment D Page 51 of 54 Staff_DR_091 Supplemental Attachment D Page 52 of 54 Staff_DR_091 Supplemental Attachment D Page 53 of 54 Staff_DR_091 Supplemental Attachment D Page 54 of 54 Staff_DR_091 Supplemental Attachment E Page 1 of 37 Staff_DR_091 Supplemental Attachment E Page 2 of 37 Staff_DR_091 Supplemental Attachment E Page 3 of 37 Staff_DR_091 Supplemental Attachment E Page 4 of 37 Staff_DR_091 Supplemental Attachment E Page 5 of 37 Staff_DR_091 Supplemental Attachment E Page 6 of 37 Staff_DR_091 Supplemental Attachment E Page 7 of 37 Staff_DR_091 Supplemental Attachment E Page 8 of 37 Staff_DR_091 Supplemental Attachment E Page 9 of 37 Staff_DR_091 Supplemental Attachment E Page 10 of 37 Staff_DR_091 Supplemental Attachment E Page 11 of 37 Staff_DR_091 Supplemental Attachment E Page 12 of 37 Staff_DR_091 Supplemental Attachment E Page 13 of 37 Staff_DR_091 Supplemental Attachment E Page 14 of 37 Staff_DR_091 Supplemental Attachment E Page 15 of 37 Staff_DR_091 Supplemental Attachment E Page 16 of 37 Staff_DR_091 Supplemental Attachment E Page 17 of 37 Staff_DR_091 Supplemental Attachment E Page 18 of 37 Staff_DR_091 Supplemental Attachment E Page 19 of 37 Staff_DR_091 Supplemental Attachment E Page 20 of 37 Staff_DR_091 Supplemental Attachment E Page 21 of 37 Staff_DR_091 Supplemental Attachment E Page 22 of 37 Staff_DR_091 Supplemental Attachment E Page 23 of 37 Staff_DR_091 Supplemental Attachment E Page 24 of 37 Staff_DR_091 Supplemental Attachment E Page 25 of 37 Staff_DR_091 Supplemental Attachment E Page 26 of 37 Staff_DR_091 Supplemental Attachment E Page 27 of 37 Staff_DR_091 Supplemental Attachment E Page 28 of 37 Staff_DR_091 Supplemental Attachment E Page 29 of 37 Staff_DR_091 Supplemental Attachment E Page 30 of 37 Staff_DR_091 Supplemental Attachment E Page 31 of 37 Staff_DR_091 Supplemental Attachment E Page 32 of 37 Staff_DR_091 Supplemental Attachment E Page 33 of 37 Staff_DR_091 Supplemental Attachment E Page 34 of 37 Staff_DR_091 Supplemental Attachment E Page 35 of 37 Staff_DR_091 Supplemental Attachment E Page 36 of 37 Staff_DR_091 Supplemental Attachment E Page 37 of 37 Page 1 of 2 Electric Attrition Study 2017 Attrition (000s) 6 Months- 06.2018 Attrition (000s) As Filed:38,568$ 10,301$ Net Change 2,419$ 135$ As Revised using 12.2015 CBR: (See Below)40,987$ 10,436$ (The Company is not requesting the revised 2017 Attrition Study revenue requirement produced using the 12.2015 CB adjusted results. The Company's requested electric increase is $38.6 million for 2017, and $10.3 million for 2018 (6-months Jan-Jun 2018). Natural Gas Attrition Study 2017 Attrition (000s) 6 Months- 06.2018 Attrition (000s) As Filed:4,397$ 941$ Net Change (see item 4 (f) below)4,410$ 586$ As Revised using 12.2015 CBR: (See Below)8,807$ 1,527$ (The Company is not requesting the revised 2017 Attrition Study revenue requirement produced using the 12.2015 CB adjusted results. The Company's requested natural gas increase is $4.4 million for 2017, and $1.1 million for 2018 (6-months Jan-Jun 2018).) AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/09/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Elizabeth Andrews REQUESTER: UTC Staff - Hancock RESPONDER: Liz Andrews TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff – 091-Supplemental TELEPHONE: (509) 495-8601 EMAIL: liz.andrews@avistacorp.com REQUEST: Has the Company analyzed the impact of including its December 2015 normalized commission basis results within its 2017 and 2018 pro forma cross check studies, or recreated its pro forma cross check studies using the 2015 commission basis results? If so, please provide these studies and all supporting work papers. RESPONSE: The Company has not completed this analysis, but is in the process of updating its Pro Forma and Cross Check Studies using 12.2015 CBR data, and will supplement this information once it is available. However, as noted within the Company’s response to Staff_DR_030, which provided an update to the Company’s filed electric and natural gas Attrition 2017 and 2018 (6 months) Studies using December 2015 finalized Commission Basis Reports (12.2015 CBR), updating these Attrition models to include 12.2015 CBR data increased the 2017 and June 2018 revenue requirement as follows (see Staff_DR_030- Attachment A “Summary of Electric Changes” and “Summary of Natural Gas Changes” for the excerpted tables below): Summary of Electric Changes: Summary of Natural Gas Changes Although the revised electric and natural gas Attrition Studies, as shown above, produce an increased revenue requirement from that requested with Avista’s direct filed case, the Company is not requesting the revised Attrition amounts. A reconciliation and description of the changes impacting the revised revenue requirement noted in the tables above were included in Staff_DR_030-Attachment A. Page 2 of 2 Supplemental – 06/09/2016 See Staff_DR_091 – Supplemental Attachments for the Electric & Natural Gas Pro Forma/Cross Check Studies updated to reflect 12.2015 information: Staff_DR_091 – Supplemental Attachment A – Summary of Electric & Natural Gas Pro Forma/Cross Check Changes Staff_DR_091 – Supplemental Attachment B – Electric Pro Forma / 2017-2018 (6 mos.) Cross Check Studies Staff_DR_091 – Supplemental Attachment C – Natural Gas Pro Forma / 2017-2018 (6 mos.) Cross Check Studies Staff_DR_091 – Supplemental Attachment D – Electric Workpapers (.pdf and electronic format) Staff_DR_091 – Supplemental Attachment E – Natural Gas Workpapers (.pdf and electronic format) As noted within the electric and natural gas Pro Forma/Cross Check models (see Staff_DR_091 – Supplemental Attachments B and C), the Company has not updated its capital pro forma and cross check adjustments. The Company is in the process of updating this information to include actual transfers to plant for the period Jan. 2016 – May 2016, with updated expected transfers forward. This information is expected to be available by the end of June. The company will supplement its Pro Forma/Cross Check models to incorporate all capital changes as soon as possible once this information is available. In addition, any impact on the capital related “After Attrition” adjustments, included within the electric and natural gas attrition models provided in Staff_DR_030, will be provided in a future supplement to Staff_DR_030 as soon as the information is available. Page 1 of 2 Electric Attrition Study 2017 Attrition (000s) 6 Months- 06.2018 Attrition (000s) As Filed:38,568$ 10,301$ Net Change 2,419$ 135$ As Revised using 12.2015 CBR: (See Below)40,987$ 10,436$ (The Company is not requesting the revised 2017 Attrition Study revenue requirement produced using the 12.2015 CB adjusted results. The Company's requested electric increase is $38.6 million for 2017, and $10.3 million for 2018 (6-months Jan-Jun 2018). Natural Gas Attrition Study 2017 Attrition (000s) 6 Months- 06.2018 Attrition (000s) As Filed:4,397$ 941$ Net Change (see item 4 (f) below)4,410$ 586$ As Revised using 12.2015 CBR: (See Below)8,807$ 1,527$ (The Company is not requesting the revised 2017 Attrition Study revenue requirement produced using the 12.2015 CB adjusted results. The Company's requested natural gas increase is $4.4 million for 2017, and $1.1 million for 2018 (6-months Jan-Jun 2018).) AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/09/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Elizabeth Andrews REQUESTER: UTC Staff - Hancock RESPONDER: Liz Andrews TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff – 091-Supplemental TELEPHONE: (509) 495-8601 EMAIL: liz.andrews@avistacorp.com REQUEST: Has the Company analyzed the impact of including its December 2015 normalized commission basis results within its 2017 and 2018 pro forma cross check studies, or recreated its pro forma cross check studies using the 2015 commission basis results? If so, please provide these studies and all supporting work papers. RESPONSE: The Company has not completed this analysis, but is in the process of updating its Pro Forma and Cross Check Studies using 12.2015 CBR data, and will supplement this information once it is available. However, as noted within the Company’s response to Staff_DR_030, which provided an update to the Company’s filed electric and natural gas Attrition 2017 and 2018 (6 months) Studies using December 2015 finalized Commission Basis Reports (12.2015 CBR), updating these Attrition models to include 12.2015 CBR data increased the 2017 and June 2018 revenue requirement as follows (see Staff_DR_030- Attachment A “Summary of Electric Changes” and “Summary of Natural Gas Changes” for the excerpted tables below): Summary of Electric Changes: Summary of Natural Gas Changes Although the revised electric and natural gas Attrition Studies, as shown above, produce an increased revenue requirement from that requested with Avista’s direct filed case, the Company is not requesting the revised Attrition amounts. A reconciliation and description of the changes impacting the revised revenue requirement noted in the tables above were included in Staff_DR_030-Attachment A. Page 2 of 2 Supplemental – 06/09/2016 See Staff_DR_091 – Supplemental Attachments for the Electric & Natural Gas Pro Forma/Cross Check Studies updated to reflect 12.2015 information: Staff_DR_091 – Supplemental Attachment A – Summary of Electric & Natural Gas Pro Forma/Cross Check Changes Staff_DR_091 – Supplemental Attachment B – Electric Pro Forma / 2017-2018 (6 mos.) Cross Check Studies Staff_DR_091 – Supplemental Attachment C – Natural Gas Pro Forma / 2017-2018 (6 mos.) Cross Check Studies Staff_DR_091 – Supplemental Attachment D – Electric Workpapers (.pdf and electronic format) Staff_DR_091 – Supplemental Attachment E – Natural Gas Workpapers (.pdf and electronic format) As noted within the electric and natural gas Pro Forma/Cross Check models (see Staff_DR_091 – Supplemental Attachments B and C), the Company has not updated its capital pro forma and cross check adjustments. The Company is in the process of updating this information to include actual transfers to plant for the period Jan. 2016 – May 2016, with updated expected transfers forward. This information is expected to be available by the end of June. The company will supplement its Pro Forma/Cross Check models to incorporate all capital changes as soon as possible once this information is available. In addition, any impact on the capital related “After Attrition” adjustments, included within the electric and natural gas attrition models provided in Staff_DR_030, will be provided in a future supplement to Staff_DR_030 as soon as the information is available. Page 1 of 1 Electric Attrition Study 2017 Attrition (000s) 6 Months- 06.2018 Attrition (000s) As Filed:38,568$ 10,301$ Net Change 2,419$ 135$ As Revised using 12.2015 CBR: (See Below)40,987$ 10,436$ (The Company is not requesting the revised 2017 Attrition Study revenue requirement produced using the 12.2015 CB adjusted results. The Company's requested electric increase is $38.6 million for 2017, and $10.3 million for 2018 (6-months Jan-Jun 2018). Natural Gas Attrition Study 2017 Attrition (000s) 6 Months- 06.2018 Attrition (000s) As Filed:4,397$ 941$ Net Change (see item 4 (f) below)4,410$ 586$ As Revised using 12.2015 CBR: (See Below)8,807$ 1,527$ (The Company is not requesting the revised 2017 Attrition Study revenue requirement produced using the 12.2015 CB adjusted results. The Company's requested natural gas increase is $4.4 million for 2017, and $1.1 million for 2018 (6-months Jan-Jun 2018).) AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/06/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Elizabeth Andrews REQUESTER: UTC Staff - Hancock RESPONDER: Liz Andrews TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff - 091 TELEPHONE: (509) 495-8601 EMAIL: liz.andrews@avistacorp.com REQUEST: Has the Company analyzed the impact of including its December 2015 normalized commission basis results within its 2017 and 2018 pro forma cross check studies, or recreated its pro forma cross check studies using the 2015 commission basis results? If so, please provide these studies and all supporting work papers. RESPONSE: The Company has not completed this analysis, but is in the process of updating its Pro Forma and Cross Check Studies using 12.2015 CBR data, and will supplement this information once it is available. However, as noted within the Company’s response to Staff_DR_030, which provided an update to the Company’s filed electric and natural gas Attrition 2017 and 2018 (6 months) Studies using December 2015 finalized Commission Basis Reports (12.2015 CBR), updating these Attrition models to include 12.2015 CBR data increased the 2017 and June 2018 revenue requirement as follows (see Staff_DR_030- Attachment A “Summary of Electric Changes” and “Summary of Natural Gas Changes” for the excerpted tables below): Summary of Electric Changes: Summary of Natural Gas Changes Although the revised electric and natural gas Attrition Studies, as shown above, produce an increased revenue requirement from that requested with Avista’s direct filed case, the Company is not requesting the revised Attrition amounts. A reconciliation and description of the changes impacting the revised revenue requirement noted in the tables above were included in Staff_DR_030-Attachment A. Page 1 of 1 Electric Attrition Study 2017 Attrition (000s) 6 Months- 06.2018 Attrition (000s) As Filed:38,568$ 10,301$ Net Change 2,419$ 135$ As Revised using 12.2015 CBR: (See Below)40,987$ 10,436$ (The Company is not requesting the revised 2017 Attrition Study revenue requirement produced using the 12.2015 CB adjusted results. The Company's requested electric increase is $38.6 million for 2017, and $10.3 million for 2018 (6-months Jan-Jun 2018). Natural Gas Attrition Study 2017 Attrition (000s) 6 Months- 06.2018 Attrition (000s) As Filed:4,397$ 941$ Net Change (see item 4 (f) below)4,410$ 586$ As Revised using 12.2015 CBR: (See Below)8,807$ 1,527$ (The Company is not requesting the revised 2017 Attrition Study revenue requirement produced using the 12.2015 CB adjusted results. The Company's requested natural gas increase is $4.4 million for 2017, and $1.1 million for 2018 (6-months Jan-Jun 2018).) AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/06/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Elizabeth Andrews REQUESTER: UTC Staff - Hancock RESPONDER: Liz Andrews TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff - 091 TELEPHONE: (509) 495-8601 EMAIL: liz.andrews@avistacorp.com REQUEST: Has the Company analyzed the impact of including its December 2015 normalized commission basis results within its 2017 and 2018 pro forma cross check studies, or recreated its pro forma cross check studies using the 2015 commission basis results? If so, please provide these studies and all supporting work papers. RESPONSE: The Company has not completed this analysis, but is in the process of updating its Pro Forma and Cross Check Studies using 12.2015 CBR data, and will supplement this information once it is available. However, as noted within the Company’s response to Staff_DR_030, which provided an update to the Company’s filed electric and natural gas Attrition 2017 and 2018 (6 months) Studies using December 2015 finalized Commission Basis Reports (12.2015 CBR), updating these Attrition models to include 12.2015 CBR data increased the 2017 and June 2018 revenue requirement as follows (see Staff_DR_030- Attachment A “Summary of Electric Changes” and “Summary of Natural Gas Changes” for the excerpted tables below): Summary of Electric Changes: Summary of Natural Gas Changes Although the revised electric and natural gas Attrition Studies, as shown above, produce an increased revenue requirement from that requested with Avista’s direct filed case, the Company is not requesting the revised Attrition amounts. A reconciliation and description of the changes impacting the revised revenue requirement noted in the tables above were included in Staff_DR_030-Attachment A. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/02/2016 CASE NO: UE-160228 & UG-160229 WITNESS: Elizabeth Andrews REQUESTER: UTC Staff - Hancock RESPONDER: Paul Kimball TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff – 092 TELEPHONE: (509) 495-4584 EMAIL: paul.kimball@avistacorp.com REQUEST: Please provide, in Excel format, the data used to generate Illustration No. 5 on page 15 of Mr. Morris’s direct testimony. RESPONSE: Please see the Excel file titled “Illustration No. 5 Support.xlsx” in Mr. Morris’s workpapers provided with the original case filing. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/02/2016 CASE NO: UE-160228 & UG-160229 WITNESS: Elizabeth Andrews REQUESTER: UTC Staff - Hancock RESPONDER: Paul Kimball TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff – 092 TELEPHONE: (509) 495-4584 EMAIL: paul.kimball@avistacorp.com REQUEST: Please provide, in Excel format, the data used to generate Illustration No. 5 on page 15 of Mr. Morris’s direct testimony. RESPONSE: Please see the Excel file titled “Illustration No. 5 Support.xlsx” in Mr. Morris’s workpapers provided with the original case filing. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/31/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: UTC Staff - White RESPONDER: Ryan Finesilver TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff – 093 TELEPHONE: (509) 495-4324 EMAIL: ryan.finesilver@avistacorp.com REQUEST: In the company-provided file 1)CB – Property Tax ADJ, on tab E-RPT, cells B16 through E16 show hardcoded amounts labelled “Current Period Expense.” Please provide the source report or accounting data summing to these amounts or provide the calculation resulting in these amounts. RESPONSE: Cells B16 through E16 come from the Company workpaper 1) CB – HPA-1 beginning in cell X179 and ending in cell X184. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/31/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: UTC Staff - White RESPONDER: Ryan Finesilver TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff – 093 TELEPHONE: (509) 495-4324 EMAIL: ryan.finesilver@avistacorp.com REQUEST: In the company-provided file 1)CB – Property Tax ADJ, on tab E-RPT, cells B16 through E16 show hardcoded amounts labelled “Current Period Expense.” Please provide the source report or accounting data summing to these amounts or provide the calculation resulting in these amounts. RESPONSE: Cells B16 through E16 come from the Company workpaper 1) CB – HPA-1 beginning in cell X179 and ending in cell X184. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/31/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: UTC Staff - White RESPONDER: Ryan Finesilver TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff – 094 TELEPHONE: (509) 495-4324 EMAIL: ryan.finesilver@avistacorp.com REQUEST: Also in the company-provided file 1)CB – Property Tax ADJ, on tab G-RPT, cells B18 through E18 show hardcoded amounts labelled “Current Period Expense.” Please provide the source report or accounting data summing to these amounts or provide the calculation resulting in these amounts. RESPONSE: Cells B16 through E16 come from the Company workpaper 1) CB – HPA-1 beginning in cell X190 and ending in cell X192. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 05/31/2016 CASE NO.: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: UTC Staff - White RESPONDER: Ryan Finesilver TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff – 094 TELEPHONE: (509) 495-4324 EMAIL: ryan.finesilver@avistacorp.com REQUEST: Also in the company-provided file 1)CB – Property Tax ADJ, on tab G-RPT, cells B18 through E18 show hardcoded amounts labelled “Current Period Expense.” Please provide the source report or accounting data summing to these amounts or provide the calculation resulting in these amounts. RESPONSE: Cells B16 through E16 come from the Company workpaper 1) CB – HPA-1 beginning in cell X190 and ending in cell X192. Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/08/2016 CASE NO: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: UTC Staff - Huang RESPONDER: Ryan Finesilver TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff – 095 TELEPHONE: (509) 495-4873 EMAIL: ryan.finesilver@avistacorp.com REQUEST: Please update the restating property tax adjustment using actual tax rate for Column X, in worksheet “2015 2016 - #3 on Jan 7 2016”, under Excel file “CB – HPA-1”, in Ms. Jennifer Smith’s workpaper. RESPONSE: Please see Staff_DR_095 Attachment A and B. The impact of restating the Property Tax adjustment reduces Washington restated property tax expense for 2015 by approximately $767,000 electric and $163,000 Natural Gas. See Avista’s response to Staff_DR_096 for impact on the revised Pro Forma Property Tax Adjustment (3.06). Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/08/2016 CASE NO: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: UTC Staff - Huang RESPONDER: Ryan Finesilver TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff – 095 TELEPHONE: (509) 495-4873 EMAIL: ryan.finesilver@avistacorp.com REQUEST: Please update the restating property tax adjustment using actual tax rate for Column X, in worksheet “2015 2016 - #3 on Jan 7 2016”, under Excel file “CB – HPA-1”, in Ms. Jennifer Smith’s workpaper. RESPONSE: Please see Staff_DR_095 Attachment A and B. The impact of restating the Property Tax adjustment reduces Washington restated property tax expense for 2015 by approximately $767,000 electric and $163,000 Natural Gas. See Avista’s response to Staff_DR_096 for impact on the revised Pro Forma Property Tax Adjustment (3.06). Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/08/2016 CASE NO: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: UTC Staff - Huang RESPONDER: Ryan Finesilver TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff – 096 TELEPHONE: (509) 495-4873 EMAIL: ryan.finesilver@avistacorp.com REQUEST: Please update the pro forma property tax adjustment using actual tax rate for Column X, in worksheet “2015 2016 - #3 on Jan 7 2016”, under Excel file “PF 2016 – HPA-1”, in Ms. Jennifer Smith’s workpaper. RESPONSE: Please see Staff_DR_096 Attachment A and B. The impact of restating the Pro Forma Property Tax adjustment, from that previously included in the Company’s direct filing, reduces property tax expense for 2016 by approximately $38,000 electric and $128,000 Natural Gas. See Avista’s response to Staff_DR_095 for the revised Restating Property Tax Adjustment (2.02). Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 06/08/2016 CASE NO: UE-160228 & UG-160229 WITNESS: Jennifer Smith REQUESTER: UTC Staff - Huang RESPONDER: Ryan Finesilver TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: Staff – 096 TELEPHONE: (509) 495-4873 EMAIL: ryan.finesilver@avistacorp.com REQUEST: Please update the pro forma property tax adjustment using actual tax rate for Column X, in worksheet “2015 2016 - #3 on Jan 7 2016”, under Excel file “PF 2016 – HPA-1”, in Ms. Jennifer Smith’s workpaper. RESPONSE: Please see Staff_DR_096 Attachment A and B. The impact of restating the Pro Forma Property Tax adjustment, from that previously included in the Company’s direct filing, reduces property tax expense for 2016 by approximately $38,000 electric and $128,000 Natural Gas. See Avista’s response to Staff_DR_095 for the revised Restating Property Tax Adjustment (2.02). Page 1 of 1 AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: WASHINGTON DATE PREPARED: 04/01/2016 CASE NO: UE-160228 & UG-160229 WITNESS: Elizabeth Andrews REQUESTER: The Energy Project RESPONDER: Paul Kimball TYPE: Data Request DEPT: State & Federal Regulation REQUEST NO.: TEP – 1 TELEPHONE: (509) 495-4584 EMAIL: paul.kimball@avistacorp.com REQUEST: Please provide copies of any and all data request submitted to you by any party to this proceeding and your response to those data request. This is a continuing request. RESPONSE: Avista has provided and will continue to provide copies of data requests, along with corresponding data responses, from all parties to this proceeding as they are completed.