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Home My WebLink About20161114Andrews Exhibit 14.pdfC' ,: C •: I ,j C D I \. ~.. .I ~-I ~- DAVID J . MEYER VICE PRESIDENT AND CHIEF COUNSEL FOR : . : :i ;1:·v• 14 Ah 9: 50 REGULATORY & GOVERNMENTAL AFFAIRS AVISTA CORPORATION P .O. BOX 3727 1411 EAST MISSION AVENUE SPOKANE , WASHINGTON 99220-3727 TELEPHONE : (509) 495 -4316 FACSIMILE : (509) 495 -8851 DAVID .MEYER@AVISTACORP .COM I •• I I' j l .... -• '10 .J ~ .., .... I BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION IN THE MATTER OF THE APPLICATION ) CASE NO . AVU-E -16-03 OF AVISTA CORPORATION FOR THE ) AUTHORITY TO INCREASE ITS RATES ) AND CHARGES FOR ELECTRIC ) SERVICE TO ELECTRIC CUSTOMERS ) EXHIBIT NO. 14 IN THE STATE OF IDAHO ) )ELIZABETH M. ANDREWS _________________ ) FOR AVISTA CORPORATION (ELECTRIC ) David J. Meyer, Esq. Vice President and Chief Counsel of Regulatory and Governmental Affairs A vista Corporation 1411 E. Mission A venue P.O. Box 3727 Spokane, Washington 99220 Phone: (509) 495-4316, Fax : (509) 495-8851 Brandon Karpen Deputy Attorney General Idaho Public Utilities Commission Staff P.O. Box 83720 Boise, ID 83720-0074 Phone: (208) 334-0312, Fax: (208) 334-3762 BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION IN THE MATTER OF THE APPLICATION ) OF A VISTA CORPORATION DBA A VISTA ) CASE NO. A VU-E-16-03 UTILITIES FOR AUTHORITY TO ) INCREASE ITS RA TES AND CHARGES ) FOR ELECTRIC SERVICE IN IDAHO ) ) STIPULATION AND SETTLEMENT This Stipulation is entered into by and among A vista Corporation, doing business as Avista Utilities ("Avista" or "Company"), the Staff of the Idaho Public Utilities Commission ("Staff), Clearwater Paper Corporation ("Clearwater"), Idaho Forest Group, LLC ("Idaho Forest"), the Community Action Partnership Association of Idaho ("CAPAI"), and the Snake River Alliance ("Snake River"). These entities are collectively referred to as the "Parties," and represent all of the parties in the above-referenced cases. The Parties understand this Stipulation is subject to approval by the Idaho Public Utilities Commission ("IPUC" or the "Commission"). STIPULATION AND SETTLEMENT-AVU-E-16-03 Page 1 I. INTRODUCTION 1. The terms and conditions of this Stipulation are set forth herein. The Parties agree that this Stipulation represents a fair, just and reasonable compromise of all the issues raised in the proceeding, is in the public interest and its acceptance by the Commission represents a reasonable resolution of the multiple issues identified in this case. The Parties, therefore, recommend that the Commission, in accordance with RP 274, approve the Stipulation and all of its terms and conditions without material change or condition. II. BACKGROUND 2. On May 26, 2016, A vista filed an Application with the Commission for authority to increase revenue effective January 1, 2017 for electric service in Idaho by 6.3%. If approved, the Company's 2017 revenues for electric base retail rates would have increased by $15 .4 million annually. By Order No. 33536, dated June 7, 2016, the Commission suspended the proposed schedules of rates and charges for electric service. 3. Petitions to intervene in this proceeding were filed by Clearwater, Idaho Forest, CAPAI, and Snake River. The Commission granted these interventions through IPUC Order Nos. 33539, 33542, 33549 and 33550. 4. A settlement conference was noticed and held in the Commission offices on October 3, 2016, and was attended by parties to this case. 1 As a compromise of positions in this case, and for other consideration as set forth below, the Parties agree to the following terms: 1 Clearwater and Snake River were unable to attend the settlement conference, but are supportive of the Stipulation and Settlement. STIPULATION AND SETTLEMENT-AVU-E-16-03 Page 2 III. TERMS OF THE STIPULATION AND SETTLEMENT 5. Overview of Settlement and Revenue Requirement. The Parties agree that Avista should be allowed to implement revised tariff schedules designed to recover $6.25 million in additional annual electric revenue, which represents a 2.6% increase in electric annual base tariff revenues. New electric rates would become effective January 1, 2017. 6. Cost of Capital. The Settling Parties agree to a 9.5 percent return on equity, with a 50.0 percent common equity ratio. The capital structure and resulting rate of return is as set forth below: Capital Component Structure Cost Weighted Cost Debt 50% 5.67% 2.83% Common Equity 50% 9.50% 4.75% Total 100% 7.58% A. ELECTRIC REVENUE REQUIREMENT 7. Overview of Electric Revenue Requirement. Below is a summary table and descriptions of the electric revenue requirement components agreed to by the Parties: SUMMARY TABLE OF ADJUSTMENTS TO ELECTRIC REVENUE REQUIREMENT EFFECTIVE JANUARY 1, 2017 (OOOs of Dollars) Amount as Filed: Adjustments: a.) Cost of Capital b.) Revise Net Rate Base c.) Revise Deferred Debits and Credits to Reflect Corrected 2016 Balances d.) Remove 2017 Non-Union Labor Expenses e.) Update 2016 Employee Benefit Costs £) Add Nine Mile Investment Tax Credit g.) Remove Officer Incentives h.) Remove 2015 Storm Costs i.) Include Palouse Wind in PCA j.) Miscellaneous A&G Adjustments: Board of Director Expenses, Reallocation of Legal Expenses, Expired Leases and Inclusion of O&M Savings Adjusted Amounts Effective January 1, 2017 STIPULATION AND SETTLEMENT-AVU-E-16-03 Revenue Requirement Rate Base $ 15,433 $ 754,636 $ (2,471) $ (1,329) $ (740) $ (62) $ 107 $ (310) $ 1,221 $ (162) $ (171) $ (1,057) $ (4,509) $ (333) $ 6,250 $ 754,003 Page 3 a. Cost of Capital. As previously described (see Paragraph 6 above). This adjustment reduces the overall revenue requirement by $2.471 million. b. Revise Net Rate Base. Reflects adjustments to net rate base to: 1) update information related to 2016 capital additions; 2) remove adjustments proposed by the Company for Plant Held For Future Use and 2017 capital additions, including related depreciation expense, as well as the impact on Accumulated Depreciation and Accumulated Deferred Federal Income Taxes; and 3) remove agreed-upon amount related to Asset Management Transmission project. This adjustment reduces the overall revenue requirement by $1.329 million and reduces net rate base by $740,000. c. Revise Deferred Debits and Credits. Revises the deferred debits and credits regulatory balances to reflect corrected balances as of December 2016, rather than the 2017 balances as proposed by the Company. This adjustment decreases the overall revenue requirement by $62,000 and increases rate base by $107,000. d. Remove 2017 Non-Union Labor Expenses -This adjustment reduces the overall revenue requirement by $310,000, by removing 2017 incremental non-union labor expenses. e. Update 2016 Employee Benefit Costs. Reflects updated information related to 2016 incremental pension and medical costs. This adjustment increases the overall revenue requirement by $1 .221 million. f. Add Nine Mile Investment Tax Credit. Reflects the amortization of the investment tax credit benefit associated with the Nine Mile Redevelopment upgrade project on Units 1 and 2. g. Remove Officer Incentives. Reflects the removal of all officer incentives. This adjustment decreases the overall revenue requirement by $171 ,000. STIPULATION AND SETTLEMENT - A VU-E-16-03 Page 4 h. Remove 2015 Storm Costs. Removes 2015 storm-related expenses included in the Company's historical test period beyond the 6-year average (2009-2014) of storm expenses. Includes $210,000 of amortization expense representing the customer portion ($630,000) to recover for regulatory purposes over the period 2017-2019. This adjustment reduces the overall revenue requirement by $1.057 million. 1. Include Palouse Wind in PCA. Reflects the removal of the Palouse Wind Power Purchase Agreement net expenses from base power supply expense. The Parties agree that, for purposes of this case, the recovery of costs related to the Palouse Wind Power Purchase Agreement ("PPA") will continue to be included in the PCA, subject to the current sharing (90% customer, 10% Company). This adjustment decreases the overall revenue requirement by $4.509 million. J. Miscellaneous A&G Adjustments. Reflects the net change in administrative and general (A&G) expenses related to: 1) removing additional Board of Director expenses included in 2015 ($159,000); 2) removing legal expenses allocated to Idaho electric in error ($33 ,000); 3) removing expenses associated with certain expired leases in 2015 ($62,000); and 4) inclusion of the O&M savings associated with the Company's Street & Area Light project ($79,000). This adjustment decreases the overall revenue requirement by $333,000. B. OTHER SETTLEMENT COMPONENTS 8. PCA Authorized Level of Expense. The new level of power supply revenues, expenses, retail load and Load Change Adjustment Rate resulting from the January 1, 2017 settlement revenue requirement for purposes of the monthly PCA mechanism calculations are detailed in Appendix A. STIPULATION AND SETTLEMENT - A VU-E-16-03 Page 5 9. Electric Fixed Cost Adjustment Mechanism Authorized Base. The new level of baseline values for the electric fixed cost adjustment mechanism resulting from the January 1, 2017 settlement revenue requirement are detailed in Appendix B. C. COST OF SERVICE/RATE SPREAD/RATE DESIGN/LOW INCOME 10. Cost of Service. For electric operations, the Company prepared an analysis using a system load factor peak credit method of classifying production costs, allocating 100% of transmission costs to demand, and allocating transmission costs on a twelve-month coincident peak allocation factor. For settlement purposes, the Parties agreed to use a pro-rata allocation based on the Company's proposed 25% move towards unity for purposes of spreading the revised electric revenue requirement, while not agreeing to any particular cost of service methodology. 11. Rate Spread/Rate Design (Base Rate Changes). As indicated above, the Parties agreed that the increase in base revenues would be spread to all electric rate schedules on a pro rata allocation of the Company's rate spread percentages from its original filing. 12. Electric Rate Design. With the exception of the Residential Basic Charge, the Parties agree to the rate design changes proposed by the Company in Mr. Ehrbar' s direct testimony. For the electric Residential Basic Charge (Schedule 1), the Parties agreed that it will increase from $5.25 per month to $5.75 per month, an increase of $0.50 per month. Appendix C provides a summary of the current and revised rates and charges (as per the Settlement) for electric service. 13. Resulting Percentage Increase by Electric Service Schedule. The following tables reflect the agreed-upon percentage increase by schedule for electric service: STIPULATION AND SETTLEMENT-A VU-E-16-03 Page 6 Increase in Increase in Rate Schedule Base Rates Billing Rates Residential Schedule 1 3.2% 3.1% General Service Schedules l l /12 1.9% 1.8% Large General Service Schedules 2 l /22 2.3% 2.3% Extra Large General Service Schedule 25 1.9% 1.9% Clearwater Paper Schedule 25P 1.8% 1.8% Pumping Service Schedules 31/32 3.1% 3.0% Street & Area Lights Schedules 41 -48 3.4% 3.3% Overall 2.6% 2.5% 14. Electric Cost of Service Workshop. The Parties agreed, prior to the Company's next general rate case filing, to meet and confer regarding the Company's electric cost of service study. Included in the workshop(s) would be discussion related to the methodologies used by A vista to classify and allocate its costs, as well as a review of the changes that occurred between the cost of service study results from the Company's 2015 general rate case filing and its 2016 general rate case filing. The Company will provide available information, studies and data requested by a Party so as to enable meaningful workshop participation and discussion of issues. Unless it decides to do so, a Party shall not be bound by workshop discussions and may contest cost of service and rate spread issues in subsequent proceedings. 15. Collaboration on Low Income Issues. The Company and interested parties will meet and confer prior to the Company's next general rate filing in order to assess the Low Income Weatherization and Low Income Energy Conservation Education Programs to explore policy goals and program structures that may enhance or improve A vista's low-income program. STIPULATION AND SETTLEMENT - A VU-E-16-03 Page 7 IV. OTHER GENERAL PROVISIONS 16. The Parties agree that this Stipulation represents a compromise of the positions of the Parties in this case. As provided in RP 272, other than any testimony filed in support of the approval of this Stipulation, and except to the extent necessary for a Party to explain before the Commission its own statements and positions with respect to the Stipulation, all statements made and positions taken in negotiations relating to this Stipulation shall be confidential and will not be admissible in evidence in this or any other proceeding. 17. The Parties submit this Stipulation to the Commission and recommend approval in its entirety pursuant to RP 274. Parties shall support this Stipulation before the Commission, and no Party shall appeal a Commission Order approving the Stipulation or an issue resolved by the Stipulation. If this Stipulation is challenged by any person not a party to the Stipulation, the Parties to this Stipulation reserve the right to file testimony, cross-examine witnesses and put on such case as they deem appropriate to respond fully to the issues presented, including the right to raise issues that are incorporated in the settlement terms embodied in this Stipulation. Notwithstanding this reservation of rights, the Parties to this Stipulation agree that they will continue to support the Commission's adoption of the terms of this Stipulation. 18. If the Commission rejects any part or all of this Stipulation or imposes any additional material conditions on approval of this Stipulation, each Party reserves the right, upon written notice to the Commission and the other Parties to this proceeding, within 14 days of the date of such action by the Commission, to withdraw from this Stipulation. In such case, no Party shall be bound or prejudiced by the terms of this Stipulation, and each Party shall be entitled to seek reconsideration of the Commission's order, file testimony as it chooses, cross-examine witnesses, and do all other things necessary to put on such case as it deems appropriate. In such case, the Parties immediately will request the prompt reconvening of a prehearing conference for STIPULATION AND SETTLEMENT-AVU-E-16-03 Page 8 purposes of establishing a procedural schedule for the completion of the case. The Parties agree to cooperate in development of a schedule that concludes the proceeding on the earliest possible date, taking into account the needs of the Parties in participating in hearings and preparing testimony and briefs. 19. The Parties agree that this Stipulation is in the public interest and that all of its terms and conditions are fair, just and reasonable. 20. No Party shall be bound, benefited or prejudiced by any position asserted in the negotiation of this Stipulation, except to the extent expressly stated herein, nor shall this Stipulation be construed as a waiver of the rights of any Party unless such rights are expressly waived herein. Execution of this Stipulation shall not be deemed to constitute an acknowledgment by any Party of the validity or invalidity of any particular method, theory or principle of regulation or cost recovery. No Party shall be deemed to have agreed that any method, theory or principle of regulation or cost recovery employed in arriving at this Stipulation is appropriate for resolving any issues in any other proceeding in the future. No findings of fact or conclusions of law other than those stated herein shall be deemed to be implicit in this Stipulation. 21. The obligations of the Parties under this Stipulation are subject to the Commission's approval of this Stipulation in accordance with its terms and conditions and upon such approval being upheld on appeal, if any, by a court of competent jurisdiction. 22. This Stipulation may be executed in counterparts and each signed counterpart shall constitute an original document. STIPULATION AND SETTLEMENT -A VU-E-16-03 Page 9 1 ~.!- DATED this _,_ day of October, 2016. A vista Corporation By:~/ 'Dill.Meyer Attorney for A vista Corporation Clearwater Paper Corporation By: _____________ _ Peter Richardson Attorney for Clearwater Paper Community Action Partnership Association ofidaho By: _____________ _ Brad Purdy Attorney for CAP AI Idaho Public Utilities Commission Staff By: ___________ _ Brandon Karpen Deputy Attorney General Idaho Forest Group By: _____________ _ Dean J. Miller Attorney for Idaho Forest Group LLC Snake River Alliance By: _____________ _ Ken Miller Snake River Alliance STIPULATION AND SETTLEMENT-AVU-E-16-03 Page 10 "" DATED this fly day of October, 2016. A vista Corporation By: ____________ _ David J. Meyer Attorney for A vista Corporation Clearwater Paper Corporation By: ____________ _ Peter Richardson Attorney for Clearwater Paper Community Action Partnership Association ofldaho By: ____________ _ Brad Purdy Attorney for CAP AI Idaho Forest Group By: ____________ _ Dean J. Miller Attorney for Idaho Forest Group LLC Snake River Alliance By: ____________ _ Ken Miller Snake River Alliance STIPULATION AND SETTLEMENT-AVU-E-16-03 Page 10 -----------·· \tY DATED this 9 day of October 2016. A vista Corporation By: _____________ _ David J. Meyer Attorney for A vista Corporation CIV-M Corpor~tion _ _) By:~~ Peter Richardson Attorney for Clearwater Paper Community Action Partnership Association ofidaho By: _____________ _ Brad Purdy Attorney for CAP AI Idaho Public Utilities Commission Staff By: ___________ ~ Brandon Karpen Deputy Attorney General Idaho Forest Group By: ____________ _ Dean J. Miller Attorney for Idaho Forest Gro Snake River Alliance By: ---:-:----------...J Ken Miller Snake River Alliance DATED this __ day of October, 2016. A vista Corporation By: _____________ _ David J. Meyer Attorney for A vista Corporation Clearwater Paper Corporation By: _____________ _ Peter Richardson Attorney for Clearwater Paper Community Action Partnership Association ofidaho By: _____________ _ Brad Purdy Attorney for CAP AI Idaho Public Utilities Commission Staff By: _____________ _ Brandon Karpen Deputy Attorney General :~~ Dean J. Miller Attorney for Idaho Forest Group LLC Snake River Alliance By: _____________ _ Ken Miller Snake River Alliance STIPULATION AND SETILEMENT-AVU-E-16-03 Page 10 DATED this __ day of October, 2016. A vista Corporation Idaho Public Utilities Commission Staff By: _____________ _ By: _____________ _ David J. Meyer Brandon Karpen Attorney for A vista Corporation Deputy Attorney General Clearwater Paper Corporation Idaho Forest Group By: ____________ _ By: ___________ _ Peter Richardson Dean J. Miller Attorney for Clearwater Paper Attorney for Idaho Forest Group LLC Community Action Partnership Association ofidaho - By,e~ Brad Purdy Attom:::: Snake River Alliance By: ___________ _ Ken Miller Snake River Alliance STIPULATION AND SETTLEMENT-AVU-E-16-03 Page 10 ----------------------------------------------- DATED this __ day of October, 2016. A vista Corporation By: _____________ _ David J. Meyer Attorney for A vista Corporation Clearwater Paper Corporation By: _____________ _ Peter Richardson Attorney for Clearwater Paper Community Action Partnership Association ofldaho By: _____________ _ Brad Purdy Attorney for CAP AI Idaho Public Utilities Commission Staff By: _____________ _ Brandon Karpen Deputy Attorney General Idaho Forest Group By: _____________ _ Dean J. Miller Attorney for Idaho Forest Group LLC Snake ~er Alliance By:~~ Ken Miller Snake River Alliance STIPULATION AND SETTLEMENT-AVU-E-16-03 Page 10 Avista Corp Proforma January 2017 -December 2017 PCA Authorized Expense and Retail Sales 2015 Normalized Loads PCA Authorized Power Sueelll Exeense -Sl,!stem Numbers (1) Total January February March 8.l!Ii! M!!ll Account 555 -Purchased Power $90,526,809 $9,519,018 $8,941,137 $8,090,123 $7,193,081 $5,574,392 Account 501 -Thermal Fuel $28,582,064 $2,623,577 $2,414,726 $2,489,588 $2,219,535 $1 ,919,943 Account 547 -Natural Gas Fuel $63,615,977 $7,496,448 $6,383,459 $6,191,000 $4,127,172 $2,227,503 Account 447 -Sale for Resale $42,666,054 $3,853,546 $3,409,878 $3,652,294 $4,889,733 $3,785,610 Power Supply Expense $140,058,796 $15,785,497 $14,329,444 $13,118,418 $8,650,056 $5,936,228 Transmission Expense $17,696,508 $1 ,494,602 $1,475,745 $1 ,463,502 $1,469,692 $1,454,063 Transmission Revenue $17,163,284 $1 ,258,554 $1,342,410 $1 ,380,906 $1,325,245 $1,456,540 Net REC Revenue $3,423,000 $290,850 $262,050 $290,850 $281 ,250 $290,850 $137,169,021 PCA Idaho Retail Sales Total January February March 8.l!Ii! M!!ll Total Retail Sales, MWh 3,011,312 287,473 258,568 271,002 228,286 228,974 Load Change Adjustment Rate $24.00 /MV\/h 1) Multiply system numbers by 34.37% to determine Idaho share. 2) 12 months ended December 2015 weather normalized Idaho retail sales. Appendix A June ,Ml,! August September $5,284,240 $6,394,106 $7,883,449 $6,345,982 $1,572,469 $2,337,541 $2,599,424 $2,567,872 $1 ,803,506 $3,770,606 $5,642,678 $5,571 ,559 $2,350,863 $3,011,999 $2,803,724 $2,951,547 $6,309,353 $9,490,254 $13,321,827 $11,533,866 $1 ,425,853 $1,474,893 $1,469,493 $1,450,695 $1 ,614,866 $1,670,553 $1 ,520,946 $1 ,466,611 $281,250 $290,850 $290,850 $281,250 June ,Ml,! August September 224,777 245,462 255,918 214,673 October November December $6,367,918 $9,249,398 $9,683,965 $2,552,450 $2,593,186 $2,691,753 $5,667,221 $6,527,519 $8,207,306 $2,433,459 $4,254,971 $5,268,431 $12,154,129 $14,115,132 $15,314,593 $1,483,230 $1,490,253 $1 ,544,488 $1 ,406,355 $1,406,387 $1 ,313,910 $290,850 $281,250 $290,850 October November December 238,519 248,276 309,383 Stipulation and Settlement Case No. AVU-E-16-03 Avista Page 1 of 1 Avista Utilities Electric Fixed Cost Adjustment Mechanism (Idaho) Development of Fixed Cost Adjustment Revenue by Rate Schedule -Electric AVU-E-16-03 Rates Effective 1/1/2017 RESIDENTIAL GENERAL SVC. LG. GEN. SVC. TOTAL SCHEDULE l SCH. ll ,12 SCH. 21,22 Total Normalized Test Year Revenue $ 243,599,000 $ 105,522,000 $ 36,021 ,000 $ 52,133,000 2 Proposed Revenue Increase $ 6,250,000 $ 3,330,000 $ 667,000 $ 1,196,000 3 Total Rate Revenue (January I, 2017) $ 249,849,000 $ I 08,852,000 $ 36,688,000 $ 53,329,000 4 Normalized kWhs (Test Year) 3,011,311 ,824 1,143,267,490 357,684,869 657,453,609 5 Load Change Adjustment Rate (Ln 14) $ 0.02416 $ 0.02416 $ 0.02416 $ 0.02416 6 Variable Power Supply Revenue (Ln 4 • Ln 5) $ 72,753,294 $ 27,621,343 $ 8,641,666 $ 15,884,079 6A Fixed Production and Transmission Rate per kWh (New Customers Only) $ 0.02459 $ 0.02838 $ 0.02407 68 Fixed Production and Transmission Revenue (New Customers Only) $ 70,578,572 $ 28,117,257 $ [0,149,399 $ 15,825,220 7 Subtotal (Ln 3 -Ln 6) (Test Year Customers) $ [51 ,061 ,711 $ 81,230,657 $ 28,046,334 $ 37,444,921 7A Subtotal (Ln 3 -Ln 6 -Ln 68) (New Customers) $ 95,866,503 $ 53, 113,40 I $ 17,896,935 $ 21,619,701 8 Customer Bills (Test Year) 1,525,780 1,246,051 249,128 [3,816 9 Proposed Fixed Charges $ 5.75 $ 12.00 $ 400.00 IO Fixed Charge Revenue (Ln 8 • Ln 9) $ [5,848,579 $ 7,164,793 $ 2,989,536 $ 5,526,400 [[ Fixed Cost Adjustment Revenue (Ln 7 -Ln I 0) (Test Year Customers) $ 135,2[3,132 $ 74,065,864 $ 25,056,798 $ 31,918,521 I IA Fixed Cost Adjustment Revenue (Ln 7A -Ln 10) (New Customers) $ 80,017,924 $ 45,948,607 $ 14,907,399 $ 16,093,301 12 Load Change Adjustment Rate $0.02400 13 Gross Up Factor for Revenue Related Exp 100.68% 14 Grossed Up Load Change Adjustment Rate $0.02416 Residential Non-Residential Group 15 Average Number of Customers (Line 8 / 12) 103,838 23,311 16 Annual kWh 1,143,267,490 1,080,502,749 17 Basic Charge Revenues 7,164,793 8,683,786 18 Customer Bills 1,246,051 279,729 19 Average Basic Charge $5.75 $3104 Appendix B $ $ $ $ $ $ $ $ $ $ $ $ $ OTHER PUMPING SERVICE SCH.31,32 SCHEDULES 5,742,000 $ 44,181 ,000 177,000 $ 880,000 5,919,000 $ 45,061 ,000 65,364,271 787,541,585 0.02416 1,579,20 l $ [9,027,005 0.01688 1,103,332 $ 15,383,365 4,339,799 Excluded From 3,236,467 Fixed Cost 16,785 Adjustment 10.00 167,850 4,171 ,949 3,068,617 Stipulation and Settlement Case No. AVU-E-16-03 Avista Page 1 of 4 Line No. 1 2 3 2 3 A vista Utilities Electric Fixed Cost Adjustment Mechanism (Idaho) Development of Annual Fixed Cost Adjustment Revenue Per Customer -Electric AVU-E-16-03 Rates Effective 1/1/2017 Source (a) (b) Existing Customer FCA Fixed Cost Adjustment Revenue Page 1 $ Test Year Number of Customers Revenue Data Fixed Cost Adjustment Revenue Per Customer (1)/(2) $ New Customer FCA Fixed Cost Adjustment Revenue Page 1 $ Test Year Number of Customers Revenue Data Fixed Cost Adjustment Revenue Per Customer (1)/(2) $ * Schedules 11 , 12, 21, 22, 31, and 32. Appendix B Residential (c) 74,065,864 $ 103,838 713.29 $ 45,948,607 $ 103,838 442.50 $ Non-Residential Schedules* (d) 61 ,147,268 23,311 2,623.14 34,069,317 23,311 1,461.53 Stipulation and Settlement Case No. AVU-E-16-03 Avista Page 2 of 4 Avista Utilities Electric Fixed Cost Adjustment Mechanism (Idaho) Development of Monthly Fixed Cost Adjustment Revenue Per Customer -Electric AVU-E-16-03 Rates Effective 1/1/2017 Line Source Jan Feb Ma, Ap, May Jun Jul Aug No. (a) (b) (c) (d) (c) (f) (g) (h) (i) Gl Electric Sales Residential -Wcathcr-Nonnalizcd kWh Sales Monthly Test Year 134,935,067 I 06,332,869 111,428,605 83,668,292 77,786,324 69,134,768 86,644,444 79,655,406 -% of Annual Total %of Total 11.80% 9.30% 9.75% 7.32% 6.80% 6.05% 7.58% 6.97% 6 Non-Residential• - Weather-Normalized kWh Sales Monthly Test Year 86,125,182 89,927,649 90,755,331 83,493,150 87,183,940 88,747,983 91,963,568 97,627,588 -% of Annual Total %of Total 7.97% 8.32% 8.40% 7.73% 8.07% 8.21% 8.51% 9.04% 9 10 II MQnlhll:'. Fi:1$:d ,ost AdjuJtms:nt Revenus: Per ,ustoms:r {"RP~") 12 For Test Year Exi!1tin1:,. Cu.'itomers 13 Residential 14 -2016 Fixed Cost Adj. Revenue per Customer Page 2 15 - 2016 Monthly Fixed Cost Adj. Revenue per Custom (4) X (14) s 84.19 s 66.34 s 69.52 $ 52.20 s 48.53 s 43.13 s 54.06 s 49.70 16 17 Non-Residential• Jg -2016 Fixed Cost Adj. Revenue per Customer Page 2 19 -2016 Monthly Fixed Cost Adj. Revenue per Custom (8) X (JS) s 209.09 s 218.32 s 220.33 s 202.70 s 211.66 s 215.45 s 223.26 $ 237.01 20 21 22 For New Customers 23 Residential 24 -2016 Fixed Cost Adj. Revenue per Customer Page 2 25 -2016 Monthly Fixed Cost Adj. Revenue per Custom (4) X (24) s 52.23 s 41.16 s 43.13 s 32.38 s 30.11 s 26.76 s 33.54 s 30.83 26 27 Non-Residential• 28 -2016 Fixed Cost Adj. Revenue per Customer Page 2 29 -2016 Monthly Fixed Cost Adj. Revenue per Custom (8) X (28) s 116.50 s 121.64 s 122.76 s 112.94 s 117.93 s 120.04 s 124.39 s 132.05 • Schedules 11, 12, 21, 22, 31, and 32. Appendix B Sep Oct (k) (I) 67,301,724 82,073,309 5.89% 7.18% 86,161,233 91,867,649 7.97% 8.50% $ 41.99 $ 51.21 s s 209.17 s 223.03 s s 26.05 s 31.77 s s 116.55 s 124.26 s Nov Dec TOTAL (m) (n) (o) 101,867,616 142,439,066 1,143,267,490 8.91% 12.46% 100.00% 84,390,531 102,258,945 1,080,502,749 7.81% 9.46% 100.00% $ 713.29 63.56 $ gg_g7 s 713.29 s 2,623.14 204.88 s 248.25 $ 2,623.14 s 442.50 39.43 s 55.13 s 442.50 s 1,461.53 114.15 s 138.32 s 1,461.53 Stipulation and Settlement Case No. AVU-E-16-03 Avista Page 3 of 4 Sumcost AVISTA UTILITIES Idaho Jurisdiction Scenario: AVU-E-16-03 Settlement Case Revenue to Cost by Functional Component Summary Electric Utility 10/03/16 Load Factor Peak Credit For the Twelve Months Ended December 31, 2015 Trans mission By Demand 12 CP (b) (c) (d) (e) (ij (g) (h) (i) (j) (k) (I) (m) Residential General Large Gen Extra Large Extra Large Pumping Street & System Service Service Service Gen Service Service CP Service Area Lights Description Total Sch 1 Sch 11-12 Sch 21-22 Sch 25 Sch 25P Sch 31-32 Sch 41-49 Functional Cost Components at Current Return by Schedule Production 115,040,037 44,320,419 14,809,845 25,422,314 12,569,224 15,262,249 2,227,995 427,991 Trans mission 25,264,199 9,933,659 3,684,724 5,699,676 2,409,625 3,092,119 394,325 50,070 3 Distribution 61,360,578 29,280,337 10,965,292 14,030,362 2,047,999 383,093 2,205,173 2,448,321 4 Common 41,934,186 21,987,585 6,561,139 6,980,648 2,392,152 2,509,538 914,507 588,617 Total Current Rate Revenue 243,599,000 105,522,000 36,021,000 52,133,000 19,419,000 21 ,247,000 5,742,000 3,515,000 Expressed as $/kWh 6 Production $0.03820 $0.03877 $0.04140 $0.03867 $0.03552 $0.03638 $0.03409 $0.03016 7 Trans mission $0.00839 $0.00869 $0 01030 $0.00867 $0.00681 $0.00737 $000603 $0.00353 8 Distribution $0.02038 $0 02561 $0.03066 $0.02134 $0.00579 $000091 $0.03374 $0.17255 9 Common $0.01393 $0.01923 $0.01834 $0.01062 $0.00676 $0.00598 $0.01399 $0.04148 10 Total Current Melded Rates $008089 $0 09230 $0.10071 $0.07930 $0 05487 $0 05065 $0 08785 $0.24772 Functional Cost Components at Uniform Current Return 11 Production 114,116,865 46,899,317 13,687,291 24,468,703 11,915,390 14,434,008 2,280,276 431,879 12 Transmission 25,076,464 11,609,150 3,032,045 5,170,758 2,106,273 2,687,382 419,574 51,282 13 Distribution 62,120,226 32,911,083 9,379,279 12,854,443 1,815,929 334,848 2,325,977 2,498,666 14 Common 42,285,445 23,644,757 5,929,464 6,620,623 2,224,127 2,326,060 944,028 596,386 15 Total Uniform Current Cost 243,599,000 115,064,307 32,028,080 49,114,527 18,061,720 19,782,298 5,969,855 3,578,213 Expressed as $/kWh 16 Production $0.03790 $0.04102 $0.03827 $0.03722 $0.03367 $0.03441 $0.03489 $0.03044 17 Transmission $0.00833 $0.01015 $0.00848 $0.00786 $0.00595 $0.00641 $0.00642 $0.00361 18 Distribution $0.02063 $0.02879 $0.02622 $0.01955 $0.00513 $0.00080 $003558 $0.17610 19 Common $0.01404 $0.02068 $0.01658 $0.01007 $0.00628 $0.00555 $0.01444 $0.04203 20 Total Current Uniform Melded Rates $0.08089 $0.10065 $0 08954 $0.07470 $005104 $0.04716 $0.09133 $0.25218 21 Revenue to Cost Ratio at Current Rates 1.00 0.92 1.12 106 1.08 1.07 0.96 0.98 Functional Cost Components at Proposed Return by Schedule 22 Production 116,951,569 45,220,072 14,997,271 25,799,984 12,749,325 15,481,021 2,268,589 435,306 23 Transmission 26,380,297 10,518,528 3,793,794 5,909,315 2,493,252 3,199,113 413,944 52,352 24 Distribution 63,624,243 30,547,580 11,230,294 14,496,417 2,111,971 395,846 2,299,031 2,543,103 25 Common 42,892,891 22,565,820 6,666,641 7,123,284 2,438,451 2,558,020 937,436 603,239 26 Total Proposed Rate Revenue 249,849,000 108,852,000 36,688,000 53,329,000 19,793,000 21,634,000 5,919,000 3,634,000 Expressed as $/kWh 27 Production $0.03884 $0.03955 $0.04193 $0.03924 $0.03603 $0.03691 $0.03471 $0.03068 28 Transmission $0.00876 $0.00920 $0.01061 $0.00899 $0.00705 $0.00763 $0.00633 $0.00369 29 Distribution $0.02113 $0 02672 $0.03140 $0.02205 $0.00597 $0.00094 $0 03517 $0.17923 30 Common $0.01424 $0.01974 $0.01864 $0.01083 $0 00689 $0.00610 $0.01434 $0.04251 31 Total Proposed Melded Rates $0.08297 $0 09521 $0.10257 $0.08111 $0.05593 $0.05157 $0.09055 $0.25611 Functional Cost Components at Uniform Requested Return 32 Production 116,060,094 47,697,938 13,920,364 24,885,366 12,118,290 14,679,797 2,319,105 439,233 33 Transmission 26,198,029 12,128,378 3,167,656 5,402,024 2,200,478 2,807,578 438,340 53,575 34 Distribution 64,360,317 34,036,086 9,708,775 13,368,580 1,887,993 349,175 2,415,756 2,593,951 35 Common 43,230,560 24,158,070 6,060,652 6,777,981 2,276,286 2,380,526 965,960 611,085 36 Total Uniform Cost 249,849,000 118,020,473 32,857,446 50,433,952 18,483,047 20,217,075 6,139,162 3,697,845 Expressed as $/kWh 37 Production $0.03854 $0 04172 $0.03892 $0.03785 $0.03424 $0.03500 $0.03548 $0.03096 38 Transmission $0.00870 $0.01061 $0.00886 $0 00822 $0 00622 $0.00669 $0.00671 $0.00378 39 Distribution $0.02137 $0.02977 $0.02714 $0.02033 $0.00534 $0.00083 $0.03696 $0.18281 40 Common $0.01436 $0.02113 $0.01694 $0.01031 $0.00643 $0.00568 $0.01478 $0.04307 41 Total Uniform Melded Rates $0.08297 $0.10323 $0.09186 $0.07671 $0 05223 $0 04820 $0.09392 $0.26061 42 Revenue to Cost Ratio at Proposed Rates 1.00 0.92 1.12 1.06 1.07 1.07 0.96 0.98 43 Current Revenue to Proposed Cost Ratio 0.97 0.89 1.10 1.03 1.05 1.05 0.94 0.95 44 Target Revenue Increase 6,250,000 12,499,000 (3,164,000) {1,699,000) (936,000) {1,030,000) 397,000 183,000 Stipulation and Settlement Case No. AVU-E-16-03 Avista Appendix B Page 4 of 4 AVISTA UTILITIES IDAHO ELECTRIC, CASE NO. AVU-E-16-03 PROPOSED INCREASE BY SERVICE SCHEDULE 12 MONTHS ENDED DECEMBER 31, 2015 (OOOs of Dollars) Base Tariff Base Tariff Base Total Billed Total Billed Percent Revenue Proposed Revenue Tariff Revenue Total Revenue Increase Line Type of Schedule Under Present General Under Proposed Percent at Present General at Proposed on Billed No. Service Number Rates(1) Increase Rates (1) Increase Rates(2) Increase (a) (b) (c) (d) (e) (f} (g) (h) Residential 1 $105,522 $3,330 $108,852 3.2% $106,402 $3,330 2 General Service 11,12 $36,021 $667 $36,688 1.9% $36,604 $667 3 Large General Service 21,22 $52,133 $1,196 $53,329 2.3% $52,797 $1,196 4 Extra Large General Service 25 $19,419 $374 $19,793 1.9% $19,540 $374 5 Clearwater 25P $21,247 $387 $21,634 1.8% $21 ,343 $387 6 Pumping Service 31,32 $5,742 $177 $5,919 3.1% $5,828 $177 7 Street & Area Lights 41-49 $3.515 illi. $3.634 3.4% $3.594 illi. 8 Total $243,599 $6,250 $249,849 2.6% $246,107 $6,250 (1) Excludes all present rate adjustments (see below). (2) Includes all present rate adjustments: Schedule 59 -Residential & Farm Energy Rate Adjustment, Schedule 66 -Temporary Power Cost Adjustment, Schedule 91 -Energy Efficiency Rider Adjustment, and Schedule 97 -Earnings Test Deferral. Pro-rata Allocation of Avista Proposed Type of Schedule Service Number Residential 1 General Service 11, 12 Large General Service 21,22 Extra Large General Service 25 Clearwater 25P Pumping Service 31,32 Street & Area Lights 41-49 Original Proposed General Increase $8,223 $1 ,648 $2,954 $924 $955 $436 $293 $15,433 Percentage of Total 53.28% 10.68% 19.14% 5.98% 6.19% 2.83% 1.90% 100.00% Settlement Spread $6.25 Million $3,330 $667 $1,196 $374 $387 $177 illi. $6,250 Appendix C Rates(2) (i) $109,732 $37,270 $53,993 $19,913 $21,730 $6,005 $3.713 $252,357 Revenue U) 3.1% 1.8% 2.3% 1.9% 1.8% 3.0% 3.3% 2.5% Stipulation and Settlement Case No. AVU-E-16-03 Avista Page 1 of 2 AVISTA UTILITIES IDAHO ELECTRIC, CASE NO. AVU-E-16-03 PRESENT AND PROPOSED RATE COMPONENTS BY SCHEDULE Effective January 1, 2017 General Proposed Proposed Base Tariff Present Present Rate Billing Base Tariff Sch. Rate Other Adj.(1) Billing Rate lnc/{Decr) Rate Rate (a) (b) (c) (d) (e) (f) (g) Residential Service -Schedule 1 Basic Charge $5.25 $5.25 $0.50 $5.75 $5.75 Energy Charge: First 600 kWhs $0.08224 $0.00077 $0.08301 $0.00225 $0.08526 $0.08449 All over 600 kWhs $0.09183 $0.00077 $0.09260 $0.00251 $0.09511 $0.09434 General Services -Schedule 11 Basic Charge $10.00 $10.00 $2.00 $12.00 $12.00 Energy Charge: First 3,650 kWhs $0.09686 $0.00163 $0.09849 $0.00018 $0.09867 $0.09704 All over 3,650 kWhs $0.07216 $0.00163 $0.07379 $0.00000 $0.07379 $0.07216 Demand Charge: 20 kW or less no charge no charge no charge no charge Over20 kW $5.25/kW $5.25/kW $0.50/kW $5.75/kW $5.75/kW Large General Service -Schedule 21 Energy Charge: First 250,000 kWhs $0.06344 $0.00101 $0.06445 ($0.00022) $0.06423 $0.06322 All over 2 (2) Includes all presen $0.05414 $0.00101 $0.05515 ($0.00018) $0.05497 $0.05396 Demand Charge: 50 kW or less $350.00 $350.00 $50.00 $400.00 $400.00 Over50 kW $4.75/kW $4.75/kW $0.50/kW $5.25/kW $5.25/kW Primary Voltage Discount $0.20/kW $0.20/kW $0.20/kW $0.20/kW Extra Large General Service -Schedule 25 Energy Charge: First 500,000 kWhs $0.05251 $0.00034 $0.05285 $0.00048 $0.05333 $0.05299 All over 500,000 kWhs $0.04446 $0.00034 $0.04480 $0.00041 $0.04521 $0.04487 Demand Charge: 3,000 kva or less $12,500 $12,500 $1,000 $13,500 $13,500 Over 3,000 kva $4.50/kva $4.50/kva $0.25/kva $4.75/kva $4.75/kva Primary Volt. Discount $0.20/kW $0.20/kW $0.20/kW $0.20/kW Annual Minimum Present: $687,360 $704,290 Clearwater -Schedule 25P Energy Charge: all kWhs $0.04272 $0.00023 $0.04295 $0.00036 $0.04331 $0.04308 Demand Charge: 3,000 kva or less $12,500 $12,500 $1,000 $13,500 $13,500 3,000 -55,000 kva $4.50/kva $4.50/kva $0.25/kva $4.75/kva $4.75/kva Over 55,000 kva $2.00/kva $2.00/kva $0.25/kva $2.25/kva $2.25/kva Primary Volt. Discount $0.20/kW $0.20/kW $0.20/kW $0.20/kW Annual Minimum Present: $619,920 $635,880 PumQing Service -Schedule 31 Basic Charge $8.00 $8.00 $2.00 $10.00 $10.00 Energy Charge: First 165 kW/kWhs $0.09365 $0.00132 $0.09497 $0.00240 $0.09737 $0.09605 All additional kWhs $0.07983 $0.00132 $0.08115 $0.00204 $0.08319 $0.08187 (1) Includes all present rate adjustments: Schedule 59 -Residential & Farm Energy Rate Adjustment, Schedule 66 - Temporary Power Cost Adjustment, Schedule 91 -Energy Efficiency Rider Adjustment, and Schedule 97 -Earnings Test Deferral Appendix C Stipulation and Settlement Case No. AVU-E-16-03 Avista Page 2 of 2