20150601Miller Exhibit 14.pdf

DAVID J. MEYER VICE PRESIDENT AND CHIEF COUNSEL FOR
REGULATORY & GOVERNMENTAL AFFAIRS AVISTA CORPORATION P.O. BOX 3727 1411 EAST MISSION AVENUE SPOKANE, WASHINGTON 99220-3727
TELEPHONE: [phone] FACSIMILE: [phone] [e-mail]

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

IN THE MATTER OF THE APPLICATION ) OF AVISTA CORPORATION FOR THE ) CASE NO. AVU-G-15-01
AUTHORITY TO INCREASE ITS RATES ) AND CHARGES FOR ELECTRIC AND )
NATURAL GAS SERVICE TO ELECTRIC ) Exhibit No. 14 AND NATURAL GAS CUSTOMERS IN THE ) STATE OF IDAHO ) JOSEPH D. MILLER
)
FOR AVISTA CORPORATION
(NATURAL GAS)

NATURAL GAS COST OF SERVICE STUDY 1
A cost of service study is an engineering-economic study, which apportions the revenue, 2
expenses, and rate base associated with providing natural gas service to designated groups of 3
customers. It indicates whether the revenue provided by customers recovers the cost to serve those 4
customers. The study results are used as a guide in determining the appropriate rate spread among 5
the groups of customers. 6
There are three basic steps involved in a cost of service study: functionalization, 7
classification, and allocation. See the flow chart below. 8
First, the expenses and rate base associated with the natural gas system under study are 9
assigned to functional categories. The uniform system of accounts provides the basic segregation 10
into production, underground storage, and distribution. Traditionally customer accounting, 11
customer information, and sales expenses are included in the distribution function and 12
administrative and general expenses and general plant rate base are allocated to all functions. This 13
study includes a separate functional category for common costs. Administrative and general costs 14
that cannot be directly assigned to the other functions have been placed in this category. 15
Second, the expenses and rate base items are classified into three primary cost components: 16
demand, commodity and customer related. Demand (capacity) related costs are allocated to rate 17
schedules on the basis of each schedule’s contribution to system peak demand. Commodity 18
(energy) related costs are allocated based on each rate schedule’s share of commodity 19
consumption. Customer related items are allocated to rate schedules based on the number of 20
customers within each schedule. The number of customers may be weighted by appropriate 21
factors such as relative cost of metering equipment. In addition to these three cost components, 22
any revenue related expense is allocated based on the proportion of revenues by rate schedule. 23
Exhibit No. 14 Case No. AVU-G-15-01 J. Miller, Avista
Schedule 1, p. 1 of 9
Pro Forma Results of Operations by Customer Group
Underground Storage
Production / Purchased Gas Cost
Distribution and Customer Relations
Energy / Commodity Related
Customer RelatedDemand / Capacity Related
Residential
101
Small General111/112 Interruptible131/132
Transportation146
Pro Forma
Results of Operations
Functionalization
Common
Classification
Allocation
Direct AssignmentThroughputSales Therms
Firm Therms Direct AssignmentCoincident PeakNon-Coincident Peak
Direct AssignmentNumber of CustomersWeighted Number of
Customers
The final step is allocation of the costs to the various rate schedules utilizing the allocation 1
factors selected for each specific cost item. These factors are derived from usage and customer 2
information associated with the test period results of operations. 3
Exhibit No. 14 Case No. AVU-G-15-01 J. Miller, Avista
Schedule 1, p. 2 of 9
BASE CASE COST OF SERVICE STUDY 1
Production - Purchased Gas Costs 2
The Company has no natural gas production facilities to serve its retail customers. In 3
addition, the revenue and expenses associated with the gas purchased to serve sales customers and 4
pipeline transportation to get it to our system have been removed from the Company’s filing. The 5
natural gas costs included in the production function include the expenses of the gas supply 6
department. 7
The expenses of the gas supply department recorded in account 813 are classified as 8
commodity related costs. The gas scheduling process includes transportation customers, so 9
estimated scheduling dispatch labor expenses are allocated by throughput. The remaining gas 10
supply department expenses are allocated 95% by sales volumes and 5% on total throughput. 11
Underground Storage 12
Underground storage rate base, operating and maintenance expenses are classified as 13
commodity related and allocated to customer groups by winter throughput. This approach was 14
proposed by commission Staff and accepted by the Idaho Public Utilities Commission in Case No. 15
AVU-G-04-01. 16
Distribution Facilities Classification (Peak and Average) 17
Distribution mains and regulator station equipment (both general use and city gate stations) 18
are classified Demand and Commodity using the peak and average ratio for the distribution 19
system. Peak demand is defined as the average of the five-day sustained peaks from the most 20
recent three years. Average daily load is calculated by dividing annual throughput by 365 (days in 21
the year). The average daily load is divided by peak load to arrive at the system load factor of 22
44.92%. This proportion is classified as commodity related. The remaining 55.08% is classified 23
as demand related. Meters, services and industrial measuring & regulating equipment are 24
Exhibit No. 14 Case No. AVU-G-15-01 J. Miller, Avista
Schedule 1, p. 3 of 9
classified as customer related distribution plant. Distribution operating and maintenance expenses 1
are classified (and allocated) in relation to the plant accounts they are associated with. 2
Customer Relations Distribution Cost Classification 3
Customer service, customer information and sales expenses are the core of the customer 4
relations functional unit which is included with the distribution cost category. For the most part 5
these costs are classified as customer related. Exceptions include uncollectible accounts expense, 6
which is considered separately as a revenue conversion item, and any Demand Side Management 7
amortization expense recorded in Account 908. Any demand side management investment costs 8
and amortization expense included in base rates would be included with the distribution function 9
and classified to demand and commodity by the peak and average ratio. At this point in time, the 10
Company’s demand side management investments in base rates have been fully amortized. All 11
current demand side management costs are managed through the Schedule 191 Energy Efficiency 12
Rider Adjustment balancing account which is not included in this cost study. 13
Distribution Cost Allocation 14
Demand related distribution costs are allocated to customer groups (rate schedules) by each 15
groups’ contribution to the three year average five-day sustained peak. Commodity related 16
distribution costs are allocated to customer groups by annual throughput. Distribution main 17
investment has been segregated into large and small mains. Small mains are defined as less than 18
four inches, with large mains being four inches or greater. The small main costs use the same 19
demand and commodity data, but large usage customers (Schedules 131, 132, and 146) that 20
connect to large system mains have been excluded from the allocations. 21
Most customer related costs are allocated by the annualized number of customers billed 22
during the test period. Meter investment costs are allocated using the number of customers 23
weighted by the relative current cost of meters in service at December 31, 2014. Services 24
Exhibit No. 14 Case No. AVU-G-15-01 J. Miller, Avista
Schedule 1, p. 4 of 9
investment costs are allocated using the number of customers weighted by the relative current cost 1
of typical service installations. Industrial measuring and regulating equipment investment costs 2
are allocated by number of turbine meters which effectively excludes small usage customers. 3
Administrative and General Costs 4
General and intangible rate base items are allocated by the Company’s 4-factor allocator. 5
Administrative and general expenses are segregated into plant related, labor related, revenue 6
related and other. The plant related items are allocated based on total plant in service. Labor 7
related items are allocated by operating and maintenance labor expense. Revenue related items are 8
allocated by pro forma revenue. Other administrative and general expenses are allocated by the 9
Company’s 4-factor. Whenever costs are allocated by sums of other items within the study, 10
classifications are imputed from the relationship embedded in the summed items. 11
Special Contract Customer Revenue 12
Two special contract customers receive transportation service from the Company. Rates 13
for these customers were individually negotiated to cover any incremental costs together with 14
some contribution to margin. The rates for these customers are not being adjusted in this case. 15
The revenue from these special contract customers has been segregated from general rate revenue 16
and allocated back to all the other rate classes by relative rate base. In treating these revenues like 17
other operating revenues their system contribution reduces costs for all rate schedules. 18
Revenue Conversion Items 19
In this study uncollectible accounts and commission fees have been classified as revenue 20
related and are allocated by pro forma revenue. These items vary with revenue and are included in 21
the calculation of the revenue conversion factor. Income tax expense items are allocated to 22
schedules by net income before income tax less interest expense. 23
Exhibit No. 14 Case No. AVU-G-15-01 J. Miller, Avista
Schedule 1, p. 5 of 9
For the functional summaries on pages 2 and 3 of the cost of service study, these items are 1
assigned to the component cost categories. The revenue related expense items have been reduced 2
to a percent of all other costs and loaded onto each cost category by that ratio. Similarly, income 3
tax items have been assigned to cost categories by relative rate base (as is net income). 4
The following matrix outlines the methodology applied in the Company Base Case natural 5
gas cost of service study. 6
Exhibit No. 14 Case No. AVU-G-15-01 J. Miller, Avista
Schedule 1, p. 6 of 9
IPUC Case No. AVU-G-15-01 Methodology Matrix
Avista Utilities Idaho Jurisdiction
Natural Gas Cost of Service Methodology
Line Account Functional Category Classification Allocation
Underground Storage Plant1 350 - 357 Underground Storage Underground Storage Commodity E08 Winter throughput
Distribution Plant
2 374 Land Distribution Demand/Commodity/Customer from Other Dist Plant S05 Sum of accounts 376-385
3 375 Structures Distribution Demand/Commodity/Customer from Other Dist Plant S05 Sum of accounts 376-385
4 376(S) Small Mains Distribution Demand/Commodity by Peak & Average D02/E06 Coincident peak, annual therms (both excl lg use cust)
5 376(L) Large Mains Distribution Demand/Commodity by Peak & Average D01/E01 Coincident peak (all), annual throughput (all)
6 378 M&R General Distribution Demand/Commodity by Peak & Average D01/E01 Coincident peak (all), annual throughput (all)
7 379 M&R City Gate Distribution Demand/Commodity by Peak & Average D01/E01 Coincident peak (all), annual throughput (all)
8 380 Services Distribution Customer C02, Customers wei hted b current t ical service cos9 381 Meters Distribution Customer C03, Customers wei hted b avera e current meter cos10 385 Industrial M&R Distribution Customer C06, Lar e use customers 11 387 Other Distribution Demand/Commodity/Customer from Other Dist Plant S05 Sum of accounts 376-385
General Plant
12 389-399 All General Plant Common Demand/Commodity/Customer 4-Factor O&M less resource & labor, O&M labor, net direct lant, & customers
Intangible Plant
13 303 Misc Intangible Plant Distribution Demand/Commodity/Customer from Dist Plant S15 Sum of Distribution Plant in Service
14 303 Computer Software Common Demand/Commodity/Customer 4-Factor O&M less resource & labor, O&M labor, net direct lant, & customers
Reserve for Depreciation
15 Underground Storage Underground Storage Commodity same as related plant Allocations linked to related plant accounts16 Distribution Distribution Demand/Commodity/Customer same as related plant Allocations linked to related plant accounts17 General Common Demand/Commodity/Customer same as related plant Allocations linked to related plant accounts18 Intangible Distribution/Common Demand/Commodity/Customer same as related plant Allocations linked to related plant accounts
Other Rate Base
19 Accumulated Deferred FIT All Demand/Commodity/Customer from Plant in Service S17 Sum of Total Plant in Service
20 Constuction Advances Distribution Customer C10 Residential only
21 Gas Inventory Underground Storage Commodity from Underground Storage Plant S14 Sum of Underground Storage Plant in Service
22 Gain on Sale of Office Bldg Common Demand/Commodity/Customer from UG & D Plant S03 Sum of Underground Storage and Distribution Plant in Service
23 DSM Investment Distribution Demand/Commodity by Peak & Average D01/E01 Coincident peak (all), annual throughput (all)
Purchased Gas Expenses
24 804 Purchased Gas Cost Production Removed all Purchased Gas Costs from Filing N/A25 813 Other Gas Expenses Production Commodity E01/E04 Annual Throughput / Annual Sales Therms
Underground Storage O&M26 814 - 837 Underground Storage Exp Underground Storage Commodity E08 Winter throughput
Exhibit No. 14
Case No. AVU-G-15-01
J. Miller, Avista
Schedule 1, p. 7 of 9
IPUC Case No. AVU-G-15-01 Methodology Matrix
Avista Utilities Idaho Jurisdiction
Natural Gas Cost of Service Methodology
Line Account Functional Category Classification Allocation
Distribution O&M1 870 OP Super & Engineering Distribution Demand/Commodity/Customer from Dist Plant S15 Sum of Distribution Plant in Service2 871 Load Dispatching Distribution Commodity E01 Annual throughput3 874 Mains & Services Distribution Demand/Commodity/Customer from related plant S06 Sum of Mains and Services Plant in Service
4 875 M&R Station - General Distribution Demand/Commodity from related plant S08 Sum of Meas & Reg Station - General Plant in Service
5 876 M&R Station - Industrial Distribution Customer from related plant S19 Sum of Meas & Reg Station - Industrial Plant in Service
6 877 M&R Station - City Gate Distribution Demand/Commodity from related plant S09 Sum of Meas & Reg Station - City Gate Plant in Service
7 878 Meter & House Regulator Distribution Customer from related plant S07 Sum of Meter and Installation Plant in Service
8 879 Customer Installations Distribution Customer C05, Customers wei hted b avera e current meter cos9 880 Other OP Expenses Distribution Demand/Commodity/Customer from other dist expense S04 Sum of Accounts 870 - 879 and 881 - 894
10 881 Rents Distribution Demand/Commodity/Customer from other dist expense S04 Sum of Accounts 870 - 879 and 881 - 894
11 885 MT Super & Engineering Distribution Demand/Commodity/Customer from Dist Plant S15 Sum of Distribution Plant in Service12 886 MT of Structures Distribution Demand/Commodity/Customer from Other Dist Plant S05 Sum of accounts 376-38513 887 MT of Mains Distribution Demand/Commodity from related plant S21 Sum of Distribution Mains Plant in Service14 889 MT of M&R General Distribution Demand/Commodity from related plant S08 Sum of Meas & Reg Station - General Plant in Service15 890 MT of M&R Industrial Distribution Customer from related plant S19 Sum of Meas & Reg Station - Industrial Plant in Service
16 891 MT of M&R City Gate Distribution Demand/Commodity from related plant S09 Sum of Meas & Reg Station - City Gate Plant in Service
17 892 MT of Services Distribution Customer from related plant S20 Sum of Services Plant in Services
18 893 MT of Meters & Hs Reg Distribution Customer from related plant S07 Sum of Meter and Installation Plant in Service
19 894 MT of Other Equipment Distribution Demand/Commodity/Customer from Dist Plant S15 Sum of Distribution Plant in Service
Customer Accounting Expenses
20 901 Supervision Customer Relations Customer C01 All customers (unweighted)
21 902 Meter Reading Customer Relations Customer C01 All customers (unweighted)22 903 Customer Records & Collections Customer Relations Customer C01 All customers (unweighted)23 904 Uncollectible Accounts Revenue Conversion Revenue R03 Retail Sales Revenue24 905 Misc Cust Accounts Customer Relations Customer C01 All customers (unweighted)
Customer Service & Info Expenses
25 907 Supervision Customer Relations Customer C01 All customers (unweighted)
26 908 Customer Assistance Customer Relations Customer C01 All customers (unweighted)
27 908 DSM Amortization Distribution Demand/Commodity by Peak & Average D01/E01 Coincident peak (all), annual throughput (all)
28 909 Advertising Customer Relations Customer C01 All customers (unweighted)
29 910 Misc Cust Service & Info Customer Relations Customer C01 All customers (unweighted)
Sales Expenses
30 911 - 916 Sales Expenses Customer Relations Customer C01 All customers (unweighted)
Exhibit No. 14
Case No. AVU-G-15-01
J. Miller, Avista
Schedule 1, p. 8 of 9
IPUC Case No. AVU-G-15-01 Methodology Matrix
Avista Utilities Idaho Jurisdiction
Natural Gas Cost of Service Methodology
Line Account Functional Category Classification Allocation
Admin & General Expenses1 920 Salaries Common Demand/Commodity/Customer from Other O&M 4-Factor O&M less resource & labor, O&M labor, net direct lant, & customers2 921 Office Supplies Common Demand/Commodity/Customer from Other O&M 4-Factor O&M less resource & labor, O&M labor, net direct lant, & customers3 922 Admin Expense Transferred - Credit Common Demand/Commodity/Customer from Other O&M 4-Factor O&M less resource & labor, O&M labor, net direct lant, & customers
4 923 Outside Services Common Demand/Commodity/Customer from Other O&M 4-Factor O&M less resource & labor, O&M labor, net direct lant, & customers
5 924 Property Insurance Common Demand/Commodity/Customer from Plant in Service S17 Sum of Total Plant in Service
6 925 Injuries & Damages Common Demand/Commodity/Customer from Other O&M 4-Factor O&M less resource & labor, O&M labor, net direct lant, & customers
7 926 Pensions & Benefits Common Demand/Commodity/Customer from Labpr O&M S13 O&M Labor Expense
8 927 Franchise Requirements Common Demand/Commodity/Customer from Other O&M 4-Factor O&M less resource & labor, O&M labor, net direct lant, & customers9 928 Regulatory Commision Common Demand/Commodity/Customer from Other O&M 4-Factor O&M less resource & labor, O&M labor, net direct lant, & customers10 928 Commission Fees Revenue Conversion Revenue R01 Retail Sales Revenue
11 930 Miscellaneous General Common Demand/Commodity/Customer from Other O&M 4-Factor O&M less resource & labor, O&M labor, net direct lant, & customers12 931 Rents Common Demand/Commodity/Customer from Other O&M 4-Factor O&M less resource & labor, O&M labor, net direct lant, & customers13 935 MT of General Plant Common Demand/Commodity/Customer from Plant in Service S17 Sum of Total Plant in Service
Depreciation Expense
14 Underground Storage Underground Storage Commodity same as related plant Allocations linked to related plant accounts
15 Distribution Distribution Demand/Commodity/Customer same as related plant Allocations linked to related plant accounts
16 General Common Demand/Commodity/Customer same as related plant Allocations linked to related plant accounts
17 Intangible Distribution/Common Demand/Commodity/Customer same as related plant Allocations linked to related plant accounts
Taxes
18 Property Tax All Demand/Commodity/Customer from related plant S14/S15/S16 Sum of UG Plant/Sum of Dist Plant/Sum of Gen Plant
19 Miscellaneous Dist Tax Distribution Demand/Commodity/Customer from Dist Plant S15 Sum of Distribution Plant in Service20 State Income Tax Revenue Conversion Revenue R02 Net Income before Taxes less Interest Expense21 Federal Income Tax Revenue Conversion Revenue R02 Net Income before Taxes less Interest Expense22 Deferred FIT Revenue Conversion Revenue R02 Net Income before Taxes less Interest Expense23 ITC Revenue Conversion Revenue R02 Net Income before Taxes less Interest Expense
Operating Revenues
24 Revenue from Rates Revenue Revenue Pro Forma Revenue per Revenue Study
25 Special Contract Revenue All Demand/Commodity/Customer from Rate Base S01 Sum of Rate Base
26 Off System Sales Production Commodity from PGA Tracker E04 Sales Therms
27 Miscellaneous Service Revenue Distribution Demand/Commodity/Customer from Dist Plant S15 Sum of Distribution Plant in Service
28 Rent From Gas Property All Demand/Commodity/Customer from Rate Base S01 Sum of Rate Base
29 Other Gas Revenue Underground Storage Commodity from Underground Storage Plant S14 Sum of Underground Storage Plant in Service
Exhibit No. 14
Case No. AVU-G-15-01
J. Miller, Avista
Schedule 1, p. 9 of 9
AVISTA UTILITIES Natural Gas Utility
Company Base Case Cost of Service General Summary Idaho Jurisdiction
For the Year Ended December 31, 2014

(b) (c) (d) (e) (f) (g) (h) (j) (k)
Residential Large Firm Interrupt Transport
System Service Service Service Service
Line Description Total Sch 101 Sch 111 Sch 131 Sch 146
Plant In Service
1 Production Plant
2 Underground Storage Plant 11,020,000 8,033,154 2,716,189 34,278 236,379
3 Distribution Plant 185,053,000 151,801,662 31,358,997 401,267 1,491,074
4 Intangible Plant 4,645,000 4,063,089 545,334 6,149 30,428
5 General Plant 28,535,000 25,186,558 3,133,521 34,261 180,659
6 Total Plant In Service 229,253,000 189,084,463 37,754,041 475,956 1,938,540
Accum Depreciation
7 Production Plant
8 Underground Storage Plant (4,263,000) (3,107,562) (1,050,736) (13,260) (91,441)
9 Distribution Plant (64,859,000) (54,366,703) (9,894,452) (125,986) (471,859)
10 Intangible Plant (1,885,000) (1,663,805) (206,998) (2,263) (11,934)
11 General Plant (8,192,000) (7,230,709) (899,590) (9,836) (51,865)
12 Total Accumulated Depreciation (79,199,000) (66,368,779) (12,051,776) (151,346) (627,099)
13 Net Plant 150,054,000 122,715,684 25,702,265 324,610 1,311,441
14 Accumlulated Deferred FIT (32,216,000) (26,571,277) (5,305,423) (66,884) (272,415)
15 Miscellaneous Rate Base 9,660,000 7,373,459 2,098,858 26,480 161,203
16 Total Rate Base 127,498,000 103,517,866 22,495,700 284,206 1,200,229
17 Revenue From Retail Rates 36,173,000 29,139,824 6,625,127 67,596 340,452
18 Other Operating Revenues 222,000 180,330 39,100 494 2,076
19 Total Revenues 36,395,000 29,320,154 6,664,227 68,091 342,529
Operating Expenses
20 Purchased Gas Costs 335,000 234,497 96,586 1,391 2,527
21 Underground Storage Expenses 368,000 268,258 90,704 1,145 7,894
22 Distribution Expenses 6,043,000 5,082,658 884,970 8,880 66,492
23 Customer Accounting Expenses 2,228,000 2,165,164 61,228 266 1,341
24 Customer Information Expenses 365,000 358,404 6,567 5 24
25 Sales Expenses (0) (0) (0) (0) (0)
26 Admin & General Expenses 5,621,000 4,902,434 672,916 7,589 38,061
27 Total O&M Expenses 14,960,000 13,011,415 1,812,972 19,276 116,337
28 Taxes Other Than Income Taxes 1,937,000 1,580,453 335,406 4,288 16,853
29 Depreciation Expense
30 Underground Storage Plant Depr 182,000 132,671 44,859 566 3,904
31 Distribution Plant Depreciation 4,628,000 3,801,615 779,647 9,911 36,826
32 General Plant Depreciation 1,987,000 1,753,835 218,199 2,386 12,580
33 Amortization of Intangible Plant 1,113,000 907,465 193,283 2,471 9,781
34 Total Depr & Amort Expense 7,910,000 6,595,586 1,235,989 15,334 63,091
35 Income Tax 3,843,000 2,521,115 1,258,113 10,145 53,627
36 Total Operating Expenses 28,650,000 23,708,570 4,642,479 49,043 249,908
37 Net Income 7,745,000 5,611,584 2,021,748 19,048 92,620
38 Rate of Return 6.07% 5.42% 8.99% 6.70% 7.72%
39 Return Ratio 1.00 0.89 1.48 1.10 1.27
40 Interest Expense 3,404,000 2,763,767 600,601 7,588 32,044
Exhibit No. 14
Case No. AVU-G-15-01
J. Miller, Avista
Schedule 2, p. 1 of 4
AVISTA UTILITIES Natural Gas Utility
Company Base Case Summary by Function with Margin Analysis Idaho Jurisdiction
For the Year Ended December 31, 2014

(b) (c) (d) (e) (f) (g) (h) (j) (k)
Residential Large Firm Interrupt Transport
System Service Service Service Service
Line Description Total Sch 101 Sch 111 Sch 131 Sch 146
Functional Cost Components at Current Rates
1 Production 337,031 235,918 97,171 1,399 2,542
2 Underground Storage 1,719,472 1,107,975 562,773 5,581 43,144
3 Distribution 23,628,251 18,839,423 4,525,714 45,395 217,719
4 Common 10,488,246 8,956,508 1,439,469 15,221 77,048
5 Total Current Rate Revenue 36,173,000 29,139,824 6,625,127 67,596 340,452
6 Exclude Cost of Gas w / Revenue Exp. 0 0 0 0 0
7 Total Margin Revenue at Current Rates 36,173,000 29,139,824 6,625,127 67,596 340,452
Margin per Therm at Current Rates
8 Production $0.00413 $0.00423 $0.00423 $0.00423 $0.00094
9 Underground Storage $0.02105 $0.01989 $0.02452 $0.01689 $0.01593
10 Distribution $0.28921 $0.33815 $0.19722 $0.13740 $0.08041
11 Common $0.12838 $0.16076 $0.06273 $0.04607 $0.02846
12 Total Current Margin Melded Rate per Therm $0.44275 $0.52303 $0.28870 $0.20459 $0.12574
Functional Cost Components at Uniform Current Return
13 Production 337,031 235,918 97,171 1,399 2,542
14 Underground Storage 1,659,853 1,209,969 409,118 5,163 35,604
15 Distribution 23,602,001 19,789,048 3,577,829 42,775 192,349
16 Common 10,574,115 9,188,426 1,298,242 14,877 72,571
17 Total Uniform Current Cost 36,173,000 30,423,361 5,382,359 64,214 303,066
18 Exclude Cost of Gas w / Revenue Exp. 0 0 0 0 0
19 Total Uniform Current Margin 36,173,000 30,423,361 5,382,359 64,214 303,066
Margin per Therm at Uniform Current Return
20 Production $0.00413 $0.00423 $0.00423 $0.00423 $0.00094
21 Underground Storage $0.02032 $0.02172 $0.01783 $0.01563 $0.01315
22 Distribution $0.28889 $0.35519 $0.15591 $0.12947 $0.07104
23 Common $0.12943 $0.16492 $0.05657 $0.04503 $0.02680
24 Total Current Uniform Margin Melded Rate per $0.44275 $0.54606 $0.23455 $0.19435 $0.11193
25 Margin to Cost Ratio at Current Rates 1.00 0.96 1.23 1.05 1.12
Functional Cost Components at Proposed Rates
26 Production 337,028 235,917 97,171 1,399 2,542
27 Underground Storage 1,991,177 1,335,243 601,840 6,379 47,715
28 Distribution 26,005,559 20,955,352 4,766,705 50,404 233,098
29 Common 11,044,236 9,473,226 1,475,369 15,879 79,762
30 Total Proposed Rate Revenue 39,378,000 31,999,738 6,941,084 74,061 363,116
31 Exclude Cost of Gas w / Revenue Exp. 0 0 0 0 0
32 Total Margin Revenue at Proposed Rates 39,378,000 31,999,738 6,941,084 74,061 363,116
Margin per Therm at Proposed Rates
33 Production $0.00413 $0.00423 $0.00423 $0.00423 $0.00094
34 Underground Storage $0.02437 $0.02397 $0.02623 $0.01931 $0.01762
35 Distribution $0.31831 $0.37612 $0.20772 $0.15256 $0.08609
36 Common $0.13518 $0.17003 $0.06429 $0.04806 $0.02946
37 Total Proposed Margin Melded Rate per Therm $0.48198 $0.57436 $0.30247 $0.22416 $0.13411
Functional Cost Components at Uniform Proposed Return
38 Production 337,028 235,917 97,171 1,399 2,542
39 Underground Storage 1,943,529 1,416,758 479,037 6,045 41,689
40 Distribution 25,984,580 21,714,298 4,009,149 48,310 212,823
41 Common 11,112,863 9,658,576 1,362,499 15,604 76,184
42 Total Uniform Proposed Cost 39,378,000 33,025,548 5,947,856 71,358 333,237
43 Exclude Cost of Gas w / Revenue Exp. 0 0 0 0 0
44 Total Uniform Proposed Margin 39,378,000 33,025,548 5,947,856 71,358 333,237
Margin per Therm at Uniform Proposed Return
45 Production $0.00413 $0.00423 $0.00423 $0.00423 $0.00094
46 Underground Storage $0.02379 $0.02543 $0.02088 $0.01830 $0.01540
47 Distribution $0.31805 $0.38975 $0.17471 $0.14622 $0.0786048 Common 0.13602 0.17336 0.05937 0.04723 0.02814
49 Total Proposed Uniform Margin Melded Rate pe $0.48198 $0.59277 $0.25919 $0.21598 $0.12307
50 Margin to Cost Ratio at Proposed Rates 1.00 0.97 1.17 1.04 1.09
51 Current Margin to Proposed Cost Ratio 0.92 0.88 1.11 0.95 1.02
Exhibit No. 14
Case No. AVU-G-15-01
J. Miller, Avista
Schedule 2, p. 2 of 4
AVISTA UTILITIES Natural Gas Utility
Company Base Case Summary by Classification with Unit Cost Analysis Idaho Jurisdiction
For the Year Ended December 31, 2014
(b) (c) (d) (e) (f) (g) (h) (j) (k)
Residential Large Firm Interrupt Transport
System Service Service Service Service
Line Description Total Sch 101 Sch 111 Sch 131 Sch 146
Cost by Classification at Current Return by Schedule
1 Commodity 9,175,533 5,898,602 3,078,548 36,446 161,936
2 Demand 7,929,786 5,498,834 2,314,276 29,739 86,937
3 Customer 19,067,681 17,742,388 1,232,303 1,411 91,579
4 Total Current Rate Revenue 36,173,000 29,139,824 6,625,127 67,596 340,452
Revenue per Therm at Current Rates
5 Commodity $0.11231 $0.10587 $0.13415 $0.11031 $0.05981
6 Demand $0.09706 $0.09870 $0.10085 $0.09001 $0.03211
7 Customer $0.23339 $0.31845 $0.05370 $0.00427 $0.03382
8 Total Revenue per Therm at Current Rates $0.44275 $0.52303 $0.28870 $0.20459 $0.12574
Cost per Unit at Current Rates
9 Commodity Cost per Therm $0.11231 $0.10587 $0.13415 $0.11031 $0.05981
10 Demand Cost per Peak Day Therms $15.91 $14.92 $19.64 $17.04 $8.60
11 Customer Cost per Customer per Month $20.61 $19.53 $74.03 $117.59 $1,526.32
Cost by Classification at Uniform Current Return
12 Commodity 8,893,485 6,252,044 2,465,664 34,608 141,170
13 Demand 7,782,498 5,817,937 1,859,788 28,251 76,522
14 Customer 19,497,016 18,353,381 1,056,908 1,355 85,373
15 Total Uniform Current Cost 36,173,000 30,423,361 5,382,359 64,214 303,066
Cost per Therm at Current Return
16 Commodity $0.10886 $0.11222 $0.10745 $0.10475 $0.05214
17 Demand $0.09526 $0.10443 $0.08104 $0.08551 $0.02826
18 Customer $0.23864 $0.32942 $0.04606 $0.00410 $0.03153
19 Total Cost per Therm at Current Return $0.44275 $0.54606 $0.23455 $0.19435 $0.11193
Cost per Unit at Uniform Current Return
20 Commodity Cost per Therm $0.10886 $0.11222 $0.10745 $0.10475 $0.05214
21 Demand Cost per Peak Day Therms $15.62 $15.78 $15.78 $16.19 $7.57
22 Customer Cost per Customer per Month $21.07 $20.20 $63.49 $112.89 $1,422.89
23 Revenue to Cost Ratio at Current Rates 1.00 0.96 1.23 1.05 1.12
Cost by Classification at Proposed Return by Schedule
24 Commodity 10,134,992 6,686,140 3,234,367 39,960 174,525
25 Demand 8,765,515 6,209,858 2,429,824 32,583 93,250
26 Customer 20,477,493 19,103,740 1,276,893 1,519 95,341
27 Total Proposed Rate Revenue 39,378,000 31,999,738 6,941,084 74,061 363,116
Revenue per Therm at Proposed Rates
28 Commodity $0.12405 $0.12001 $0.14094 $0.12095 $0.06446
29 Demand $0.10729 $0.11146 $0.10588 $0.09862 $0.03444
30 Customer $0.25064 $0.34289 $0.05564 $0.00460 $0.03521
31 Total Revenue per Therm at Proposed Rates $0.48198 $0.57436 $0.30247 $0.22416 $0.13411
Cost per Unit at Proposed Rates
32 Commodity Cost per Therm $0.12405 $0.12001 $0.14094 $0.12095 $0.06446
33 Demand Cost per Peak Day Therms $17.59 $16.85 $20.62 $18.67 $9.23
34 Customer Cost per Customer per Month $22.13 $21.03 $76.70 $126.59 $1,589.01
Cost by Classification at Uniform Proposed Return
35 Commodity 9,909,578 6,968,613 2,744,546 38,491 157,929
36 Demand 8,647,802 6,464,886 2,066,595 31,393 84,927
37 Customer 20,820,620 19,592,049 1,136,715 1,474 90,381
38 Total Uniform Proposed Cost 39,378,000 33,025,548 5,947,856 71,358 333,237
Cost per Therm at Proposed Return
39 Commodity $0.12129 $0.12508 $0.11960 $0.11650 $0.05833
40 Demand $0.10585 $0.11604 $0.09006 $0.09502 $0.03137
41 Customer $0.25484 $0.35165 $0.04953 $0.00446 $0.03338
42 Total Cost per Therm at Proposed Return $0.48198 $0.59277 $0.25919 $0.21598 $0.12307
Cost per Unit at Uniform Proposed Return
43 Commodity Cost per Therm $0.12129 $0.12508 $0.11960 $0.11650 $0.05833
44 Demand Cost per Peak Day Therms $17.35 $17.54 $17.54 $17.99 $8.41
45 Customer Cost per Customer per Month $22.50 $21.57 $68.28 $122.83 $1,506.35
46 Revenue to Cost Ratio at Proposed Rates 1.00 0.97 1.17 1.04 1.09
47 Current Revenue to Proposed Cost Ratio 0.92 0.88 1.11 0.95 1.02
Exhibit No. 14
Case No. AVU-G-15-01
J. Miller, Avista
Schedule 2, p. 3 of 4
AVISTA UTILITIES Natural Gas Utility
Company Base Case Customer Cost Analysis Idaho Jurisdiction
For the Year Ended December 31, 2014

(b) (c) (d) (e) (f) (g) (h) (j) (k)
Residential Large Firm Interrupt Transport
System Service Service Service ServiceLine Description Total Sch 101 Sch 111 Sch 131 Sch 146
Rate Base
1 Services 57,836,000 56,620,726$ 1,162,029$ 2,528$ 50,717$
2 Services Accum. Depr. (26,039,000) (25,491,858)$ (523,170)$ (1,138)$ (22,834)$
3 Total Services 31,797,000 31,128,868 638,859 1,390 27,883
4 Meters 24,149,000 21,016,940$ 3,036,231$ 5,000$ 90,828$
5 Meters Accum. Depr. (6,476,000) (5,636,080)$ (814,221)$ (1,341)$ (24,357)$
6 Total Meters 17,673,000 15,380,860 2,222,010 3,659 66,471
7 Total Rate Base 49,470,000 46,509,728 2,860,869 5,049 94,354
8 Return on Rate Base @ 7.62% 3,769,614 3,544,041 217,998 385 7,190
9 Tax Benefit of Interest Expense (462,297) (434,633) (26,735) (47) (882)
10 Revenue Conversion Factor 0.61459 0.61459 0.61459 0.61459 0.61459
11 Rate Base Revenue Requirement 5,381,339 5,059,321 311,205 549 10,264
Expenses
12 Services Depr Exp 1,416,000 1,386,246$ 28,450$ 62$ 1,242$
13 Meters Depr Exp 675,000 587,454$ 84,867$ 140$ 2,539$
14 Services Maintenance Exp 874,999 856,614$ 17,580$ 38$ 767$
15 Meters Maintenance Exp 769,999 670,133$ 96,811$ 159$ 2,896$
16 Meter Reading 201,001 197,368$ 3,617$ 3$ 13$
17 Billing 1,779,999 1,747,834$ 32,027$ 23$ 115$
18 Total Expenses 5,716,998 5,445,649 263,352 425 7,572
19 Revenue Conversion Factor 0.994222 0.994222 0.994222 0.994222 0.994222
20 Expense Revenue Requirement 5,750,223 5,477,297 264,882 427 7,616
21 11,131,561 10,536,617 576,087 977 17,880
22 Total Customer Bills 925,202 908,483 16,647 12 60
23 Average Unit Cost per Month $12.03 $11.60 $34.61 $81.39 $298.00
24 Total Customer Related Cost 20,820,620 19,592,049 1,136,715 1,474 90,381
25 Customer Related Unit Cost per Month $22.50 $21.57 $68.28 $122.83 $1,506.35
26 Other Non-Gas Costs 18,557,380 13,433,499 4,811,141 69,884 242,856
27 Other Non-Gas Unit Cost per Month $20.06 $14.79 $289.01 $5,823.68 $4,047.60
28 Total Fixed Unit Cost per Month $42.56 $36.35 $357.29 $5,946.51 $5,553.95
Total Meter, Service, Meter Reading, and
Meter, Services, Meter Reading & Billing Costs by Schedule at Requested Rate of Return
Fixed Costs per Customer
Exhibit No. 14
Case No. AVU-G-15-01
J. Miller, Avista
Schedule 2, p. 4 of 4