20170612Miller Exhibit 15.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-17-01
AUTHORITY TO INCREASE ITS RATES )
AND CHARGES FOR ELECTRIC AND )
NATURAL GAS SERVICE TO ELECTRIC ) Exhibit No. 15
AND NATURAL GAS CUSTOMERS IN THE )
STATE OF IDAHO ) JOSEPH D. MILLER
)

FOR AVISTA CORPORATION

(NATURAL GAS)

Exhibit No. 15
Case No. AVU-G-17-01
J. Miller, Avista
Schedule 1, p. 1 of 9

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
As shown in the flowchart below, there are three basic steps involved in a cost of service 7
study: functionalization, classification, and allocation. 8
First, the expenses and rate base associated with the natural gas system under study are 9
assigned to functional categories. The FERC uniform system of accounts provides the basic 10
segregation into production, underground storage, and distribution. Traditionally customer 11
accounting, 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-related (capacity) costs are allocated to rate 17
schedules on the basis of each schedule’s contribution to system peak demand. Commodity-related 18
(energy) costs are allocated based on each rate schedule’s share of commodity consumption. 19
Customer-related items are allocated to rate schedules based on the number of customers within 20
each schedule. The number of customers may be weighted by appropriate factors such as relative 21
cost of metering equipment. In addition to these three cost components, any revenue-related expense 22
is allocated based on the proportion of revenues by rate schedule. 23
Exhibit No. 15
Case No. AVU-G-17-01
J. Miller, Avista
Schedule 1, p. 2 of 9

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
BASE CASE COST OF SERVICE STUDY FLOWCHART 4
5
Pro Forma Results of Operations by Customer Group
Underground
Storage
Production /
Purchased Gas
Cost
Distribution and
Customer
Relations
Energy /
Commodity
Related
Customer
Related
Demand /
Capacity Related
Residential
101
Small General
111/112
Interruptible
131/132
Transportation
146
Pro Forma
Results of
Operations
Functionalization
Common
Classification
Allocation
Direct Assignment
ThroughputSales Therms
Firm Therms Direct Assignment
Coincident Peak
Non-Coincident Peak
Direct Assignment
Number of CustomersWeighted Number of
Customers
Exhibit No. 15
Case No. AVU-G-17-01
J. Miller, Avista
Schedule 1, p. 3 of 9

Production - Purchased Gas Costs 1
The Company has no natural gas production facilities to serve its retail customers. In 2
addition, the revenue and expenses associated with the gas purchased to serve sales customers and 3
pipeline transportation to get it to our system have been removed from the Company’s filing. The 4
natural gas costs included in the production function include the expenses of the gas supply 5
department. 6
The expenses of the gas supply department recorded in account 813 are classified as 7
commodity related costs. The gas scheduling process includes transportation customers, so 8
estimated scheduling dispatch labor expenses are allocated by throughput. The remaining gas 9
supply department expenses are allocated 95% by sales volumes and 5% on total throughput. 10
Underground Storage 11
Underground storage rate base, operating and maintenance expenses are classified as 12
commodity-related and allocated to customer groups by winter throughput. This approach was 13
proposed by commission Staff and accepted by the Idaho Public Utilities Commission in Case No. 14
AVU-G-04-01. 15
Distribution Facilities Classification (Peak and Average) 16
Distribution mains and regulator station equipment (both general use and city gate stations) 17
are classified Demand and Commodity using the peak and average ratio for the distribution system. 18
Peak demand is defined as the average of the five-day sustained peaks from the most recent three 19
years. Average daily load is calculated by dividing annual throughput by 365 (days in the year). 20
The average daily load is divided by peak load to arrive at the system load factor of 38.75%. This 21
proportion is classified as commodity-related. The remaining 61.25% is classified as demand-22
related. Meters, services and industrial measuring & regulating equipment are classified as 23
Exhibit No. 15
Case No. AVU-G-17-01
J. Miller, Avista
Schedule 1, p. 4 of 9

customer-related distribution plant. Distribution operating and maintenance expenses are classified 1
(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 908.1 8
Distribution Cost Allocation 9
Demand-related distribution costs are allocated to customer groups (rate schedules) by each 10
groups’ contribution to the three year average five-day sustained peak. Commodity-related 11
distribution costs are allocated to customer groups by annual throughput. Distribution main 12
investment has been segregated into large and small mains. Small mains are defined as less than 13
four inches, with large mains being four inches or greater. The small main costs use the same 14
demand and commodity data, but large usage customers (Schedules 131, 132, and 146) that connect 15
to large system mains have been excluded from the allocations. 16
Most customer-related costs are allocated by the annualized number of customers billed 17
during the test period. Meter investment costs are allocated using the number of customers weighted 18
by the relative current cost of meters in service at December 31, 2016. Services investment costs 19
are allocated using the number of customers weighted by the relative current cost of typical service 20

1 Any demand side management investment costs and amortization expense included in base rates would be included with
the distribution function and classified to demand and commodity by the peak and average ratio. At this point in time, the
Company’s demand side management investments in base rates have been fully amortized. All current demand side
management costs are managed through the Schedule 191 Energy Efficiency Rider Adjustment balancing account which
is not included in this cost study.
Exhibit No. 15
Case No. AVU-G-17-01
J. Miller, Avista
Schedule 1, p. 5 of 9

installations. Industrial measuring and regulating equipment investment costs are allocated by 1
number of turbine meters which effectively excludes small usage customers. 2
Administrative and General Costs 3
General and intangible rate base items are allocated by the Company’s four-factor allocator. 4
Administrative and general expenses are segregated into plant-related, labor-related, revenue-related 5
and other. The plant-related items are allocated based on total plant in service. Labor-related items 6
are allocated by operating and maintenance labor expense. Revenue-related items are allocated by 7
pro forma revenue. Other administrative and general expenses are allocated by the Company’s four-8
factor. 9
Special Contract Customer Revenue 10
Two special contract customers receive transportation service from the Company. Rates for 11
these customers were individually negotiated to cover any incremental costs together with some 12
contribution to margin. The rates for these customers are not being adjusted in this case. The 13
revenue from these special contract customers has been segregated from general rate revenue and 14
allocated back to all the other rate classes by relative rate base. In treating these revenues like other 15
operating revenues their system contribution reduces costs for all rate schedules. 16
Revenue Conversion Items 17
In this study uncollectible accounts and commission fees have been classified as revenue-18
related and are allocated by pro forma revenue. These items vary with revenue and are included in 19
the calculation of the revenue conversion factor. Income tax expense items are allocated to 20
schedules by net income before income tax less interest expense. 21
For the functional summaries on pages 2 and 3 of the cost of service study, these items are 22
assigned to the component cost categories. The revenue-related expense items have been reduced 23
Exhibit No. 15
Case No. AVU-G-17-01
J. Miller, Avista
Schedule 1, p. 6 of 9

to a percent of all other costs and loaded onto each cost category by that ratio. Similarly, income 1
tax items have been assigned to cost categories by relative rate base (as is net income). 2
The following matrix outlines the methodology applied in the Company Base Case natural 3
gas cost of service study. 4
IPUC Case No. AVU-G-17-01 Methodology Matrix
Avista Utilities Idaho Jurisdiction
Natural Gas Cost of Service Methodology
Line Account Functional Category Classification Allocation
Underground Storage Plant
1 350 - 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 weighted by current typical service cost
9 381 Meters Distribution Customer C03, Customers weighted by average current meter cost
10 385 Industrial M&R Distribution Customer C06, Large 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 plant, & 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 plant, & customers)
Reserve for Depreciation
15 Underground Storage Underground Storage Commodity same as related plant Allocations linked to related plant accounts
16 Distribution Distribution Demand/Commodity/Customer same as related plant Allocations linked to related plant accounts
17 General Common Demand/Commodity/Customer same as related plant Allocations linked to related plant accounts
18 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/A
25 813 Other Gas Expenses Production Commodity E01/E04 Annual Throughput / Annual Sales Therms
Underground Storage O&M
26 814 - 837 Underground Storage Exp Underground Storage Commodity E08 Winter throughput
Exhibit No. 15
Case No. AVU-G-17-01
J. Miller, Avista
Schedule 1, p. 7 of 9
IPUC Case No. AVU-G-17-01 Methodology Matrix
Avista Utilities Idaho Jurisdiction
Natural Gas Cost of Service Methodology
Line Account Functional Category Classification Allocation
Distribution O&M
1 870 OP Super & Engineering Distribution Demand/Commodity/Customer from Dist Plant S15 Sum of Distribution Plant in Service
2 871 Load Dispatching Distribution Commodity E01 Annual throughput
3 874 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 weighted by average current meter cost
9 880 Other OP Expenses Distribution Demand/Commodity/Customer from other dist expenses S04 Sum of Accounts 870 - 879 and 881 - 894
10 881 Rents Distribution Demand/Commodity/Customer from other dist expenses 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 Service
12 886 MT of Structures Distribution Demand/Commodity/Customer from Other Dist Plant S05 Sum of accounts 376-385
13 887 MT of Mains Distribution Demand/Commodity from related plant S21 Sum of Distribution Mains Plant in Service
14 889 MT of M&R General Distribution Demand/Commodity from related plant S08 Sum of Meas & Reg Station - General Plant in Service
15 890 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 Revenue
24 905 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. 15
Case No. AVU-G-17-01
J. Miller, Avista
Schedule 1, p. 8 of 9
IPUC Case No. AVU-G-17-01 Methodology Matrix
Avista Utilities Idaho Jurisdiction
Natural Gas Cost of Service Methodology
Line Account Functional Category Classification Allocation
Admin & General Expenses
1 920 Salaries Common Demand/Commodity/Customer from Other O&M 4-Factor (O&M less resource & labor, O&M labor, net direct plant, & customers)
2 921 Office Supplies Common Demand/Commodity/Customer from Other O&M 4-Factor (O&M less resource & labor, O&M labor, net direct plant, & customers)
3 922 Admin Expense Transferred - Credit Common Demand/Commodity/Customer from Other O&M 4-Factor (O&M less resource & labor, O&M labor, net direct plant, & 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 plant, & 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 plant, & 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 plant, & customers)
9 928 Regulatory Commision Common Demand/Commodity/Customer from Other O&M 4-Factor (O&M less resource & labor, O&M labor, net direct plant, & customers)
10 928 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 plant, & customers)
12 931 Rents Common Demand/Commodity/Customer from Other O&M 4-Factor (O&M less resource & labor, O&M labor, net direct plant, & customers)
13 935 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 Service
20 State Income Tax Revenue Conversion Revenue R02 Net Income before Taxes less Interest Expense
21 Federal Income Tax Revenue Conversion Revenue R02 Net Income before Taxes less Interest Expense
22 Deferred FIT Revenue Conversion Revenue R02 Net Income before Taxes less Interest Expense
23 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. 15
Case No. AVU-G-17-01
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, 2016

(b)(c)(d)(e)(f)(g)(h)(i)(j)
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 12,393,000 9,166,589 2,942,053 - 284,358
3 Distribution Plant 217,930,000 180,176,484 35,351,294 - 2,402,222
4 Intangible Plant 11,241,000 9,955,572 1,202,107 - 83,321
5 General Plant 38,116,000 34,057,278 3,794,587 - 264,135
6 Total Plant In Service 279,680,000 233,355,922 43,290,041 - 3,034,037
Accum Depreciation
7 Production Plant
8 Underground Storage Plant (4,913,000) (3,633,943) (1,166,328) - (112,729)
9 Distribution Plant (79,803,000) (66,992,890) (11,993,854) - (816,256)
10 Intangible Plant (2,730,000) (2,428,286) (282,120) - (19,594)
11 General Plant (14,631,000) (13,073,041) (1,456,569) - (101,390)
12 Total Accumulated Depreciation (102,077,000) (86,128,160) (14,898,872) - (1,049,968)
13 Net Plant 177,603,000 147,227,763 28,391,169 - 1,984,068
14 Accumlulated Deferred FIT (41,561,000) (34,677,151) (6,432,986) - (450,864)
15 Miscellaneous Rate Base 10,405,000 8,309,420 1,935,879 - 159,701
16 Total Rate Base 146,447,000 120,860,032 23,894,063 - 1,692,906
17 Revenue From Retail Rates 39,475,000 32,290,969 6,782,356 - 401,675
18 Other Operating Revenues 172,000 141,963 28,054 - 1,983
19 Total Revenues 39,647,000 32,432,932 6,810,409 - 403,658
Operating Expenses
20 Purchased Gas Costs 444,000 316,512 124,072 - 3,416
21 Underground Storage Expenses 407,000 301,041 96,620 - 9,339
22 Distribution Expenses 6,432,000 5,570,881 793,079 - 68,040
23 Customer Accounting Expenses 2,550,000 2,486,954 61,774 - 1,272
24 Customer Information Expenses 385,000 378,133 6,838 - 29
25 Sales Expenses (0) (0) (0) - (0)
26 Admin & General Expenses 5,935,000 5,238,188 651,402 - 45,410
27 Total O&M Expenses 16,153,000 14,291,710 1,733,784 - 127,506
28 Taxes Other Than Income Taxes 1,942,000 1,594,425 324,643 - 22,933
29 Depreciation Expense
30 Underground Storage Plant Depr 231,000 170,861 54,839 - 5,300
31 Distribution Plant Depreciation 5,575,000 4,615,191 899,569 - 60,240
32 General Plant Depreciation 3,936,000 3,516,881 391,843 - 27,276
33 Amortization of Intangible Plant 1,486,000 1,233,846 235,648 - 16,505
34 Total Depr & Amort Expense 11,228,000 9,536,780 1,581,899 - 109,321
35 Income Tax 2,333,000 1,355,550 941,216 - 36,234
36 Total Operating Expenses 31,656,000 26,778,464 4,581,542 - 295,994
37 Net Income 7,991,000 5,654,468 2,228,867 - 107,664
38 Rate of Return 5.46%4.68%9.33%0.00%6.36%
39 Return Ratio 1.00 0.86 1.71 - 1.17
40 Interest Expense 4,141,000 3,417,492 675,639 - 47,869
Exhibit No. 15
Case No. AVU-G-17-01
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, 2016

(b)(c)(d)(e)(f)(g)(h)(i)(j)
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 446,250 318,116 124,700 0 3,433
2 Underground Storage 1,484,314 969,036 479,335 0 35,943
3 Distribution 24,294,102 19,566,716 4,472,984 0 254,401
4 Common 13,250,335 11,437,101 1,705,336 0 107,898
5 Total Current Rate Revenue 39,475,000 32,290,969 6,782,356 0 401,675
6 Exclude Cost of Gas w / Revenue Exp.0 0 0 0 0
7 Total Margin Revenue at Current Rates 39,475,000 32,290,969 6,782,356 0 401,675
Margin per Therm at Current Rates
8 Production $0.00540 $0.00556 $0.00556 $0.00000 $0.00119
9 Underground Storage $0.01797 $0.01692 $0.02136 $0.00000 $0.01243
10 Distribution $0.29413 $0.34172 $0.19928 $0.00000 $0.08799
11 Common $0.16042 $0.19974 $0.07598 $0.00000 $0.03732
12 Total Current Margin Melded Rate per Therm $0.47792 $0.56394 $0.30217 $0.00000 $0.13893
Functional Cost Components at Uniform Current Return
13 Production 446,250 318,116 124,700 0 3,433
14 Underground Storage 1,428,759 1,056,794 339,182 0 32,783
15 Distribution 24,230,121 20,663,944 3,329,879 0 236,299
16 Common 13,369,871 11,769,958 1,495,432 0 104,482
17 Total Uniform Current Cost 39,475,000 33,808,811 5,289,192 0 376,996
18 Exclude Cost of Gas w / Revenue Exp.0 0 0 0 0
19 Total Uniform Current Margin 39,475,000 33,808,811 5,289,192 0 376,996
Margin per Therm at Uniform Current Return
20 Production $0.00540 $0.00556 $0.00556 $0.00000 $0.00119
21 Underground Storage $0.01730 $0.01846 $0.01511 $0.00000 $0.01134
22 Distribution $0.29335 $0.36088 $0.14835 $0.00000 $0.08173
23 Common $0.16187 $0.20555 $0.06662 $0.00000 $0.03614
24 Total Current Uniform Margin Melded Rate per Therm $0.47792 $0.59045 $0.23564 $0.00000 $0.13040
25 Margin to Cost Ratio at Current Rates 1.00 0.96 1.28 0.00 1.07
Functional Cost Components at Proposed Rates
26 Production 446,254 318,120 124,701 0 3,433
27 Underground Storage 1,698,022 1,152,077 505,521 0 40,424
28 Distribution 26,821,976 21,855,334 4,686,568 0 280,074
29 Common 13,988,748 12,131,439 1,744,565 0 112,744
30 Total Proposed Rate Revenue 42,955,000 35,456,969 7,061,356 0 436,675
31 Exclude Cost of Gas w / Revenue Exp.0 0 0 0 0
32 Total Margin Revenue at Proposed Rates 42,955,000 35,456,969 7,061,356 0 436,675
Margin per Therm at Proposed Rates
33 Production $0.00540 $0.00556 $0.00556 $0.00000 $0.00119
34 Underground Storage $0.02056 $0.02012 $0.02252 $0.00000 $0.01398
35 Distribution $0.32473 $0.38169 $0.20880 $0.00000 $0.09687
36 Common $0.16936 $0.21187 $0.07772 $0.00000 $0.03900
37 Total Proposed Margin Melded Rate per Therm $0.52006 $0.61923 $0.31460 $0.00000 $0.15104
Functional Cost Components at Uniform Proposed Return
38 Production 446,254 318,120 124,701 0 3,433
39 Underground Storage 1,653,244 1,222,836 392,474 0 37,934
40 Distribution 26,770,373 22,740,028 3,764,540 0 265,806
41 Common 14,085,129 12,399,821 1,575,256 0 110,051
42 Total Uniform Proposed Cost 42,955,000 36,680,805 5,856,971 0 417,224
43 Exclude Cost of Gas w / Revenue Exp.0 0 0 0 0
44 Total Uniform Proposed Margin 42,955,000 36,680,805 5,856,971 0 417,224
Margin per Therm at Uniform Proposed Return
45 Production $0.00540 $0.00556 $0.00556 $0.00000 $0.00119
46 Underground Storage $0.02002 $0.02136 $0.01749 $0.00000 $0.01312
47 Distribution $0.32411 $0.39714 $0.16772 $0.00000 $0.09194
48 Common $0.17053 $0.21655 $0.07018 $0.00000 $0.03806
49 Total Proposed Uniform Margin Melded Rate per Therm $0.52006 $0.64060 $0.26094 $0.00000 $0.14431
50 Margin to Cost Ratio at Proposed Rates 1.00 0.97 1.21 0.00 1.05
51 Current Margin to Proposed Cost Ratio 0.92 0.88 1.16 0.00 0.96
Exhibit No. 15
Case No. AVU-G-17-01
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, 2016
(b)(c)(d)(e)(f)(g)(h)(i)(j)
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 8,465,240 5,488,549 2,832,608 0 144,083
2 Demand 9,037,567 6,265,411 2,611,627 0 160,529
3 Customer 21,972,193 20,537,009 1,338,120 0 97,064
4 Total Current Rate Revenue 39,475,000 32,290,969 6,782,356 0 401,675
Revenue per Therm at Current Rates
5 Commodity $0.10249 $0.09585 $0.12620 $0.00000 $0.04984
6 Demand $0.10942 $0.10942 $0.11635 $0.00000 $0.05552
7 Customer $0.26602 $0.35866 $0.05962 $0.00000 $0.03357
8 Total Revenue per Therm at Current Rates $0.47792 $0.56394 $0.30217 $0.00000 $0.13893
Cost per Unit at Current Rates
9 Commodity Cost per Therm $0.10249 $0.09585 $0.12620 $0.00000 $0.04984
10 Demand Cost per Peak Day Therms $15.48 $14.31 $20.01 $0.00 $10.18
11 Customer Cost per Customer per Month $22.88 $21.77 $78.45 $0.00 $1,348.10
Cost by Classification at Uniform Current Return
12 Commodity 8,159,302 5,836,622 2,188,213 0 134,466
13 Demand 8,824,993 6,682,845 1,992,372 0 149,776
14 Customer 22,490,705 21,289,344 1,108,607 0 92,754
15 Total Uniform Current Cost 39,475,000 33,808,811 5,289,192 0 376,996
Cost per Therm at Current Return
16 Commodity $0.09878 $0.10193 $0.09749 $0.00000 $0.04651
17 Demand $0.10684 $0.11671 $0.08876 $0.00000 $0.05181
18 Customer $0.27230 $0.37180 $0.04939 $0.00000 $0.03208
19 Total Cost per Therm at Current Return $0.47792 $0.59045 $0.23564 $0.00000 $0.13040
Cost per Unit at Uniform Current Return
20 Commodity Cost per Therm $0.09878 $0.10193 $0.09749 $0.00000 $0.04651
21 Demand Cost per Peak Day Therms $15.11 $15.27 $15.27 $0.00 $9.50
22 Customer Cost per Customer per Month $23.42 $22.57 $64.99 $0.00 $1,288.25
23 Revenue to Cost Ratio at Current Rates 1.00 0.96 1.28 0.00 1.07
Cost by Classification at Proposed Return by Schedule
24 Commodity 9,325,294 6,214,559 2,953,013 0 157,721
25 Demand 10,039,202 7,136,089 2,727,334 0 175,778
26 Customer 23,590,505 22,106,321 1,381,008 0 103,176
27 Total Proposed Rate Revenue 42,955,000 35,456,969 7,061,356 0 436,675
Revenue per Therm at Proposed Rates
28 Commodity $0.11290 $0.10853 $0.13156 $0.00000 $0.05455
29 Demand $0.12154 $0.12463 $0.12151 $0.00000 $0.06080
30 Customer $0.28561 $0.38607 $0.06153 $0.00000 $0.03569
31 Total Revenue per Therm at Proposed Rates $0.52006 $0.61923 $0.31460 $0.00000 $0.15104
Cost per Unit at Proposed Rates
32 Commodity Cost per Therm $0.11290 $0.10853 $0.13156 $0.00000 $0.05455
33 Demand Cost per Peak Day Therms $17.19 $16.30 $20.90 $0.00 $11.15
34 Customer Cost per Customer per Month $24.56 $23.44 $80.96 $0.00 $1,433.00
Cost by Classification at Uniform Proposed Return
35 Commodity 9,078,597 6,495,211 2,433,245 0 150,141
36 Demand 9,867,812 7,472,666 2,227,843 0 167,303
37 Customer 24,008,591 22,712,928 1,195,883 0 99,779
38 Total Uniform Proposed Cost 42,955,000 36,680,805 5,856,971 0 417,224
Cost per Therm at Proposed Return
39 Commodity $0.10991 $0.11343 $0.10841 $0.00000 $0.05193
40 Demand $0.11947 $0.13050 $0.09926 $0.00000 $0.05787
41 Customer $0.29067 $0.39666 $0.05328 $0.00000 $0.03451
42 Total Cost per Therm at Proposed Return $0.52006 $0.64060 $0.26094 $0.00000 $0.14431
Cost per Unit at Uniform Proposed Return
43 Commodity Cost per Therm $0.10991 $0.11343 $0.10841 $0.00000 $0.05193
44 Demand Cost per Peak Day Therms $16.90 $17.07 $17.07 $0.00 $10.61
45 Customer Cost per Customer per Month $25.00 $24.08 $70.11 $0.00 $1,385.82
46 Revenue to Cost Ratio at Proposed Rates 1.00 0.97 1.21 0.00 1.05
47 Current Revenue to Proposed Cost Ratio 0.92 0.88 1.16 0.00 0.96
Exhibit No. 15
Case No. AVU-G-17-01
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, 2016

(b)(c)(d)(e)(f)(g)(h)(i)(j)
Residential Large Firm Interrupt Transport
System Service Service Service Service
Line Description Total Sch 101 Sch 111 Sch 131 Sch 146
Rate Base
1 Services 71,412,000 69,233,974$ 2,083,286$ -$ 94,740$
2 Services Accum. Depr.(31,121,000)(30,171,827)$ (907,886)$ -$ (41,287)$
3 Total Services 40,291,000 39,062,147 1,175,400 0 53,453
4 Meters 25,635,000 22,279,576$ 3,218,056$ -$ 137,369$
5 Meters Accum. Depr.(8,478,000)(7,368,295)$ (1,064,274)$ -$ (45,431)$
6 Total Meters 17,157,000 14,911,281 2,153,781 0 91,938
7 Total Rate Base 57,448,000 53,973,428 3,329,181 0 145,391
8 Return on Rate Base @ 7.62%4,377,538 4,112,775 253,684 0 11,079
9 Tax Benefit of Interest Expense (536,852)(504,382)(31,111)0 (1,359)
10 Revenue Conversion Factor 0.61459 0.61459 0.61459 0.61459 0.61459
11 Rate Base Revenue Requirement 6,249,184 5,871,221 362,148 0 15,816
Expenses
12 Services Depr Exp 1,793,000 1,738,315$ 52,307$ -$ 2,379$
13 Meters Depr Exp 732,000 636,187$ 91,891$ -$ 3,923$
14 Services Maintenance Exp 1,112,000 1,078,085$ 32,440$ -$ 1,475$
15 Meters Maintenance Exp 712,000 618,805$ 89,380$ -$ 3,815$
16 Meter Reading 242,000 237,684$ 4,298$ -$ 18$
17 Billing 2,072,000 2,035,044$ 36,800$ -$ 155$
18 Total Expenses 6,663,000 6,344,119 307,116 0 11,765
19 Revenue Conversion Factor 0.994886 0.994886 0.994886 0.994886 0.994886
20 Expense Revenue Requirement 6,697,250 6,376,729 308,695 0 11,826
21 12,946,434 12,247,950 670,842 0 27,641
22 Total Customer Bills 960,374 943,245 17,057 0 72
23 Average Unit Cost per Month $13.48 $12.98 $39.33 $0.00 $383.91
24 Total Customer Related Cost 24,008,591 22,712,928 1,195,883 0 99,779
25 Customer Related Unit Cost per Month $25.00 $24.08 $70.11 $0.00 $1,385.82
26 Other Non-Gas Costs 18,946,409 13,967,876 4,661,088 0 317,445
27 Other Non-Gas Unit Cost per Month $19.73 $14.81 $273.27 $0.00 $4,408.96
28 Total Fixed Unit Cost per Month $44.73 $38.89 $343.38 $0.00 $5,794.78
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. 15
Case No. AVU-G-17-01
J. Miller, Avista
Schedule 2, p. 4 of 4