20121011Knox DI.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 ) CASE NO. AVU-E-12-08
OF AVISTA CORPORATION FOR THE ) CASE NO. AVU-G-12-07
AUTHORITY TO INCREASE ITS RATES )
AND CHARGES FOR ELECTRIC AND )
NATURAL GAS SERVICE TO ELECTRIC ) DIRECT TESTIMONY
AND NATURAL GAS CUSTOMERS IN THE ) OF
STATE OF IDAHO ) TARA L. KNOX
)

FOR AVISTA CORPORATION

(ELECTRIC AND NATURAL GAS)

Knox, Di 1
Avista Corporation
I. INTRODUCTION 1
Q. Please state your name, business address and 2
present position with Avista Corporation. 3
A. My name is Tara L. Knox and my business address 4
is 1411 East Mission Avenue, Spokane, Washington. I am 5
employed as a Senior Regulatory Analyst in the State and 6
Federal Regulation Department. 7
Q. Would you briefly describe your duties? 8
A. Yes. I am responsible for preparing the 9
regulatory cost of service models for the Company, as well 10
as providing support for the preparation of results of 11
operations reports. 12
Q. What is your educational background and 13
professional experience? 14
A. I am a graduate of Washington State University 15
with a Bachelor of Arts degree in General Humanities in 16
1982, and a Master of Accounting degree in 1990. As an 17
employee in the State and Federal Regulation Department at 18
Avista since 1991, I have attended several ratemaking 19
classes, including the EEI Electric Rates Advanced Course 20
that specializes in cost allocation and cost of service 21
issues. I have also been a member of the Cost of Service 22
Working Group and the Northwest Pricing and Regulatory 23
Forum, which are discussion groups made up of technical 24
Knox, Di 2
Avista Corporation
professionals from regional utilities and utilities 1
throughout the United States and Canada concerned with cost 2
of service issues. 3
Q. What is the scope of your testimony in this 4
proceeding? 5
A. My testimony and exhibits will cover the 6
Company’s electric and natural gas cost of service studies 7
performed for this proceeding. Additionally, I am 8
sponsoring the electric and natural gas revenue 9
normalization adjustments to the test year results of 10
operations and the proposed Load Change Adjustment Rate 11
(LCAR) to be used in the Power Cost Adjustment (PCA). A 12
table of contents for my testimony is as follows: 13
Table of Contents Page 14
I. Introduction 1 15
II. Revenue Normalization 3 16
Electric 3 17
Natural Gas 7 18
III. Proposed Load Change Adjustment Rate 11 19
IV. Electric Cost of Service 13 20
Illustration 1 Base Case Results 21 21
V. Natural Gas Cost of Service 22 22
Illustration 2 Base Case Results 26 23
Q. Are you sponsoring any exhibits in this case? 24
A. Yes. I am sponsoring Exhibit 12 composed of six 25
schedules as follows. Schedule 1, the proposed Load Change 26
Adjustment Rate calculation; Schedule 2, the electric cost 27
of service study process description; Schedule 3, the 28
Knox, Di 3
Avista Corporation
electric cost of service study summary results; Schedule 4, 1
the cost of service workshop presentation; Schedule 5, the 2
natural gas cost of service study process description; and 3
Schedule 6, the natural gas cost of service study summary 4
results. 5
Q. Were these exhibits prepared by you or under your 6
direction? 7
A. Yes, they were. 8
II. REVENUE NORMALIZATION 9
Electric Revenue Normalization 10
Q. Would you please describe the electric revenue 11
adjustment included in Company witness Ms. Andrews pro 12
forma results of operations? 13
A. Yes, I will. The electric revenue normalization 14
adjustment represents the difference between the Company’s 15
actual recorded retail revenues during the twelve months 16
ended June 2012 test period, and retail revenues on a 17
normalized (pro forma) basis. The total revenue 18
normalization adjustment increases Idaho net operating 19
income by $1,724,000, as shown in adjustment column 2.09 on 20
page 7 of Ms. Andrews Exhibit No. 10, Schedule 1. The 21
revenue normalization adjustment consists of three primary 22
components: 1) re-pricing customer usage (adjusted for any 23
known and measurable changes) at base tariff rates 24
presently in effect, 2) adjusting customer loads and 25
revenue to a 12-month calendar basis (unbilled revenue 26
Knox, Di 4
Avista Corporation
adjustment), and 3) weather normalizing customer usage and 1
revenue1. 2
Q. Since these three elements are combined into a 3
single adjustment, would you please identify the impact 4
(before taxes and revenue related expenses) of each 5
component? 6
A. Yes. The re-pricing of billed usage comprises 7
the majority of the change in test year revenue. The 8
combined impact of the rate increase effective October 1, 9
20112, and the elimination of revenue and amortization 10
expense from adder schedules (Schedule 59 Residential 11
Exchange, Schedule 91 Public Purpose Tariff Rider, Schedule 12
95 Optional Renewable Power, and Schedule 99 DSIT refund)3, 13
is an increase in net revenue of $2,097,000. Re-pricing of 14
unbilled calendar usage and elimination of unbilled adder 15
schedule revenue and expense results in a net revenue 16
increase of $90,0004. Finally, the weather normalization 17
adjustment increases revenue by $530,000. The combined 18
impact of these elements is an increase of $2,717,000 19
which, after revenue-related expenses and income tax, 20

1 Documentation related to this adjustment is detailed in the Knox
workpapers accompanying this case.
2 IPUC Case No. AVU-E-11-01.
3 Municipal Franchise Fee and Power Cost Adjustment revenues are
eliminated in separate adjustments.
4 The unbilled adjustment consists of removing June 2011 usage billed in
July 2011 from the 12 Months Ended June 2012 test year, adding June
2012 usage billed in July 2012 to the 12 Months Ended June 2012 test
year, and re-pricing the net adjustment to usage at October 1, 2011
base rates.
Knox, Di 5
Avista Corporation
results in the increase to net operating income of 1
$1,724,000. 2
Q. Would you please briefly discuss electric weather 3
normalization? 4
A. Yes. The Company’s electric weather 5
normalization adjustment calculates the change in kWh usage 6
required to adjust actual loads during the twelve months 7
ended June 2012 test period to the amount expected if 8
weather had been normal. This adjustment incorporates the 9
effect of both heating and cooling on weather-sensitive 10
customer groups. The weather adjustment is developed from 11
regression analysis of ten years of billed usage per 12
customer and billing period heating and cooling degree-day 13
data. The resulting seasonal weather sensitivity factors 14
(use-per-customer-per-heating-degree day and use-per-15
customer-per-cooling-degree day) are applied to monthly 16
test period customers and the difference between normal 17
heating/cooling degree-days and monthly test period 18
observed heating/cooling degree-days. 19
Q. Have the seasonal weather sensitivity factors 20
been updated since the last rate case? 21
A. Yes. The factors used in the weather adjustment 22
are based on regression analysis of monthly billed usage 23
per customer from January 2001 through December 2010 which 24
Knox, Di 6
Avista Corporation
is the most recent completed analysis. Autoregressive 1
terms were included in the regressions in order to correct 2
for autocorrelation in the data. 3
Q. What data did you use to determine “normal” 4
heating and cooling degree days? 5
A. Normal heating and cooling degree days are based 6
on a rolling 30-year average of heating and cooling degree-7
days reported for each month by the National Weather 8
Service for the Spokane Airport weather station. Each year 9
the normal values are adjusted to capture the most recent 10
year with the oldest year dropping off, thereby reflecting 11
the most recent information available at the end of each 12
calendar year. 13
Q. Is this proposed weather adjustment methodology 14
consistent with the methodology utilized in the Company’s 15
last general rate case in Idaho? 16
A. Yes, the process for determining the weather 17
sensitivity factors and the monthly adjustment calculation 18
is consistent with the methodology presented in Case No. 19
AVU-E-11-01. 20
Q. What was the impact of electric weather 21
normalization on the twelve months ended June 2012 test 22
year? 23
Knox, Di 7
Avista Corporation
A. Weather was slightly warmer than normal during 1
the winter, and cooler than normal during the spring of 2
2012 as well as the summer of 2011 (with offsetting impacts 3
in June where it was necessary to both deduct heating 4
degree-days and add cooling degree-days). Overall, the 5
adjustment to normal required the addition of only 92 6
heating degree-days during the heating season5 and 4 cooling 7
degree-days during the cooling season. The total 8
adjustment to Idaho sales volumes was an addition of 9
6,207,276 kWhs which is approximately 0.2% of billed usage. 10
Natural Gas Revenue Normalization 11
Q. Would you please describe the natural gas revenue 12
adjustment included in Ms. Andrews pro forma results of 13
operations? 14
A. Yes. The natural gas revenue normalization 15
adjustment is similar to the electric adjustment and 16
represents the difference between the Company’s actual 17
recorded retail revenues during the twelve months ended 18
June 2012 test period and retail revenues on a normalized 19
(pro forma) basis. The adjustment includes the re-pricing 20
of pro forma sales and transportation volumes at present 21

5 The heating season includes the months of October through June. The
cooling season includes the months of June through September. The
early part of June typically requires heating whereas the end of June
typically requires cooling, therefore, for normalization purposes June
is treated as both a heating and cooling month.
Knox, Di 8
Avista Corporation
rates using pro forma sales volumes that have been adjusted 1
for unbilled sales, abnormal weather, and any material 2
customer load or schedule changes. The rates used exclude: 3
1) Temporary Gas Rate Adjustment Schedule 155, which 4
reflects the approved amortization rate for prior deferred 5
natural gas costs approved in the Company’s last PGA 6
filing, 2) Public Purposes Rider Adjustment Schedule 191, 7
and 3) Deferred State Income Tax Adjustment Schedule 1996. 8
Q. Does the Revenue Normalization Adjustment contain 9
a component reflecting normalized natural gas costs? 10
A. Yes. Purchase gas costs are normalized using the 11
natural gas costs approved by the Commission in Case No. 12
AVU-G-12-05, the Company’s 2012 PGA filing, as set forth 13
under Schedule 150. These natural gas costs, effective 14
October 1, 2012, are applied to the pro forma retail sales 15
volumes so that there is a matching of revenues and natural 16
gas costs. 17
Q. Have you determined the impact of each of the 18
components of this adjustment? 19
A. Yes. The re-pricing of billed revenue and 20
natural gas costs increased margin7 by $240,000. Re-pricing 21

6 Documentation related to this adjustment is detailed in the Knox
workpapers accompanying this case.
7 The term “margin” in this context consists of revenues less gas costs
and adder schedule amortization expenses but does not include the
effect of revenue related expenses or income taxes.
Knox, Di 9
Avista Corporation
unbilled revenue and natural gas costs decreased margin by 1
$116,000, and the weather adjustment at present rates 2
increased margin by $282,000. 3
The total net amount of the natural gas revenue 4
normalization adjustment, which includes the related 5
purchase gas cost normalization, is an increase to net 6
operating income of $275,000, as shown in adjustment column 7
2.01, on page 5 of Ms. Andrews Exhibit No. 10, Schedule 2. 8
Q. Would you please briefly discuss natural gas 9
weather normalization? 10
A. Yes. The natural gas weather normalization 11
adjustment is developed from a regression analysis of ten 12
years of billed usage per customer and billing period 13
heating degree-day data. The resulting seasonal weather 14
sensitivity factors (use-per-customer-per-heating-degree 15
day) are applied to monthly test period customers and the 16
difference between normal heating degree-days and monthly 17
test period observed heating degree-days. This calculation 18
produces the change in therm usage required to adjust 19
existing loads to the amount expected if weather had been 20
normal. 21
Q. In your discussion of electric weather 22
normalization you indicated that the adjustment utilized 23
sensitivity factors from the ten year period January 2001 24
Knox, Di 10
Avista Corporation
through December 2010. Is this true for natural gas as 1
well? 2
A. Yes, the natural gas weather adjustment utilized 3
updated weather sensitivity factors. 4
Q. What data did you use to determine “normal” 5
heating degree days? 6
A. Normal heating degree-days are based on a rolling 7
30-year average of heating degree-days reported for each 8
month by the National Weather Service for the Spokane 9
Airport weather station. Each year the normal values are 10
adjusted to capture the most recent year with the oldest 11
year dropping off, thereby reflecting the most recent 12
information available at the end of each calendar year. 13
Q. Is this proposed weather adjustment methodology 14
consistent with the methodology utilized in the Company’s 15
last general rate case in Idaho? 16
A. Yes. The process for determining the weather 17
sensitivity factors and the monthly adjustment calculation 18
are consistent with the methodology presented in Case No. 19
AVU-G-11-01. 20
Q. What was the impact of natural gas weather 21
normalization on the twelve months ended June 2012 test 22
year? 23
Knox, Di 11
Avista Corporation
A. Weather was slightly warmer than normal during 1
the fall and winter months, largely offset by a cooler than 2
normal spring. The adjustment to normal required the 3
addition of 92 heating degree-days from October through 4
June.8 The adjustment to sales volumes was an addition of 5
818,604 therms which is approximately 0.7% of billed usage. 6
7
III. PROPOSED LOAD CHANGE ADJUSTMENT RATE 8
Q. What is the Load Change Adjustment Rate? 9
A. The Load Change Adjustment Rate (LCAR) is part of 10
the Power Cost Adjustment (PCA) mechanism that prices the 11
change in power supply-related costs associated with the 12
change in actual retail loads from the retail loads that 13
were used to set the PCA base costs. The LCAR 14
determination process for all Idaho investor-owned 15
utilities was established in IPUC Case No. GNR-E-10-03, 16
Order No. 32206 which was approved on March, 15, 2011. 17
Q. How is the rate determined? 18
A. The proposed LCAR in this case is determined by 19
computing the proposed revenue requirement on the 20
production and transmission costs contained within Ms. 21
Andrews’ Idaho electric pro forma total results of 22

8 Heating degree days that occur during July through September do not
impact the natural gas weather normalization adjustment as the seasonal
sensitivity factor is zero for summer months.
Knox, Di 12
Avista Corporation
operations. The production/transmission revenue 1
requirement amount is then divided by the Idaho normalized 2
retail load used to set rates in order to arrive at the 3
average production and transmission cost-per-kWh embedded 4
in proposed rates. This amount is then multiplied by the 5
proportion of production and transmission costs classified 6
as energy-related in the cost of service study. 7
Q. Do you have an exhibit schedule that shows the 8
calculation of the proposed LCAR? 9
A. Yes. Exhibit No. 12, Schedule 1 begins with the 10
identification of the production and transmission revenue, 11
expense and rate base amounts included in each of Ms. 12
Andrews’ actual, restating, and pro forma adjustments to 13
results of operations. The “Pro Forma Total Production and 14
Transmission Costs” on line 32 at the bottom of page 1 15
shows the resulting production and transmission cost 16
components. 17
Page 2 shows the revenue requirement calculation on 18
the production and transmission cost components. The rate 19
of return and debt cost percentages on Line 2 are inputs 20
from the proposed cost of capital. The normalized retail 21
load on Line 10 comes from the workpapers supporting the 22
revenue normalization and energy efficiency load 23
adjustments. Line 11 represents the average total 24
Knox, Di 13
Avista Corporation
production and transmission cost-per-kWh proposed to be 1
embedded in Idaho customer retail rates. Lines 12 and 13 2
are values taken from the cost of service study supporting 3
report titled Functional Cost Summary by Classification at 4
Uniform Requested Return representing total costs at unity. 5
Line 12 shows the amount of production and transmission 6
costs classified as energy related, while Line 13 shows the 7
total production and transmission costs in the study. 8
The resulting load change adjustment rate on Line 14 9
is $0.02768 per kWh or $27.68 per MWh. The calculation of 10
the load change adjustment rate will be revised based on 11
the final production and transmission costs, and rate of 12
return, that are approved by the Commission in this case. 13
14
IV. ELECTRIC COST OF SERVICE 15
Q. Please briefly summarize your testimony related 16
to the electric cost of service study. 17
A. I believe the Base Case cost of service study 18
presented in this case is a fair and reasonable 19
representation of the costs to serve each customer group. 20
The Base Case study shows Residential Service Schedule 1, 21
Extra Large General Service Schedule 25, Pumping Service 22
Schedule 31 and the Street and Area Lighting Schedules 23
provide less than the overall rate of return under present 24
Knox, Di 14
Avista Corporation
rates. General Service Schedule 11, Large General Service 1
Schedule 21 and Extra Large General Service to Clearwater 2
Paper Schedule 25P provide more than the overall rate of 3
return under present rates. 4
Q. What is an electric cost of service study and 5
what is its purpose? 6
A. An electric cost of service study is an 7
engineering-economic study, which separates the revenue, 8
expenses, and rate base associated with providing electric 9
service to designated groups of customers. The groups are 10
made up of customers with similar load characteristics and 11
facilities requirements. Costs are assigned or allocated 12
to each group based on (among other things), test period 13
load and facilities requirements, resulting in an 14
evaluation of the cost of the service provided to each 15
group. The rate of return by customer group indicates 16
whether the revenue provided by the customers in each group 17
recovers the cost to serve those customers. The study 18
results are used as a guide in determining the appropriate 19
rate spread among the groups of customers. Exhibit No. 12, 20
Schedule 2 explains the basic concepts involved in 21
performing an electric cost of service study. It also 22
details the specific methodology and assumptions utilized 23
in the Company’s Base Case cost of service study. 24
Knox, Di 15
Avista Corporation
Q. What is the basis for the electric cost of 1
service study provided in this case? 2
A. The electric cost of service study provided by 3
the Company as Exhibit No. 12, Schedule 3 is based on the 4
twelve months ended June 30, 2012 test year pro forma 5
results of operations presented by Ms. Andrews in Exhibit 6
No. 10, Schedule 1. 7
Q. Would you please explain the cost of service 8
study presented in Exhibit No. 12, Schedule 3? 9
A. Yes. Exhibit No. 12, Schedule 3 is composed of a 10
series of summaries of the cost of service study results. 11
The summary on page 1 shows the results of the study by 12
FERC account category. The rate of return by rate schedule 13
and the ratio of each schedule’s return to the overall 14
return are shown on Lines 39 and 40. This summary was 15
provided to Company witness Mr. Ehrbar for his work on rate 16
spread and rate design. The results will be discussed in 17
more detail later in my testimony. 18
Pages 2 and 3 are both summaries that show the 19
revenue-to-cost relationship at current and proposed 20
revenue. Costs by category are shown first at the existing 21
schedule returns (revenue); next the costs are shown as if 22
all schedules were providing equal recovery (cost). These 23
comparisons show how far current and proposed rates are 24
Knox, Di 16
Avista Corporation
from rates that would be in alignment with the cost study. 1
Page 2 shows the costs segregated into production, 2
transmission, distribution, and common functional 3
categories. Line 44 on page 2 shows the target change in 4
revenue which would produce unity in this cost study. Page 5
3 segregates the costs into demand, energy, and customer 6
classifications. Page 4 is a summary identifying specific 7
customer related costs embedded in the study. 8
The Excel model used to calculate the cost of service 9
and supporting schedules has been included in its entirety 10
both electronically and in hard copy in the workpapers 11
accompanying this case. 12
Q. Does the Company’s electric Base Case cost of 13
service study follow the methodology filed in the Company’s 14
last electric general rate case in Idaho? 15
A. In most respects, yes. In the last case (Case 16
No. AVU-E-11-01) the Company’s electric Base Case cost of 17
service study was prepared using the methodology presented 18
in Case No. AVU-E-04-01 through Case No. AVU-E-09-01 except 19
that the peak credit classification of production and 20
transmission costs was revised. While a revision to the 21
peak credit classification of production and transmission 22
costs was also proposed in Case No. AVU-E-10-01, only the 23
classification of transmission costs as 100% demand-related 24
Knox, Di 17
Avista Corporation
was accepted as part of the settlement in that case. In 1
this case the Company’s Base Case cost of service study 2
utilizes the study methodology accepted in the Settlement 3
from Case No. AVU-E-10-01.9 4
Q. Given that the specific details of this 5
methodology are described in Exhibit No. 12, Schedule 2, 6
would you please give a brief overview of the key elements 7
and the history associated with those elements? 8
A. Yes. Production costs are classified to energy 9
and demand in this case using the Company’s traditional 10
peak credit assignments derived from replacement cost of 11
plant investment. Transmission costs are classified as 12
100% demand and allocated by the average of the 12 monthly 13
coincident peaks, as accepted in the Settlement in Case No. 14
AVU-E-10-01. 15
Distribution costs are classified and allocated by the 16
basic customer theory10 accepted by the Idaho Commission in 17
Case No. WWP-E-98-11. Additional direct assignment of 18
demand related distribution plant has been incorporated to 19
reflect improvements accepted by the Commission in Case No. 20
AVU-E-04-01. 21

9 This methodology contains only one methodological difference from the
studies presented from Case Nos. AVU-E-04-01 through AVU-E-09-01.
Namely, transmission costs are classified as 100% demand-related.
10 Basic customer theory classifies only meters, services and street
lights as customer-related plant; all other distribution facilities are
considered demand-related
Knox, Di 18
Avista Corporation
Administrative and general costs are first directly 1
assigned to production, transmission, distribution, or 2
customer relations functions. The remaining administrative 3
and general costs are categorized as common costs and have 4
been assigned to customer classes by the four-factor 5
allocator accepted by the Idaho Commission in Case No. AVU-6
E-04-01. 7
Q. The settlement in Case No. AVU-E-11-01 required 8
the convening of a public workshop regarding cost of 9
service issues before the next rate case. Please explain. 10
A. In Order No. 32371 from Case No. AVU-E-11-01 and 11
AVU-G-11-01, the Commission approved an all-party 12
Settlement Stipulation. In Section 10 of the Settlement 13
Stipulation, beginning on page 5 it states: 14
The Parties have agreed to exchange information 15
and convene a public workshop, prior to the 16
Company’s next general rate case, with respect to 17
the method of allocation of demand and energy 18
among the customer classes such as the possible 19
use of a revised peak credit method for 20
classifying production costs, as well as 21
consideration of the use of a 12 Coincident Peak 22
(CP) (whether “weighted” or not) versus a 7 CP or 23
other method for allocating transmission costs. 24
The workshop was convened on September 18, 2012 at the 25
Idaho Public Utilities Commission, and was attended by the 26
Knox, Di 19
Avista Corporation
key stakeholders regarding cost of service issues.11 The 1
Company’s presentation from the workshop is included as 2
Schedule 4 of Exhibit No. 12. 3
Q. Was any consensus reached among the Parties 4
regarding the alternative peak credit classification 5
approach? 6
A. No, there was not. Even though the system load 7
factor approach to production peak credit, in the Company’s 8
view, is simple and straightforward, related to the test 9
year under evaluation, and should provide a stable 10
relationship over time, the Parties could not agree that it 11
provides for a better representation of production cost-12
causation than the traditional peak credit methodology. In 13
fact, certain parties suggested potentially removing 14
certain items, such as fuel, from the system load factor 15
methodology and classifying those costs as 100% energy 16
related. 17
Q. Was consensus reached among the parties as it 18
relates to the demand allocation factor for transmission 19
costs? 20
A. No consensus was reached. The general sentiment 21
among the parties on this issue, and even the peak credit 22

11 Parties attending the workshop included Avista, IPUC Staff, Idaho
Forest Group, Clearwater Paper, Idaho Conservation League, and
Community Action Partnership Association of Idaho (CAPAI).
Knox, Di 20
Avista Corporation
issue, is that there should be stability in methodology 1
over time, and that modifications to existing practices 2
should be well founded. Enough changes occur in cost 3
recovery relationships stemming from test year differences 4
without layering on changes to how the cost elements are 5
treated through a methodology change. 6
Q. Did the workshop influence your decision to 7
propose the traditional peak credit methodology and 8
unweighted 12CP demand for transmission in this case? 9
A. Yes it did. First, it is important to note that 10
the Company believes that the revised peak credit 11
methodology for classifying production costs into energy 12
and demand components which it proposed in Case No. AVU-E-13
11-01 is a preferable methodology. That being said, some 14
parties at the September 2012 workshop, and IPUC Staff in 15
particular, believe that methodological consistency is very 16
important, and that the Company’s traditional peak credit 17
methodology is a valid approach for production cost 18
classification. 19
With that in mind, as well as to potentially limit the 20
number of issues in this case, Avista is presenting the 21
prior traditional peak credit methodology in the cost of 22
service study. This methodology includes using 12 CP for 23
allocating transmission costs instead of a weighted 12 CP 24
Knox, Di 21
Avista Corporation
as proposed in the last case. The Company, however, is 1
proposing to continue to employ the recent change to 2
classify transmission costs as 100% demand-related. 3
Q. What are the results of the Company’s electric 4
cost of service study presented in this case? 5
A. The following Illustration shows the rate of 6
return and the relationship of the customer class return to 7
the overall return (relative return ratio) at present rates 8
for each rate schedule: 9
Illustration 1 10

Customer Class
Rate of
Return
Return
Ratio
Residential Service Schedule 1 5.74% 0.78
General Service Schedule 11/12 10.26% 1.40
Large General Service Schedule 21/22 8.40% 1.15
Extra Large General Service Schedule 25 7.10% 0.97
Extra Large General Service Clearwater
Paper Schedule 25P

8.75%

1.20
Pumping Service Schedule 31/32 6.92% 0.95
Lighting Service Schedules 41 - 49 5.51% 0.75
Total Idaho Electric System 7.32% 1.00
As can be observed from the above table, residential, 11
extra large general service, pumping service and lighting 12
service schedules (1, 25, 31 and 41-49) show under-recovery 13
of the costs to serve them. The general service, large 14
general service, and extra large Clearwater Paper schedules 15
(11, 21, 25P) show over-recovery of the costs to serve 16
Knox, Di 22
Avista Corporation
them. The summary results of this study were provided to 1
Mr. Ehrbar as an input into development of the proposed 2
electric rates. 3
4
V. NATURAL GAS COST OF SERVICE 5
Q. Please describe the natural gas cost of service 6
study and its purpose. 7
A. A natural gas cost of service study is an 8
engineering-economic study which separates the revenue, 9
expenses, and rate base associated with providing natural 10
gas service to designated groups of customers. The groups 11
are made up of customers with similar usage characteristics 12
and facility requirements. Costs are assigned in relation 13
to each group’s test year load and facilities requirements, 14
resulting in an evaluation of the cost of the service 15
provided to each group. The rate of return by customer 16
group indicates whether the revenue provided by the 17
customers in each group recovers the cost to serve those 18
customers. The study results are one of the key inputs in 19
determining the appropriate rate spread among the groups of 20
customers. Exhibit No. 12, Schedule 5 explains the basic 21
concepts involved in performing a natural gas cost of 22
service study. It also details the specific methodology 23
Knox, Di 23
Avista Corporation
and assumptions utilized in the Company’s Base Case cost of 1
service study. 2
Q. What is the basis for the natural gas cost of 3
service study provided in this case? 4
A. The cost of service study provided by the Company 5
as Exhibit 12, Schedule 6 is based on the twelve months 6
ended June 2012 test year pro forma results of operations 7
presented by Ms. Andrews in Exhibit 10, Schedule 2. 8
Q. Would you please explain the natural gas cost of 9
service study presented in Schedule 6? 10
A. Yes. Exhibit 12, Schedule 6 is composed of a 11
series of summaries of the cost of service study results. 12
Page 1 shows the results of the study by FERC account 13
category. The rate of return, and the ratio of each 14
schedule’s return to the overall return, are shown on lines 15
38 and 39. This summary is provided to Mr. Ehrbar for his 16
work on rate spread and rate design, and the results will 17
be presented later in my testimony. Additional summaries 18
show the costs organized by functional category (page 2) 19
and classification (page 3), including margin and unit cost 20
analysis at current and proposed rates. Finally, page 4 is 21
a summary identifying specific customer related costs 22
embedded in the study. 23
Knox, Di 24
Avista Corporation
The Excel model used to calculate the natural gas cost 1
of service and supporting schedules has been included in 2
its entirety both electronically and hard copy in the 3
natural gas workpapers accompanying this case. 4
Q. Does the Natural Gas Base Case cost of service 5
study utilize the methodology from the Company’s last 6
natural gas case in Idaho? 7
A. Yes. The Base Case cost of service study was 8
prepared using the methodology accepted by the Idaho 9
Commission in Case No. AVU-G-04-01, and presented in AVU-G-10
08-01, AVU-G-09-01, AVU-G-10-01 and AVU-G-11-01. 11
Q. What are the key elements that define the cost of 12
service methodology? 13
A. Allocations of natural gas costs reflect the 14
current Purchased Gas Adjustment methodology. Underground 15
storage costs are allocated by normalized winter 16
throughput. 17
Natural gas main investment has been segregated into 18
large and small mains. Large usage customers that take 19
service from large mains do not receive an allocation of 20
small mains. Meter installation and services investment is 21
allocated by number of customers weighted by the relative 22
current cost of those items. System facilities that serve 23
all customers are classified by the peak and average ratio 24
Knox, Di 25
Avista Corporation
that reflects the system load factor, then allocated by 1
coincident peak demand and throughput, respectively. 2
General plant is allocated by the sum of all other 3
plant. Administrative & general expenses are segregated 4
into labor-related, plant-related, revenue-related, and 5
“other”. The costs are then allocated by factors 6
associated with labor, plant in service, or revenue, 7
respectively. The “other” A&G amounts get a combined 8
allocation that is one-half based on O&M expenses and one-9
half based on throughput. A detailed description of the 10
methodology is included in Exhibit 12, Schedule 5. 11
Q. What are the results of the Company’s natural gas 12
cost of service study? 13
A. I believe the Base Case cost of service study 14
presented in this filing is a fair and reasonable 15
representation of the costs to serve each customer group. 16
The study indicates that General Service (primarily 17
residential) Schedule 101, Interruptible Service Schedules 18
131/132 and Transportation Service Schedule 146 are 19
providing less than the overall return (unity), and Large 20
General Service Schedules 111/112 are providing more than 21
unity. 22
Knox, Di 26
Avista Corporation
The following Illustration shows the rate of return 1
and the relative return ratio at present rates for each 2
rate schedule: 3
Illustration 2 4

Customer Class
Rate of
Return
Return
Ratio
General Firm Service Schedule 101 5.40% 0.92
Large Firm Service Schedule 111/112 7.98% 1.37
Interruptible Service Schedule 131/132 5.35% 0.92
Transportation Service Schedule 146 4.69% 0.80
Total Idaho Natural Gas System 5.84% 1.00
The summary results of this study were provided to Mr. 5
Ehrbar as an input into development of the proposed rates. 6
Q. Does this conclude your pre-filed direct 7
testimony? 8
A. Yes, it does. 9

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 ) CASE NO. AVU-E-12-08
OF AVISTA CORPORATION FOR THE ) CASE NO. AVU-G-12-07
AUTHORITY TO INCREASE ITS RATES )
AND CHARGES FOR ELECTRIC AND )
NATURAL GAS SERVICE TO ELECTRIC ) EXHIBIT NO. 12
AND NATURAL GAS CUSTOMERS IN THE )
STATE OF IDAHO ) TARA L. KNOX
)

FOR AVISTA CORPORATION

(ELECTRIC AND NATURAL GAS)

Line Column Description of Adjustment (000's)Revenue Expense Plant
Accumulated
Depreciation
Deferred
Debits/Credits
Deferred
Tax
1 1.00 Per Results Report 101,316 226,548 585,254 (213,725) 1,765 (61,642)
2 1.01 Deferred FIT Rate Base - - - - - (285)
3 1.02 Deferred Debits and Credits - (64) - - (414) -
4 1.03 Working Capital - - - - - -
5 1.04 Restate 2011 Capital - 236 9,873 (4,733) - (835)
6 2.01 Eliminate B & O Taxes - - - - - -
7 2.02 Uncollect. Expense - - - - - -
8 2.03 Regulatory Expense - - - - - -
9 2.04 Injuries and Damages - - - - - -
10 2.05 FIT/DFIT/ ITC/PTC Expense - - - - - -
11 2.06 ID PCA - (9,871) - - - -
12 2.07 Nez Perce Settlement Adjustment - (18) - - - -
13 2.08 CS2 Levelized - 235 - - - -
14 2.09 Revenue Normalization - 9,635 - - - -
15 2.10 Misc Restating - - - - - -
16 2.11 Restate Incentives - - - - - -
17 2.12 Colstrip / CS2 Maintenance - 1,339 - - - -
18 2.13 Restate Debt Interest - - - - - -
19 3.01 Pro Forma Power Supply (73,823) (76,210) - - - -
20 3.02 Pro Forma Transmission Rev/Exp 371 3 - - - -
21 3.03 Pro Forma Labor Non-Exec - 290 - - - -
22 3.04 Pro Forma Generation Major O&M - 921 - - - -
23 3.05 Pro Forma Employee Benefits - 353 - - - -
24 3.06 Pro Forma Insurance - - - - - -
25 3.07 Pro Forma Property Tax - 380 - - - -
26 3.08 Pro Forma IS/IT Costs - 80 - - - -
27 3.09 Planned Capital Add 2012 - 534 23,728 (13,617) - (1,765)
28 3.10 Planned Capital Add 2013 AMA - 128 6,735 (6,162) - (661)
29 3.11 PF Energy Efficiency Load Adj. - (976) - - - -
30 3.12 O&M Offsets - (35) - - - -
31 3.13 Depreciation Study - (1,780) - - - -
32 Pro Forma Total 27,864 151,728 625,590 (238,237) 1,351 (65,188)
Production / Transmission
AVISTA UTILITIES
AVERAGE PRODUCTION AND TRANSMISSION COST
IDAHO ELECTRIC
TWELVE MONTHS ENDED JUNE 30, 2012
Exhibit No. 12
Case No. AVU-E-12-08
T. Knox, Avista
Schedule 1, p. 1 of 2
AVISTA UTILITIES
AVERAGE PRODUCTION AND TRANSMISSION COST
IDAHO ELECTRIC
TWELVE MONTHS ENDED JUNE 30, 2012
Line ($000's) Debt Cost
1 Prod/Trans Pro Forma Rate Base 323,516
2 Cost of Capital Proposed Rate of Return 8.460% 3.01%
3 Rate Base Net Operating Income Requirement $27,369
4 Tax Effect Net Operating Income Requirement ($3,408)
(Rate Base x Debt Cost x -35%)
5 Net Expense Net Operating Income Requirement 123,864
(Expense - Revenue)
6 Tax Effect Net Operating Income Requirement ($43,352)
(Net Expense x -.35%)
7 Total Prod/Trans Net Operating Income Requirement $104,473
8 1 - Tax Rate Conversion Factor (Excl. Rev. Rel. Exp.) 0.65
9 Prod/Trans Revenue Requiremen $160,727
10 Test Year WA Normalized Retail Load MWh 3,364,879 with EELA Billing Determinant Adjustment
11 Prod/Trans Rev Requirement per kWh 0.04777$
12 Cost of Service Energy Classified Production/Transmission Costs $94,413 Company Case at Unity AVU-E-12-08
13 Cost of Service Total Production/Transmission Costs $162,919 Company Case at Unity AVU-E-12-08
14 Load Change Adjustment Rate per kWh (Line 11 * Line 12 / Line 13 0.02768$
Proposed Production and Transmission Revenue Requirement
Calculation of Load Change Adjustment Rate
Exhibit No. 12
Case No. AVU-E-12-08
T. Knox, Avista
Schedule 1, p. 2 of 2
Exhibit No. 12
Case No. AVU-E-12-08
T. Knox, Avista
Schedule 2, p. 1 of 9

1.
A cost of service study is an engineering-economic study, which apportions the revenue, 2
expenses, and rate base associated with providing electric 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
ELECTRIC COST OF SERVICE 1
There are three basic steps involved in a cost of service study: functionalization, 7
classification, and allocation. See flow chart below. 8
First, the expenses and rate base associated with the electric system under study are 9
assigned to functional categories. The uniform system of accounts provides the basic segregation 10
into production, transmission, and distribution. Traditionally customer accounting, customer 11
information, and sales expenses are included in the distribution function, and administrative and 12
general expenses and general plant rate base are allocated to all functions. This study includes a 13
separate functional category for common costs. Administrative and general costs that cannot be 14
directly assigned to the other functions have been placed in this category. 15
Second, the expenses and rate base items that cannot be directly assigned to customer 16
groups are classified into three primary cost components: energy, demand or customer related. 17
Energy related costs are allocated based on each rate schedule’s share of commodity consumption. 18
Demand (capacity) related costs are allocated to rate schedules on the basis of each schedule’s 19
contribution to peak demand. Customer related items are allocated to rate schedules based on the 20
number of customers within each schedule. The number of customers may be weighted by 21
appropriate factors such as relative cost of metering equipment. In addition to these three cost 22
components, any revenue related expense is allocated based on the proportion of revenues by rate 23
schedule. 24
Exhibit No. 12
Case No. AVU-E-12-08
T. Knox, Avista
Schedule 2, p. 2 of 9

Customer classes shown in this flowchart are illustrative and may not match the Company’s actual rate schedules. 1
Pro Forma Results of Operations by Customer Group 1
ELECTRIC COST OF SERVICE STUDY FLOWCHART
TransmissionProduction Common
Energy / Commodity Related
CustomerRelated
Demand / Capacity Related
Residential Small General Large General Extra LargeGeneral Pumping Street & AreaLights
Allocation
Pro Forma
Results of
Operations
Functionalization
Distribution and Customer
Relations
Classification
Direct Assignment
Number of CustomersWeighted Number of Customers
Direct Assignment
Coincident PeakNon-Coincident Peak
Direct AssignmentGeneration Level mWh's
Customer Level mWh's
Exhibit No. 12
Case No. AVU-E-12-08
T. Knox, Avista
Schedule 2, p. 3 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
Production Classification (Traditional Peak Credit) 5
BASE CASE COST OF SERVICE STUDY 4
This study utilizes a Peak Credit methodology to classify production costs into demand and 6
energy classifications. The Peak Credit method acknowledges that baseload production facilities 7
provide energy throughout the year as well as capacity during system peaks. The demand/energy 8
ratio is determined by the relationship of the current replacement cost per KW generating capacity 9
of the Company’s peaking units to the current replacement cost per KW generating capacity of the 10
Company’s thermal or hydro plant. The peak credit ratio for thermal plant is 42.00% to demand 11
and 58.00% to energy. The peak credit ratio for hydro plant is 41.83% to demand and 58.17% to 12
energy. As an intermediate resource (between peaking and baseload), Coyote Springs II has been 13
included with the thermal plant costs, whereas all other plants in the 340 to 349 FERC plant 14
accounts are considered peaking units. Fuel and load dispatching expenses are classified entirely 15
to energy. Peaking plant related costs are classified entirely to demand. Purchased Power and 16
Other Power Supply expenses are classified to demand and energy by the relative amounts of 17
assigned and allocated Production Plant in Service. 18
Production Allocation 19
Production demand related costs are allocated to the customer classes by class contribution 20
to the average of the twelve monthly system coincident peak loads. Although the Company is 21
usually technically a winter peaking utility, it experiences high summer peaks and careful 22
management of capacity requirements is required throughout the year. The use of the average of 23
twelve monthly peaks recognizes that customer capacity needs are not limited to the heating 24
Exhibit No. 12
Case No. AVU-E-12-08
T. Knox, Avista
Schedule 2, p. 4 of 9

season. Energy related costs are allocated to class by pro forma annual kilowatt-hour sales 1
adjusted for losses to reflect generation level consumption. 2
Transmission Classification and Allocation 3
Transmission costs are classified as 100% demand related due in part to the fact that the 4
facilities are designed for meeting system peak loads. These costs are then allocated to the 5
customer classes by class contribution to the average of the twelve monthly system coincident peak 6
loads (12CP). The use of the average of twelve monthly peaks recognizes that customer capacity 7
needs are not limited to the heating season. 8
Distribution Facilities Classification (Basic Customer) 9
The Basic Customer method considers only services and meters and directly assigned 10
Street Lighting apparatus (FERC Accounts 369, 370, and 373 respectively) to be customer related 11
distribution plant. All other distribution plant is then considered demand related. This division 12
delineates plant which benefits an individual customer from plant which is part of the system. The 13
basic customer method provides a reasonable, clearly definable division between plant that 14
provides service only to individual customers from plant that is part of the interconnected 15
distribution network. 16
Customer Relations Distribution Cost Classification 17
Customer service, customer information and sales expenses are the core of the customer 18
relations functional unit which is included with the distribution cost category. For the most part 19
they are classified as customer related. Exceptions are sales expenses which are classified as 20
energy related and uncollectible accounts expense which is considered separately as a revenue 21
conversion item. Demand Side Management expenses (if any) recorded in Account 908 would be 22
considered separately from the other customer information costs. 23
Exhibit No. 12
Case No. AVU-E-12-08
T. Knox, Avista
Schedule 2, p. 5 of 9

Any demand side management investment and amortization included in base rates would 1
be classified implicitly to demand and energy by the sum of production plant in service, then 2
allocated to rate schedules by coincident peak demand and energy consumption respectively. At 3
this point in time, the Company’s demand side management investments in base rates have been 4
fully amortized except for some minor outstanding loan balances that will remain on the books 5
until satisfied. All current demand side management costs are managed through the Schedule 91 6
Public Purpose Tariff Rider balancing account which is not included in this cost study. 7
Distribution Cost Allocation 8
Distribution demand related costs which cannot be directly assigned are allocated to 9
customer class by the average of the twelve monthly non-coincident peaks for each class. 10
Distribution facilities that serve only secondary voltage customers are allocated by the non-11
coincident peak excluding primary voltage customers or number of customers excluding primary 12
voltage customers. This includes line transformers, services, and secondary voltage overhead or 13
underground conductors and devices. The costs of specific substations and related primary voltage 14
distribution facilities are directly assigned to Extra Large General Service customers based on their 15
load ratio share of the substation capacity from which they receive service. 16
Most customer costs are allocated by average number of customers. Weighted customer 17
allocators have been developed using typical current cost of meters, estimated meter reading time, 18
and direct assignment of billing costs for hand-billed customers. Street and area light customers 19
are excluded from metering and meter reading expenses as their service is not metered. 20
Administrative and General Costs 21
Administrative and general costs which are directly associated with production, 22
transmission, distribution, or customer relations functions are directly assigned to those functions 23
and allocated to customer class by the relevant plant or number of customers. The remainder of 24
Exhibit No. 12
Case No. AVU-E-12-08
T. Knox, Avista
Schedule 2, p. 6 of 9

administrative and general costs are considered common costs, and have been left in their own 1
functional category. These common costs are classified by the implicit relationship of energy, 2
demand and customer within the four-factor allocator applied to them. The four-factor allocator 3
consists of a 25% weighting of each of the following: 1) operating & maintenance expenses 4
excluding resource costs, labor expenses, and administrative and general expenses; 2) operating 5
and maintenance labor expenses excluding administrative and general labor expenses; 3) net 6
production, transmission, and distribution plant; and 4) number of customers. 7
Revenue Conversion Items 8
In this study uncollectible accounts and commission fees have been classified as revenue 9
related and are allocated by pro forma revenue. These items vary with revenue and are included in 10
the calculation of the revenue conversion factor. Income tax expense items are allocated to 11
schedules by net income before income tax adjusted by interest expense. 12
For the functional summaries on pages 2 and 3 of the cost of service study, these items are 13
assigned to component cost categories. The revenue related expense items have been reduced to a 14
percent of all other costs and loaded onto each cost category by that ratio. Similarly, income tax 15
items have been reduced to a percent of net income before tax then assigned to cost categories by 16
relative rate base (as is net income). 17
The following matrix outlines the methodology applied in the Company Base Case cost of 18
service study. 19
IPUC Case No. AVU-E-12-08 Methodology Matrix
Avista Utilities Idaho Jurisdiction
Electric Cost of Service Methodology
Line Account Functional Category Classification Allocation
Production Plant
1 Thermal Production P = Production Demand/Energy by Thermal Peak Credit D01/E02 Coincident Peak Demand/Annual Generation Level Consumption
2 Hydro Production P = Production Demand/Energy by Hydro Peak Credit D01/E02 Coincident Peak Demand/Annual Generation Level Consumption
3 Other Production (Coyote Springs) P = Production Demand/Energy by Thermal Peak Credit D01/E02 Coincident Peak Demand/Annual Generation Level Consumption
4 Other Production P = Production Demand D01 Coincident Peak Demand (12CP)
Transmission Plan
5 All Transmission T = Transmission Demand D01 Coincident Peak Demand (12CP)
Distribution Plan
6 360 Land D = Distribution Demand D03 Non-coincident Peak Demand (NCP)
7 361 Structures D = Distribution Demand D04/D05/D06 Direct Assign Large / Non-coincident Peak Demand Excl DA
8 362 Station Equipment D = Distribution Demand D04/D05/D06 Direct Assign Large / Non-coincident Peak Demand Excl DA
9 364 Poles Towers & Fixtures D = Distribution Demand D04/D05/D07/D08 Direct Assign Large & Lights / NCP Excl DA / NCP Secondary
10 365 Overhead Conductors & Devices D = Distribution Demand D04/D05/D07 Direct Assign Large / NCP Excl DA / NCP Secondary
11 366 Underground Conduit D = Distribution Demand D04/D05/D07 Direct Assign Large / NCP Excl DA / NCP Secondary
12 367 Underground Conductors & Devices D = Distribution Demand D04/D05/D07 Direct Assign Large / NCP Excl DA / NCP Secondary
13 368 Line Transformers D = Distribution Demand D07 Non-coincident Peak Demand Secondary
14 369 Services D = Distribution Customer C02 Secondary Customers unweighted Excl Lighting
15 370 Meters D = Distribution Customer C04 Customers weighted by Current Typical Meter Cost
16 373 Street and Area Lighting Systems D = Distribution Customer C05 Direct Assignment to Street and Area Lights
General Plan
17 All General O=Other Demand/Energy/Customer by Corp Cost Allocator S23 25% direct O&M, 25% direct labor, 25% net direct plant, 25% number of customers
Intangible Plan
18 301 Organization O=Other Energy/Customer by Corp Cost Allocator S23 25% direct O&M, 25% direct labor, 25% net direct plant, 25% number of customers
19 302 Franchises & Consents - Hydro Relicensing P = Production Demand/Energy by Hydro Peak Credit D01/E02 Coincident Peak Demand/Annual Generation Level Consumption
20 303 Misc Intangible Plant - Transmission Agreements T = Transmission Demand D01 Coincident Peak Demand (12CP)
21 303 Misc Intangible Plant - Software O=Other Demand/Energy/Customer by Corp Cost Allocator S23 25% direct O&M, 25% direct labor, 25% net direct plant, 25% number of customers
Reserve for Depreciation/Amortizati
22 Intangible P/T/O Follows Related Plant S01/S02/S23 Sum of Production Plant / Sum of Transmission Plant / Corp Cost Allocator
23 Production P = Production Follows Related Plant D01/E02 Coincident Peak Demand/Annual Generation Level Consumption
24 Transmission T = Transmission Follows Related Plant D01 Coincident Peak Demand (12CP)
25 Distribution D = Distribution Follows Related Plant D03/D04/D05/D06/D07/D08/C02/C04/C05 - See Related Plant
26 General O=Other Demand/Energy/Customer by Corp Cost Allocator S23 25% direct O&M, 25% direct labor, 25% net direct plant, 25% number of customers
Other Rate Bas
27 252 Customer Advances for Construction D = Distribution Customer S13 Sum of Account 369 Services Plant
28 282/190 Accumulated Deferred Income Tax P/T/D/O Follows Related Plant S01/S02/S03/S04 Sums of Production / Transmission / Distribution / General Plant
29 Gain on Sale of General Office Building O=Other Demand/Energy/Customer by Corp Cost Allocator S23 25% direct O&M, 25% direct labor, 25% net direct plant, 25% number of customers
30 Hydro Relicensing Related Settlements P = Production Demand/Energy by Hydro Peak Credit D01/E02 Coincident Peak Demand/Annual Generation Level Consumption
31 Demand Side Management Investment DSM Demand/Energy from Production Plant S01 Sum of Production Plant
32 Working Capital P/T/D/G Demand/Energy/Customer as in related Plant S06 Sum of Production, Transmission, Distribution, and General Plant
Production O&
33 Thermal P = Production Demand/Energy by Thermal Peak Credit D01/E02 Coincident Peak Demand/Annual Generation Level Consumption
34 Thermal Fuel (501) P = Production Energy E02 Annual Generation Level Consumption
35 Hydro P = Production Demand/Energy by Hydro Peak Credit D01/E02 Coincident Peak Demand/Annual Generation Level Consumption
Exhibit No. 12
Case No. AVU-E-12-08
T. Knox, Avista
Schedule 2, p. 7 of 9
IPUC Case No. AVU-E-12-08 Methodology Matrix
Avista Utilities Idaho Jurisdiction
Electric Cost of Service Methodology
Line Account Functional Category Classification Allocation
Production O&M (continued)
1 Water for Power (536) P = Production Energy E02 Annual Generation Level Consumption
2 Other (Coyote Springs) P = Production Demand/Energy by Thermal Peak Credit D01/E02 Coincident Peak Demand/Annual Generation Level Consumption
3 Other Fuel (547) P = Production Energy E02 Annual Generation Level Consumption
4 Other P = Production Demand D01 Coincident Peak Demand (12CP)
5 Purchased Power and Other Expenses (555 and 557) P = Production Demand/Energy from Production Plant S01 Sum of Production Plant
6 System Control & Misc (556 ) P = Production Energy E02 Annual Generation Level Consumption
Transmission O&
7 All Transmission T = Transmission Demand D01 Coincident Peak Demand (12CP)
Distribution O&
8 580 OP Super & Engineering D = Distribution Demand/Customer from Other Dist Op Exp S16 Sum of Other Distribution Operating Expenses
9 581 Load Dispatching D = Distribution Demand D03 Non-coincident Peak Demand
10 582 Station Expenses D = Distribution Demand S09 Sum of Account 362 Station Equipment
11 583 Overhead Lines D = Distribution Demand S10 Sum of Accounts 364 and 365 Poles, Towers, Fixtures & Overhead Conductors
12 584 Underground Lines D = Distribution Demand S11 Sum of Accounts 366 and 367 Underground Conduit & Underground Conductors
13 585 Street Lights D = Distribution Customer S15 Sum of Account 373 Street Light and Signal Systems
14 586 Meters D = Distribution Customer S14 Sum of Account 370 Meters
15 587 Customer Installations D = Distribution Customer S13 Sum of Account 369 Services
16 588 Misc Operating Expense D = Distribution Demand/Customer from Other Dist Op Exp S16 Sum of Other Distribution Operating Expenses
17 589 Rents D = Distribution Demand D03 Non-coincident Peak Demand
18 590 MT Super & Engineering D = Distribution Demand/Customer from Other Dist Mt Exp S17 Sum of Other Distribution Maintenance Expenses
19 591 MT of Structures D = Distribution Demand S08 Sum of Account 361 Structures & Improvements
20 592 MT of Station Equipment D = Distribution Demand S09 Sum of Account 362 Station Equipment
21 593 MT of Overhead Lines D = Distribution Demand S10 Sum of Accounts 364 and 365 Poles, Towers, Fixtures & Overhead Conductors
22 594 MT of Underground Lines D = Distribution Demand S11 Sum of Accounts 366 and 367 Underground Conduit & Underground Conductors
23 595 MT of Line Transformers D = Distribution Demand S12 Sum of Account 368 Line Transformers
24 596 MT of Street Lights D = Distribution Customer S15 Sum of Account 373 Street Light and Signal Systems
25 597 MT of Meters D = Distribution Customer S14 Sum of Account 370 Meters
26 598 Misc Maintenance Expense D = Distribution Demand/Customer from Other Dist Mt Exp S17 Sum of Other Distribution Maintenance Expenses
Customer Accounts Expense
27 901 Supervision C = Customer Relations Customer S18 Sum of Other Customer Accounts Expenses Excluding Uncollectibles
28 902 Meter Reading C = Customer Relations Customer C03/C06 Customers Weighted by Est. Meter Reading Time/Direct Assign Handbilled Cu
29 903 Customer Records & Collections C = Customer Relations Customer C01/C06 All Customers unweighted / Direct Assign Handbilled Cust
30 904 Uncollectible Accounts R = Revenue Conversion Revenue R01 Retail Sales Revenue
31 905 Misc Cust Accounts C = Customer Relations Customer C01 All Customers unweighted
Customer Service & Info Expense
32 907 Supervision C = Customer Relations Customer C01 All Customers unweighted
33 908 Customer Assistance C = Customer Relations Customer C01 All Customers unweighted
34 908 DSM Amortization Expenses DSM Demand/Energy from Production Plant S01 Sum of Production Plant
35 909 Advertising C = Customer Relations Customer C01 All Customers unweighted
36 910 Misc Cust Service & Info C = Customer Relations Customer C01 All Customers unweighted
Sales Expense
37 911 - 916 C = Customer Relations Energy E02 Annual Generation Level Consumption
Exhibit No. 12
Case No. AVU-E-12-08
T. Knox, Avista
Schedule 2, p. 8 of 9
IPUC Case No. AVU-E-12-08 Methodology Matrix
Avista Utilities Idaho Jurisdiction
Electric Cost of Service Methodology
Line Account Functional Category Classification Allocation
Admin & General Expenses
1 920 - 927 & 930 -935 Assigned to Production P = Production Demand/Energy from Production Plant S01 Sum of Production Plant
2 920 - 927 & 930 -935 Assigned to Transmission T = Transmission Demand/Energy from Transmission Plant S02 Sum of Transmission Plant
3 920 - 927 & 930 - 935 Assigned to Distribution D = Distribution Demand/Customer from Distribution Plant S03 Sum of Distribution Plant
4 920 - 927 & 930 - 935 Assigned to Customer Relations C = Customer Relations Customer C01 All Customers unweighted
5 920 - 935 Assigned to Other O=Other Demand/Energy/Customer by Corp Cost Allocator S23 25% direct O&M, 25% direct labor, 25% net direct plant, 25% number of customers
6 928 FERC Commission Fees P = Production Energy E02 Annual Generation Level Consumption
7 928 IPUC Commission Fees R = Revenue Conversion Revenue R01 Retail Sales Revenue
Depreciation & Amortization Expen
8 Intangible P/T/O Demand/Energy/Customer as in related Plant S01/S02/S23 Sum of Production Plant / Sum of Transmission Plant / Corp Cost Alloctor
9 Production P = Production Demand/Energy by Peak Credit as in related Plant D01/E02 Coincident Peak Demand/Annual Generation Level Consumption
10 Transmission T = Transmission Demand D01 Coincident Peak Demand (12CP)
11 Distribution D = Distribution Demand/Customer as in related Plant D03/D04/D05/D06/D07/D08/C02/C04/C05 - See Related Plant
12 General O=Other Demand/Energy/Customer by Corp Cost Allocator S23 25% direct O&M, 25% direct labor, 25% net direct plant, 25% number of customers
Taxes
13 Property Tax P/T/D/O Demand/Energy/Customer from related Plant S01/S02/S03/S04 Sums of Production / Transmission / Distribution / General Plant
14 State kWh Generation Taxes P = Production Demand/Energy by 1/2 Fuel, 1/2 Transmission D01/E02 Coincident Peak Demand/Annual Generation Level Consumption
15 Misc Production Taxes P = Production Demand/Energy by 1/2 Fuel, 1/2 Transmission D01/E02 Coincident Peak Demand/Annual Generation Level Consumption
16 Misc Distribution Taxes D = Distribution Demand/Customer from Distribution Plant S03 Sum of Distribution Plant
17 Idaho State Income Tax R = Revenue Conversion Revenue R03 Revenue less Expenses Before Income Taxes less Interest Expense
18 Federal Income Tax R = Revenue Conversion Revenue R03 Revenue less Expenses Before Income Taxes less Interest Expense
19 Deferred FIT R = Revenue Conversion Revenue R03 Revenue less Expenses Before Income Taxes less Interest Expense
Other Income Related Item
20 CS2 Levelized Return and Boulder Write-off Amort. P = Production Demand/Energy by Peak Credit as in related Plant D01/E02 Coincident Peak Demand/Annual Generation Level Consumption
Operating Revenue
21 Sales of Electricity- Retail R = Revenue from Rates Revenue Input Pro Forma Revenue per Revenue Study
22 Sales for Resale (447) P = Production Demand/Energy from Production Plant S01 Sum of Production Plant
23 Misc Service Revenue (451) D = Distribution Demand/Customer from Distribution Plant S03 Sum of Distribution Plant
24 Sales of Water & Water Power (453) P = Production Demand D01 Coincident Peak Demand (12CP)
25 Rent from Production Property (454) P = Production Demand/Energy from Production Plant S01 Sum of Production Plant
26 Rent from Transmission Property (454) T = Transmission Demand/Energy from Transmission Plant S02 Sum of Transmission Plant
27 Rent from Distribution Property (454) D = Distribution Demand/Customer from Distribution Plant S03 Sum of Distribution Plant
28 Other Electric Revenues - Generation (456) P = Production Demand/Energy from Production Plant S01 Sum of Production Plant
29 Other Electric Revenues - Wheeling (456) T = Transmission Demand/Energy from Transmission Plant S02 Sum of Transmission Plant
30 Other Electric Revenues - Energy Delivery (456) D = Distribution Demand/Customer from Distribution Plant S03 Sum of Distribution Plant
Salaries & Wages (allocation factor inpu
Operation & Maintenance Expenses
31 Production Total P = Production Demand/Energy from Production Plant S01 Sum of Production Plant
32 Transmission Total T = Transmission Demand/Energy from Transmission Plant S02 Sum of Transmission Plant
33 Distribution Total D = Distribution Demand/Customer from Distribution Plant S03 Sum of Distribution Plant
34 Customer Accounts Total C = Customer Relations Customer S18 Sum of Other Customer Accounts Expenses Excluding Uncollectibles
35 Customer Service Total C = Customer Relations Customer C01 All Customers unweighted
36 Sales Total C = Customer Relations Energy E02 Annual Generation Level Consumption
37 Admin & General Total O=Other Energy/Customer by Corp Cost Allocator S23 25% direct O&M, 25% direct labor, 25% net direct plant, 25% number of customers
Exhibit No. 12
Case No. AVU-E-12-08
T. Knox, Avista
Schedule 2, p. 9 of 9
Sumcost VISTA UTILITIES Idaho Jurisdiction
Scenario: AVU-E-12-08 Company Cas Cost of Service Basic Summary Electric Utility 10-10-12
VU-E-10-01 Settlement Method For the Twelve Months Ended June 30, 2012
Transmission By Demand 12 CP
(b) (c) (d) (e) (f) (g) (h) (i) (j) (k) (l) (m)
Residential General Large Gen Extra Large Extra Large Pumping Street &
System Service Service Service Gen Service Service CP Service rea Lights
Description Total Sch 1 Sch 11-12 Sch 21-22 Sch 25 Sch 25P Sch 31-32 Sch 41-49
Plant In Service
1 Production Plant 402,565,000 149,638,011 40,682,236 80,301,297 34,458,283 89,941,661 6,239,766 1,303,746
2 Transmission Plant 193,225,000 78,729,256 19,788,854 37,732,611 15,884,481 37,989,699 2,676,142 423,958
3 Distribution Plant 449,614,000 225,605,267 64,270,329 110,145,165 9,287,020 2,737,865 15,430,461 22,137,894
4 Intangible Plant 54,867,000 23,810,109 6,166,529 9,958,073 3,823,947 9,725,364 922,792 460,186
5 General Plant 88,487,000 48,015,959 11,628,726 13,352,814 3,786,351 8,559,695 1,659,918 1,483,536
6 Total Plant In Service 1,188,758,000 525,798,603 142,536,673 251,489,960 67,240,083 148,954,284 26,929,078 25,809,319
ccum Depreciation
7 Production Plant (174,598,000) (64,910,989) (17,644,862) (34,826,500) (14,943,998) (39,000,750) (2,705,768) (565,134)
8 Transmission Plant (66,055,000) (26,914,017) (6,764,925) (12,899,095) (5,430,195) (12,986,982) (914,853) (144,932)
9 Distribution Plant (151,682,000) (75,312,738) (20,623,837) (37,302,715) (2,961,053) (731,153) (5,147,372) (9,603,132)
10 Intangible Plant (11,443,000) (5,817,267) (1,434,259) (1,838,075) (587,737) (1,397,545) (207,226) (160,891)
11 General Plant (34,403,000) (18,668,200) (4,521,151) (5,191,462) (1,472,101) (3,327,937) (645,362) (576,786)
12 Total Accumulated Depreciation (438,181,000) (191,623,212) (50,989,034) (92,057,846) (25,395,084) (57,444,367) (9,620,582) (11,050,875)
13 Net Plant 750,577,000 334,175,391 91,547,639 159,432,113 41,844,999 91,509,917 17,308,496 14,758,444
14 ccumulated Deferred FIT (119,554,000) (52,622,048) (14,256,245) (25,204,201) (6,885,548) (15,403,257) (2,673,478) (2,509,223)
15 Miscellaneous Rate Base 8,007,000 3,223,674 914,043 1,813,323 519,015 1,185,858 181,919 169,167
16 Total Rate Base 639,030,000 284,777,017 78,205,437 136,041,236 35,478,467 77,292,518 14,816,938 12,418,388
17 Revenue From Retail Rates 248,720,000 99,497,000 32,432,000 51,400,000 16,036,000 41,091,000 4,859,000 3,405,000
18 Other Operating Revenues 29,727,000 11,482,225 3,089,386 5,992,225 2,405,525 6,094,169 487,054 176,415
19 Total Revenues 278,447,000 110,979,225 35,521,386 57,392,225 18,441,525 47,185,169 5,346,054 3,581,415
Operating Expenses
20 Production Expenses 121,242,000 43,633,193 12,198,017 24,352,993 10,513,928 28,163,848 1,945,460 434,561
21 Transmission Expenses 10,671,000 4,347,884 1,092,855 2,083,813 877,233 2,098,011 147,792 23,413
22 Distribution Expenses 11,311,000 5,419,369 1,684,669 2,570,085 255,627 97,643 373,434 910,172
23 Customer Accounting Expenses 4,343,000 3,248,473 675,400 175,647 64,162 113,336 53,439 12,544
24 Customer Information Expenses 601,000 490,809 96,818 6,057 44 5 6,640 626
25 Sales Expenses 4,000 1,357 399 813 355 991 68 17
26 Admin & General Expenses 23,863,000 12,589,773 3,107,324 3,796,522 1,066,358 2,428,810 461,067 413,147
27 Total O&M Expenses 172,035,000 69,730,858 18,855,482 32,985,930 12,777,706 32,902,644 2,987,901 1,794,479
28 Taxes Other Than Income Taxes 9,171,000 3,795,741 1,035,428 1,938,010 614,626 1,454,900 187,375 144,920
29 Other Income Related Items 397,000 141,952 39,907 79,851 34,515 92,913 6,413 1,450
Depreciation Expense
30 Production Plant Depreciation 8,771,000 3,284,857 887,308 1,746,702 748,439 1,941,191 134,816 27,687
31 Transmission Plant Depreciation 3,550,000 1,446,443 363,568 693,237 291,835 697,961 49,167 7,789
32 Distribution Plant Depreciation 13,770,000 6,991,324 2,124,901 3,257,960 269,195 48,617 474,761 603,243
33 General Plant Depreciation 9,283,000 5,037,261 1,219,947 1,400,818 397,219 897,981 174,139 155,635
34 Amortization Expense 472,000 185,047 48,113 93,090 39,422 98,111 6,905 1,312
35 Total Depreciation Expense 35,846,000 16,944,931 4,643,837 7,191,808 1,746,110 3,683,860 839,788 795,666
36 Income Tax 14,195,000 4,008,667 2,920,617 3,773,418 747,990 2,285,559 298,625 160,125
37 Total Operating Expenses 231,644,000 94,622,149 27,495,271 45,969,016 15,920,947 40,419,875 4,320,102 2,896,640
38 Net Income 46,803,000 16,357,077 8,026,115 11,423,208 2,520,578 6,765,294 1,025,952 684,775
39 Rate of Return 7.32% 5.74% 10.26% 8.40% 7.10% 8.75% 6.92% 5.51%
40 Return Ratio 1.00 0.78 1.40 1.15 0.97 1.20 0.95 0.75
41 Interest Expense 19,235,000 8,571,876 2,354,008 4,094,883 1,067,913 2,326,529 445,994 373,797
42 Revenue Related Operating Expenses 1,259,000 503,646 164,168 260,183 81,173 207,999 24,596 17,236
Exhibit No. 12
Case No. AVU-E-12-08
T. Knox, Avista
Schedule 3, p. 1 of 4
Sumcost VISTA UTILITIES Idaho Jurisdiction
Scenario: AVU-E-12-08 Company Cas Revenue to Cost by Functional Component Summary Electric Utility 10-10-12
VU-E-10-01 Settlement Method For the Twelve Months Ended June 30, 2012
Transmission By Demand 12 CP
(b) (c) (d) (e) (f) (g) (h) (i) (j) (k) (l) (m)
Residential General Large Gen Extra Large Extra Large Pumping Street &
System Service Service Service Gen Service Service CP Service rea 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 Schedul
1 Production 136,364,788 47,060,028 14,621,765 27,931,027 11,690,137 32,448,878 2,150,089 462,864
2 Transmission 21,689,704 7,685,638 2,701,310 4,544,899 1,736,647 4,692,231 288,429 40,550
3 Distribution 55,412,989 26,385,511 10,099,956 13,372,398 1,092,762 369,065 1,760,044 2,333,253
4 Common 35,252,519 18,365,822 5,008,969 5,551,676 1,516,454 3,580,826 660,438 568,334
5 Total Current Rate Revenue 248,720,000 99,497,000 32,432,000 51,400,000 16,036,000 41,091,000 4,859,000 3,405,000
Expressed as $/kWh
6 Production $0.04053 $0.04180 $0.04412 $0.04129 $0.03896 $0.03770 $0.03809 $0.03328
7 Transmission $0.00645 $0.00683 $0.00815 $0.00672 $0.00579 $0.00545 $0.00511 $0.00292
8 Distribution $0.01647 $0.02344 $0.03048 $0.01977 $0.00364 $0.00043 $0.03118 $0.16774
9 Common $0.01048 $0.01631 $0.01512 $0.00821 $0.00505 $0.00416 $0.01170 $0.04086
10 Total Current Melded Rates $0.07392 $0.08837 $0.09787 $0.07599 $0.05344 $0.04774 $0.08608 $0.24480
Functional Cost Components at Uniform Current Return
11 Production 135,669,121 48,969,282 13,654,976 27,233,957 11,751,370 31,407,161 2,170,311 482,063
12 Transmission 21,490,270 8,756,180 2,200,894 4,196,579 1,766,654 4,225,172 297,638 47,152
13 Distribution 56,126,482 29,467,448 8,428,038 12,355,724 1,110,937 330,840 1,813,571 2,619,924
14 Common 35,434,128 19,156,149 4,648,672 5,391,551 1,525,634 3,446,346 667,697 598,078
15 Total Uniform Current Cost 248,720,000 106,349,060 28,932,579 49,177,812 16,154,596 39,409,519 4,949,216 3,747,217
Expressed as $/kWh
16 Production $0.04032 $0.04349 $0.04121 $0.04026 $0.03916 $0.03649 $0.03845 $0.03466
17 Transmission $0.00639 $0.00778 $0.00664 $0.00620 $0.00589 $0.00491 $0.00527 $0.00339
18 Distribution $0.01668 $0.02617 $0.02543 $0.01827 $0.00370 $0.00038 $0.03213 $0.18835
19 Common $0.01053 $0.01701 $0.01403 $0.00797 $0.00508 $0.00400 $0.01183 $0.04300
20 Total Current Uniform Melded Rates $0.07392 $0.09446 $0.08731 $0.07271 $0.05383 $0.04578 $0.08768 $0.26940
21 Revenue to Cost Ratio at Current Rates 1.00 0.94 1.12 1.05 0.99 1.04 0.98 0.91
Functional Cost Components at Proposed Return by Schedul
22 Production 140,184,410 48,492,742 14,991,954 28,713,644 12,016,444 33,285,836 2,212,176 471,615
23 Transmission 23,642,289 8,489,027 2,892,935 4,935,990 1,896,563 5,067,511 316,703 43,559
24 Distribution 59,930,158 28,698,341 10,740,181 14,513,912 1,189,616 399,779 1,924,395 2,463,934
25 Common 36,356,143 18,958,890 5,146,930 5,731,454 1,565,377 3,688,875 682,726 581,892
26 Total Proposed Rate Revenue 260,113,000 104,639,000 33,772,000 53,895,000 16,668,000 42,442,000 5,136,000 3,561,000
Expressed as $/kWh
27 Production $0.04166 $0.04307 $0.04524 $0.04245 $0.04004 $0.03867 $0.03919 $0.03391
28 Transmission $0.00703 $0.00754 $0.00873 $0.00730 $0.00632 $0.00589 $0.00561 $0.00313
29 Distribution $0.01781 $0.02549 $0.03241 $0.02146 $0.00396 $0.00046 $0.03409 $0.17714
30 Common $0.01080 $0.01684 $0.01553 $0.00847 $0.00522 $0.00429 $0.01210 $0.04183
31 Total Proposed Melded Rates $0.07730 $0.09294 $0.10191 $0.07968 $0.05554 $0.04931 $0.09099 $0.25601
Functional Cost Components at Uniform Requested Return
32 Production 139,481,645 50,383,935 14,040,165 27,994,752 12,077,948 32,260,841 2,229,521 494,483
33 Transmission 23,437,170 9,549,442 2,400,283 4,576,766 1,926,703 4,607,949 324,602 51,424
34 Distribution 60,656,479 31,751,124 9,094,204 13,465,411 1,207,871 362,167 1,970,308 2,805,394
35 Common 36,537,706 19,741,741 4,792,223 5,566,316 1,574,598 3,556,553 688,952 617,321
36 Total Uniform Cost 260,113,000 111,426,243 30,326,875 51,603,244 16,787,120 40,787,511 5,213,383 3,968,622
Expressed as $/kWh
37 Production $0.04145 $0.04475 $0.04237 $0.04139 $0.04025 $0.03748 $0.03950 $0.03555
38 Transmission $0.00697 $0.00848 $0.00724 $0.00677 $0.00642 $0.00535 $0.00575 $0.00370
39 Distribution $0.01803 $0.02820 $0.02744 $0.01991 $0.00403 $0.00042 $0.03491 $0.20169
40 Common $0.01086 $0.01753 $0.01446 $0.00823 $0.00525 $0.00413 $0.01221 $0.04438
41 Total Uniform Melded Rates $0.07730 $0.09897 $0.09152 $0.07629 $0.05594 $0.04738 $0.09236 $0.28532
42 Revenue to Cost Ratio at Proposed Rates 1.00 0.94 1.11 1.04 0.99 1.04 0.99 0.90
43 Current Revenue to Proposed Cost Ratio 0.96 0.89 1.07 1.00 0.96 1.01 0.93 0.86
44 Target Revenue Increase 11,393,000 11,929,000 (2,105,000)203,000 751,000 (303,000)354,000 564,000Exhibit No. 12
Case No. AVU-E-12-08
T. Knox, Avista
Schedule 3, p. 2 of 4
Sumcost VISTA UTILITIES Idaho Jurisdiction
Scenario: AVU-E-12-08 Company Cas Revenue to Cost By Classification Summary Electric Utility 10-10-12
VU-E-10-01 Settlement Method For the Twelve Months Ended June 30, 2012
Transmission By Demand 12 CP
(b) (c) (d) (e) (f) (g) (h) (i) (j) (k) (l) (m)
Residential General Large Gen Extra Large Extra Large Pumping Street &
System Service Service Service Gen Service Service CP Service rea Lights
Description Total Sch 1 Sch 11-12 Sch 21-22 Sch 25 Sch 25P Sch 31-32 Sch 41-49
Cost Classifications at Current Return by Schedul
1 Energ 99,505,249 32,531,602 10,437,176 20,531,033 8,737,229 25,198,840 1,669,300 400,069
2 Demand 121,741,170 48,056,898 16,472,134 30,165,949 7,258,252 15,886,884 2,788,487 1,112,567
3 Custome 27,473,580 18,908,500 5,522,690 703,018 40,519 5,276 401,213 1,892,364
4 Total Current Rate Revenue 248,720,000 99,497,000 32,432,000 51,400,000 16,036,000 41,091,000 4,859,000 3,405,000
Expressed as Unit Cos
5 Energ $/kWh $0.02957 $0.02889 $0.03150 $0.03035 $0.02912 $0.02927 $0.02957 $0.02876
6 Demand $/kW/mo $16.47 $17.46 $20.82 $17.41 $13.03 $12.27 $12.54 $26.84
7 Custome $/Cust/mo $18.54 $15.62 $23.13 $47.07 $375.18 $439.66 $24.50 $1,225.62
Cost Classifications at Uniform Current Return
8 Energ 98,939,877 33,556,100 9,876,410 20,114,130 8,774,446 24,521,928 1,682,297 414,565
9 Demand 121,619,568 52,793,443 14,088,965 28,393,268 7,339,470 14,882,475 2,859,134 1,262,812
10 Custome 28,160,555 19,999,517 4,967,205 670,413 40,679 5,116 407,785 2,069,840
11 Total Uniform Current Cost 248,720,000 106,349,060 28,932,579 49,177,812 16,154,596 39,409,519 4,949,216 3,747,217
Expressed as Unit Cos
12 Energ $/kWh $0.02940 $0.02980 $0.02980 $0.02974 $0.02924 $0.02849 $0.02980 $0.02980
13 Demand $/kW/mo $16.45 $19.18 $17.81 $16.39 $13.18 $11.50 $12.86 $30.47
14 Custome $/Cust/mo $19.00 $16.53 $20.81 $44.89 $376.66 $426.35 $24.91 $1,340.57
15 Revenue to Cost Ratio at Current Rates 1.00 0.94 1.12 1.05 0.99 1.04 0.98 0.91
Cost Classifications at Proposed Return by Schedule
16 Energ 101,745,475 33,300,372 10,651,891 20,999,090 8,935,553 25,742,689 1,709,204 406,677
17 Demand 129,723,846 51,611,403 17,384,713 32,156,285 7,691,075 16,693,907 3,005,406 1,181,057
18 Custome 28,643,678 19,727,226 5,735,396 739,625 41,372 5,404 421,389 1,973,266
19 Total Proposed Rate Revenue 260,113,000 104,639,000 33,772,000 53,895,000 16,668,000 42,442,000 5,136,000 3,561,000
Expressed as Unit Cos
20 Energ $/kWh $0.03024 $0.02958 $0.03214 $0.03105 $0.02978 $0.02991 $0.03028 $0.02924
21 Demand $/kW/mo $17.55 $18.75 $21.98 $18.56 $13.81 $12.89 $13.52 $28.49
22 Custome $/Cust/mo $19.33 $16.30 $24.02 $49.52 $383.08 $450.36 $25.74 $1,278.02
Cost Classifications at Uniform Requested Return
23 Energ 101,178,013 34,315,179 10,099,826 20,569,136 8,972,935 25,076,643 1,720,353 423,943
24 Demand 129,574,068 56,303,142 15,038,521 30,328,109 7,772,653 15,705,622 3,066,004 1,360,017
25 Custome 29,360,919 20,807,922 5,188,529 706,000 41,533 5,247 427,026 2,184,662
26 Total Uniform Cost 260,113,000 111,426,243 30,326,875 51,603,244 16,787,120 40,787,511 5,213,383 3,968,622
Expressed as Unit Cos
27 Energ $/kWh $0.03007 $0.03048 $0.03048 $0.03041 $0.02990 $0.02913 $0.03048 $0.03048
28 Demand $/kW/mo $17.53 $20.45 $19.01 $17.50 $13.96 $12.13 $13.79 $32.81
29 Custome $/Cust/mo $19.81 $17.19 $21.73 $47.27 $384.56 $437.26 $26.08 $1,414.94
30 Revenue to Cost Ratio at Proposed Rates 1.00 0.94 1.11 1.04 0.99 1.04 0.99 0.90
31 Current Revenue to Proposed Cost Ratio 0.96 0.89 1.07 1.00 0.96 1.01 0.93 0.86
32 nnual Consumption (mWh's) 3,364,879 1,125,882 331,376 676,398 300,092 860,777 56,445 13,910
33 Monthly Average NCP Demand (kW) 615,990 229,407 65,917 144,389 46,413 107,884 18,526 3,454
34 Monthly Average Number of Customers 123,495 100,853 19,895 1,245 9 1 1,364 129
Exhibit No. 12
Case No. AVU-E-12-08
T. Knox, Avista
Schedule 3, p. 3 of 4
Sumcost VISTA UTILITIES Idaho Jurisdiction
Scenario: AVU-E-12-08 Company Cas Customer Cost Analysis Electric Utility 10-10-12
VU-E-10-01 Settlement Method For the Twelve Months Ended June 30, 2012
Transmission By Demand 12 CP
(b) (c) (d) (e) (f) (g) (h) (i) (j) (k) (l) (m)
Residential General Large Gen Extra Large Extra Large Pumping Street &
System Service Service Service Gen Service Service CP Service rea Lights
Description Total Sch 1 Sch 11-12 Sch 21-22 Sch 25 Sch 25P Sch 31-32 Sch 41-49
Rate Base
1 Services 45,622,000 37,307,157 7,359,316 450,806 0 0 504,721 0
2 Services Accum. Depr. (16,622,000) (13,592,556) (2,681,306) (164,247) 0 0 (183,891) 0
3 Total Services 29,000,000 23,714,602 4,678,010 286,558 0 0 320,830 0
4 Meters 20,634,000 11,920,038 6,231,158 1,759,439 35,061 6,159 682,146 0
5 Meters Accum. Depr. (1,530,000) (883,864) (462,037) (130,461) (2,600) (457) (50,581) 0
6 Total Meters 19,104,000 11,036,173 5,769,121 1,628,977 32,461 5,702 631,565 0
7 Total Rate Base 48,104,000 34,750,775 10,447,131 1,915,536 32,461 5,702 952,395 0
8 Return on Rate Base @ 8.46% 4,069,603 2,939,919 883,828 162,054 2,746 482 80,573 0
9 Revenue Conversion Facto 0.63711 0.63711 0.63711 0.63711 0.63711 0.63711 0.63711 0.63711
10 Rate Base Revenue Requiremen 6,387,629 4,614,482 1,387,253 254,360 4,310 757 126,467 0
Expenses
11 Services Depr Exp 1,255,000 1,026,270 202,445 12,401 0 0 13,884 0
12 Meters Depr Exp 1,533,000 885,597 462,943 130,717 2,605 458 50,680 0
13 Services Operations Exp 333,000 272,309 53,716 3,290 0 0 3,684 0
14 Meters Operating Exp 545,000 314,841 164,582 46,472 926 163 18,017 0
15 Meters Maintenance Exp 29,000 16,753 8,758 2,473 49 9 959 0
16 Meter Reading 430,000 336,412 66,362 4,152 16,671 1,852 4,551 0
17 Billing 2,945,000 2,402,643 473,952 29,652 2,865 318 32,505 3,065
18 Total Expenses 7,070,000 5,254,824 1,432,757 229,157 23,116 2,800 124,280 3,065
19 Revenue Conversion Facto 0.995010 0.995010 0.995010 0.995010 0.995010 0.995010 0.995010 0.995010
20 Expense Revenue Requiremen 7,105,456 5,281,177 1,439,943 230,306 23,232 2,814 124,904 3,081
21 13,493,085 9,895,660 2,827,195 484,666 27,542 3,571 251,370 3,081
22 Total Customer Bills 1,481,940 1,210,233 238,734 14,936 108 12 16,373 1,544
23 Average Unit Cost per Month $9.11 $8.18 $11.84 $32.45 $255.02 $297.57 $15.35 $2.00
24 Total Customer Related Cost 29,360,919 20,807,922 5,188,529 706,000 41,533 5,247 427,026 2,184,662
25 Customer Related Unit Cost per Month $19.81 $17.19 $21.73 $47.27 $384.56 $437.26 $26.08 $1,414.94
26 Total Distribution Demand Related Cost 51,861,024 24,639,071 7,079,654 15,152,454 1,384,083 426,568 1,989,689 1,189,506
27 Dist Demand Related Unit Cost per Month $35.00 $20.36 $29.65 $1,014.49 $12,815.59 $35,547.33 $121.52 $770.41
28 Total Distribution Unit Cost per Month $54.81 $37.55 $51.39 $1,061.76 $13,200.15 $35,984.59 $147.60 $2,185.34
Meter, Services, Meter Reading & Billing Costs by Schedule at Requested Rate of Return
Total Meter, Service, Meter Reading, and
Distribution Fixed Costs per Customer
Exhibit No. 12
Case No. AVU-E-12-08
T. Knox, Avista
Schedule 3, p. 4 of 4
Avista Utilities
Cost of Service / Rate Design Workshop
September 18, 2012 IPUC Workshop
Exhibit No. 12 Case Nos. AVU-E-12-08 and AVU-G-12-07
T. Knox, Avista Schedule 4, Page 1 of 14
Settlement Stipulation (AVU-E-11-01)

10. Cost of Service. The Parties have agreed to exchange information
and convene a public workshop, prior to the Company’s next general
rate case, with respect to the method of allocation of demand and
energy among the customer classes such as the possible use of a
revised peak credit method for classifying production costs, as well as
consideration of the use of a 12 Coincident Peak (CP) (whether
“weighted” or not) versus a 7 CP or other method for allocating
transmission costs. This workshop will also address the merits of
inclining or declining block rates for service schedules 11, 21, 25 and
31.

2
Exhibit No. 12 Case Nos. AVU-E-12-08 and AVU-G-12-07
T. Knox, Avista Schedule 4, Page 2 of 14
Workshop Topics

Item # 1 – Peak Credit Classification Method

Item # 2 – Allocation of Transmission Costs

Item # 3 – Merits of Inclining or Declining Block Rates

3
Exhibit No. 12 Case Nos. AVU-E-12-08 and AVU-G-12-07
T. Knox, Avista Schedule 4, Page 3 of 14
Item #1 - Peak Credit Classification Method

1.Review Previous Peak Credit Methodology
2.Discuss Avista Proposed Peak Credit Methodology
3.Why the change is preferable from Avista’s viewpoint
4.Is the Proposed Peak Credit Methodology stable over time?

4
Exhibit No. 12 Case Nos. AVU-E-12-08 and AVU-G-12-07
T. Knox, Avista Schedule 4, Page 4 of 14
Item #1 - Peak Credit Classification Method (continued)
5
Prior Method
Avista’s electric system resource costs were classified to energy and demand using
a comparison of the replacement cost-per-kW of the Company’s peaking units, to
the replacement cost-per-kW of the Company’s thermal and hydro generating
facilities (separately).
•Created separate peak credit ratios applied to thermal plant and hydro plant.
•Transmission costs were assigned to energy and demand by a 50/50 weighting
of the thermal and hydro peak credit ratios.
•Fuel and load dispatching expenses were classified entirely to energy.
•Peaking plant related costs were classified entirely to demand.
Exhibit No. 12 Case Nos. AVU-E-12-08 and AVU-G-12-07
T. Knox, Avista Schedule 4, Page 5 of 14
Item #1 - Peak Credit Classification Method (continued)
6
Proposed Method
Uses the system load factor to determine peak credit ratio.
•Stemmed from discussions at the February 2011 Cost of Service workshop.
•The Classification ratio is applied to all production costs.
•Calculation: One minus the load factor equals the demand percentage or peak
credit ratio.
Net effect – slightly increases the overall production costs that are classified as
demand-related.
•Using the prior method, approximately 32% of total production costs were
classified as demand-related.
•Under the proposed load factor peak credit method, 36.4% of total production
costs would be classified as demand-related.
Exhibit No. 12 Case Nos. AVU-E-12-08 and AVU-G-12-07
T. Knox, Avista Schedule 4, Page 6 of 14
Item #1 - Peak Credit Classification Method (continued)
7
Why does Avista view this methodology to be preferable?
•Tied to the Company’s actual use of the system in the test year.
•Actual load factor represents current use of the system vs. historical
replacement cost analysis which is based on vintage investments.
•Less complicated single ratio applied to all production costs vs. multiple
ratios, weight dependent on each cost item’s relationship to plant investment.
•Overall weighted demand/energy relationship stays the same when power
costs are updated – not impacted by swings in the cost of fuel, unlike prior
method.

Exhibit No. 12 Case Nos. AVU-E-12-08 and AVU-G-12-07
T. Knox, Avista Schedule 4, Page 7 of 14
Item #1 - Peak Credit Classification Method (continued)
8
Will the new methodology provide a “stable” demand/energy classification
over time?
•Avista believes the proposed method will be more consistent over time
versus the prior method.
•Proposed method demand proportion has varied from 34% to 39% in the last
5 years – a range of 5%.
•Prior method demand proportion has varied from 23% to 34% in the last 5
years – a range of 11% (driven in part by the cost of fuel)

Exhibit No. 12 Case Nos. AVU-E-12-08 and AVU-G-12-07
T. Knox, Avista Schedule 4, Page 8 of 14
Item #2 – Allocation of Transmission Costs
9
Historically, transmission costs were included in the production peak credit
classification as they were considered extension of generation facilities
•Demand classified portion allocated to customer classes by 12 CP (average
of the 12 monthly system coincident peak hours)

In the Settlement approved in AVU-E-10-01, the methodology was changed to now
classify transmission costs as 100% demand.
•This is consistent with traditional NARUC approach.
•While the Settlement approved transmission classification as 100%
demand, it kept the 12 CP allocation and required February 2011
workshop to discuss alternatives.
•In the AVU-E-11-01 general rate case, Avista proposed a weighted 12 CP
allocation for transmission costs (stemming from February 2011 workshop
discussions).

Exhibit No. 12 Case Nos. AVU-E-12-08 and AVU-G-12-07
T. Knox, Avista Schedule 4, Page 9 of 14
Item #2 – Allocation of Transmission Costs (continued)
10
Workshop Discussion – “consideration of the use of a 12 CP (whether “weighted”
or not) versus a 7 CP or other method for allocating transmission costs”.
1.12 CP (average of the monthly system coincident peaks)
•Captures relative contribution to demand throughout the year
•Aligns with FERC Open Access transmission cost methodology
2.Weighted 12 CP - see Handout
•Weighted by Relative Monthly System Peaks
•Captures seasonal impacts of capacity utilization
3.7 CP (average of 4 winter and 3 summer monthly system coincident
peaks)
•Assumes no transmission demand cost in shoulder months

Exhibit No. 12 Case Nos. AVU-E-12-08 and AVU-G-12-07
T. Knox, Avista Schedule 4, Page 10 of 14
Item #3 – Merits of Inclining or Declining Block Rates
for Schedules 11, 21, 25 and 31
11
Exhibit No. 12 Case Nos. AVU-E-12-08 and AVU-G-12-07
T. Knox, Avista Schedule 4, Page 11 of 14

Present Base Rates
Schedule 1 (Residential)
Basic Charge $5.25
First 600 kWh 7.848¢
Over 600 kWh 8.764¢

Schedule 11 (General Service)
Basic charge $10.00
First 3,650 kWh 9.338¢
Over 3,650 kWh 6.958¢
Demand over 20 kW $5.25

Schedule 21 (Large General Service)
First 250,000 kWh 6.039¢
Over 250,000 kWh 5.154¢
Demand 1st 50 kW $350
Over 50 kW $4.75

Schedule 25 (Extra Large General Service)
First 500,000 kWh 5.047¢
Over 500,000 kWh 4.275¢
Demand 1st 3,000 kVa $12,500
Over 3,000 kVa $4.50

Schedule 31 (Pumping)
Basic charge $8.00
1st block 8.939¢
2nd block 8.939¢
3rd block 7.620¢

12
Exhibit No. 12 Case Nos. AVU-E-12-08 and AVU-G-12-07
T. Knox, Avista Schedule 4, Page 12 of 14
Support for Declining Block Rates – Schedules 11, 21, and 25:
Generally, the incremental fixed costs required to provide service to commercial
and industrial customers do not increase proportionately with increasing
energy usage.
–As most of the Company’s fixed costs of service are recovered through the
energy charges (and demand charges where applicable), larger use
customers are generally less costly to serve than smaller use customers on
an embedded cost per kWh basis, as fixed costs are spread over a larger
base of usage.
–Within the Company’s commercial and industrial schedules, there is also a
substantial range of energy usage. Therefore, declining block rates for
commercial and industrial customers generally reflect the cost of providing
service within rate schedules, as well as across rate schedules.

Implementing rate structure changes can create potential customer bill volatility
resulting from the new rate structure.
13
Exhibit No. 12 Case Nos. AVU-E-12-08 and AVU-G-12-07
T. Knox, Avista Schedule 4, Page 13 of 14
Merits for Inclining Block Rates:
•Sends a conservation price signal, and penalizes large users.
•Can promote fuel conversion – electric to natural gas fuel switching for
residential customers.
14
Exhibit No. 12 Case Nos. AVU-E-12-08 and AVU-G-12-07
T. Knox, Avista Schedule 4, Page 14 of 14
Exhibit No. 12
Case No. AVU-G-12-07
T. Knox, Avista
Schedule 5, p. 1 of 9

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
NATURAL GAS COST OF SERVICE STUDY 1
There are three basic steps involved in a cost of service study: functionalization, 7
classification, and allocation. See flow chart. 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 or 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. 12
Case No. AVU-G-12-07
T. Knox, Avista
Schedule 5, p. 2 of 9

Customer classes shown in this flowchart are illustrative and may not match the Company’s actual rate schedules. 1
Pro Forma Results of Operations by Customer Group 1
NATURAL GAS COST OF SERVICE STUDY FLOWCHART
Underground Storage
Production / Purchased Gas
Cost
Distribution and Customer Relations
Energy / Commodity Related
Customer Related
Demand /
Capacity Related
Residential Small General Large General Interruptible Transportation
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
Exhibit No. 12
Case No. AVU-G-12-07
T. Knox, Avista
Schedule 5, p. 3 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
Production - Purchased Gas Costs 5
BASE CASE COST OF SERVICE STUDY 4
The Company has no natural gas production facilities to serve its retail customers. The 6
natural gas costs included in the production function include the cost of gas purchased to serve 7
sales customers, pipeline transportation to get it to our system, and expenses of the gas supply 8
department. 9
The demand and commodity components of account 804 have been determined directly 10
from the weighted average cost of gas (WACOG) approved in the most recent purchased gas 11
adjustment (PGA) filing effective October 1, 2012. The allocation of these costs agrees with the 12
gas costs computation used to determine pro forma results of operations. 13
The expenses of the gas supply department recorded in account 813 are classified as 14
commodity related costs. The gas scheduling process includes transportation customers, so 15
estimated scheduling dispatch labor expenses are allocated by throughput. The remaining gas 16
supply department expenses are allocated by sales volumes. 17
Underground Storage 18
Underground storage rate base, operating and maintenance expenses are classified as 19
commodity related and allocated to customer groups by winter throughput. This approach was 20
proposed by commission Staff and accepted by the Idaho Public Utilities Commission in Case No. 21
AVU-G-04-01. 22
23
Exhibit No. 12
Case No. AVU-G-12-07
T. Knox, Avista
Schedule 5, p. 4 of 9

Distribution Facilities Classification (Peak and Average) 1
Distribution mains and regulator station equipment (both general use and city gate stations) 2
are classified Demand and Commodity using the peak and average ratio for the distribution 3
system. Peak demand is defined as the average of the five-day sustained peaks from the most 4
recent three years. Average daily load is calculated by dividing annual throughput by 365 (days in 5
the year). The average daily load is divided by peak load to arrive at the system load factor of 6
34.40%. This proportion is classified as commodity related. The remaining 65.60% is classified 7
as demand related. Meters, services and industrial measuring & regulating equipment are 8
classified as customer related distribution plant. Distribution operating and maintenance expenses 9
are classified (and allocated) in relation to the plant accounts they are associated with. 10
Customer Relations Distribution Cost Classification 11
Customer service, customer information and sales expenses are the core of the customer 12
relations functional unit which is included with the distribution cost category. For the most part 13
these costs are classified as customer related. Exceptions include uncollectible accounts expense, 14
which is considered separately as a revenue conversion item, and any Demand Side Management 15
amortization expense recorded in Account 908. Any demand side management investment costs 16
and amortization expense included in base rates would be included with the distribution function 17
and classified to demand and commodity by the peak and average ratio. At this point in time, the 18
Company’s demand side management investments in base rates have been fully amortized. All 19
current demand side management costs are managed through the Schedule 191 Public Purpose 20
Tariff Rider balancing account which is not included in this cost study. 21
Distribution Cost Allocation 22
Demand related distribution costs are allocated to customer groups (rate schedules) by each 23
groups’ contribution to the three year average five-day sustained peak. Commodity related 24
Exhibit No. 12
Case No. AVU-G-12-07
T. Knox, Avista
Schedule 5, p. 5 of 9

distribution costs are allocated to customer groups by annual throughput. Distribution main 1
investment has been segregated into large and small mains. Small mains are defined as less than 2
four inches, with large mains being four inches or greater. The small main costs use the same 3
demand and commodity data, but large usage customers (Schedules 131, and 146) that connect to 4
large system mains have been excluded from the allocations. 5
Most customer related costs are allocated by the annualized number of customers billed 6
during the test period. Meter investment costs are allocated using the number of customers 7
weighted by the relative current cost of meters in service at December 31, 2011. Services 8
investment costs are allocated using the number of customers weighted by the relative current cost 9
of typical service installations. Industrial measuring and regulating equipment investment costs 10
are allocated by number of turbine meters which effectively excludes small usage customers. 11
Administrative and General Costs 12
General and intangible rate base items are allocated by the sum of Underground Storage 13
and Distribution plant. Administrative and general expenses are segregated into plant related, 14
labor related, revenue related and other. The plant related items are allocated based on total plant 15
in service. Labor related items are allocated by operating and maintenance labor expense. 16
Revenue related items are allocated by pro forma revenue. Other administrative and general 17
expenses are allocated 50% by annual throughput (classified commodity related) and 50% by the 18
sum of operating and maintenance expenses not including purchased gas cost or administrative & 19
general expenses. Whenever costs are allocated by sums of other items within the study, 20
classifications are imputed from the relationship embedded in the summed items. 21
Special Contract Customer Revenue 22
Three special contract customers receive transportation service from the Company. Rates 23
for these customers were individually negotiated to cover any incremental costs and retain some 24
Exhibit No. 12
Case No. AVU-G-12-07
T. Knox, Avista
Schedule 5, p. 6 of 9

contribution to margin. The rates for these customers are not being adjusted in this case. The 1
revenue from these special contract customers has been segregated from general rate revenue and 2
allocated back to all the other rate classes by relative rate base. In treating these revenues like 3
other operating revenues their system contribution reduces costs for all rate schedules. 4
Revenue Conversion Items 5
In this study uncollectible accounts and commission fees have been classified as revenue 6
related and are allocated by pro forma revenue. These items vary with revenue and are included in 7
the calculation of the revenue conversion factor. Income tax expense items are allocated to 8
schedules by net income before income tax less interest expense. 9
For the functional summaries on pages 2 and 3 of the cost of service study, these items are 10
assigned to the component cost categories. The revenue related expense items have been reduced 11
to a percent of all other costs and loaded onto each cost category b that ratio. Similarly, income 12
tax items have been assigned to cost categories by relative rate base (as is net income). 13
The following matrix outlines the methodology applied in the Company Base Case natural 14
gas cost of service study. 15
IPUC Case No. AVU-G-12-07 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 Plan
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 co
9 381 Meters Distribution Customer C03, Customers weighted by average current meter co
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 from UG & D Plant S03 Sum of Underground Storage and Distribution Plant in Service
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 from UG & D Plant S03 Sum of Underground Storage and Distribution Plant in Service
Reserve for Depreciatio
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 Bas
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 Demand/Commodity from PGA Tracker WACOG D05/E07 PGA Demand / PGA Commodity
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. 12
Case No. AVU-G-12-07
T. Knox, Avista
Schedule 5, p. 7 of 9
IPUC Case No. AVU-G-12-07 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 co
9 880 Other OP Expenses Distribution Demand/Commodity/Customer from other dist expensesS04 Sum of Accounts 870 - 879 and 881 - 894
10 881 Rents Distribution Demand/Commodity/Customer from other dist expensesS04 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 Expense
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 Expense
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 Expense
30 911 - 916 Sales Expenses Customer Relations Customer C01 All customers (unweighted)
Exhibit No. 12
Case No. AVU-G-12-07
T. Knox, Avista
Schedule 5, p. 8 of 9
IPUC Case No. AVU-G-12-07 Methodology Matrix
Avista Utilities Idaho Jurisdiction
Natural Gas Cost of Service Methodology
Line Account Functional Category Classification Allocation
Admin & General Expense
1 920 Salaries Common Demand/Commodity/Customer from Other O&M S02/E01 50% O&M excl Gas Purchases and A&G / 50% throughput
2 921 Office Supplies Common Demand/Commodity/Customer from Other O&M S02/E01 50% O&M excl Gas Purchases and A&G / 50% throughput
3 922 Admin Expense Transferred - Credit Common Demand/Commodity/Customer from Other O&M S02/E01 50% O&M excl Gas Purchases and A&G / 50% throughput
4 923 Outside Services Common Demand/Commodity/Customer from Other O&M S02/E01 50% O&M excl Gas Purchases and A&G / 50% throughput
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 S02/E01 50% O&M excl Gas Purchases and A&G / 50% throughput
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 S02/E01 50% O&M excl Gas Purchases and A&G / 50% throughput
9 928 Regulatory Commision Common Demand/Commodity/Customer from Other O&M S02/E01 50% O&M excl Gas Purchases and A&G / 50% throughput
10 928 Commission Fees Revenue Conversion Revenue R01 Retail Sales Revenue
11 930 Miscellaneous General Common Demand/Commodity/Customer from Other O&M S02/E01 50% O&M excl Gas Purchases and A&G / 50% throughput
12 931 Rents Common Demand/Commodity/Customer from Other O&M S02/E01 50% O&M excl Gas Purchases and A&G / 50% throughput
13 935 MT of General Plant Common Demand/Commodity/Customer from Plant in Service S17 Sum of Total Plant in Service
Depreciation Expens
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. 12
Case No. AVU-G-12-07
T. Knox, Avista
Schedule 5, p. 9 of 9
Sumcost AVISTA UTILITIES Natural Gas Utility
Company Base Case Cost of Service General Summary Idaho Jurisdiction 10-Oct-12
AVU-G-04-01 Method For the Year Ended June 30, 2012

(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 10,832,000 7,986,151 2,606,033 40,792 199,024
3 Distribution Plant 160,940,000 134,562,866 24,897,046 381,443 1,098,645
4 Intangible Plant 2,880,000 2,391,170 460,142 7,063 21,625
5 General Plant 21,237,000 17,624,022 3,400,338 52,203 160,437
6 Total Plant In Service 195,889,000 162,564,209 31,363,559 481,502 1,479,731
Accum Depreciation
7 Production Plant
8 Underground Storage Plant (3,970,000) (2,926,978) (955,128) (14,951) (72,944)
9 Distribution Plant (56,320,000) (47,953,864) (7,900,330) (122,542) (343,264)
10 Intangible Plant (1,273,000) (1,056,672) (203,614) (3,126) (9,589)
11 General Plant (7,261,000) (6,025,711) (1,162,587) (17,848) (54,854)
12 Total Accumulated Depreciation (68,824,000) (57,963,224) (10,221,659) (158,467) (480,650)
13 Net Plant 127,065,000 104,600,985 21,141,900 323,035 999,081
14 Accumlulated Deferred FIT (24,281,000) (20,150,297) (3,887,603) (59,683) (183,417)
15 Miscellaneous Rate Base 8,146,000 6,128,328 1,854,175 28,951 134,547
16 Total Rate Base 110,930,000 90,579,015 19,108,473 292,302 950,211
17 Revenue From Retail Rates 63,338,000 47,851,692 14,995,946 201,088 289,275
18 Other Operating Revenues 156,000 127,635 26,644 408 1,314
19 Total Revenues 63,494,000 47,979,327 15,022,590 201,496 290,588
Operating Expenses
20 Purchased Gas Costs 33,351,000 23,596,182 9,619,766 133,184 1,868
21 Underground Storage Expenses 275,000 202,750 66,161 1,036 5,053
22 Distribution Expenses 4,972,000 4,151,083 748,901 9,399 62,617
23 Customer Accounting Expenses 2,306,000 2,227,555 76,950 571 923
24 Customer Information Expenses 399,000 392,154 6,815 5 27
25 Sales Expenses 3,000 2,949 51 0 0
26 Admin & General Expenses 5,900,000 4,632,934 1,139,648 18,541 108,877
27 Total O&M Expenses 47,206,000 35,205,607 11,658,293 162,736 179,364
28 Taxes Other Than Income Taxes 1,024,000 854,789 159,613 2,447 7,152
29 Depreciation Expense
30 Underground Storage Plant Depr 165,000 121,650 39,697 621 3,032
31 Distribution Plant Depreciation 4,076,000 3,415,369 623,992 9,436 27,203
32 General Plant Depreciation 1,974,000 1,638,170 316,065 4,852 14,913
33 Amortization of Intangible Plant 549,000 455,625 87,881 1,349 4,145
34 Total Depr & Amort Expense 6,764,000 5,630,814 1,067,634 16,259 49,292
35 Income Tax 2,021,000 1,394,722 611,619 4,408 10,251
36 Total Operating Expenses 57,015,000 43,085,932 13,497,159 185,849 246,060
37 Net Income 6,479,000 4,893,395 1,525,430 15,646 44,529
38 Rate of Return 5.84% 5.40% 7.98% 5.35% 4.69%
39 Return Ratio 1.00 0.92 1.37 0.92 0.80
40 Interest Expense 3,339,000 2,726,434 575,166 8,798 28,601
Exhibit No. 12
Case No. AVU-G-12-07
T. Knox, Avista
Schedule 6, p. 1 of 4
Sumcost AVISTA UTILITIES Natural Gas Utility
Company Base Case Summary by Function with Margin Analysis Idaho Jurisdiction 10-Oct-12
AVU-G-04-01 Method For the Year Ended June 30, 2012

(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 33,521,417 23,716,754 9,668,921 133,864 1,878
2 Underground Storage 1,415,902 953,474 436,491 4,833 21,105
3 Distribution 19,044,897 15,749,532 3,127,224 35,691 132,449
4 Common 9,355,784 7,431,932 1,763,310 26,700 133,843
5 Total Current Rate Revenue 63,338,000 47,851,692 14,995,946 201,088 289,275
6 Exclude Cost of Gas w / Revenue Exp. 33,188,726 23,482,973 9,573,613 132,140 0
7 Total Margin Revenue at Current Rates 30,149,274 24,368,719 5,422,333 68,948 289,275
Margin per Therm at Current Rates
8 Production $0.00424 $0.00436 $0.00436 $0.00436 $0.00073
9 Underground Storage $0.01806 $0.01780 $0.01999 $0.01223 $0.00817
10 Distribution $0.24295 $0.29399 $0.14319 $0.09036 $0.05125
11 Common $0.11935 $0.13873 $0.08074 $0.06760 $0.05179
12 Total Current Margin Melded Rate per Therm $0.38460 $0.45488 $0.24827 $0.17456 $0.11193
Functional Cost Components at Uniform Current Return
13 Production 33,521,417 23,716,754 9,668,921 133,864 1,878
14 Underground Storage 1,381,729 1,018,713 332,425 5,203 25,387
15 Distribution 19,072,494 16,256,713 2,634,104 37,400 144,277
16 Common 9,362,360 7,515,337 1,684,192 26,977 135,854
17 Total Uniform Current Cost 63,338,000 48,507,517 14,319,643 203,444 307,397
18 Exclude Cost of Gas w / Revenue Exp. 33,188,726 23,482,973 9,573,613 132,140 0
19 Total Uniform Current Margin 30,149,274 25,024,544 4,746,030 71,303 307,397
Margin per Therm at Uniform Current Return
20 Production $0.00424 $0.00436 $0.00436 $0.00436 $0.00073
21 Underground Storage $0.01763 $0.01902 $0.01522 $0.01317 $0.00982
22 Distribution $0.24330 $0.30346 $0.12061 $0.09469 $0.05583
23 Common $0.11943 $0.14029 $0.07711 $0.06830 $0.05257
24 Total Current Uniform Margin Melded Rate per $0.38460 $0.46712 $0.21731 $0.18052 $0.11894
25 Margin to Cost Ratio at Current Rates 1.00 0.97 1.14 0.97 0.94
Functional Cost Components at Proposed Rates
26 Production 33,521,324 23,716,688 9,668,895 133,864 1,878
27 Underground Storage 1,920,688 1,319,496 564,632 6,688 29,872
28 Distribution 22,530,362 18,595,034 3,734,430 44,235 156,663
29 Common 9,926,626 7,899,855 1,860,727 28,083 137,961
30 Total Proposed Rate Revenue 67,899,000 51,531,073 15,828,685 212,869 326,373
31 Exclude Cost of Gas w / Revenue Exp. 33,188,634 23,482,908 9,573,586 132,140 0
32 Total Margin Revenue at Proposed Rates 34,710,366 28,048,165 6,255,098 80,729 326,373
Margin per Therm at Proposed Rates
33 Production $0.00424 $0.00436 $0.00436 $0.00436 $0.00073
34 Underground Storage $0.02450 $0.02463 $0.02585 $0.01693 $0.01156
35 Distribution $0.28741 $0.34710 $0.17099 $0.11199 $0.06062
36 Common $0.12663 $0.14746 $0.08520 $0.07110 $0.05338
37 Total Proposed Margin Melded Rate per Therm $0.44278 $0.52356 $0.28640 $0.20438 $0.12629
Functional Cost Components at Uniform Proposed Return
38 Production 33,521,324 23,716,688 9,668,895 133,864 1,878
39 Underground Storage 1,884,238 1,389,199 453,322 7,096 34,620
40 Distribution 22,559,790 19,136,920 3,206,979 46,115 169,777
41 Common 9,933,648 7,988,967 1,776,102 28,388 140,191
42 Total Uniform Proposed Cost 67,899,000 52,231,774 15,105,298 215,462 346,466
43 Exclude Cost of Gas w / Revenue Exp. 33,188,634 23,482,908 9,573,586 132,140 0
44 Total Uniform Proposed Margin 34,710,366 28,748,866 5,531,712 83,322 346,466
Margin per Therm at Uniform Proposed Return
45 Production $0.00424 $0.00436 $0.00436 $0.00436 $0.00073
46 Underground Storag $0.02404 $0.02593 $0.02076 $0.01796 $0.01340
47 Distribution $0.28778 $0.35722 $0.14684 $0.11675 $0.0656948 Common 0.12672 0.14913 0.08132 0.07187 0.05425
49 Total Proposed Uniform Margin Melded Rate p $0.44278 $0.53664 $0.25328 $0.21095 $0.13406
50 Margin to Cost Ratio at Proposed Rates 1.00 0.98 1.13 0.97 0.94
51 Current Margin to Proposed Cost Ratio 0.87 0.85 0.98 0.83 0.83
Exhibit No. 12
Case No. AVU-G-12-07
T. Knox, Avista
Schedule 6, p. 2 of 4
Sumcost AVISTA UTILITIES Natural Gas Utility
Company Base Case Summary by Classification with Unit Cost Analysis Idaho Jurisdiction 10-Oct-12
AVU-G-04-01 Method For the Year Ended June 30, 2012
(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 34,160,448 23,838,005 9,991,218 172,884 158,342
2 Demand 15,568,367 11,351,736 4,131,987 27,201 57,443
3 Customer 13,609,184 12,661,951 872,741 1,003 73,489
4 Total Current Rate Revenue 63,338,000 47,851,692 14,995,946 201,088 289,275
Revenue per Therm at Current Rates
5 Commodity $0.43577 $0.44497 $0.45747 $0.43770 $0.06127
6 Demand $0.19860 $0.21190 $0.18919 $0.06886 $0.02223
7 Customer $0.17361 $0.23635 $0.03996 $0.00254 $0.02844
8 Total Revenue per Therm at Current Rates $0.80797 $0.89322 $0.68662 $0.50910 $0.11193
Cost per Unit at Current Rates
9 Commodity Cost per Therm $0.43577 $0.44497 $0.45747 $0.43770 $0.06127
10 Demand Cost per Peak Day Therms $24.94 $23.55 $32.33 $12.37 $4.72
11 Customer Cost per Customer per Month $15.09 $14.28 $56.65 $83.60 $1,224.82
Cost by Classification at Uniform Current Return
12 Commodity 34,031,219 24,006,790 9,682,672 174,093 167,665
13 Demand 15,512,746 11,562,903 3,858,320 28,310 63,214
14 Customer 13,794,035 12,937,824 778,652 1,041 76,518
15 Total Uniform Current Cost 63,338,000 48,507,517 14,319,643 203,444 307,397
Cost per Therm at Current Return
16 Commodity $0.43412 $0.44812 $0.44334 $0.44076 $0.06488
17 Demand $0.19789 $0.21584 $0.17666 $0.07167 $0.02446
18 Customer $0.17596 $0.24150 $0.03565 $0.00264 $0.02961
19 Total Cost per Therm at Current Return $0.80797 $0.90547 $0.65565 $0.51507 $0.11894
Cost per Unit at Uniform Current Return
20 Commodity Cost per Therm $0.43412 $0.44812 $0.44334 $0.44076 $0.06488
21 Demand Cost per Peak Day Therms $24.85 $23.99 $30.19 $12.87 $5.19
22 Customer Cost per Customer per Month $15.29 $14.59 $50.55 $86.75 $1,275.30
23 Revenue to Cost Ratio at Current Rates 1.00 0.99 1.05 0.99 0.94
Cost by Classification at Proposed Return by Schedule
24 Commodity 35,512,391 24,784,909 10,371,125 178,930 177,427
25 Demand 17,107,424 12,536,458 4,468,962 32,747 69,257
26 Customer 15,279,184 14,209,705 988,597 1,193 79,690
27 Total Proposed Rate Revenue 67,899,000 51,531,073 15,828,685 212,869 326,373
Revenue per Therm at Proposed Rates
28 Commodity $0.45301 $0.46265 $0.47486 $0.45300 $0.06865
29 Demand $0.21823 $0.23401 $0.20462 $0.08291 $0.02680
30 Customer $0.19491 $0.26525 $0.04526 $0.00302 $0.03084
31 Total Revenue per Therm at Proposed Rates $0.86615 $0.96191 $0.72475 $0.53893 $0.12629
Cost per Unit at Proposed Rates
32 Commodity Cost per Therm $0.45301 $0.46265 $0.47486 $0.45300 $0.06865
33 Demand Cost per Peak Day Therms $27.40 $26.00 $34.97 $14.89 $5.69
34 Customer Cost per Customer per Month $16.94 $16.03 $64.17 $99.38 $1,328.16
Cost by Classification at Uniform Proposed Return
35 Commodity 35,374,366 24,965,244 10,041,098 180,260 187,764
36 Demand 17,047,939 12,762,074 4,176,242 33,968 75,655
37 Customer 15,476,695 14,504,456 887,957 1,234 83,048
38 Total Uniform Proposed Cost 67,899,000 52,231,774 15,105,298 215,462 346,466
Cost per Therm at Proposed Return
39 Commodity $0.45125 $0.46601 $0.45975 $0.45637 $0.07265
40 Demand $0.21747 $0.23822 $0.19122 $0.08600 $0.02927
41 Customer $0.19743 $0.27075 $0.04066 $0.00312 $0.03213
42 Total Cost per Therm at Proposed Return $0.86615 $0.97499 $0.69162 $0.54549 $0.13406
Cost per Unit at Uniform Proposed Return
43 Commodity Cost per Therm $0.45125 $0.46601 $0.45975 $0.45637 $0.07265
44 Demand Cost per Peak Day Therms $27.31 $26.47 $32.68 $15.45 $6.21
45 Customer Cost per Customer per Month $17.16 $16.36 $57.64 $102.85 $1,384.13
46 Revenue to Cost Ratio at Proposed Rates 1.00 0.99 1.05 0.99 0.94
47 Current Revenue to Proposed Cost Ratio 0.93 0.92 0.99 0.93 0.83
Exhibit No. 12
Case No. AVU-G-12-07
T. Knox, Avista
Schedule 6, p. 3 of 4
Sumcost AVISTA UTILITIES Natural Gas Utility
Company Base Case Customer Cost Analysis Idaho Jurisdiction 10-Oct-12
AVU-G-04-01 Method For the Year Ended June 30, 2012

(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
Rate Base
1 Services 49,451,000 48,578,554$ 844,170$ 1,973$ 26,303$
2 Services Accum. Depr. (22,558,000) (22,160,017)$ (385,084)$ (900)$ (11,999)$
3 Total Services 26,893,000 26,418,537 459,086 1,073 14,305
4 Meters 21,321,000 18,565,797$ 2,658,436$ 5,024$ 91,743$
5 Meters Accum. Depr. (4,746,000) (4,132,699)$ (591,761)$ (1,118)$ (20,422)$
6 Total Meters 16,575,000 14,433,099 2,066,675 3,906 71,321
7 Total Rate Base 43,468,000 40,851,635 2,525,761 4,978 85,625
8 Return on Rate Base @ 8.46% 3,677,393 3,456,048 213,679 421 7,244
9 Revenue Conversion Factor 0.63711 0.63711 0.63711 0.63711 0.63711
10 Rate Base Revenue Requirement 5,771,990 5,424,571 335,389 661 11,370
Expenses
11 Services Depr Exp 1,224,000 1,202,405$ 20,895$ 49$ 651$
12 Meters Depr Exp 632,000 550,330$ 78,802$ 149$ 2,719$
13 Services Maintenance Exp 418,000 410,625$ 7,136$ 17$ 222$
14 Meters Maintenance Exp 415,000 361,372$ 51,745$ 98$ 1,786$
15 Meter Reading 252,000 247,676$ 4,304$ 3$ 17$
16 Billing 1,702,000 1,672,795$ 29,069$ 23$ 113$
17 Total Expenses 4,643,000 4,445,204 191,950 338 5,509
18 Revenue Conversion Factor 0.995009 0.995009 0.995009 0.995009 0.995009
19 Expense Revenue Requirement 4,666,289 4,467,501 192,913 340 5,536
20 10,438,280 9,892,072 528,301 1,001 16,906
21 Total Customer Bills 901,972 886,495 15,405 12 60
22 Average Unit Cost per Month $11.57 $11.16 $34.29 $83.41 $281.77
23 Total Customer Related Cost 15,476,695 14,504,456 887,957 1,234 83,048
24 Customer Related Unit Cost per Month $17.16 $16.36 $57.64 $102.85 $1,384.13
25 Other Non-Gas Costs 19,233,671 14,244,410 4,643,754 82,088 263,419
26 Other Non-Gas Unit Cost per Month $21.32 $16.07 $301.44 $6,840.63 $4,390.31
27 Total Fixed Unit Cost per Month $38.48 $32.43 $359.09 $6,943.48 $5,774.44
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. 12
Case No. AVU-G-12-07
T. Knox, Avista
Schedule 6, p. 4 of 4