20090123Knox Direct.pdf

DAVID J. MEYER
VICE PRESIDENT AND CHIEF COUNSEL OF
REGULATORY & GOVERNENTAL AFFAIRS
AVISTA CORPORATION
P.O. BOX 3727
1411 EAST MISSION AVENUE
SPOKANE, WASHINGTON 99220-3727
TELEPHONE: [phone]
FACSIMILE: [phone]
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2089 JAN 23 PM 12: 44
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF AVISTA CORPORATION FOR THE
AUTHORITY TO INCREASE ITS RATES
AND CHARGES FOR ELECTRIC AND
NATURAL GAS SERVICE TO ELECTRIC
AND NATURAL GAS CUSTOMERS IN THE
STATE OF IDAHO
CASE NO. AVU-E-09-01
CASE NO. AVU-G-09-01
DIRECT TESTIMONY
OF
TARA L. KNOX
FOR AVISTA CORPORATION
(ELECTRIC AND NATURAL GAS)
1 I . INTRODUCTION
2 Q.Please state your name, business address and
3 present position with Avista Corporation?
4
5
A.My name is Tara L. Knox and my business address
is 1411 East Mission Avenue, Spokane, Washington.I am
6 employed as a Senior Rate Analyst in the State and Federal
7 Regulation Department.
8
9
Q.Would you briefly describe your duties?
A.I am responsible for preparing the regulatory
10 cost of service models for the Company, as well as
11 providing support for the preparation of results of
12 operations reports.
13 Q.Would you describe your educational background
14 and professional experience?
15 A.Yes.I am a 1982 graduate of Washington State
16 university with a Bachelor of Arts degree in General
17 Humanities, and a Master of Accounting degree in 1990. As
18 an employee in the Rate Department at Avista since 1991, I
19 have attended several ratemaking classes, including the EEI
20 Electric Rates Advanced Course that specializes in cost
21 allocation and cost of service issues. I have also been a
22 member of the Cost of Service Working Group and the
23 Northwest Pricing and Regulatory Forum,which are
24 discussion groups made up of technical professionals from
25 regional utilities and utilities throughout the United
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Avista Corporation
1 States and Canada concerned with cost of service issues.
2 Q.
3 proceedings?
4 A.
What is the scope of your testimony in these
My testimony and exhibits will thecover
5 Company's electric and natural gas cost of service studies
Addi tionally,I am6
7
performed for this proceeding.
natural gas revenuesponsoringtheelectricand
8 normalization adjustments to the test year results of
9 operations and the proposed retail revenue credit rate to
10 be used in the Power Cost Adjustment mechanism.
11 Table of Contents
12
13
14
15
16
17
18
19
20
21
22
23
24
25
i.
II.
III.iv.
v.
VI.
Q.
26 filed testimony?
27 A.
Introduction
Table of Contents
Revenue Normalization
Electric Revenue Normalization
Natural Gas Revenue Normalization
Proposed Retail Revenue Credit Rate
Electric Cost of Service
Demand Study
Scenario 1
Scenario 2
Scenario 3
Scenario 4
Natural Gas Cost of Service
Page 1
Page 2
Page 3
Page 3
Page 7
Page 11
Page 12
Page 17
Page 20
Page 22
Page 25
Page 27
Page 32
Are you sponsoring any Exhibits with your pre-
Yes.I am sponsoring Exhibit No. 11 composed of
28 six schedules as follows: Schedule 1, retail revenue credit
29 rate calculation; Schedule 2, electric cost of service
30 study process description; Schedule 3, electric cost of
31 service study results;Schedule 4,Demandsummary
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Avista Corporation
1 Sensitivity Results summary; Schedule 5, natural gas cost
2 of service study process description; and Schedule 6,
3 natural gas cost of service summary results.
4 Q.Were these exhibits prepared by you or under your
5 direction?
6 A.Yes.
7
8
9
II. REVENU NORMLIZATION
Electric Revenue Normlization
Q.Would you please describe the electric revenue
10 adjustment included in Company witness Ms. Andrews pro
11 form results of operations?
12 A.Yes.The electric revenue normalization
13 adjustment represents the difference between the Company's
14 actual recorded retail revenues during the twelve months
15 ended September 2008 test period and retail revenues on a
16 normalized (pro forma)basis.The total revenue
17 normalization adjustment increases Idaho net operating
18 income by $14,065,000 as shown in column (u) on page 6 of
Ms. Andrews Exhibit No .10, Schedule 1.The revenue19
20 normalization adjustment consists of three primary
21 components: 1) re-pricing customer usage (adjusted for any
22 known and measurable changes) at present base tariff rates
23 in effect,2) adjusting customer loads and revenue to a
24 12-month calendar basis (unbilled revenue adjustment), and
25 3) weather normalizing customer usage and revenue.
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Avista Corporation
1 Q.Since these three elements are combined into a
2 single adjustment, would you please identify the impact
3 (before taxes and revenue related expenses) of each
4 component?
5
6
A.Yes.The re-pricing of billed usage comprises
the majority of the change in test year revenue.The
7 combined impact of the rate increase effective October 1,
8 2008 and the elimination of revenue and amortization
9 expense from adder schedules, (Schedule 59 Residential
10 Exchange, and Schedule 91 Public purpose Tariff Rider1) is
11 an increase of $23,880,000.The impact of the pro forma
12 unbilled revenue compared to the amount included in results
13 of operations is a reduction of $31,000, and the weather
14 normalization adjustment reduces revenue by $1,837,000.
15 The resulting net operating income adjustment is
16 $14,065,000.
17 Q.Would you please briefly discuss electric weather
18 normalization?
19 A.Yes.The Company's weather normalization
20 adjustment calculates the change in kWh usage required to
21 adjust actual loads during the twelve months ended
22 September 2008 test period to the amount expected if
23 weather had been normal. This adjustment incorporates the
24 effect of both heating and cooling on weather-sensitive
1 City Franchise Fee and Power Cost Adjustment revenues are eliminated in separate adjustments.
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Avista Corporation
1 cus tomer groups.The weather adjustment is developed from
2 regression analysis of five years of billed usage per
3 customer and billing period heating and cooling degree-day
4 data.The resulting seasonal weather sensitivity factors
5 (use per customer per heating degree day and use per
6 customer per cooling degree day) are applied to monthly
7 test period customers and the difference between normal
8 heating / cooling degree-days and monthly test period
9 observed heating/cooling degree-days.
10 Q.How are norml heating and cooling degree days
11 defined?
12 A.Normal heating and cooling degree days are based
13 on a rolling 30-year average of heating and cooling degree-
14 days reported for each month by the National Weather
15 Service for the Spokane Airport weather station.For
16 heating, the 30 years are included on a heating season
17 basis, July through June, so, for example, the October
18 average reflects all the Octobers beginning in 1978 and
19 through 2007, whereas the May average reflects all of the
20 Mays beginning in 1979 and through 2008.For cooling, the
21 30 years reflect the cooling season calendar years
22 beginning in 1979 and through 20082.Each year the normal
2 The National Climatic Data Center publication used to acquire the final quality controlled data for the
Spokane Airort weather station did not include cooling degree day information prior to 1980.
Consequently, the 30 year average is actually a 29 year average including the years 1980 though 2008.
As a rolling average, in all futue years it would contain a full 30 years of data. Heating degree day
information was available for all the desired years.
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Avista Corporation
1 values will be adjusted to capture the next heating and
2 cooling season with the oldest data dropping off, thereby
3 encapsulating the most recent information available at the
4 end of each calendar year.
5 Q.Are there any changes in the weather adjustment
6 methodology since the company's last general rate case in
7 Idaho?
8 A. Yes.In Case No. AVU-E-08-01 the Company used a
9 twenty-five year rolling average to determine normal
10 heating and cooling degree days for each month.As
11 mentioned above, in this case an additional five years have
12 been included in the rolling average calculation.
13 Otherwise,the process is the same3 as the method
14 introduced in Case No. AVU-E-08-01.
15 Q.Why are you proposing to change from a 25-year to
16 a 30-year average for normal degree days?
17 A.In response to concerns in another jurisdiction
18 that twenty-five years may be insufficient to determine
19 "normal i # I performed additional analysis on how the
20 rolling averages change over time.Specifically,I
21 compared twenty-five year rolling averages to thirty year
22 rolling averages for all data available from the NOAA
23 published Annual Climatological Summary for the Spokane
3 The regression analysis presented in Case No. AVU-E-08~01 used ten years of data for Schedule 1 and
five years for all other schedules. In the updated analysis Schedule 1 no longer met all the statistical tests
with ten years of data. The five year analysis passed all the tests and was used in this analysis.
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Avista Corporation
1 Airport weather station. This analysis revealed that while
2 both a thirty-year average and a twenty-five year average
3 captures the long term trend in regional temperatures, the
4 thirty-year averages showed less variability.
5 The proposed averaging process maintains the advantage
6 of reflecting current weather trends by updating the values
7 annually, while providing a less volatile statistic through
8 the use of additional years of data.
9 Q.What was the impact of electric weather
10 normalization on the twelve months ended Septemer 2008
11 test year?
12 A.Weather was colder than normal during the winter
13 and spring, and warmer than normal during the summer of the
14 test year. The adjustment to normal required the deduction
15 of 294 heating degree-days and 45 cooling degree-days. The
16 total adjustment to Idaho sales volumes was a reduction of
17 24,948,329 kWhs which is approximately 0.7 percent of
18 billed usage.
19 Natural Gas Revenue Normlization
20 Q.Would you please describe the natural gas revenue
21 adjustment included in Ms. Andrews pro form results of
22 operations?
23 A.Yes.The natural gas revenue normalization
24 adjustment is similar to the electric adjustment and
25 represents the difference between the Company's actual
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Avista Corporation
1 recorded retail revenues during the twelve months ended
2 September 2008 test period and retail revenues on a
3 normalized (pro forma) basis.The adj us tmen t inc 1 udes the
4 re-pricing of pro forma sales and transportation volumes at
5 present rates (effective October 1, 2008) using pro forma
6 sales volumes that have been adjusted for unbilled sales,
7 abnormal weather,and any material customer load or
8 schedule changes.The rates used exclude:1) Temporary
9 Gas Rate Adjustment Schedule 155, which reflects the
10 approved amortization rate for deferred gas costs approved
11 in the Company's last PGA filing and 2) Public Purposes
12 Rider Adjustment Schedule 191.
13 Q.Does the Revenue Normlization Adjustment contain
14 a component reflecting normlized gas costs?
15 A.Yes. Purchase gas costs are normalized using the
16 gas costs approved by the Commission in Case No. AVU-G-08-
17 03, the Company's 2008 PGA filing4, as set forth under
18 Schedule 150.Those gas costs are then applied to the pro
19 forma retail sales volumes so that there is a matching of
20 revenues and gas cos ts .
21 The total net amount of the natural gas revenue
22 normalization,which includes the purchase gas cos t
23 adjustment, is an increase to net operating income of
4 The Januar 6,2009 gas cost reduction to customer charges was accomplished though Schedule 155
which is excluded from base revenues.
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Avista Corporation
1 $2,359,000, as shown in column (i), page 5 of Ms. Andrews
2 Exhibit No .10, Schedule 2.
3 Q.Would you please briefly discuss natural gas
4 weather normlization?
5 A.Yes.The natural gas weather adjustment is
6 developed from a regression analysis of ten years of billed
7 usage per customer and billing period heating degree-day
8 data.The resulting seasonal weather sensitivity factors
9 (use per customer per heating degree day) are applied to
10 monthly test period customers and the difference between
11 normal heating degree~days and monthly test period observed
12 heating degree-days.This calculation produces the change
13 in therm usage required to adjust existing loads to the
14 amount expected if weather had been normal.
15
16
Q.How are normal heating degree days defined?
A.Normal heating degree-days are based on a rolling
17 30-year average of heating degree-days reported for each
18 month by the National Weather Service for the Spokane
19 Airport weather station.The 30 years are included on a
20 heating season basis, July through June, so, for example,
21 the October average reflects all the Octobers beginning in
22 1978 and through 2007 whereas the May average reflects all
23 of the Mays beginning in 1979 and through 2008. Each year
24 the normal values will be adjusted to capture the next
25 heating season with the oldest data dropping off, thereby
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Avista Corporation
1 encapsulating the most recent information available at the
2 end of each calendar year.
3 Q.Other than the change from a 25-year rolling
4 average to a 30-year rolling average discussed with regards
5 to electric weather normlization, were any changes made to
6 the gas weather normalization methodology?
7 A. No,the process for determining the weather
8 sensitivity factors and the monthly adjustment calculation
9 are the same as the method introduced in Case No. AVU-G-08-
10 01.
11 Q.What was the impact of natural gas weather
12 normlization on the twelve months ended Septemer 2008
13 test year?
14 A.Weather was colder than normal during the
15 2007/2008 heating season.The adjustment to normal
16 required the deduction of 352 heating degree-days from
17 October through June.Warmer than normal weather that
18 occurred during the summer months did not impact gas usage
19 as customers are at baseload during that time.The
20 adjustment to sales volumes was a reduction of 2,827,731
21 therms which is approximately 2.3 percent of billed usage.
22 The margin impact (revenue less gas cost) of the weather
23 adjustment was a reduction of $834,000.
24
25
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Avista Corporation
1
2
III. PROPOSED RETAIL REVENU CREDIT RATE
Q. Company witness Mr. Johnson discusses using the
3 average cost of production and transmission for the retail
4 revenue credit rate in the Power Cost Adjustment (PCA).
5 How is that rate determined?
6 A. The retail revenue credit rate is determined by
7 computing the proposed revenue requirement on the
8 production and transmission subset of Ms. Andrews Idaho
9 Electric Pro forma Total Results of Operations.The
10 production/transmission revenue requirement amount is then
11 divided by the Idaho Normalized Retail Load used to set
12 rates in order to arrive at the average production and
13 transmission cost per kwh embedded in proposed rates.
14
15
Q. Is this process illustated in an Exhibit?
A. Yes.Exhibit No. 11, Schedule 1 begins with the
16 identification of the production and transmission revenue,
17 expense and rate base amounts included in each of Ms.
18 Andrews actual, restating, and pro forma adjustments to
19 results of operations. The "Pro Forma Total" at the bottom
20 of page 1 shows the resulting subset of these components.
21 Page 2 shows the revenue requirement calculation on
22 the production and transmission cost components. The rate
23 of return and debt cost percentages on line 2 are inputs
24 from the proposed cost of capital.The normalized retail
25 load on Line 10 comes from the workpapers to the revenue
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Avista Corporation
1 normalization adjustment.The proposed retail revenue
2 credit rate is shown on Line 11 and represents the average
3 Production and Transmission cost per kWh proposed to be
4 embedded in Idaho customer retail rates.
5
6
iv. ELECTRIC COST OF SERVICE
Q.Please briefly sunarize your testimony related
7 to the electric cost of service study.
8 A.I believe the Base Case cost of service study
9 presented in this case is a fair representation of the
10 costs to serve each customer group. The Base Case study
11 shows Residential Service Schedule 1, Extra Large General
12 Service Schedule 25 and 25P, and Street and Area Lighting
13 provide less than the overall rate of return under present
14 rates. General Service Schedule 11, Large General Service
15 Schedule 21 and Pumping Service Schedule 31 provide more
16 than the overall rate of return under present rates but
17 less than the requested return.
18 Q.What is an electric cost of service study and
19 what is its purpose?
20 A.An electric cost of service study is an
21 engineering-economic study, which separates the revenue,
22 expenses, and rate base associated with providing electric
23 service to designated groups of customers. The groups are
24 made up of customers with similar load characteristics and
25 facili ties requirements. Costs are assigned in relation to
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Avista Corporation
1 each group's characteristics, resulting in an evaluation of
2 the cost of the service provided to each group.The rate
3 of return by customer group indicates whether the revenue
4 provided by the customers in each group recovers the cost
5 to serve those customers. The study results are used as a
6 guide in determining the appropriate rate spread among the
7 groups of customers.Exhibi t No. 11, Schedule 2 explains
8 the basic concepts involved in performing an electric cost
9 of service study. It also details the specific methodology
10 and assumptions utilized in the Company's Base Case cost of
11 service study.
12 Q.What is the basis for the electric cost of
13 service study provided in this case?
14 A.The electric cost of service study provided by
15 the Company as Exhibit No .11, Schedule 3 is based on the
16 twelve months ended September 2008 test year pro forma
17 results of operations presented by Company witness Ms.
18 Andrews in Exhibi t NO.1 0, Schedule 1.
19 Q.Would you please explain the cost of service
20 study presented in Exhibit No. 11, Schedule 3?
21 A.Yes. Exhibit No. 11, Schedule 3 is composed of a
22 series of summaries of the cost of service study results.
23 The summary on page 1 shows the results of the study by
24 FERC account category. The rate of return by rate schedule
25 and the ratio of each schedule's return to the overall
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Avista Corporation
1 return are shown on Lines 39 and 40.This summary was
2 provided to Mr. Hirschkorn for his work on rate spread and
3 rate design. The results will be discussed in more detail
4 later in my testimony.
5 Pages 2 and 3 are both summaries that show the revenue
6 to cost relationship at current and proposed revenue.
7 Costs by category are shown first at the existing schedule
8 returns (revenue); next the costs are shown as if all
9 schedules were providing equal recovery (cost).These
10 comparisons show how far current and proposed rates are,
11 from rates that would be in alignment with the cost study.
12 Page 2 shows the costs segregated into production,
13
14
transmission,distribution,and common functional
categories.Page 3 segregates the costs into demand,
15 energy, and customer classifications.
16 The Excel model used to calculate the cost of service
17 and supporting schedules have been included in their
18 entirety both electronically and hard copy in the
19 workpapers accompanying this case.
20 Q.Does the Company's electric Base Case cost of
21 service study follow the methodology accepted in the
22 Company's last electric general rate case in Idaho?
23 A.Yes.The Base Case cost of service study was
24 prepared using the methodology accepted by the Idaho
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1 commission in Case No. AVU-E-04-01 and used in Case No.
2 AVU-E-08-01.
3 Q.Given that the specific details of this
4 methodology are described in Exhibit No. 11, Schedule 2,
5 would you please gi ve a brief overview of the key elements
6 and the history associated with those elements?
7 A.Yes.Production and transmission costs are
8 classified to energy and demand by a peak credit analysis.
9 Avista has been using the peak credit classification
10 process for cost of service studies in both Washington and
11 Idaho jurisdictions since the 1980' s.Distribution costs
12 are classified and allocated by the basic customer theory5
13 accepted by the Idaho commission in Case No. WWP-E-98-11.
14 Additional direct assignment of demand related distribution
15 plant has been incorporated to reflect improvements
16 accepted by the commission in Case No. AVU-E-04-01.
17 Administrative and general costs are first directly
18 assigned to production,transmission, distribution, or
19 customer relations functions. The remaining administrative
20 and general costs are categorized as common costs and have
21 been assigned to customer classes by the four-factor
22 allocator accepted by the Idaho commission in Case No. AVU-
23 E-04-01.
5 Basic customer theory classifies only meters, services and the direct assignment of street light fixtures as customer-
related plant; all other distrbution facilities are considered demand-related.
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Avista Corporation
1 Q.What are the results of the Company's Base Case
2 cost of service study?
3 A.The following table shows the rate of return and
4 the relationship of the customer class return to the
5 overall return (relative return ratio) at present rates for
6 each rate schedule:
7 Illustration 1:
Customer Class
Residential Service Schedule 1
General Service Schedule 11
Large General Service Schedule 21
Extra Large General Service Schedule 25
Ex. Lg. Gen. Service Potlatch Schedule 25P
Pumping Service Schedule 31
Lighting Service Schedules 41 - 49
Total Idaho Electric System
Rate of Return Return Ratio
4.56%
7.89%
6.74%
3.15%
3.93%
7.64%
4.89%2.
0.85
1.48
1.26
0.59
0.73
1. 43
0.92
1. 00
8 As can be observed from the above table, residential,
9 extra large general service, and lighting service schedules
10 (1, 25, 25P, and 41-49) show under-recovery of the costs to
11 serve them, while the general, large general, and pumping
12 service schedules (11, 21, and 31) show over-recovery of
13 the costs to serve them.However, al 1 cus tomer groups are
14 currently providing a rate of return lower than the rate of
15 return requested in this case. The summary results of this
16 study were provided to Mr. Hirschkorn as an input into
17 development of the proposed rates.
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Avista Corporation
1
2
V. DEM STUDY
Q An issue was raised in Case No. AVU-E-08-01
3 regarding the load data used to develop demand allocations
4 in the electric cost of service. Please elaborate on this
5 issue.
6 A.In the last rate case, the Company indicated
7 that, while the estimation process used to create the
8 demand allocators in the cost of service study provides a
9 reasonable assignment of cost to the existing customer
10 groups, the Company's load data was in the process of being
11 updated.Accordingly,the Commission provided the
12 following directive on page 13 of its Order No. 30647:
13 In this case the Commission finds the Company-filed
14 cost of service study to be sufficient to determine
15 rate design in this case. We direct the Company in its16 next general rate case to provide updated load data as
17 part of its COS study or, in the alternative, show how
18 the lack of such an update affects COS-based revenue
19 allocations to customer classes. (emphasis added)
20
21 Q Has the Company provided updated load data as
22 part of the cost of service study in this case?
23 A.No. While an electric demand study is currently
24 underway, wi th nearly all sample meters in place collecting
25 data (and the last few expected to be in place shortly), ~
26 full year of hourly load data is necessary to make use of
27 the information in the cost of service demand allocations.
28 The first full year of sample data will be collected over
29 the calendar year 2009. Consequently, the earliest that a
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Avista Corporation
1 general rate filing could incorporate updated load study
2 data would be sometime in 2010.
3 Q.Have you performed a sensitivity analysis to
4 determine the potential impact of updated load infor.ation
5 on cost of service based revenue allocations to customer
6 classes?
7 A.Yes. There are two types of demand allocations,
8 namely coincident peak and non-coincident peak.The
9 coincident peak allocations are applied to demand-related
10 production and transmission costs. The non-coincident peak
11 allocations are applied to demand-related distribution
12 costs.
13 i ran two sensitivity cases to determine how changes
14 in non-coincident demand for each customer class, i. e. ,
15 from a new load study, would affect the allocation of
16 demand costs.I also ran two sensitivity cases to
17 determine how changes in coincident demand for each
18 customer class would affect the allocation of demand costs.
19 Before I walk through the four sensi ti vi ty studies, it
20 is important to have some context for what we are trying to
21 test with the studies. Colum (a) in the table below shows
22 the relative rates of return for each customer class from
23 our Base Case cost of service study under present retail
24 rates.Column (b) shows the relative rates of return by
25 schedule after application of the proposed rate increase in
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Avista Corporation
1 this case.As Mr. Hirschkorn explains in his testimony,
2 the spread of the revenue increase to each customer class
3 was designed to move each customer class closer to unity
4 (wi th the exception of Street and Area Lights) .
5
6
7
8
9
10
11
12
13
14
15
16
Present
Relative ROR
(a)
0.85
1. 48
1.26
0.59
0.73
1. 43
0.92
1. 00
Residential Sch. 1
General Srvc. Sch. 11
Lg. Gen. Srvc. Sch. 21
Ex. Lg. Gen. Srvc. Sch. 25
Potlatch-Lewiston Sch. 25P
Pumping Srvc. Sch. 31
Street & Area Lgt. Schs.
Overall
Proposed
Relative ROR
(b)
0.86
1. 27
1.17
0.84
0.99
1. 28
0.73
1. 00
The table shows that the relative rate of return for
17 some customer schedules is above unity (1.0) for both
18 present rates and proposed rates, and others are below
19 unity.The purpose of the sensitivity studies is to
20 determine whether demand data from a new load study would
21 likely cause us to spread the revenue increase to customer
22 classes differently than that proposed by the Company in
23 this case.
24 Q.What was your conclusion after running the four
25 sensitivity studies?
26 A.The results of each of the studies, that I will
27 explain below, show that while an updated load study may
28 fine tune the cost relationships among the customer groups,
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Avista Corporation
1 we can expect relatively small changes in the overall cost
2 of service results.Therefore,we believe the current cost
3 of service study provides a sound foundation for rate
4 spread purposes.
5 Scenario 1
6 Q.What did you test in the first sensitivity run,
7 and what did the results show?
8 A.The first sensitivity run, which i will refer to
9 as Scenario 1, was designed to examine how a change in the
10 non-coincident peak for each customer class would affect
11 the allocation of demand-related distribution costs.For
12 this scenario I simply took the non-coincident peak demand
13 for each customer class embedded in the cost of service
14 study, and doubled the demand for each class, with the
15 exception of Schedules 25 and 25P. By doubling the demand
16 for each class, we will see what happens to demand
17 allocations if a new load study were to show that the non-
18 coincident peak demand for each class were to increase in
19 the same proportion.
20 Q.Why did you not double the peak demnd for
21 Schedules 25 and 25P?
22 A.We already have hourly metering, and hourly data,
23 for Schedules 25 and 25P, so we already know what their
24 actual non-coincident peak demand is without a new load
25 study.
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Avista Corporation
1 It is also important to note, as I mentioned earlier,
2 that the non-coincident peak demand analysis is used
3 entirely to allocate demand-related distribution costs.
4 Nearly all demand-related distribution costs for Schedules
5 25 and 25P are directly assigned, and therefore, a change
6 in the non-coincident peak demand for these Schedules would
7 result in essentially no change in the allocation of
8 distribution costs to these Schedules.
9 Q.What were the results from this first scenario?
The results from Scenario 1, compared with the10A.
11 Base Case cost of service study filed in this case, are
12 summarized on Exhibit 11, Schedule 4, lines 1 through 8.
13 Although the rate base and net income values change
14 slightly, the relative rates of return for Scenario 1 are
15 virtually the same as our Base Case study for all customer
16 classes, as shown in the Illustration 2 below.
17 Illustration 2:
Customer Class
Residential Service Schedule 1
General Service Schedule 11
Large General Service Schedule 21
Extra Large General Service Schedule 25
Ex. Lg. Gen. Service Potlatch Schedule 25P
Pumping Service Schedule 31
Lighting Service Schedules 41 - 49
Total Idaho Electric System
Base Case
Rate of Return
4.56%
7.89%
6.74%
3.15%
3.93%
7.64%
4.89%
5. 34%
0.85
1. 48
1.26
0.59
0.73
1. 43
0.92
1. 00
Scenario 1
Rate of Return
4.56%
7.89%
6.74%
3.16%
3.94%
7.64%
4.89%
5.34%
0.85
1. 48
1. 26
0.59
0.74
1.43
0.92
1. 00
18
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Avista Corporation
1 Therefore, if a new load study were to show a
2 significant increase in non-coincident peak demand across
3 all schedules, it would result in very little change in our
4 cost of service results.
5 Scenario 2
6 Q.What did you test in Scenario 2, and what did the
7 results show?
8 A.The first scenario explored what would happen if
9 the non-coincident peak demand was higher for all schedules
10 than our Base Case demand data.In Scenario 2 I wanted to
11 test what would happen if a new load study were to indicate
12 that some schedules have higher non-coincident peak demand
13 than our Base Case, and other schedules have lower demand.
14 For Scenario 2 i made the following adjustments to the
15 Base Case non-coincident peak demand data:
16
17
18
19
20
21
22
23
24
25
26
1.For customer classes that have a relative rate ofreturn above uni ty (1. 0) in the Base Case study, I
increased the non-coincident peak demand for the class
by 15%.
2.For customer classes that a have a relative rate of
return below unity (1.0), I decreased the non-
coincident peak demand for the class by 15%.
Q.What were you trying to measure by making these
27 adjustments?
28 A.In this filing we are proposing a rate spread
29 that is designed to move each customer class closer to
Knox, Di 22
Avista corporation
1 For example, for those customer classes that areunity.
2 above unity, we are proposing a lower percentage base rate
3 increase in order to accomplish this movement.if a new
4 load study were to show an increased non-coincident peak
5 demand for these customer classes (above unity), and a
6 lower non-coincident peak demand for the customer classes
7 below unity, it would result in the following changes to
8 the cost of service study:
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
1.The increase in non-coincident peak demand for
customer classes above unity would result in an
increased allocation of demand-related distribution
costs to these customer classes, which would lower the
relative rate of return for these classes (move themcloser to unity) .
2.The decrease in non-coincident peak demand for
customer classes below unity would result in a
decreased allocation of demand-related distribution
costs to these customer classes, which would increase
the relative rate of return for these classes (movethem closer to unity) .
24 The purpose of this Scenario was to determine how much
25 movement toward unity would occur for each customer class
26 if the new load study were to show a significant increase
27 in non-coincident peak demand for classes above unity, and
28 a significant decrease for those below unity. As mentioned
29 above, we increased the non-coincident peak demand for
30 classes above unity by 15%, and reduced the demand for
31 classes below unity by 15%.
32 What were the results for Scenario 2?Q.
Knox, Di 23
Avista Corporation
1 A.The results of Scenario 2 are shown on Exhibit
2 No. 11, Schedule 4, lines 9 through 12.Illustration 3
3 below highlights the rates of return produced by this
4 scenario compared to the base case.
5 Illustration 3:
Customer Class
Residential Service Schedule 1
General Service Schedule 11
Large General Service Schedule 21
Extra Large General Service Schedule 25
Ex. Lg. Gen. Service Potlatch Schedule 25P
Pumping Service Schedule 31
Lighting Service Schedules 41 - 49
Total Idaho Electric System
Base Case
Rate of Return
4.56%
7.89%
6.74%
3.15%
3.93%
7.64%
4.89%
5.34%
0.85
1. 48
1. 26
0.59
0.73
1. 43
0.92
1. 00
Scenario 2
Rate of Return
5.19%
7.09%
5.89%
3.15%
3.93%
6.85%
5.02%
5.34%
0.97
1. 33
1.10
0.59
0.73
1. 28
0.94
1. 00
6
7 Costs did shift in this scenario, but not enough to
8 change the rate spread implications.Schedules 11, 21 and
9 31 are still above unity, and Schedules 1 and Lighting
10 are improved bu t
11 Therefore, even if this Scenario were to occur, there would
service remain less than unity.
12 still be a need for a rate spread proposal to move relative
13 rates of return for customer classes closer to unity,
14 similar to what Mr. Hirschkorn has proposed in this case.
15 Q.would you expect the new load study to show
16 higher non-coincident peak demands for only the customer
17 classes above unity, and lower non-coincident peak demnds
18 for only the customer classes below unity, as you tested in
19 Scenario 2?
Knox, Di 24
Avista Corporation
1 A.No.It is unlikely that such a scenario would
2 actually occur.However, for my sensitivity analysis I
3 wanted to test a scenario that is probably beyond what
4 would likely occur.
5 Scenario 3
6
7
Q.Lets move on to the two sensitivity studies
related to coincident peak.How are the class
8 contributions to system peak demnd determined in the Base
9 Case?
10 A.The coincident peak allocation factor is based on
11 the electric system hourly peak for each month of the
12 twelve-month test period (12 hourly coincident peaks). The
13 total Idaho peak load is known for the twelve peak hours.
14 With regard to each customer class, the peak demand
15 for each class, for each of the 12 monthly peak hours
16 (contribution to the system peak), is based on an analysis
17 of monthly billing data, weather sensitivity statistics,
18 and hourly load shapes from prior load studies.
19 Q.Are the twel ve hourly coincident peaks for
20 Schedules 25 and 25P estimated in the same manner?
21 A.No.As I mentioned earlier, we have actual,
22 hourly load data for Schedules 25 and 25P, and therefore,
23 we know what their usage is at the time of the twelve
24 monthly system peaks. Thus, with regard to the use of peak
25 demand data in cost of service studies to allocate demand-
Knox, Di 25
Avista Corporation
1 related production and transmission costs, the current cost
2 of service study already includes the actual, metered
3 contribution to the system peak for these schedules.
4 Q.What change did you make to the coincident peak
5 demand data in Scenario 3, and what were you trying to
6 measure?
7 A.In Scenario 3, i made one change from the Base
8 Case in the determination of the hourly coincident peak
9 contribution for each schedule.Rather than use hourly
10 load shapes from prior load studies to determine the hourly
11 peak for each customer class on the peak day, I used one-
12 sixteenth, or 6.25%, of the daily energy use on the peak
13 day for each class to represent the hourly peak demand at
14 the time of the system coincident peak.
15 The use of 6.25% of daily energy to represent a peak
16 hour demand for the peak day has been used historically in
17 the natural gas industry to determine the appropriate size
18 of natural gas delivery service equipment.Al though the
19 6.25% may not be perfectly transferrable to the electric
20 industry, it provided a reasonable basis to achieve my
21 obj ecti ve in this Scenario.
22 My objective in Scenario 3 was to adjust the peak
23 demand data such that the peak hour for each customer class
24 occurred at the time of the system peak, i. e., all customer
Knox, Di 26
Avista Corporation
1 classes peak at the time of the system peak in each of the
2 twel ve months.
3 Q.What were the results of Scenario 3?
Scenario 3 results are shown on Exhibit 11,4 A.
5 Schedule 4, lines 13 through 16.Illustration 4 below
6 highlights the rates of return produced by this Scenario
7 compared to the Base Case.
8 Illustration 4:
Customer Class
Residential Service Schedule 1
General Service Schedule 11
Large General Service Schedule 21
Extra Large General Service Schedule 25
Ex. Lg. Gen. Service Potlatch Schedule 25P
Pumping Service Schedule 31
Lighting Service Schedules 41 - 49
Total Idaho Electric System
Base Case
Rate of Return
4.56%
7.89%
6.74%
3.15%
3.93%
7.64%
4.89%
5.34%
0.85
1. 48
1. 26
0.59
0.73
1.43
0.92
1. 00
Scenario 3
Rate of Return
4.66%
7.96%
6.55%
3.15%
3.93%
6.77%
4.89%
5.34%
0.87
1. 49
1. 23
0.59
0.73
1.27
0.92
1. 00
9
10 The rate of return and return ratios for Schedules 1
11 and 11 rise slightly, while they fall somewhat for
12 Schedules 21 and 31, but the rate spread implications
13 remain unchanged.
14 Scenario 4
15 Q.What did you test in the fourth scenario?
In Scenario 4 I wanted to test what would happen16A.
17 if a new load study were to indicate that some schedules
18 have a higher contribution to the system coincident peak
Knox, Di 27
Avista Corporation
1 than the Base Case, and other schedules have a lower
2 contribution.
3 For Scenario 4 I made the following adjustments to the
4 Base Case coincident demand data:
5
6
7
8
9
10
11
12
13
14
15
1.For customer classes that have a relative rate ofreturn above uni ty ( 1. 0), I increased the demand for
the class at the time of the system coincident peak by
approximately 10%.6
2.For customer classes that a have a relative rate of
return below unity (1.0), i decreased the demand for
the class at the time of the system coincident peak by
approximately 10%.
16 Q.What were you trying to measure by making these
17 adjustments?
18 A.As I explained earlier related to Scenario 2, in
19 this filing we are proposing a rate spread that is designed
20 to move each customer class closer to unity. If a new load
21 study were to show an increased contribution to the system
22 coincident peak for the customer classes above unity, and a
23 lower contribution to the system coincident peak for the
24 customer classes below unity, it would result in the
25 following changes to the cost of service study:
26
27
28
29
30
1.The increased contribution to the system coincident
peak for customer classes above unity would result in
an increased allocation of demand-related production
and transmission costs to these customer classes,
6 In order to preserve the same level of Idaho peak demand as the Base Case, it was necessar to adjust
the percentage increase to Schedules 11, 21 and 31 to 11.6%, and reduce the percentage decrease for
Schedules 1 and Lighting service to 9.4%.
Knox, Di 28
Avista Corporation
which would lower the relative rate of return for
these classes (move them closer to unity) .
1
2
3
4
5
6
7
8
9
10
The decreased contribution to the system coincident
peak for customer classes below unity would result in
a decreased allocation of demand-related production
and transmission costs to these customer classes,
which would increase the relative rate of return forthese classes (move them closer to unity) .
2.
11 The purpose of this Scenario was to determine how much
12 movement toward unity would occur for each customer class
13 if the new load study were to show a significant increase
14 in contribution to the system coincident peak for classes
15 above unity, and a significant decrease for those below
16 unity.
17 Q.What were the results of Scenario 4?
Scenario 4 results are shown on Exhibit 11,18 A.
19 Schedule 4, lines 17 through 20.Illustration 5 below
20 highlights the rates of return produced by this scenario
21 compared to the Base Case.
22 Illustration 5:
Customer Class
Residential Service Schedule 1
General Service Schedule 11
Large General Service Schedule 21
Extra Large General Service Schedule 25
Ex. Lg. Gen. Service Potlatch Schedule 25P
Pumping Service Schedule 31
Lighting Service Schedules 41 - 49
Total Idaho Electric System
Base Case
Rate of Return
4.56%
7.89%
6.74%
3.15%
3.93%
7.64%
4.89%
5.34%
0.85
1. 48
1.26
0.59
0.73
1.43
0.92
1. 00
Scenario 4
Rate of Return
5.06%
7.26%
6.09%
3.15%
3.93%
7.08%
4.95%
5.34%
0.95
1. 36
1.14
0.59
0.73
1. 32
0.93
1. 00
23
Knox, Di 29
Avista Corporation
1 The rate of return and return ratios for Schedules 1
2 and Lighting service improve, but are still below unity and
3 the return ratios for Schedules 11, 21 and 31 each drop by
4 about one-tenth but are still well above unity.The rate
5 spread implications remain essentially unchanged.
6 Q.Would you expect the new load study to show a
7 higher contribution to the system coincident peak for only
8 the customer classes above unity, and a lower contribution
9 to the system coincident peak for only the customer classes
10 below unity, as you tested in Scenario 4?
11
12
A.No. As with Scenario 2, it is unlikely that such
a scenario would actually occur.However, again, for my
13 sensitivity analysis I wanted to test a scenario that is
14 probably beyond what would likely occur.
15 Q.What conclusions do you draw from these demand
16 allocation sensitivity studies?
17 A. The following chart illustrates the return ratios
18 for the Base Case and all four sensitivity scenarios:
Knox, Di 30
Avista Corporation
1 Illustration 6:
Class Rate of Return Vs. Unity
Base ca Vs. All Other seitiv Scnari
1.6
1.4
.S 1.2 Ui1iII
E 1
::..II 0.8
0.6
0.4
~#"-
cP
,,'l.."-
cP
",rO
cP'l cPt(~
cP
a.-.~
cPfb
~
cPt.
Scedule
-- Return RatiBa Ca __ Return Ratinarl 1 -- Return Ratinarl 2
-- Retrn Ratio-Scnar 3 __ Retrn Rati-scaro 42
3 As can be seen in Illustration 6 above,the
4 sensitivity analyses demonstrate that, while an updated
5 load study may fine tune the cost relationships among the
6 customer groups, we can expect only relatively small
7 changes in results.The schedules that are well above
8 unity will continue to be above unity, and the schedules
9 that are well below unity will continue to be below unity.
10 (There will be little or no change to Schedules 25 and 25P,
11 which already have actual, hourly demand data and receive
12 direct assignment of most distribution plant.) Therefore,
13 the Company believes that the existing cost of service
14 study, even absent new load study information, provides a
15 sound foundation for rate spread purposes.
Knox, Di 31
Avista Corporation
1
2
VI. NATURAL GAS COST OF SERVICE
Q.Please describe the natural gas cost of service
3 study and its purpose.
4 A.A natural gas cost of service study is an
5 engineering-economic study which separates the revenue,
6 expenses, and rate base associated with providing natural
7 gas service to designated groups of customers. The groups
8 are made up of customers with similar usage characteristics
9 and facility requirements.Costs are assigned in relation
10 to each groups' characteristics, resulting in an evaluation
11 of the cost of the service provided to each group.The
12 rate of return by customer group indicates whether the
13 revenue provided by the customers in each group recovers
14 the cost to serve those customers.The study results are
15 used as a guide in determining the appropriate rate spread
16 among the groups of customers.Exhibi t No .11, Schedule 5
17 explains the basic concepts involved in performing a
18 natural gas cost of service study.It also details the
19 specific methodology and assumptions utilized in the
20 Company's Base Case cost of service study.
21 Q.What is the basis for the natural gas cost of
22 service study provided in this case?
23 A.The cost of service study provided by the Company
24 as Exhibit No.ll, Schedule 6 is based on the twelve months
25 ended September 2008 test year pro forma results of
Knox, Di 32
Avista Corporation
1 operations presented by Ms. Andrews in Exhibit No.10,
2 Schedule 2.
3 Q.Would you please explain the cost of service
4 study presented in Exhibit No. 11, Schedule 6?
5 A.Yes. Exhibit No. 11, Schedule 6 is composed of a
6 series of summaries of the cost of service study results.
7 Page 1 shows the results of the study by FERC account
8 category.The rate of return and the ratio of each
9 schedule's return to the overall return are shown on lines
10 38 and 39. This summary is provided to Mr. Hirschkorn for
11 his work on rate spread and rate design. The results will
12 be discussed in more detail later in my testimony.The
13 additional sumaries show the costs organized by functional
14 category (page 2) and classification (page 3), including
15 margin and unit cost analysis at current and proposed
16 rates.
17 The Excel model used to calculate the cost of service
18 and supporting schedules have been included in their
19 entirety both electronically and hard copy in the
20 workpapers accompanying this case.
21 Q.Does the Natural Gas Base Case cost of service
22 study utilize the methodology from the company's last
23 natural gas case in Idaho?
Knox, Di 33
Avista Corporation
1 A.Yes.The Base Case cost of service study was
2 prepared using the methodology accepted by the Idaho
3 Commission in Case No. AVU-G-04-01 and AVU-G-08-01.
4 Q.What are the key elements that define the cost of
5 service methodology?
6
7
A.Purchased gas costs are derived from the current
purchased gas tracker methodology.Underground storage
8 costs are allocated by normalized winter throughput.
9 Natural gas main investment has been segregated into large
10 and small mains.Large usage customers that take service
11 from large mains do not receive an allocation of small
12 mains.Meter installation and services investment is
13 allocated by number of customers weighted by the relative
14 current cost of those items.System facilities that serve
15 all customers are classified by the peak and average ratio
16 that reflects the system load factor, then allocated by
17 coincident peak demand and throughput,respectively.
18 Demand side management costs are treated in the same way as
19 system facilities.General plant is allocated by the sum
20 of all other plant. Administrative & general expenses are
21 segregated into labor related, plant related, revenue
22 related, and "other".The costs are then allocated by
23 factors associated with labor, plant in service, or
24 revenue, respecti vely.The "other" A&G amounts get a
25 combined allocation that is one-half based on O&M expenses
Knox, Di 34
Avista Corporation
1 and one-half based on throughput.A detailed description
2 of the methodology is included in Exhibit No .11, Schedule
3 5.
4 Q.What are the results of the Company's natural gas
5 cost of service study?
6 A.I believe the Base Case cost of service study
7 presented in this filing is a fair representation of the
8 costs to serve each customer group.The study indicates
9 that Large Firm general service Schedule 111 is providing
10 slightly less than the overall return (unity), while all
11 other schedules are providing slightly more than unity to
12 varying degrees.The return for all of the Schedules are
13 relatively close to the overall return indicating the
14 current rate spread is fair.
15 The following table shows the rate of return and the
16 relative return ratio at present rates for each rate
17 schedule:
18 Illustration 7:
Customer Class Rate of
Return
Return Ratio
Residential Service Schedule 101
Small Firm Service Schedule 111
Interruptible Service Schedule 131
Transportation Service Schedule 146
Total Idaho Natural Gas System
6.97%
6.24%
7.44%
8.78%
6.87%
1. 02
0.91
1. 08
1.28
1. 00
19
Knox, Di 35
Avista Corporation
1 The summary results of this study were provided to Mr.
2 Hirschkorn as an input into development of the proposed
3 rates.
4 Q.Does this conclude your pre-filed direct
5 testimony?
6 A. Yes.
Knox, Di 36
Avista Corporation
e~~~D P~ËS~~~~~ AND CHIEF COUNSEL OF lûß~ Jr"N 23 PM i2: II '5
REGULATORY & GOVERNENTAL AFFAIRS
AVISTA CORPORATION
P . O. BOX 3727
1411 EAST MISSION AVENUE
SPOKANE, WASHINGTON 99220-3727
TELEPHONE: [phone]
FACSIMILE: [phone]
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION ) CASE NO. AVU-E-09-01
OF AVISTA CORPORATION FOR THE ) CASE NO. AVU-G-09-01
AUTHORITY TO INCREASE ITS RATES )
AND CHARGES FOR ELECTRIC AND )
NATURAL GAS SERVICE TO ELECTRIC ) EXHIBIT NO. 11
AND NATURAL GAS CUSTOMERS IN THE )STATE OF IDAHO ) TARA L. KNOX
)
FOR AVISTA CORPORATION
(ELECTRIC AND GAS)
A VISTA UTILITIES
AVERAGE PRODUCTION AND TRANSMISSION COST
IDAHO ELECTRIC
TWLVE MONTHS ENDED SEPTEMBER 30. 2008
(OOO's)Revenue
87,662
Production/ransmission
Expene Rate Base
196,202 337,543
(47,411)
Column Description of Adjustment
b Per Results Report
c Defered FIT Rate Base
d Deferred Gain on Offce Building
e Colstrp 3 AFUDC Elimination
f Colstrp Common AFUDC
g Kettle Falls & Boulder Park Disallow.
h Customer Advances
Weatherin and DSM Investment
202 1,956
925
(2,233)
1,669
Actual 87,662 292,449
j Depreciation True-up
k Eliminate B & 0 Taxes
i Proper Tax
m Uncollect. Expense
n Regulatory Expense
o Injuries and Damages
p FIT
q IdahoPCA
Nez Perce Settlement Adjustment
Eliminate NR Expenes
Misc Restating Adjs
u Revenue Nonnalization Adjustment
v Clark Fork PM&E
w Restate Debt Interest
59
196,404
(377)
1,143
5,603
(12)
1,358
1,010
Restated Total 87,721 292,449
PFI
PF2
PF3
PF4
PF5
PF6
PF7
PF8
PF9
PFIO
PFlI
PF12
PFI3
PF14
PFI6
PF15
PF16
PFI7
PFI8
PFI9
PF20
PF21
PF22
Pro Forma Power Supply
Pro Forma Production Proper Adj
Pro Forma Labor Non-Exec
Pro Forma Labor Exec
Pro Forma Transmission Rev/Exp
Pro Forma Capital Add 2008
Pro Forma Capita Add 2009
Pro Forma Information Services
Pro Forma Asset Management
Pro Forma Spokae Rvr Relicening
Pro Forma CDA Tribe Settement
Pro Forma Montana Lease
Pro Forma Colstrp Mercur Emiss. O&M
Pro Forma Incentives
Pro Forma ID AMR
Pro Forma CS2 Levelized Adj
Pro Forma ID AMR
Pro Forma O&M Plant Expense
Pro Forma Employee Benefits
Pro Forma Insurance
Pro Forma Chicago Climate (CCX)
Pro Forma Warila Amortzation
Pro Forma Colstrp Lawsuit StImnt
(55,375)
(1,332)
425
13
205,129
(45,585)
(6,528)
399
5
5
(39)
661
240
2,100
401
1,917
596
199
1,400
368
185
369
(10,202)
3,427
2,929
12,184
7,861
1,583
Pro Forma Tota 31,452 310,231161,822
Exhibit No. 11
Case No. AVU-E-09-01
T. Knox, Avista
Schedule 1, p. 1 of 2
A VISTA UTILITIES
AVERAGE PRODUCTION AND TRANSMISSION COST
IDAHO ELECTRIC
TWELVE MONTHS ENDED SEPTEMBER 30. 2008
Proposed Production and Trasmission Revenue Requirement
Calculation of Retal Revenue Credit Rate at Proposed Return
Line ($OOO's)Debt Cost
i Prod/Tran Pro Forma Rate Base $310,231
2 Proposed Rate of Retu 8.800%3.00%
3 Rate Base Net Operating Income Requirement $27,300
4 Tax Effect Net Operating Income Requirement ($3,583)
(Rate Base x Debt Cost x -35%)
5 Net Expense Net Operating Income Requirement 130,370
(Expense - Revenue)
6 Tax Effect Net Operating Income Requirement ($45,629)
(Net Expense x -.35%)
7 Total Prodlran Net Operating Income Requirement $108,457
8 i - Tax Rate Conversion Factor (Excl. Rev. ReI. Exp.)0.65
9 Prod/Trans Revenue Requirement $166,857l
10 12ME Sept 2008 ID Normalized Retail Load MWh 3,487,446
11 Prod/Tras Rev Requirement per kWh (Retail Revenue Credit Rate)L $0.047851
Exhibit No. 11
Case No. AVU-E-09-01
T. Knox, Avista
Schedule 1, p. 2 of 2
1. ELECTRIC COST OF SERVICE
2 A cost of service study is an engineering-economic study, which apportions the revenue,
3 expenses, and rate base associated with providing electrc serce to designated groups of
4 customers. It indicates whether the revenue provided by the customers recovers the cost to serve
5 those customers. The study results are used as a guide in deterining the appropriate rate spread
6 among the groups of customers.
7 There are three basic steps involved in a cost of service study: fuctionalization,
8 classification, and allocation. See flow char.
9 First, the expenses and rate base associated with the electrc system under study are
10 assigned to fuctional categories. The uniform system of accounts provides the basic segregation
11 into production, transmission, and distrbution. Traditionally customer accounting, customer
12 information, and sales expenses are included in the distrbution function and administrative and
13 general expenses and general plant rate base are allocated to all functions. In ths study I have
14 created a separate functional category for common costs. Administrative and general costs that
15 canot be directly assigned to the other functions have been placed in this category.
16 Second, the expenses and rate base items that canot be directly assigned to customer
17 groups are classified into three primar cost components: energy, demand or customer related.
18 Energy related costs are allocated based on each rate schedule's share of commodity consumption.
19 Demand (capacity) related costs are allocated to rate schedules on the basis of each schedule's
20 contribution to peak demand. Customer related items are allocated to rate schedules based on the
21 number of customers within each schedule. The number of customers may be weighted by
22 appropriate factors such as relative cost of metering equipment. In addition to these three cost
23 components, any revenue related expense is allocated based on the proportion of revenues by rate
24 schedule.
Exhbit No. 11
Case No. A VU-E-09-01
T. Knox, Avista
Schedule 2, p. 1 of9
ELECTRIC COST OF SERVICE STUDY FLOWCHART
Pro Forma
Results of
Operations
Fu nctionalization/
Production Transmission
Distribution and
Customer
Relations Common
Energy i
Commodity
Related
Demand i
Capacity Related
Customer
Related
Direct Assignment
Generation Level mWh's
Customer Level mWh's
Residential Small General Large General Extra Large
General
Pumping Street & Area
Lights
Pro Forma Results of Operations by Customer Group
Exhibit No. 11
Case No. A VU-E-09-01
T. Knox, A vista
Schedule 2, p. 2 of9
1 The final step is allocation of the costs to the varous rate schedules utilzing the allocation
2 factors selected for each specific cost item. These factors are derived from usage and customer
3 information associated with the test period results of operations.
4 BASE CASE COST OF SERVICE STUDY
5 Production and Transmission Classifcation (Peak Credit)
6 This study utilzes a Peak Credit methodology to classify production and transmission costs
7 into demand and energy classifications. The Peak Credit method acknowledges that baseload
8 production facilities provide energy throughout the year as well as capacity durng system peaks
9 and likewise the transmission system is built not only for peak use, but also for everyday delivery
10 of energy. The demand/energy ratio is determined by the relationship of the curent replacement
11 cost per kW generating capacity of the Company's peakng units to the current replacement cost
12 per kW generating capacity of the Company's thermal or hydro plant. The peak credit ratio for
13 thermal plant is 37.16% to demand and 62.84% to energy. The peak credit ratio for hydro plant is
14 36.49% to demand and 63.51% to energy. As an intermediate resource (between peaking and
15 baseload), Coyote Springs II has been included with the thermal plant costs, whereas all other
16 plants in the 340 to 349 FERC plant accounts are considered peaking units.
17 Transmission costs are classified by fifty-fifty weighting of the thermal and hydro peak
18 credit ratios resulting in the transmission peak credit ratio of 36.49% to demand and 63.51 % to
19 energy. Fuel and load dispatching expenses are classified entirely to energy. Peaking plant related
20 costs are classified entirely to demand. Purchased Power and Other Power Supply expenses are
21 classified to demand and energy by the relative amounts of assigned and allocated Production Plant
22 in Service.
Exhibit No. 11
Case No. AVU-E-09-01
T. Knox, Avista
Schedule 2, p. 3 of9
1 Production and Transmission Allocation
2 Production and transmission demand related costs are allocated to the customer classes by
3 class contrbution to the average of the twelve monthly system coincident peak loads. Although
4 the Company is usually techncally a winter peaking utility, it experences high sumer peaks and
5 careful management of capacity requirements is required thoughout the year. The use of the
6 average of twelve monthly peaks recognizes that customer capacity needs are not limited to the
7 heating season.
8 Energy related costs are allocated to class by pro forma anual kilowatthour sales adjusted
9 for losses to reflect generation level consumption.
10 Distribution Facilties Classifcation (Basic Customer)
11 The Basic Customer method considers only services and meters and directly assigned
12 Street Lighting apparatus (FERC Accounts 369, 370, and 373 respectively) to be customer related
13 distrbution plant. All other distrbution plant is then considered demand related. Ths division
14 delineates plant which benefits an individual customer from plant which is par of the system. The
15 basic customer method provides a reasonable, clearly definable division between plant that
16 provides service only to individual customers from plant that is par of the interconnected
17 distribution network.
18 Customer Relations Distribution Cost Classification
19 Customer service, customer information and sales expenses are the core of the customer
20 relations functional unit which is included with the distrbution cost category. For the most par
21 they are classified as customer related. Exceptions are sales expenses which are classified as
22 energy related and uncollectible accounts expense which is considered separately as a revenue
23 conversion item. Demand Side Management expenses recorded in Account 908 are also
24 considered separately from the other customer information costs.
Exhbit No. 11
Case No. AVU-E-09-01
T. Knox, A vista
Schedule 2, p. 4of9
The demand side management investment and amortization are classified implicitly to
2 demand and energy by the sum of production plant in service, then allocated to rate schedules by
3 coincident peak demand and energy consumption respectively.
4 Distribution Cost Allocation
5 Distrbution demand related costs which canot be directly assigned are allocated to
6 customer class by the average of the twelve monthly non-coincident peaks for each class.
7 Distrbution facilities that serve only secondar voltage customers are allocated by the non-
8 coincident peak excluding primar voltage customers or number of customers excluding primary
9 voltage customers. This includes line transformers, services, and secondar voltage overhead or
10 underground conductors and devices. The costs of specific substations and related primar voltage
11 distrbution facilities are directly assigned to Extra Large General Service customers based on their
12 load ratio share of the substation capacity from which they receive service.
13 Most customer costs are allocated by average number of customers. Weighted customer
14 allocators have been developed using typical current cost of meters, estimated meter reading time,
15 and direct assignent of biling costs for hand-biled customers. Street and area light customers
16 are excluded from metering and meter reading expenses as their service is not metered.
17 Admiistrative and General Costs
18 Administrative and general costs which are directly associated with production,
19 transmission, distrbution, or customer relations fuctions are directly assigned to those fuctions
20 and allocated to customer class by the relevant plant or number of customers. The remainder of
21 administrative and general costs are considered common costs, and have been left in their own
22 functional category. These common costs are classified by the implicit relationship of energy,
23 demand and customer within the four-factor allocator applied to them. The four-factor allocator
24 consists of a 25% weighting of each of the following: 1) operating & maintenance expenses
Exhbit No. 11
Case No. A VU-E-09-01
T. Knox, A vista
Schedule 2, p. 5 of 9
1 excluding resource costs, labor expenses, and administrative and general expenses; 2) operating
2 and maintenance labor expenses excluding administrative and general labor expenses; 3) net
3 production, transmission, and distrbution plant; and 4) number of customers.
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 var 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 adjusted by interest expense.
9 For the functional summares on pages 2 and 3 of the cost of service study, these items are
10 assigned to component cost categories. The revenue related expense items have been reduced to a
11 percent of all other costs and 10aded onto each cost category by that ratio. Similarly, income tax
12 items have been reduced to a percent of net income before tax then assigned to cost categories by
13 relative rate base (as is net income).
14 The following matrx outlnes the methodology applied in the Company Base Case cost of
15 servce study.
Exhibit No. 11
Case No. A VU-E-09-01
T. Knox, Avista
Schedule 2, p. 6of9
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Sumcost AVISTA UTILITIES Idaho Jurisdiction
Scnario: Company Base Case Cost of Service Basic Summary Electric Utiity 01-5-0
AVU-E-0-Q1 Method For the Twelve Months Ended September 30, 2008
(b)(c) (d) (e)(I)(g)(h)(i)OJ (k)(I)(m)
Residential General Large Gen Exra Large Exra Large Pumping Steet &
System Service service Service Gen Service Service Potlatch Service Area Lights
Description Total Sch 1 Sch 11-2 Sch 21-22 Sch25 Sch25P Sch 31.32 Sc 41-49
Plant In Service
1 Proucion Plant 373,731 ,00 135,227,560 37,65,169 75,194,99 32,149,197 86,363,517 5,962,243 1,183,321
2 Transmission Plant 160,359,00 57,376,174 15,974,374 32,342,77 13,863,64 37,68,700 2,584,411 527,923
3 Distribution Plant 391,018,00 197,358,427 61,571,178 91,36,30 10,733,997 2,156,60 8,513,166 19,320,328
4 Intangible Plant 39,60,00 15,741,657 4,230,439 7,550,082 3,059,674 8,136,299 635,08 251,761
5 General Plant 61,178,00 32,454,852 8,011,sn 9,39,461 2,838,928 6,495,775 96,439 1,017,668
6 Total Plant In Service 1,025,891,00 438,156,66 127,438,037 215,84,610 62,645,443 140,841,892 18,659,348 22,301,001
Accum Depreciation
7 Producion Plant (146,687,00)(52,857,182)(14,716,423)(29,540,070)(12,641,759)(34,111,303)(2,34,989)(471,275)
8 Transmission Plant (55,770,00)(19,954,410)(5,555,602)(11,248,239)(4,821,529)(13,107,805)(898,812)(183,602)
9 Distribution Plant (121,422,00)(60,622,702)(17,69,227)(28,258,437)(3,147,09)(689,459)(2,423,039)(8,585,042)
10 Intangible Plant (6,504,00)(3,204,66)(807,144)(1,067,179)(358,755)(873,971)(103,04)(89,241)
11 General Plant (26,764,00)(14,198,268)(3,505,016)(4,109,865)(1,241,967)(2,841 ,756)(421,920)(445,207)
12 Total Accumulated Depreciation (357,147,00)(150,837,228)(42,280,413)(74,223,790)(22,211,105)(51,624,294)(6,195,804)(9,774,366)
13 Net Plant 66,744,00 287,321 ,441 85,157,624 141,622,820 40,434,33 89,217,598 12,463,544 12,526,635
14 Accumulated Deferred FIT (94,27,00)(39,954,758)(11,494,640)(19,54,335)(5,961,672)(13,794,122)(1,683,524)(1,841,948)
15 Miscellaneous Rate Base 2,967,00 615,534 238,461 777,855 342,392 931,229 52,419 9,109
16 Total Rate Base 577,434,00 247,982,217 73,901,445 122,854,339 34,815,05 76,354,705 10,832,439 10,693,796
17 Revenue Fro Retail Rates 220,252,00 86,358,00 27,841,00 46,63,00 14,497,00 37,941,00 4,139,00 2,842,00
18 Other Operating Revenues 32,908,00 12,105,796 3,395,160 6,669,515 2,746,549 7,285,317 533,843 17,820
19 Total Revenues 253,160,00 98,463,796 31,236,160 53,303,515 17,243,549 45,226,317 4,672,843 3,013,820
Operating Expenses
20 Producion Expnses 132,63,00 46,952,246 13,071,925 26,812,020 11,520,641 31,666,824 2,157,96 452,38
21 Transmission Expenses 8,348,00 2,986,90 831,597 1,683,706 721,716 1,962,058 134,540 27,483
22 Distribution Expenses 9,626,00 4,628,565 1,33,788 2,266,359 325,06 68,90 183,439 818,875
23 Customer Accounting Expenses 3,484,000 2,571,225 566,133 159,263 37,127 96,155 44,220 9,878
24 Customer Information Expenses 1,537,00 673,650 169,327 260,612 110,134 295,791 23,169 4,319
25 Sales Exnses 235,00 78,937 21,975 48,021 20,867 60,270 3,995 934
26 Admin & General Expnses 21,605,00 11,157,633 2,813,361 3,480,772 1,04,376 2,391,071 349,065 372,722
27 Total O&M Expenses 177,469,00 69,049,156 18,809,104 34,710,752 13,775,929 36,541,075 2,896,393 1,686,591
28 Taxes Other Than Income Taxes 8,751,00 3,527,601 1,022,110 1,837,350 603,320 1,460,444 154,807 145,368
29 Other Income Related Items (106,000)(41,853)(11,655)(20,903)(8,744)(21,069)(1,550)(226)
Depreciation Expnse
30 Production Plant Depreciation 9,335,00 3,397,568 945,964 1,875,801 800,892 2,137,719 148,120 28,936
31 Transmission Plant Depreciation 3,232,00 1,156,404 321,96 651,861 279,419 759,628 52,088 10,640
32 Distribution Plant Depreciation 10,048,00 4,96,162 1,601,384 2,459,029 30,220 51,90 226,182 438,121
33 General Plant Depreciation 4,867,00 2,581,937 637,383 747,374 225,850 516,770 76,726 80,960
34 Amortization Expnse 2,256,00 816,171 227,239 453,924 194,079 521,445 35,996 7,147
35 Total Depreciation Expense 29,738,00 12,917,243 3,733,930 6,187,989 1,806,460 3,987,461 539,112 56,805
36 Incoe Tax 6,445,00 1,704,864 1,851,60 2,307,179 (29,058)260,845 256,56 93,002
37 Total Operating Expnss 222,297,00 87,157,010 25,405,095 45,022,36 16,147,908 42,228,755 3,84,326 2,490,540
38 Net Income 30,863,00 11,30,786 5,831,065 8,281,149 1,095,641 2,997,562 827,518 523,280
39 Rate of Return 5.34%4.56%7.89%6.74%3.15%3.93%7.64%4.89%
40 Return Ratio 1.00 0.85 1.48 1.26 0.59 0.73 1.43 0.92
41 Interest Expnse 19,055,000 8,183,275 2,438,706 4,054,125 1,148,878 2,519,663 357,464 352,889
File: ID 09 Elec Case I Elec COS Base Case I Sumcost Exhibits
Exhibit No. 11
Case No. AVU-E-09-01
T. Knox, Avista
Schedule 3, p. 1 of 3
Sumcost AVISTA UTILITIES Idaho Junsdicion
Scenano: Company Base Case Revenue to Cos by Functional Compoent Summary Electnc Utility 01-5-0
AVU-E-D-01 Method For the Twelve Months Ended september 30, 200
(b)(c)(d) (e)(n (g)(h)(i)ul (k)(i)(m)
Residential General Large Gen Exra Large Exra Large Pumping Stret &
System Service Service Service Gen Service Service Potatch service Area Lights
Descnption Total Sch 1 Sch 11-2 Sch 21-22 Sc25 Sc25P Sch 31-32 Sch 41-49
Functional Cos Component at Current Return by Schedule
1 Production 135,335,36 47,29,312 14,287,020 28,463,985 11,181,180 31,376,910 2,337,896 459,067
2 Transmission 16,053,522 5,466,355 1,988,733 3,700,280 1,149,015 3,381,242 316,054 51,842
3 Distnbution 43,588,275 20,418,928 8,098,923 10,485,385 1,038,469 563,555 1,069,584 1,913,431
4 Common 25,274,833 13,243,404 3,466,324 3,984,350 1,128,33 2,619,293 415,466 417,660
5 Total Current Rate Revenue 220,252,00 86,358,00 27,841,00 46,63,00 14,497,00 37,941,00 4,139,00 2,842,00
Expressd as $IkW
6 Production $0.0381 $0.04066 $0.04419 $0.04020 $0.03559 $0.0346 $0.03977 $0.03339
7 Transmission $0.0060 $0.0071 $0.0015 $0.00523 $0.0066 $0.00372 $0.00538 $0.00371
8 Distnbution $0.01250 $0.01758 $0.02505 $0.01481 $0.001 $0.002 $0.01819 $0.13919
9 Common $0.00725 $0.01140 $0.01072 $0.00563 $0.00 $0.0089 $0.00707 $0.03038
10 Total Current Melded Rates $0.06316 $0.07435 $0.08610 $0.0687 $0.04614 $0.04179 $0.07040 $0.20674
Functional Cost Components at Uniform Current Return
11 Production 136,108,108 48,192,991 13,417,365 27,512,989 11,821,235 32,485,592 2,214,048 463,889
12 Transmission 16,382,662 5,861,688 1,631,981 3,304,215 1,416,34 3,850,471 264,030 53,93
13 Distribution 42,444,209 21,896,635 6,553,913 9,265,498 1,273,64 600,669 875,718 1,978,132
14 Common 25,317,020 13,432,535 3,314,993 3,887,051 1,174,634 2,687,691 399,046 421,070
15 Total Uniform Current Cost 220,252,00 89,383,849 24,918,252 43,969,753 15,685,857 39,624,422 3,752,841 2,917,025
Expressd as $IkWh
16 Prouction $0.0390 $0.04149 $0.04150 $0.03886 $0.03763 $0.0378 $0.03766 $0.03374
17 Transmission $0.0070 $0.00505 $0.0005 $0.0067 $0.0051 $0.0024 $0.009 $0.00392
18 Distribution $0.01217 $0.01885 $0.02027 $0.0130 $0.0005 $0.00 $0.01490 $0.14390
19 Common $0.00726 $0.01156 $0.01025 $0.009 $0.00374 $0.00296 $0.0079 $0.030
20 Total Current Uniform Melded Rates $0.0616 $0.0769 $0.07107 $0.06210 $0.0499 $0.045 $0.063 $0.21219
21 Revenue to Cost Ratio at Current Rate 1.00 0.97 1.2 1.06 0.92 0.96 1.0 0.97
Functional Cost Components at Proposed Return by Schedule
22 Production 147,845,557 51,139,821 15,323,930 30,786,204 12,472,189 35,126,868 2,517,492 479,054
23 Transmission 21,260,938 7,070,669 2,414,124 4,667,478 1,688,248 4,968,408 391,500 60,512
24 Distnbution 55,555,541 26,415,660 9,941,193 13,464,381 1,512,844 689,090 1,350,732 2,181,641
25 Common 26,822,964 14,010,850 3,646,753 4,221,937 1,221,720 2,850,635 439,276 431,793
26 Total Proposed Rate Revenue 251,485,000 98,637,000 31,326,000 53,140,00 16,895,000 43,63,00 4,69,00 3,153,00
Expressed as $IkW
27 Production $0.04239 $0.04403 $0.04739 $0.04348 $0.03970 $0.03869 $0.04282 $0.03485
28 Transmission $0.00610 $0.0009 $0.00747 $0.00659 $0.00537 $0.007 $0.0066 $0.0040
29 Distribution $0.01593 $0.02274 $0.03075 $0.01902 $0.0082 $0.0076 $0.02298 $0.15870
30 Common $0.00769 $0.01206 $0.01128 $0.0096 $0.00389 $0.0014 $0.00747 $0.03141
31 Total Proposed Melded Rates $0.07211 $0.08492 $0.098 $0.07505 $0.05378 $0.04806 $0.07993 $0.2293
Functional Cost Components at Uniform Requested Return
32 Prouction 147,899,815 52,464,728 14,60,708 29,884,869 12,835,036 35,205,453 2,401,957 501,06
33 Transmission 21,280,678 7,614,190 2,119,903 4,292,095 1,839,796 5,001,667 342,968 70,059
34 Distnbution 55,407,201 28,447,276 8,666,992 12,308,195 1,646,165 691,720 1,169,879 2,476,973
35 Common 26,897,30 14,270,875 3,521,948 4,129,718 1,247,967 2,855,483 423,959 447,358
36 Total Uniform Cost 251,485,00 102,797,06 28,915,551 50,614,878 17,568,963 43,754,324 4,338,763 3,495,453
Expressed as $IkWh
37 Prouction $0.04241 $0.04517 $0.04517 $0.04221 $0.04085 $0.0378 $0.0408 $0.0365
38 Transmission $0.0010 $0.006 $0.006 $0.00 $0.006 $0.00551 $0.0083 $0.0010
39 Distnbution $0.01589 $0.02449 $0.02680 $0.01738 $0.0024 $0.0076 $0.0199 $0.18018
40 Common $0.0077 $0.01229 $0.01089 $0.0083 $0.0097 $0.0015 $0.00721 $0.0354
41 Total Uniform Melded Rates $0.07211 $0.08850 $0.08943 $0.07149 $0.05592 $0.04819 $0.07380 $0.25427
42 Revenue to Cot Ratio at Propos Ras 1.00 0.96 1.08 1.05 0.96 1.00 1.08 0.90
43 Current Revenue to Propose Cost Ratio 0.88 0.84 0.96 0.92 0.83 0.87 0.95 0.81Exhibit No. 11
File: ID 09 Elec Case / Elec COS Base Case / Sumcost Exhibits Case No. AVU-E-Q9-01
T. Knox, Avista
Schedule 3, p. 2 of 3
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1 NATUR GAS COST OF SERVICE STUDY
2 A cost of serice study is an engineering-economic study, which apportions the revenue,
3 expenses, and rate base associated with providing natural gas service to designated groups of
4 customers. It indicates whether the revenue provided by the customers recovers the cost to sere
5 those customers. The study results are used as a guide in determining the appropriate rate spread
6 among the groups of customers.
7 There are three basic steps involved In a cost of serice study: fuctionalization,
8 classification, and allocation. See flow char.
9 First, the expenses and rate base associated with the natural gas system under study are
10 assigned to fuctional categories. The uniform system of accounts provides the basic segregation
11 into production, underground storage, and distrbution. Traditionally customer accounting,
12 customer information, and sales expenses are included in the distrbution fuction and
13 administrative and general expenses and general plant rate base are allocated to all functions. In
14 this study I have created a separate fuctional category for common costs. Administrative and
15 general costs that canot be directly assigned to the other functions have been placed in this
16 category.
17 Second, the expenses and rate base items are classified into three primar cost components:
18 Demand, commodity or customer related. Demand (capacity) related costs are allocated to rate
19 schedules on the basis of each schedule's contrbution to system peak demand. Commodity
20 (energy) related costs are allocated based on each rate schedule's share of commodity
21 consumption. Customer related items are allocated to rate schedules based on the number of
22 customers within each schedule. The number of customers may be weighted by appropriate factors
23 such as relative cost of meterng equipment. In addition to these three cost components, any
24 revenue related expense is allocated based on the proportion of revenues by rate schedule.
Exhbit No. 11
Case No. AVU-G-09-01
T. Knox, Avista
Schedule 5, p. 1 of9
NATURAL GAS COST OF SERVICE STUDY FLOWCHART
Pro Forma
Results of
Operations
Production /
Purchased Gas
Cost
Distribution and
Customer Relations
Underground
Storage Common
Energy i
Commodity
Related
Customer RelatedDemand I
Capacity Related
Residential Small General Interruptible Transportation
Pro Forma Results of Operations by Customer Group
Exhbit No. 11
Case No. AVU-G-09-01
T. Knox, A vista
Schedule 5, p. 2 of9
1
The final step is allocation of the costs to the varous rate schedules utilizing the allocation
2 factors selected for each specific cost item. These factors are derived from usage and customer
3 information associated with the test period results of operations.
4 BASE CASE COST OF SERVICE STUDY
5 Production - Purchased Gas Costs
6 The Company has no natual gas production facilities serving the Idaho jurisdiction. The
7 natural gas costs included in the production function include the cost of gas purchased to serve
8 sales customers, pipeline transportation to get it to our system, and expenses of the gas supply
9 departent.
10 The demand and commodity components of account 804 have been determined directly
11 from the weighted average cost of gas (W ACOG) approved in the most recent purchased gas
12 adjustment (pGA) filing effective October 1, 2008. The January 6, 2009 gas cost reduction to
13 customer charges was accomplished though Schedule 155 which is excluded from base revenues.
14 The allocation of these costs agrees with the gas costs computation used to detennine pro forma
15 results of operations.
16 The expenses of the gas supply department recorded in account 813 are classified as
17 commodity related costs. The gas scheduling process includes transportation customers, so
18 estimated scheduling dispatch labor expenses are allocated by throughput. The ren:aining gas
19 supply deparent expenses are allocated by sales volumes.
20 Underground Storage
21 Underground storage rate base, operating and maintenance expenses are classified as
22 commodity related and allocated to customer groups by winter throughput. This approach was
23 proposed by commission Staff and accepted by the Idaho Public Utilities Cominission inCase No.
24 A VU-G-04-0L.
Exhbit No. 11
Case No. A VU-G-09-01
T. Knox, Avista
Schedule 5, p. 3 of9
1 Distribution Facilties Classifcation (Peak and Average)
2 Distribution mains and regulator station equipment (both general use and city gate stations)
3 are classified Demand and Commodity using the peak and average ratio for the distrbution
4 system. Peak demand is defined as the average of the five-day sustained peaks from the most
5 recent three years. Average daily load is calculated by dividing annual throughput by 365 (days in
6 the year). The average daily load is divided by peak load to arve at the system load factor of
7 37%. This proportion is classified as commodity related. The remaining 63% is classified as
8 demand related. Meters, services and industral measuring & regulating equipment are classified
9 as customer related distribution plant. Distribution operating and maintenance expenses are
10 classified (and allocated) in relation to the plant accounts they are associated with.
11 Customer Relations Distribution Cost Classifcation
12 Customer service, customer information and sales expenses are the core of the customer
13 relations fuctional unit which is included with the distribution cost category. For the most par
14 these costs are classified as customer related. Exceptions include uncollectible accoUnts expense,
15 which is considered separately as a revenue conversion item, and Demand Side Management
16 amortization expense recorded in Account 908. The demand side management investinent costs
17 and amortization expense are included with the distribution function and classified to demand and
18 commodity by the peak and average ratio.
19 Distribution Cost Allocation
20 Demand related distribution costs are allocated to customer groups (rate schedules) by each
21 groups' contrbution to the three year average five-day sustained peak. Commodity related
22 distribution costs are allocated to customer groups by annual throughput. Distribution main
23 investment has been segregated into large and small mains. Small mains are defined as less than
24 four inches, with large mains being four inches or greater. The small main costs use the same
Exhbit No. 11
Case No. AVU-G-09-01
T. Knox, Avista
Schedule 5, p. 4of9
demand and commodity data, but large usage customers (Schedules 131, and 146) that connect to
2 large system mains have been excluded from the allocations.
3 Most cUstomer related costs are allocated by the annualized number of customers biled
4 durng the test period. Meter investment costs are allocated using the number of customers
5 weighted by the relative current cost of meters in service at December 31, 2007. Services
6 investment costs are allocated using the number of customers weighted by the relative curent cost
7 of tyical service installations. Industral measuring and regulating equipment investment costs
8 are allocated by number of turbine meters which effectively excludes small usage customers.
9 Admiistrative and General Costs
10 General and intangible rate base items are allocated by the sum of Underground Storage
11 and Distrbution plant. Administrative and general expenses are segregated intoplant related,
12 labor related, revenue related and other. The plant related items are allocated based on total plant
13 in serice. Labor related items are allocated by operating and maintenance labor expense.
14 Revenue related items are allocated by pro forma revenue. Other administrative and general
15 expenses are allocated 50% by annual throughput (classified commodity related) and 50% by the
16 sum of operating and maintenance expenses not including purchased gas cost or administrative &
17 general expenses. Whenever costs are allocated by sums of other items within the study,
18 classifications are imputed from the relationship embedded in the summed items.
19 Special Contract Customer Revenue
20 Thee special contract customers receive transportation service from the Compaty. Rates
21 for these customers were individually negotiated to cover any incremental costs and retain some
22 contrbution to margin. The rates for these customers are not being adjusted in this case. The
23 revenue from these special contract customers has been segregated from general rate revenue and
Exhbit No. 11
Case No. AVU-G-09-01
T. Knox, Avista
Schedule 5, p. 5 of9
1 allocated back to all the other rate classes by relative rate base. In treating these revenues like
2 other operating revenues their system contribution reduces costs for all rate schedules.
3 Revenue Conversion Items
4 In this study uncollectible accounts and commission fees have been classified as revenue
5 related and are allocated by pro forma revenue. These items var with revenue and are included in
6 the calculation of the revenue conversion factor. Income tax expense items are allocated to
7 schedules by net income before income tax less interest expense.
8 For the functional summares on pages 2 and 3 of the cost of service study, these items are
9 assigned to the component cost categories. The revenue related expense items have been reduced
10 to a percent of all other costs and loaded onto each cost category b that ratio. Siniilarly, income
11 tax items have been assigned to cost categories by relative rate base (as is net income).
12 The following matrx outlines the methodology applied in the Company Base Case natural
13 gas cost of service study.
Exhbit No. 11
Case No. AVU-G-09-01
T. Knox, A vista
Schedule 5, p. 6of9
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Sumco AVISTA UTILITIES Natural Gas utlitCopay Base Case Co of Serv General Summar Ida Juri 13-n-AVU-G.(1 Meth For the Yea Ende September 30, 20
(b)(c)(d)(e)(f)(g)(h)(j)(k)Reidntial Small Firm Interrpt Transport
Sysem Serv Serv Serv ServicDeriptiTotalSoo 101 Sc 111 Sc 131 Sc 146
Plat In Servce
1 Prouction Plan
2 Underground Storage Plan 9,08,00 6,88,160 1,958,969 38,051 20.82
3 Dibutin Plant 130,352,00 108,934,756 20,079,764 314,421 1,02,05
4 Intagible Plat 1,65,00 1,373,897 26,54 4,158 14.397
5 Genra Plant 12,58,00 10,45,53 1,989,699 31,82 110.94
6 Tot Plant In Servic 153,68,00 127,651,347 24,288,980 38,451 1,35,22
Acm Dereation
7 Prouc Plant
8 Underond Storage Plant (3,172,00)(2,40,224)(68,667)(13,280)(71,83)9 Diriutin Plant (44,780,00)(37,983,00)(6,35,878)(102,649)(337,470)
10 Intgible Plant (647,00)(537,526)(102,163)(1,63)(5,679)
11 General Plant (4,489,00)(3,728,60)(709,48)(11,347)(39,561)
12 Tot Acmulated Deren (53,08,00)(44,652,35)(7,852,197)(128,90)(45,53)
13 Net Plat 100,595,00 82,998,991 16,43,783 259,543 89.68
14 Acmlulated Deerr FIT (15,05,00)(12,50,411 )(2,378,90)(38,04)(132,63)15 Misllaneous Rae Ba 4,94,00 3,72,232 1,08,40 21,178 117,164
16 Total Rate Ba 90,491,00 74,219,812 15,144,281 242,676 88,231
17 Revenue Fro Reil Rates 91,767,00 70,716,43 20,33,80 39,352 32,40
18 Oter Oprating Reveue 147,00 12O,nO 24,428 391 1,411
19 Tota Revenues 91,914,00 70,837,202 20,35,235 396,743 321,82
Oprating Exense20 Purcase Gas Co 66,837,00 49,715,037 16,58,726 33,703 3,53
21 Underrond Stoge Exnses 167,00 126,525 35,99 699 3,78222 Diriution Exns 4,087,00 3,347,026 6n,958 6,596 55,41923 Customer Accnt Expns 1,669,00 1,795,913 71,107 1,042 93824 Cuomer Informati Exses 244,00 217,182 23,238 43 3,14825 Sale Exnss 194,00 191,749 2,235 3 14
26 Adin & General Exns 5,03,00 4,010,109 90,268 16,707 97,916
27 TotalO&M Exns 78.23,00 59,40,542 18,30,526 38,183 164,749
28 Tax Otr Than Ince Taxes 90,00 749,676 145,44 2,355 8,5229. Depretin Exense
30 Undrground Storage Plat Depr 136,00 103,039 29,312 569 3,08
31 Disutin Plant Depretion 2,83,00 2,38,2 415,324 5.079 21,34132 Geeral Plant Dereati 86,00 720.96 137,188 2,194 7,65
33 Amorttion of Intible Plan 307,00 255,017 48,506 n6 2,702
34 Totl Depr & Amort Exens 4,141,00 3,467,280 83,329 8,618 34,n2
35 Ince Tax 2,42,00 2,04,109 33,08 7.537 36,27036 Total Oprating Ex 85,701,00 65,66,60 19,413,38 378,69 244,318
37 Net Incoe 6,213,00 5,172,59 94,851 18,05 n,503
38 Rate of Retum 6.87%6.97%6.24%7.44%8.76%
39 Retum Rati 1.00 1.02 0.91 1.08 1.28
40 Intere Exse 2,986,00 2,449,087 499,727 8,00 29,178
Ei No. 11
Ca No. AVU-G-01T. Kn Avi
Scle 6, p. 1 of 3
SumCopa Ba CaAVU-G1 Meth
AVISTA UTILIES
Suma by Fun wi Margn Anis
For th Year End 8eber 30. 20
(b)(e) (d) (e)
Derion
Funl Co Copo at Curr Ra1 Prouc
2 Undrgroun Stoge3 Disbu
4 Comon
5 Tot Curr Ra Revue
6 Exud Co of Ga w I Reue Ex.
7 Totl MarIn Reve at Curr Rete
Man per TJ at Curr Rates
8 Proucio9 Undro Stora10 Ditron
11 Como
12 Tot Curr Marg Me Ra pe Thn
(I)
SysTot
66.98.781.32.26
16.711.33
6.748.621
91,78,00
66.58.776
25,177,2
$0.001
$0.0169
$0.2139
$0.081$0.3
Fun Co Copo at Unif Cur Rem13 Pro
14 Undrgroun Storge15 Distron16 Como
17 Tot Union Curr Co
18 Exud Co of Ga w I Reven Exp.
19 Tota Uni Curr Margn
Ma per TJ at Uni Currnt Rem20 Prouc
21 Undrgroun St22 Dion
23 Common
24 Tot Curr Unifon Merg Me Rat I
25 Man to Co Rat at Curr Ra
66.98.783
1.32.23
16.710.02
6.747.9691,78,00
66.58.776
25,177,2
$0.001
$0.01701
$0.2139$0.08$0.3
(g)Restialserv
So 101
49.971.519
1.019.69
14.26.69
5.45.32
70,718,4
49.68.61221,03
$0.0014
$0.01816$0.25
$0.09719$0.346
49.971.519
1.00.317
14.156.513
5.447.02670,51,35
49.68.612
20,89,78
1.00
$0.0014
$0.0179$0.25
$0.09$0.313
1.01
Natural Ga Utit
Id Juriic
(h)
Small Finnserv
So 111
16.66,2
26.857
2.248.957
1.152.71120,3,8
16.572.9103,76
$0.0014
$0.0140
$0.120
$0.06153$0.28
16.66.2828,26
2.379.55
1.165.74520,8
16.572.9103,82,8
$0.0014
$0.0152
$0.1270$0.06$O.2
Q)InrrptSe
So 131
33.43
5.976
33.119
20.8239,333.25
82,08
$0.0014
$0.01413
$0.0783$0.04$0148
33.43
5.56131,2
20.637
39,91033.25
59,85
0.96
$0.0014
$0.01315$0.07
$0.041
$0.14109
1.04
13--D
(k)TraSe
So 146
3.55
37.53
162.567
116.75732
o32
$0.00127
$0.0134
$0.051
$0.04188$0.1149
3.55
30.078
142.676
114.55
29,81
o291
$0.00127
$0.01079
$0.05117
$0.04109
$0.104
1.10
Func Co Copo at Pr Re26 Prouc27 Undrond Sto
28 Dist29 Como30 Totl Pr Ra Re31 Exud Co of Ga w I Reve Ex.32 Totl Man Reue at Pr Re
Marg per Thenn at Pro Rate33 Pro34 Undro Storge
35 Distrbuon
36 Comon
37 Tot Pro Margn Me Rate pe Th
66.98.740
1.627.837
18.92.44
6,974.5894,580
66,58.7327,918,
$0.001$0.02$0.242$0.08
$0.344
Funcon Co Copont at Uni Pr Ret38 Pro39 Undro Sto40 Di41 Como42 Totl Unif Pro Co
43 Excud Co of Gas w I Revue Ex.44 Totl Uninn Pro Man
Margin pe The at Unlfonn Pro Rem45 Pron46 Undro Stora47 Di
48 Common
49 Totl Pro Unlfnn Ma Me Rat,
50 Margin to Co Rao at Pr Re
51 Cur Marin to Pro Coa Ra
66.98.740
1.62.470
18.92.09
6.974.3094,5,80
66.58.73
27,918,8
$0.001$0.02
$0.24231$0.08$0.344
49,971.4671.2.65
16,04.43
5.641,160
7290,7349.68.56
23,219,155
$0.0014$0.027$0.279
$0.100
$0.4134
49.971.4871,2,23
15.98.59
5.63.0272,875
49.68.56
23,145,79
$0.0014
$0.02194
$0.2872
$0.100
$OA1215
1.00
0.90
16.66,27133.73
2.64.757
1.192.713
20,8,474
16.572.894,2,5
$0.0014
$0.01787
$0.14145$0.06
$0.213
16.66,2135.55
2.737.99
1,21.52
20,96,31
16.572.894,,4
1.00
$0.0014
$0.01871
$0.14616
$0.0614$0.215
G.
0.91
33,42
7.12438,2
21,35
4010933.2588,8
$0.0014
$0.0188$0.09$0.05
$0.182
33.429
6.80
36.80
21.21040,2
33.25
87,00
$0.0014
$0.01610
$0.0870
$9.0516$0158
0.8
3.55
46.331
166.047
119.35735,2
o35,2
$0.00127
$0.0168
$0.0673
$0.04281
$0.12743
3.55
36.831
160.69
116.55317,8
o317,8
$0.00127
$0.01321
$0.05764
$0.04180
$0.1139
1.3 1.12
0.9 1.01
Ei No. 11Ca No. AVu--01T. Kn. Avi
Sc 6. p. 2 of 3
SumcotCopa Ba caAVU-G1 Me
AVISTA UTIUTIES Natra Gas Utit
Summar by Clfi wi Uni Co Anais Id Juri
For the Year End 8ebe 30. 20
(b)(e) (d) (e)
Deript
(f)
SytemTot
Cos by Claon at Curr Rern by SCle1 Commodit 66.708.982 Deman 12,46.923 Custoer 12,58.084 Totl Curr Rete Revnue 91,767.0C
Revue pe Thnn at Currnt Retes5 Comod
6 Dean
7 Custer
8 Totl Revue per Th at Curr Ra
Co pe Unit at Curr Rate9 Comod Co pe Thnn10 Dema Co per Pea Da Thnns11 Cuser Co pe Cus pe Mo
Co by Claea at Uni Cu Ren12 Comoty13 Dean14 Cuser
15 Totl Uni Curren Co
Co pe Thnn at Currnt Ratm16 Como
17 Dean
18 Cusomer
19 Tot Co per Thnn at Curr Ratm
Co per Uni at Union Curr Ratm
20 Comoity Co pe Thnn
21 Dean Co pe Peak Day Therm
22 Cuom Co pe Cusom per Mo
23 Revue to Co Ratio at Curr R..
$0.8511
$0.159
$0.16119
$1.1749
$0.8511
$21.39
$14.60
66.72,46
12.48,879
12.56,63
91.767,OC
$0.85
$0.159
$0.160
$1.1749
$0.85
$21.41
$14.57
1.00
(g)ResSe
SC 101
49.720.709
9.579.188
11.416.53
70.716.43
$0.88
$0.1707$0.2$1.2
$0.88
$21.36
$13.40
49,88,889.53,58
11,35,90
70.581,375
$0.8872
$0.1697
$0.203$1.21
$0.8872
$21.27
$13.33
1.00
(h)
Sml FinnSe
SC 111
16,447.53
2,799,59
1,08,670
20,33,80
$0.877
$0.149
$0.051$1.08
$0.877
$24.18
$109.42
16.515,73
2,861,58
1,123,547
20,50,85
$0.88162
$0.1525$0.05$1.09
$0.88162
$24.72
$113.14
0.98
mInterSe
SC 131
373.05
21.02
2,'839.35
$0.88
$0.0472$0.00
$0.93738
$0.88
$10.02
$189.80
371,719
19,992
2,199
39,910
$0.8712
$0.0472$0.00
$0.93161
$0.8712
$9.53
$183.26
1.1
13-
(k)TraSe
SC 146
167.69
69.120
83,5932,40
$0.0615
$0.02479$0.02
$0.1149
$0.0615
$4.18
$1.39.30
153.150
59,72
77,98
29,861
$0.05
$0.02142$0.027
$0.104
$0.05
$3.61
$1.29.71
1.10
Co by Cleon at Pro Rern by SCle24 Comoit 67.518,81425 De 13,313,78526 Cur 13,674,0027 Tot Pro Rate Revenue 94,50,80
Rev per Then at Pro Ra28 Comoit
29 Deand30 Cusr31 Totl Revue per Th at Pro Ra
Co pe Unit at Pro Rat
32 Comoit Cot pe The
33 Demand Co per Peak Day Thnns34 Cusr Co pe Custoer pe Mo
$0.88
$0.1704
$0.1750$1.2100
$0.88
$2.84
$15.86
Co by Clacaon at Unif Pro Ra35 Comoty 67,52,8936 Deand 13.321,39737 Cusom 13.65,31638 Tot Uni Pro Co 94.50.80
Co pe Thenn at Pro Ratm39 Comoit
40 Demand
41 Customer
42 Totl Co pe Th at Pro Retum
Co per Unit at Unifonn Pro Ratm43 Como Co pe Th
44 Dean Co pe Pe Day Thnns
45 Cusomr Co pe Cusomer pe Mo
46 Revue to Co Ra at Pro Ra
47 Cur Reveue to Pro Co Rat
$0.867
$0.170
$0.1748
$1.2100
$0.867
$2.86
$15.85
1.00
0.97
50,30,38
10,219,918
12,381,437
72,901,73
$0.89
$0.18198
$0.227
$1.2913
$0.89
$2.79
$14.53
50,2,92
10.198,40
12.34.04
72.82.375
$0.89
$0.18160
$0.2198$1.29
$0.89
$2.74
$14.49
1.00
0.9
16,65,837
2,98,78
1,199,84
20,84,474
$0.8816
$0.159$0.06
$1.1128
$0.8818
$2.82
$120.82
16,70,918
3,031,65
1,24,765
20,95.341
$0.89162
$0.16183$0.06
$1.1188
$0.89162
$2.19
$123.33
0.98
0.97
376,743
23,8722,49
40,109
$0.89101$0.05$0.00$0.95
$0.89101
$11.38
$27.87
375,731
23.091
2.43
401.257
$0.881
$0.051
$0.0076$0.94
$0.881
$11.01$2.92
1.00
0.9
184.85
80.20
90,22735,27
$0.06
$0.0277$0.03
$0.12743
$0.06
$4.85
$1,50.79
166,32468,2
83.070
317.63
$0.05
$0.0244$0.02
$0.1139
$0.05
$4.13
$1,38.51
1.12
1.01
Ex No. 11ca No. AVU-G1
T. Knx. Avist
Sc 6. p. 3 of 3