20110706Knox Di.pdf

RECEl\/'::D
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]
DAVID.MEYER§AVISTACORP. COM
11 JUL-5 II: 45
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
FOR AVISTA CORPORATION
CASE NO. AVU-E-11-01
CASE NO. AVU-G-11-01
DIRECT TESTIMONY
OF
TARA L. KNOX
(ELECTRIC AND NATURAL GAS)
1
2
I. INTRODUCTION
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 Regulatory Analyst in the State and
7 Federal Regulation Department.
8
9
Q.Would you briefly describe your duties?
A.Yes.I am responsible for preparing the
10 regulatory cost of service models for the Company, as well
11 as providing support for the preparation of results of
12 opera tions reports.
13 Q.What is your educa tional background and
14 professional experience?
15 A.I am a graduate of Washington State University
16 with a Bachelor of Arts degree in General Humanities in
17 1982, and a Master of Accounting degree in 1990.As an
18 employee in the State and Federal Regulation Department at
19 Avista since 1991, I have attended several ratemaking
20 classes, including the EEI Electric Rates Advanced Course
21 that specializes in cost allocation and cost of service
22 issues.I have also been a member of the Cost of Service
23 Working Group and the Northwest Pricing and Regulatory
24 Forum, which are discussion groups made up of technical
25 professionals from regional utilities and utili ties
26 throughout the United States and Canada concerned with cost
27 of service issues.
Knox, Di 1
Avista Corporation
1 Q.
2 proceeding?
3 A.
What is the scope of your testimony in this
My testimony and exhibits will cover the
4 Company's electric and natural gas cost of service studies
5
6 sponsoring
performed for this proceeding.
natural
Addi tionally,I am
the electric and gas revenue
7 normalization adj ustments to the test year results of
9
8 operations and the proposed Load Change Adjustment Rate
(LCAR) to be used in the Power Cost Adjustment (PCA).A
10 table of contents for my testimony is as follows:
11
12
13
14
15
16
17
18
19
20
21
22
23
24
Table of Contents Page
i.II.
III.iv.
v.
Q.
A.
schedules as follows.Schedule 1, which illustrates the
Introduction
Revenue NormalizationElectric
Natural Gas
Proposed Load Change Adjustment Rate
Electric Cost of Service
Illustration 1 Base Case Results
Illustration 2 Impact of Changes
Natural Gas Cost of Service
Illustration 3 Base Case Results
1
3
3
8
12
15
26
27
28
32
Are you sponsoring any exhibits in this case?
Yes.I am sponsoring Exhibit 12 composed of six
25 proposed Load Change Adjustment Rate calculation; Schedule
26 2, the electric cost of service study process description;
28 resul ts;
27 Schedule 3, the electric cost of service study summary
Schedule 4,the cost of service workshop
29 presentation; Schedule 5, the natural gas cost of service
30 study process description; and Schedule 6, the natural gas
31 cost of service study summary results.
Knox, Di 2
Avista Corporation
1 Q.Were these exhibits prepared by you or under your
2 direction?
3
4
5
6
7
A.Yes, they were.
II. REVENU NORMIZATION
Electric Revenue Normlization
Q.Would you please describe the electric revenue
8 adjustment included in Company witness Ms. Andrews pro
9 form results of operations?
10 A.Yes.The electric revenue normalization
11 adjustment represents the difference between the Company's
12 actual recorded retail revenues during the twelve months
13 ended December 2010 test period, and retail revenues on a
14 normalized (pro forma)basis.The total revenue
15 normalization adjustment increases Idaho net operating
16 income by $11,504,000, as shown in column (z) on page 8 of
17
18
Ms. Andrews Exhibit No. 10, Schedule 1.The revenue
normalization adjustment consists of three primary
19 components: 1) re-pricing customer usage (adjusted for any
20 known and measurable changes)at base tariff rates
21 presently in effect, 2) adjusting customer loads and
22 revenue to a 12-month calendar basis (unbilled revenue
adjustment), and 3) weather normalizing customer usage and23
24
25
irevenue
Q.Since these three elements are combined into a
26 single adjustment, would you please identify the impact
1 Documentation related to this adjustment is detailed in the Knox workpapers accompanying this case.
Knox, Di 3
Avista Corporation
1 (before taxes and revenue rela ted expenses) of each
2 component?
3
4
A.Yes.The re-pricing of billed usage comprises
the maj ori ty of the change in test year revenue.The
5 combined impact of the rate increase effective October 1,
6 20102, and the elimination of revenue and amortization
7 expense from adder schedules (Schedule 59 Residential
8 Exchange, Schedule 91 Public Purpose Tariff Rider, and
9 Schedule 95 Optional Renewable Power3), is an increase in
10 net revenue of $16,612,000.Re-pricing of unbilled
11 calendar usage and elimination of unbilled adder schedule
12 revenue and expense results in a net revenue reduction of
13 $1,229,0004. Finally, the weather normalization adjustment
14 increases revenue by $2,649,000.The combined impact of
15 these elements is an increase of $18,032,000 which, after
16 revenue-related expenses and income tax, results in the
17 increase to net operating income of $11,504,000.
18 Q.Would you please briefly discuss electric weather
19 normlization?
20 A.Yes.The Company's electric weather
21 normalization adjustment calculates the change in kWh usage
22 required to adjust actual loads during the twelve months
23 ended December 2010 test period to the amount expected if
24 weather had been normal.This adjustment incorporates the
2 IPUC Case No. AVU-E-1O-L.
3 Municipal Franchise Fee and Power Cost Adjustment revenues are eliminated in separate adjustments.
4 The unbiled adjustment consists of removing December 2009 usage biled in Januar 2010 from the
2010 test year, adding December 2010 usage biled in January 2011 to the 2010 test year, and re-pricing
the net adjustment to usage at October 1, 2010 rates.
Knox, Di 4
Avista Corporation
1 effect of both heating and cooling on weather-sensitive
2 customer groups.The weather adjustment is developed from
3 regression analysis of ten years of billed usage per
4 customer and billing period heating and cooling degree-day
5
6
data.The resulting seasonal weather sensitivity factors
(use-pe r-cus tome r-per- hea t ing-degree day and use-per-
7 customer-per-cooling-degree day) are applied to monthly
8 test period customers and the difference between normal
9 heating/ cooling degree-days and monthly test period
10 observed heating/cooling degree-days.
11 Q.Have the seasonal weather sensitivity factors
12 been updated since the last rate case?
13 A.Yes.The factors used in the weather adjustment
14 are based on regression analysis of monthly billed usage
15 per customer from January 2000 through December 2009 which
16 is the most recent completed analysis.Autoregressi ve
17 terms were included in the regressions in order to correct
18 for autocorrelation in the data.
19 Q.What data did you use to determine ~norml"
20 heating and cooling degree days?
21 A.Normal heating and cooling degree days are based
22 on a rolling 30-year average of heating and cooling degree-
23 days reported for each month by the National Weather
24 Service for the Spokane Airport weather station. Each year
25 the normal values are adjusted to capture the most recent
26 year with the oldest year dropping off, thereby reflecting
Knox, Di 5
Avista Corporation
1 the most recent information available at the end of each
2 calendar year.
3 Q.Is this proposed weather adjustment methodology
4 consistent with the methodology utilized in the Company's
5 last general rate case in Idaho?
6 A.Yes, the process for determining the weather
7 sensi ti vi ty factors and the monthly adjustment calculation
8 is generally consistent with the methodology presented in
9 Case No. AVU-E-10-1. 5
10 Q.What was the impact of electric weather
11 normlization on the twelve months ended December 2010 test
12 year?
13 A.Weather was warmer than normal during the winter,
14 and cooler than normal during the spring and summer of
15 2010.The adj ustment to normal required the addition of
16 334 heating degree-days during the heating season6 and 59
17 cooling degree-days.The total adjustment to Idaho sales
18 volumes was an addition of 31,023,829 kWhs which is
19 approximately 0.9% of billed usage.
20
21
22
23 Natural Gas Revenue Normlization
5 One difference may be observed between the cases. Due to the addition of autoregressive terms in the
regression analysis, it was possible to include the desired ten years of data in this case, whereas in the
prior case only five years of data had been used for Idaho electric customer groups in order to pass the
Durbin Watson test for autocorrelation without autoregressive term.6 The heating season includes the months of January through June and October through December.
Knox, Di 6
Avista Corporation
1 Q.Would you please describe the natural gas revenue
2 adjustment included in Ms. Andrews pro form results of
3 operations?
4 A.Yes.The natural gas revenue normalization
5 adjustment is similar to the electric adjustment and
6 represents the difference between the Company's actual
7 recorded retail revenues during the twelve months ended
8 December 2010 test period and retail revenues on a
9 normalized (pro forma) basis.The adjustment includes the
10 re-pricing of pro forma sales and transportation volumes at
11 present rates using pro forma sales volumes that have been
12 adj usted for unbilled sales, abnormal weather, and any
13 material customer load or schedule changes. The rates used
14 exclude:1) Temporary Gas Rate Adjustment Schedule 155,
15 which reflects the approved amortization rate for prior
16 deferred gas costs approved in the Company's last PGA
17 filing, 2) Public Purposes Rider Adj ustment Schedule 191,
18 and 3) Deferred State Income Tax Adjustment Schedule 1997.
19 Q.Does the Revenue Normlization Adjustment contain
20 a component reflecting normlized gas costs?
21 A.Yes. Purchase gas costs are normalized using the
22 gas costs approved by the Commission in Case No. AVU-G-10-
23 3, the Company's 2010 PGA filing, as set forth under
24 Schedule 150. These gas costs, effective November 1, 2010,
25 are applied to the pro forma retail sales volumes so that
26 there is a matching of revenues and gas costs.
7 Documentation related to this adjustment is detailed in the Knox workpapers accompanying this case.
Knox, Di 7
Avista Corporation
1 Q.Have you determned the imact of each of the
2 components of this adjustment?
3 A.Yes.The re-pricing of billed revenue and gas
4 costs increased marginS by $1,263,000. Re-pricing unbilled
5 revenue and gas costs decreased margin by $463, 000, and the
6 weather adjustment at present rates increased margin by
7 $1,088,000.
8
9
The total net amount of the natural gas revenue
normalization adjustment,which includes the related
10 purchase gas cost normalization, is an increase to net
11 operating income of $1,189, 000, as shown in column (i),
12 page 8 of Ms. Andrews Exhibit No. 10, Schedule 2.
13 Q.Would you please briefly discuss natural gas
14 weather normlization?
15 A.Yes.The natural gas weather normalization
16 adjustment is developed from a regression analysis of ten
17 years of billed usage per customer and billing period
18
19
heating degree-day data.The resulting seasonal weather
sensitivity factors (use-per-cus tomer-pe r- hea t ing-degree
20 day) are applied to monthly test period customers and the
21 difference between normal heating degree-days and monthly
22 test period observed heating degree-days. This calculation
23 produces the change in therm usage required to adjust
24 existing loads to the amount expected if weather had been
25 normal.
8 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 8
Avista Corporation
1 Q.In your discussion of electric weather
2 normlization you indicated that the adjustment utilized
3 sensitivity factors from the ten year period January 2000
4 through Decemer 2009.Is this true for natural gas as
5 well?
6 A.Yes, the natural gas weather adjustment utilized
7 updated weather sensitivity factors.
8 Q.What data did you use to determine ~norml"
9 hea ting degree days?
10 A.Normal heating degree-days are based on a rolling
11 30-year average of heating degree-days reported for each
12 month by the National Weather Service for the Spokane
13 Airport weather station.Each year the normal values are
14 adjusted to capture the most recent year with the oldest
15 year dropping off, thereby reflecting the most recent
16 information available at the end of each calendar year.
17 Q.Is this proposed weather adjustment methodology
18 consistent with the methodology utilized in the Company's
19 last general rate case in Idaho?
20 A.Yes.The process for determining the weather
21 sensitivity factors and the monthly adjustment calculation
22 are consistent with the methodology presented in Case No.
23 AVU-G-10-01.
24 Q.What was the ~pact of natural gas weather
25 normlization on the twelve months ended Decemer 2010 test
26 year?
Knox, Di 9
Avista Corporation
1 A.Weather was warmer than normal during the 2010
2 winter months, somewhat offset by a cooler than normal
3 spring and fall.The adjustment to normal required the
4 addi tion of 334 heating degree-days from January through
5 June and October through December. 9 The adj ustment to
6 sales volumes was an addition of 3,225,558 therms which is
7 approximately 2.8 percent of billed usage.
8
9
10
11
III. PROPOSED LOAD CHAGE ADJUSTMNT RATE
Q.What is the Load Change Adjustment Rate?
A.The Load Change Adjustment Rate (LCAR) is part of
12 the PCA mechanism that prices the change in actual retail
13 loads from the retail loads that were used to set the PCA
14 base costs.
15 Q.In prior cases, wasn't this called the ~Retail
16 Revenue Credi t Rate"?
17 A.Yes.September of last year,the Idaho
18 Commission opened Case No. GNR-E-10-03 titled IN THE MATTER
19 OF THE COMMISSION'S INQUIRY INTO LOAD GROWTH ADJUSTMENTS
20 THAT ARE PART OF POWER COST ADJUSTMENT MECHANISMS.This
21 proceeding resulted in a modified calculation methodology
22 of the "Load Change Adjustment Rate" (LCAR) to be used
23 beginning April 1, 2011 by all of the investor-owned
24 electric utilities in their various power cost adjustment
25 mechanisms.
9 Heating degree days that occur during July through September do not impact the natual gas weather
normlization adjustment as the seasonal sensitivity factor is zero for sumer months.
Knox, Di 10
Avista Corporation
1 Q.How is the new LCAR different from the former
2 Retail Revenue Credit Rate?
3 A.The new LCAR includes only the proportion of
4 production and transmission costs that are classified as
5 energy-related in the Company's cost of service study to
6 determine the rate.The former retail revenue credit rate
7 used all production and transmission costs to determine the
8 rate.
9
10
11
Q.How is the rate determined?
A.The proposed LCAR in this case is determined by
computing the proposed revenue requirement on the
12 production and transmission costs contained wi thin Ms.
13
14
Andrews'Idaho electric pro forma total results of
operations.The production/ transmis s ion revenue
15 requirement amount is then divided by the Idaho normalized
16 retail load used to set rates in order to arrive at the
17 average production and transmission cost-per-kWh embedded
18 in proposed rates.This amount is then multiplied by the
19 proportion of production and transmission costs classified
20 as energy-related in the cost of service study.
21 Q.Do you have an exhibit schedule that shows the
22 calcula tion of the proposed LCA?
23 A.Yes. Exhibi t No. 12, Schedule 1 begins with the
24 identification of the production and transmission revenue,
25 expense and rate base amounts included in each of Ms.
26 Andrews' actual, restating, and pro forma adjustments to
27 results of operations. The ~Pro Forma Total Production and
Knox, Di 11
Avista Corporation
1 Transmission Costs" at the bottom of page 1 shows the
2 resul ting production and transmis sion cost components.
3
4
Page 2 shows the revenue requirement calculation on
the production and transmission cost components.The rate
5 of return and debt cost percentages on Line 2 are inputs
6 from the proposed cost of capital.The normalized retail
7 load on Line 10 comes from the workpapers supporting the
8
9
revenue normalization and energy efficiency load
adjustments.Line 11 represents the average total
10 production and transmission cost-per-kWh proposed to be
11 embedded in Idaho customer retail rates.Lines 12 and 13
12 are values taken from the cost of service study supporting
13 report titled Functional Cost Summary by Classification at
14 Uniform Requested Return representing total costs at unity.
15 Line 12 shows the amount of production and transmission
16 costs classified as energy related, while Line 13 shows the
17 total production and transmission costs in the study.
18 The resulting load change adjustment rate on Line 14
19 is $0.02633 per kWh or $26.33 per MWh. The calculation of
20 the load change adjustment rate will be revised based on
21 the final production and transmission costs and rate of
22 return that are approved by the Commission in this case.
23
24
25
iv. ELECTRIC COST OF SERVICE
Q.Please briefly sumrize your testimony related
26 to the electric cost of service study.
Knox, Di 12
Avista Corporation
1 A.I believe the Base Case cost of service study
2 presented in this case is a fair representation of the
3 costs to serve each customer group. The Base Case study
4 shows Residential Service Schedule 1, Extra Large General
5 Service Schedule 25, Pumping Service Schedule 31 and the
6 Street and Area Lighting Schedules provide moderately less
7 than the overall rate of return under present rates.
8 General Service Schedule 11, Large General Service Schedule
9 21 and Extra Large General Service to Clearwater Paper
10 Schedule 25P provide more than the overall rate of return
11 under present rates.
12 Q.What is an electric cost of service study and
13 what is its purpose?
14 A.An electric cost of service study is an
15 engineering-economic study, which separates the revenue,
16 expenses, and rate base associated with providing electric
17 service to designated groups of customers. The groups are
18 made up of customers with similar load characteristics and
19 facili ties requirements.Costs are assigned or allocated
20 to each group based on (among other things), test period
21 load and facilities requirements,resulting in an
22 evaluation of the cost of the service provided to each
23 group.The rate of return by customer group indicates
24 whether the revenue provided by the customers in each group
25 recovers the cost to serve those customers.The study
26 resul ts are used as a guide in determining the appropriate
27 rate spread among the groups of customers. Exhibit No. 12,
Knox, Di 13
Avista Corporation
1 Schedule 2 explains the basic concepts involved in
2 performing an electric cost of service study.It also
3 details the specific methodology and assumptions utilized
4 in the Company's Base Case cost of service study.
5 Q.What is the basis for the electric cost of
6 service study provided in this case?
7 A.The electric cost of service study provided by
8 the Company as Exhibit No. 12, Schedule 3 is based on the
9 twelve months ended December 2010 test year pro forma
10 resul ts of operations presented by Ms. Andrews in Exhibit
11 No. 10, Schedule 1.
12 Q.Would you please explain the cost of service
13 study presented in Exhibit No. 12, Schedule 3?
14 A.Yes. Exhibit No. 12, Schedule 3 is composed of a
15 series of summaries of the cost of service study results.
16 The summary on page 1 shows the results of the study by
17 FERC account category. The rate of return by rate schedule
18 and the ratio of each schedule's return to the overall
19 return are shown on Lines 39 and 40.This summary was
20 provided to Company witness Mr. Ehrbar for his work on rate
21 spread and rate design.The results will be discussed in
22 more detail later in my testimony.
23 Pages 2 and 3 are both summaries that show the
24 revenue-to-cost relationship at current and proposed
25 revenue. Costs by category are shown first at the existing
26 schedule returns (revenue); next the costs are shown as if
27 all schedules were providing equal recovery (cost).These
Knox, Di 14
Avista Corporation
1 comparisons show how far current and proposed rates are
2 from rates that would be in alignment with the cost study.
3 Page 2 shows the costs segregated into production,
4
5
transmission,distribution,and common functional
categories.Line 44 on page 2 shows the target change in
6 revenue which would produce unity in this cost study. Page
7 3 segregates the costs into demand, energy, and customer
8 classifications.Page 4 is a summary identifying specific
9 customer related costs embedded in the study.
10 The Excel model used to calculate the cost of service
11 and supporting schedules has been included in its entirety
12 both electronically and in hard copy in the workpapers
13 accompanying this case.
14 Q.Does the Company's electric Base Case cost of
15 service study follow the methodology filed in the Company's
16 last electric general rate case in Idaho?
17 A.In most respects, yes.The Base Case cost of
18 service study was prepared using the methodology applied to
19 the study presented in Case No. AVU-E-04-01 through Case
20 No. AVU-E-09-01 except that the peak credit classification
21 of production and transmission costs has been revised.
22 While a revision to the peak credit classification of
23 production and transmission costs was also proposed in Case
24 No. AVU-E-10-01, only the classification of transmission
25 costs as 100% demand-related was accepted as part of the
26 settlement in that case. Therefore the ~Prior Methodology"
27 refers to the study methodology last presented in Case No.
Knox, Di 15
Avista Corporation
1 AVU-E-O 9-01 modified only to reflect the transmission costs
2 classification change.
3 Q.Given that the specific details of this
4 methodology are described in Exhibit No. 12 , Schedule 2,
5 would you please give a brief overview of the key elemnts
6 and the history associated with those elements?
7 A.Yes.Production costs are classified to energy
8 and demand in this case based on the system load factor.
9 This is a new proposal due to the discussions at the cost
10 of service workshop arising from the Settlement in Case No.
11 AVU-E-10-01.Transmission costs are classified as 100%
12 demand and allocated by weighted 12 month coincident peaks.
13 While the transmission demand classification was accepted
14 in the Settlement in Case No. AVU-E-10-01, the weighted 12
15 month coincident peak allocation is a new proposal
16 discussed at the cost of service workshop required by the
17 Settlement Stipulation in Case No. AVU-E-10-01.
18 Distribution costs are classified and allocated by the
19 basic customer theorylO accepted by the Idaho Commission in
20 Case No. WWP-E-98-11.Addi tional direct assignment of
21 demand related distribution plant has been incorporated to
22 reflect improvements accepted by the Commission in Case No.
23 AVU-E-04-01.
24 Administrative and general costs are first directly
25 assigned to production, transmission, distribution, or
26 customer relations functions. The remaining administrative
io Basic customer theory classifies only meters, services and street lights as customer-related plant; all other
distrbution facilties are considered demand-related
Knox, Di 16
Avista Corporation
1 and general costs are categorized as common costs and have
2 been assigned to customer classes by the four-factor
3 allocator accepted by the Idaho Commission in Case No. AVU-
4 E-04-01.
5
6
Q.You mentioned a cost of service workshop arising
from the settlement in Case No. AVU-E-10-01.Please
7 explain.
8
9
10
A.In Order No. 32070 from Case No. AVU-E-10-01 and
AVU-G-10-01,the Commission approved an all-party
Settlement Stipulation.In Section 11 of the Settlement
11 Stipulation, beginning on page 5 it states:
12 The Parties have otherwise agreed to exchange13 information and convene a public workshop, prior
14 to the Company's next general rate case, with15 respect to the possible use of a revised peak16 credit method for classifying production costs, as17 well as consideration of the use of a 12 CP18 (whether "weighted" or not) versus a 7 CP or other19 method for allocating transmission costs.
20 The workshop was convened on February 8, 2011 at the
21 Idaho Public Utilities Commission, and was attended by the
22 key stakeholders regarding cost of .. 11service issues.The
23 Company's presentation and handouts from the workshop have
24 been included as Schedule 4 of Exhibit No. 12.
25 Q.Regarding production cost classification, the
26 workshop presentation emphasizes the benefits of the IRP
27 based methodology Avista proposed in Case No. AVU-E-10-01.
28 Why are you moving away from that approach in this case?
11 Paries attending the workshop included Avista, IPUC Staff, Idaho Forest Group, Clearwater Paper,
Idaho Conservation League, and Idaho Power Company.
Knox, Di 17
Avista Corporation
1 A.A number of issues were raised in the workshop
2 which led to a re-evaluation of that approach, as well as
3 the applicability of an entirely future-based relationship
4 in an embedded cost study.A system load factor
5 alternative was raised during the workshop, and the Company
6 determined that this approach to peak credit better met our
7 requirements to improve the production and transmission
8 cost classification process.
9 Q.What is the Company proposing in this case with
10 regard to the peak credit methodology?
11 A.In this case the Company is proposing to use the
12 system load factor to determine the proportion of the
13 production function that is demand-related.
12 This single
14 peak credit ratio is then applied uniformly to all
15 production costs.
16 Q.How was the prior peak credit methodology
17 determned and applied to production costs?
18 A.In the Company's prior cost of service studies,
19 Avista's electric system resource costs were classified to
20 energy and demand using a comparison of the replacement
21 cost per kW of the Company's peaking units, to the
22 replacement cost per kW of the Company's thermal and hydro
23 plants (separately).This analysis created separate peak
24 credi t ratios applied to thermal plant and hydro plant
25 costs.Fuel and system control expenses were classified
12 One minus the load factor equals the demand percentage or peak credit ratio.
Knox, Di 18
Avista Corporation
1 entirely to energy, and peaking plant related costs were
2 classified entirely to demand.
3 Q.What are the benefits of using the system load
4 factor to determne the peak credit ratio?
5
6
A.There are several benefits to the system load
factor approach for identifying the demand-related
7 proportion of production costs: 1) it is simple and
8 straightforward to calculate, 2) it is directly related to
9 the electric system and test year under evaluation, and 3)
10 the relationship should remain relatively stable from year
11 to year (i.e., not vary with changes in natural gas costs).
12 Q.What is the net effect of the proposed change in
13 the peak credit method?
14 A.The net effect of this change is to slightly
15 increase the overall level of production costs that are
16 classified as demand-related.Using the prior method,
17 approximately 31.97% of total production costs were
18 classified as demand-related.Under the proposed method,
19 36.41% of total production costs are classified as demand-
20 related.This change shifts costs away from high load
21 factor customer groups (Schedules 21, 25, and 25P) as well
22 as customer groups which have a limited contribution to
23 system peak usage (pumping and street lighting) .
24 Q.You also mentioned a change to the allocation of
25 transmission costs, what are you proposing in this case?
26 A.All transmission costs are allocated to customer
27 classes in this case by their weighted 12-month coincident
Knox, Di 19
Avista Corporation
1 peak demand.The peak demand by schedule at the time of
2 each monthly system peak in the test year is weighted by
3 the amount that the electric system peak demand in that
4 month exceeded the annual average system demand as a
5 proportion of the twelve month total excess system demand.
6 The weighting process is illustrated in Exhibit No.
7 12, Schedule 4, page 15.In this example, January system
8 peak demand of 1,779 MW exceeded annual average demand
9 (energy) of 1,134 aMW by 645 MW.645 MW was 12.4% of the
10 sum of each month's excess demand of 5,188 MW. Therefore,
11 12.4% of January coincident peak demand by schedule was
12 included in the weighted 12CP allocation factor.
13 Q.In Case No. AVU-E-10-01 you had proposed a 7CP
14 allocation factor for transmission costs, while in prior
15 cases demand-related transmission costs were allocated by
16 an unweighted 12 CP allocation factor. Why are you
17 proposing the weighted 12 CP in this case?
18 A.The 7CP allocation was proposed in the last case
19 to acknowledge that lower customer demands in the off-peak
20 fall and spring seasons do not impose the same capacity
21 utilization of the transmission facilities as the high
22 demand winter and summer seasons.The weighted 12 CP
23 allocation (developed for the workshop) is a more robust
24 method to capture the seasonal impacts on transmission
25 capacity utilization. As such, the Company considers this
26 allocation to be a better representation of the demands on
27 the transmission system than either the straight average of
Knox, Di 20
Avista Corporation
1 all monthly demands which does not recognize any seasonal
2 differences, or the average of the seven highest months
3 which ignores shoulder month demand entirely.
4 Q What is the impact on the study of moving from
5 the 12CP (per the settlement in AVU-E-10-01) to the
6 weighted 12CP in this case?
7 A.The net effect of this change is that more costs
8 are assigned to both residential and street and area light
9 customers, while all other customer classes benefit to
10 varying degrees. Street and area lights only contribute to
11 the system peak if that peak occurs after dark.This
12 generally only happens during the winter months which
13 naturally have more weight (i. e., more excess demand) than
14 the spring and summer months.Similarly, due to heating
15 loads, residential customers have their highest relative
16 demand during winter months which have more weight than
17 other times of the year.
18 Q.What are the results of the Company's electric
19 cost of service study presented in this case?
20 A.The following table shows the rate of return and
21 the relationship of the customer class return to the
22 overall return (relative return ratio) at present rates for
23 each rate schedule:
24 Illustration 1
Customer Class
Residential Service Schedule 1
General Service Schedule 11/12
Rate of Return
Return Ratio
6.27%0.83
10.48%1. 38
Knox, Di 21
Avista Corporation
Customer Class
Large General Service Schedule 21/22
Extra Large General Service Schedule 25
Extra Large General Service Clearwater
Paper Schedule 25P
Pumping Service Schedule 31/32
Lighting Service Schedules 41 - 49
Total Idaho Electric System
Rate of
Return
8.65%
6.38%
8.34%
7.21%
6.76%
7.57%
Return
Ratio
1. 14
0.84
1. 10
0.95
0.89~
1 As can be observed from the above table, residential,
2 extra large general service, pumping service and lighting
4
3 service schedules (1, 25, 31 and 41-49) show moderate
The generalunder-recovery of the costs to serve them.
5 service, large general service, and extra large Clearwater
7 of the costs to serve them.
6 Paper schedules (11, 21, 25P) show moderate over-recovery
The summary results of this
9 development of the proposed rates.
8 study were provided to Mr. Ehrbar as an input into
10 Q.Can you illustrate how the changes to the
11 methodology applied to production and transmission costs
12 impacted the cost of service study results?
13 Yes.The following
14 progression in rate of return and relative return ratio
A.table contains the
15 from the model run of the study using the prior method to
16 the proposed Base Case method.
17 Illustration 2
Customer Class
AVU-E-10-01
Settlement
Prior Method
Proposed
Add Load Factor
Peak Credit
Proposed
Add Transmission
Weighted 12CP
Knox, Di 22
Avista Corporation
Customer Class
Schedule 1
Schedule 11/12
Schedule 21/22
Schedule 25
Schedule 25P
Schedule 31/32
Schedules 41 - 49
Total Idaho
AVU-E-10-01
Settlement
Prior Method
6.48% 0.86
10.49% 1.39
8.49% 1.2
6.19% 0.82
7.96% 1.05
6.97% 0.92
6.78% 0.90
7.57% 1.00
Proposed
Add Load Factor
Peak Credit
6.39% 0.84
10.48% 1.38
8.52% 1.12
6.28% 0.83
8.18% 1.08
7.06% 0.93
6.84% 0.90
7.57% 1.00
Proposed
Add Transmission
Weighted 12CP
6.27% 0.83
10.48% 1.38
8.65% 1.14
6.38% 0.84
8.34% 1.10
7.21% 0.95
6.76% 0.89
7.57% 1.00
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
This illustration shows the incremental impact of each
change to the electric cost of service methodology. It
also shows that the proposed electric cost of service
implications of the study.
changes had a relatively minor impact on the rate spread
V. NATUR GAS COST OF SERVICE
study and its purpose.
Q. Please describe the natural gas cost of service
enginee r ing-economi c
gas cost of service study is an
study which separates the revenue,
A. A natural
expenses, and rate base associated with providing natural
gas service to designated groups of customers. The groups
are made up of customers with similar usage characteristics
and facility requirements. Costs are assigned in relation
to each group's test year load and facilities requirements,
Knox, Di 23
Avista Corporation
1 resul ting in an evaluation of the cost of the service
2 provided to each group.The rate of return by customer
3 group indicates whether the revenue provided by the
4 customers in each group recovers the cost to serve those
5 customers. The study results are one of the key inputs in
6 determining the appropriate rate spread among the groups of
7 customers.Exhibi t No. 12, Schedule 5 explains the basic
8 concepts involved in performing a natural gas cost of
9 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 natural gas cost of
13 service study provided in this case?
14 A.The cost of service study provided by the Company
15 as Exhibit 12, Schedule 6 is based on the twelve months
16 ended December 2010 test year pro forma results of
17 operations presented by Ms. Andrews in Exhibit 10, Schedule
18 2.
19 Q.Would you please explain the cost of service
20 study presented in schedule 6?
21 A.Yes.Exhibi t 12, Schedule 6 is composed of a
22 series of summaries of the cost of service study results.
23 Page 1 shows the results of the study by FERC account
24 category.The rate of return and the ratio of each
25 schedule's return to the overall return are shown on lines
26 38 and 39. This summary is provided to Mr. Ehrbar for his
27 work on rate spread and rate design.The results will be
Knox, Di 24
Avista Corporation
1 presented later in my testimony. Additional summaries show
2 the costs organized by functional category (page 2) and
3 classification (page 3), including margin and unit cost
4 analysis at current and proposed rates. Finally, page 4 is
5 a summary identifying specific customer related costs
6 embedded in the study.
7 The Excel model used to calculate the cost of service
8 and supporting schedules has been included in its entirety
9 both electronically and hard copy in the workpapers
10 accompanying this case.
11 Q.Does the Natural Gas Base Case cost of service
12 study utilize the methodology from the Company's last
13 natural gas case in Idaho?
14 A.Yes.The Base Case cost of service study was
15 prepared using the methodology accepted by the Idaho
16 Commission in Case No. AVU-G-04-01, and presented in AVU-G-
17 08-01, AVU-G-09-01 and AVU-G-10-01.
18 Q.What are the key elements that define the cost of
19 service methodology?
20
21
A.Allocations of gas costs reflect the current
purchased gas tracker methodology.Underground storage
22 costs are allocated by normalized winter throughput.
23 Natural gas main investment has been segregated into large
24 and small mains.Large usage customers that take service
25 from large mains do not receive an allocation of small
26 mains.Meter installation and services investment is
27 allocated by number of customers weighted by the relative
Knox, Di 25
Avista Corporation
1 current cost of those items.System facilities that serve
2 all customers are classified by the peak and average ratio
3 that reflects the system load factor, then allocated by
4 coincident peak demand and throughput,respectively.
5 Demand side management costs (if any) are treated in the
6 same way as system facilities. General plant is allocated
7 by the sum of all other plant. Administrative & general
8 expenses are segregated into labor-related, plant-related,
9 revenue-related, and "other". The costs are then allocated
10 by factors associated with labor, plant in service, or
11 revenue , respectively.The "other" A&G amounts get a
12 combined allocation that is one-half based on O&M expenses
13 and one-half based on throughput.A detailed description
14 of the methodology is included in Schedule 5.
15 Q.What are the results of the Company's natural gas
16 cost of service study?
17 A.I believe the Base Case cost of service study
18 presented in this filing is a fair representation of the
19 costs to serve each customer group.The study indicates
20 that the General Service (primarily residential) Schedule
21 (101) is providing slightly less than the overall return
22 (uni ty) ,and Large General,Interruptible and
23 Transportation Service Schedules (111, 131 and 146) are
24 providing slightly more than unity.All schedules are
25 currently providing return ratios that are relatively close
26 to unity.
Knox, Di 26
Avista Corporation
1 The following table shows the rate of return and the
2 relative return ratio at present rates for each rate
3 schedule:
4 Illustration 3
Customer Class
General Firm Service Schedule 101
Large Firm Service Schedule 111/112
Interruptible Service Schedule 131/132
Transportation Service Schedule 146
Total Idaho Natural Gas System
Rate of Return
Return Ratio
7.09%0.97
8.37%1. 15
7.87%1. 08
7.57%1. 04
7.31%~
5 The summary results of this study were provided to Mr.
6 Ehrbar as an input into development of the proposed rates.
7 Q.Does this conclude your pre-filed direct
8 testimony?
9 A.Yes.
Knox, Di 27
Avista Corporation
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]
DAVID. MEYER§AVISTACORP. COM
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-11-01
CASE NO. AVU-G-11-01
EXHIBIT NO. 12
TARA L. KNOX
FOR AVISTA CORPORATION
(ELECTRIC AND NATURAL GAS)
A VIST A UTILITIES
AVERAGE PRODUCTION AND TRANSMISSION COST
IDAHO ELECTRIC
TWELVE MONTHS ENDED DECEMBER 31. 2010
Production/Transmission
Column Description of Adjustment (OOO's)Revenue Expense Rate Base
b Results Report 132,780 246,222 367,353
c Deferred FIT Rate Base (56,171)
d Deferred Gain on Offce Building
e Colstrip 3 AFUDC Elimination 191 1,493
f Colstrp Common AFUDC 774
g Kettle Falls & Boulder Park Disallow.(1,880)
h Customer Advances
Weatherizn and DSM Investment 65
j Restating CDA Settlement 29 (317)
k Restating CDA Settlement Deferral 18 166
i Restating CDAlSRR CDR 348 (68)
m Restating Spokane River Deferrl 3 31
n Restating Spokane River PM&E Deferral 20 145
0 Restating Montana Lease 46 996
p Working Capital
Actual 132,780 246.877 312,587
q Eliminate B & 0 Taxes
r Propert Tax 297
s Uncollect. Expense
t Regulatory Expense
u Injuries and Damages
v FIT
w Idaho PCA (3.227)
x Nez Perce Settlement Adjustment (17)
y Eliminate AIR Expenses
z Revenue Nonnalization Adjustment 6,058
aa Misc A&G Restating Adjs (I)
ab Restating Incentive Adj
ac Restating CS2 Levelized Adj 280
ad Colstrp Stlmnt Exp (230)
ae Removal CCX Revenue 342
af O&MSavings (99)
ag Restate Debt Interest
Restated Total 132,780 250,280 312.587
PFI Pro Fonna Power Supply (114,526)(105,403)
PF2 Pro Fonna Energy Efficiency Load Adjustment 1,201 (1,157)
PF3 Pro Fonna Labor Non-Exec 371
PF4 Pro Forma Labor Exec 2
PF5 Pro Forma Transmission RevÆxp (355)832
PF6 Pro Forma Capital Add 2010 115 2,477
PF7 Pro Forma Capital Add 2011 552 (134)
PF8 Pro Forma Capital Add 2012 138 (2,438)
PF9 Pro Forma Noxon Gen 2011 & 2012 217 4,650
PFIO Pro Forma Employee Benefits 52
PF11 Pro Forma Insurance
PFI2 Pro Forma Vegetation Management
Pro Forma Total 19,100 145,999 317,142
Exhibit No. 12
Case No. AVU-E-11-01
T. Knox, Avista
Schedule 1, p. 1 of 2
A VISTA UTILITIES
AVERAGE PRODUCTION AND TRANSMISSION COST
IDAHO ELECTRIC
TWELVE MONTHS ENDED DECEMBER 31. 2010
Proposed Production and Transmission Revenue Requirement
Calculation of Load Change Adjustment Rate at Proposed Retur
Line ($OOO's)Debt Cost
1 Prod!rans Pro Forma Rate Base $317.142
2 Proposed Rate of Retu 8.490%3.020%
3 Rate Base Net Operating Income Requirement $26,925
4 Tax Effect Net Operating Income Requirement ($3,352)
(Rate Base x Debt Cost x -35%)
5 Net Expense Net Operating Income Requirement 126,899
(Expense - Revenue)
6 Tax Effect Net Operating Income Requirement ($44,415)
(Net Expense x -.35%)
7 Total Prod!rans Net Operating Income Requirement $106,058
8 1 - Tax Rate Conversion Factor (Excl. Rev. ReI. Exp.)0.65
9 Prod/Trans Revenue Requiremen1 $163,1651
10 ID Test Year Normalized Retail Load MWh 3.358,927
11 Prod!rans Rev Requirement per kWh $0.04858
12 Cost of Service Energy Classified Production/ransmission Costs $89.949
13 Cost of Service Total Production/ransmission Costs $165,977
14 Load Change Adjustment Rate per kWh (Line 11 * Line 12/ Line 13)1$0.026331
Exhibit No. 12
Case No. AVU-E-11-01
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 electric service 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 determining the appropriate rate spread
6 among the groups of customers.
7 There are three basic steps involved in a cost of service study: functionalization,
8 classification, and allocation. See flow char below.
9 First, the expenses and rate base associated with the electric system under study are
10 assigned to functional 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 distribution fuction and administrative and
13 general expenses and general plant rate base are allocated to all fuctions. In this study I have
14 created a separate functional category for common costs. Administrative and general costs that
15 cannot be directly assigned to the other fuctions have been placed in this category.
16 Second, the expenses and rate base items that cannot be directly assigned to customer
17 groups are classified into three primary 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.
Exhibit No. 12
Case No. A VU-E-11-01
T. Knox, Avista
Schedule 2, p. 1 of 9
ELECTRIC COST OF SERVICE STUDY FLOWCHART
Pro Forma
Results of
Operations
Functionalization/
Production Transmission
Distribution and
Customer
Relations Common
Energy I
Commodity
Related
Demand I
Capacity Related
Customer
Related
Residential Small General Extra Large
General
pumping
Pro Forma Results of Operations by Customer Group 1
Customer classes shown in this flowchart are ilustrative and may not match the Company's actul rate schedules.
Exhibit No. 12
Case No. AVU-E-11-01
T.. Knox, Avista
Schedule 2, p. 2 of9
The final step is allocation of the costs to the various 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 Classifcation (Load Factor Peak Credit)
6 This study utilzes a Peak Credit methodology to classify production costs into demand and
7 energy classifications. The Peak Credit method acknowledges that all energy production costs
8 contain both capacity and energy components as they provide energy throughout the year as well as
9 capacity during system peaks. The peak credit ratio (the proportion of total production cost that is
10 capacity related) is determined using the electric system load factor inherent in the test year. The
11 share of production costs attibutable to demand is one minus the load factor (average MW divided
12 by peak MW) which is 36.41 % for the 2010 test year, The same classification ratio is applied to
13 all production costs.
14 Production Allocation
15 Production demand related costs are allocated to the customer classes by class contribution
16 to the average of the twelve monthly system coincident peak loads. Although the Company is
17 usually technically a winter peaking utility, it experiences high summer peaks and careful
18 management of capacity requirements is required throughout the year. The use of the average of
19 twelve monthly peaks recognizes that customer capacity needs are not limited to the heating
20 season. Energy related costs are allocated to class by pro forma annual kilowatthour sales adjusted
21 for losses to reflect generation level consumption.
22 Transmission Classifcation and Allocation
23 Transmission costs are classified as 100% demand related due in part to the fact that the
24 facilties are designed for meeting system peak loads. These costs are then allocated to the
Exhibit No. 12
Case No. A VU-E-11-01
T. Knox, Avista
Schedule 2, p. 3 of9
customer classes by class contrbution to the monthly system coincident peak loads weighted by
2 the proportion the electric system peak demand exceeded annual average demand in each month.
3 This method ecognizes that lower customer demands in the off-peak fall and spring seasons do not
4 impose the same capacity utilzation of the transmission facilities as the high demand winter and
5 summer seasons.
6 Distribution Facilties Classifcation (Basic Customer)
7 The Basic Customer method considers only services and meters and directly assigned
8 Street Lighting apparatus (FERC Accounts 369, 370, and 373 respectively) to be customer related
9 distrbution plant. All other distrbution plant is then considered demand related. This division
10 delineates plant which benefits an individual customer from plant which is part of the system. The
11 basic customer method provides a reasonable, clearly definable division between plant that
12 provides service only to individual customers from plant that is par of the interconnected
13 distribution network.
14 Customer Relations Distribution Cost Classifcation
15 Customer service, customer information and sales expenses are the core of the customer
16 relations functional unit which is included with the distribution cost category. For the most part
17 they are classified as customer related. Exceptions are sales expenses which are classified as
18 energy related and uncollectible accounts expense which is considered separately as a revenue
19 conversion item. Demand Side Management expenses (if any) recorded in Account 908 are also
20 considered separately from the other customer information costs.
21 Any demand side management investment and amortzation included in base rates would
22 be classified implicitly to demand and energy by the sum of production plant in service, then
23 allocated to rate schedules by coincident peak demand and energy consumption respectively. At
24 this point in time, the Company's demand side management investments in base rates have been
Exhibit No. 12
Case No. A VU-E-11-0 1
T. Knox, Avista
Schedule 2, p. 4of9
fully amortized except for some minor outstanding loan balances that wil remain on the books
2 until satisfied. All current demand side management costs are managed through the Schedule 91
3 Public Purose Tariff Rider balancing account which is not included in this cost study.
4 Distribution Cost Allocation
5 Distribution demand related costs which cannot be directly assigned are allocated to
6 customer class by the average of the twelve monthly non-coincident peaks for each class.
7 Distribution facilities that serve only secondary voltage customers are allocated by the non-
8 coincident peak excluding primary voltage customers or number of customers excluding primary
9 voltage customers. This includes line transformers, services, and secondary voltage overhead or
10 underground conductors and devices. The costs of specific substations and related primary voltage
11 distribution facilties 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 tyical 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 Administrative 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 functions
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
Exhibit No. 12
Case No. AVU-E-11-01
T. Knox, Avista
Schedule 2, p. 5 of9
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 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 adjusted by interest expense.
9 For the fuctional summaries 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
i 1 percent of all other costs and loaded 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 service study.
Exhibit No. 12
Case No. AVU-E-11-01
T. Knox, Avista
Schedule 2, p. 6of9
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f
9
Sumcost AVISTA UTILITIES Idaho Jurisdiction
Scenario: Company Base Case Cost of Service Basic Summary Electric Utlity 06.15.11
AVU.E.l1-ûl Proposed Method For the Twelve Months Ended December 31. 2010
Prod by LF PC & Trans By Demand W12 CP
(b)(c) (d) (e)(n (g)(h)(I)ul (k)(I)(m)
Residential General Large Gen Extra Large Extra Large Pumping Street &
System Service Servce Service Gen Service Service CP Service Area Lights
Description Total Sch 1 Sch 11.12 Sch 21.22 Sch 25 Sch 25P Sc 31.32 Sch 41-49
Plant In Service
1 Production Plant 391,411,000 145.064,243 36,927,840 78,806,700 29,717,500 93,659,118 5,883,417 1.352,181
2 Transmission Plant 184,064,000 79,659,536 17,814,655 34,126,837 12,717,014 37,087,424 2,134,684 523,851
3 Distribution Plant 440,82,000 221,637,409 60,593,493 110,013,429 10,501,372 2,220,959 15,074,108 20,41,230
4 Intangible Plant 50,759,000 21.983,423 5,339,188 9,351,787 3,192,978 9.654,515 817,015 420,094
5 General Plant 80,147,000 43,795,365 10,038,58 12,267,439 3,126,263 8.075.112 1,461,306 1,383,058
6 Total Plant In Service 1.146.863,000 512,139.975 130,713,634 244,566,191 59,255,127 150.697.128 25,370,530 24,120,14
Accum Depreciation
7 Production Plant (166,852,000)(61,838,74)(15.741,724)(33,593,986)(12,668,076)(39,925,325)(2,508.003)(576,12)
8 Transmission Plant (63,228.000)(27,363,923)(6,119,529)(11,722,942)(4,368,33)(12.739,936)(733,287)(179,949)
9 Distribution Plant (143,547,000)(71,84,271)(18,514,037)(35.974.582)(3.369,089)(706.067)(4.812,648)(8,686.305)
10 Intangible Plant (10,13,000)(5,286,112)(1.231,174)(1,705.027)(492.500)(1,370.137)(181,397)(146,653)
11 General Plant (29.933,000)(16,358,528)(3,749,125)(4,581,597)(1,167,585)(3,015.862)(545,763)(516,539)
12 Total Accumulated Depreciation (413.973,000)(182,329.308)(45,355,590)(87,578,134)(22,065,683)(57,757,327)(8,781,099)(10,105,859)
13 Net Plant 732,890.000 329,810.667 85,358,044 156,988.058 37,189,43 92,939,801 16.589,431 14,014.556
14 Accmulated Deferred FIT (114,339,000)(51,142,46)(12,995,780)(24,091,553)(5.957,508)(15,350,408)(2,484,578)(2,316,728)
15 Miscellaneous Rate Base 8,50.000 3.337,688 896,214 1,966,304 515,668 1,374,473 187,425 172,229
16 Total Rate Base 627,001,000 282,005,909 73,258,79 134,862,809 31,747.603 78.963,866 14,292,278 11,870,057
17 Revenue From Retail Rates 246,379.000 100,09,000 30,018,000 51.853.000 14.027,000 42,128.000 4,599,000 3,345,000
18 Other Operating Revenues 20.603,000 8,099,885 2,028,573 4.173,542 1,47.568 4,378,837 330.481 144.114
19 Total Revenues 266,982.000 108,508.885 32,046,573 56,026,542 15,474,568 46,506,837 4.929,481 3,489,114
Operating Expenses
20 Producton Expenses 114.095,000 42,285,743 10,764.342 22,971,890 8,662,552 27,301.320 1,714,997 394.158
21 Transmission Expenses 10.627,000 4,599,17 1,028,535 1,970.325 734,221 2.141.256 123,247 30,245
22 Distrbution Expenses 10,241,000 4,863,111 1,322.689 2,483,533 284.251 85,895 333.212 868,308
23 Customer Accunting Expenses 3,722,000 2,856,699 572,227 124.044 45,399 72,03 43,221 8,368
24 Customer Information Expenses 531.000 434,087 84,326 6,259 35 4 5,751 539
25 Sales Expenses 18.000 6,243 1,670 3.683 1,415 4,621 293 75
26 Admin & General Expenses 21,915.000 11.645,885 2,712,434 3,529,446 898,767 2,338.996 408,648 380,823
27 Total O&M Expenses 161,149.000 66,690,939 16,86,223 31,089.181 10,626.640 31,944.135 2.629,368 1,682,514
28 Taxes Other Than Income Taxes 8,715.000 3,694,921 942,886 1,844,164 510,968 1,404,42 175.820 141,778
29 Other Income Related Items 238.000 88,207 22,454 47,919 18,070 56,950 3,577 822
Depreciation Expense
30 Producton Plant Depreciation 10,283.000 3,811.072 970,154 2,070,379 780,727 2,460,577 154.567 35,524
31 Transmission Plant Deprecation 3.770,000 1,631.587 364.880 698,986 260,70 759,625 43,723 10,730
32 Distrbution Plant Depreciation 11,935,000 5,875,355 1,624.697 3,178,847 325.280 51,534 425,51 453,835
33 General Plant Depreciation 6,25,000 3,510,864 804.735 983,422 250,617 647,343 117,146 110,873
34 Amortization Expense 1.054,000 392,932 99,530 211,623 79,77 250,809 15,716 3,619
35 Total Depreciation Expense 33,467,000 15,221,811 3,863,996 7,143,257 1.696,886 4.169,888 758,602 614,581
36 Income Tax 15,927,000 5,119,437 3,050,22 4.235.905 595,595 2,344,306 333,915 247,421
37 Total Operating Expenses 219,496,000 90,815,314 24,365,982 44,360,426 13,48,138 39,919,741 3,899,283 2.687.116
38 Net Income 47,486.000 17.693.571 7.680.592 11,666,116 2,026,29 6.587,096 1,030,198 801,998
39 Rate of Retum 7.57%6.27%10.48%8.65%6.38%8.34%7.21%6.76%
40 Return Ratio 1.00 0.83 1.38 1.14 0.84 1.10 0.95 0.89
41 Interest Expense 18,935,000 8,516,385 2,212.356 4,072.764 958,756 2,384,655 431.617 358,68
Exhibit No. 12
Case No. AVU-E-ll-Ql
T. Knox, Avista
Schedule 3, p. 1 of 4
Sumcost AVISTA UTILITIES Idaho Jurisdiction
Scenario: Company Base Case Revenue to Cost by Functional Component Summary Electric Utilty 06.15.11
AVU.E.ll.Ql Proposed Method For the Twelve Months Ended December 31.2010
Prod by LF PC & Trans By Demand W12 CP
(b)(c) (d) (e)(ij (g)(h)(i)0)(k)(I)(m)
Residential General Large Gen Exta Large Extra Large Pumping Street &
System Service Service Service Gen Servce Servce CP Service Area Lights
Description Total Sch 1 Sch 11.12 Sch 21.22 Sch 25 Sch25P Sch 31.32 Sch 41-49
Functional Cost Components at Current Return by Schedule
1 Production 138,711,985 49,691,178 13,970,021 28,585,83 10,207,062 33,727,506 2,062,011 468,724
2 Transmission 23.000,162 9,046,63 2,688,13 4,594,919 1,456,64 4,892,063 260,108 61,732
3 Distribution 53.896,661 25,57,038 9,191,343 13,746.595 1,190.148 304,966 1.716.155 2.290,416
4 Common 30.770,193 16,214,321 4,168,223 4,926,003 1,173.326 3,203.64 560.726 524,129
5 Total Current Rate Revenue 246,379,000 100.09.000 30,018,000 51,853.000 14,027,000 42,128,000 4,599,000 3.345.000
Expressed as $JkWh
6 Production $0.04130 $0.04324 $0.04546 $0.04207 $0.03841 $0.03792 $0.03823 $0.03391
7 Transmission $0.00685 $0.0078 $0.00875 $0.00676 $0.00548 $0.00550 $0.00482 $0.00447
8 Distribution $0.01605 $0.02215 $0.02991 $0.02023 $0.00448 $0.00034 $0.03182 $0.16571
9 Common $0.00916 $0.01411 $0.01356 $0.00725 $0.00442 $0.00360 $0.01040 $0.03792
10 Total Current Melded Rates $0.07335 $0.08737 $0.09768 $0.07631 $0.05279 $0.04736 $0.08527 $0.24200
Functional Cost Components at Uniform Current Return
11 Producton 138,396,052 51,292,167 13,057,035 27.86,664 10.507,586 33,116.218 2,080,273 478,107
12 Transmission 23,024,572 9,964,614 2,228,36 4.268.927 1,590,772 4,639.267 267,028 65.529
13 Distribution 54.062.933 28,076,744 7,537,586 12,671,480 1.304,906 289.050 1,766,763 2,416,05
14 Common 30,895.43 16,804,253 3,861,110 4.777.380 1.214,690 3,134.828 566,594 536,587
15 Total Uniform Current Cost 246,379,000 106,137,779 26,684,168 49,582,452 14,617,953 41,179.363 4,680,658 3,496,627
Expressed as $/kWh
16 Production $0.04120 $0.04463 $0.04249 $0.04101 $0.03954 $0.03723 $0.03857 $0.03459
17 Transmission $0.00685 $0.0867 $0.0072 $0.00628 $0.00599 $0.00522 $0.00495 $0.00474
18 Distrbution $0.01610 $0.02443 $0.02453 $0.01865 $0.00491 $0.00032 $0.03276 $0.17482
19 Common $0.00920 $0.01462 $0.01256 $0.00703 $0.00457 $0.00352 $0.01050 $0.03882
20 Total Current Uniform Melded Rates $0.07335 $0.09236 $0.08683 $0.07297 $0.05501 $0.04630 $0.08678 $0.25297
21 Revenue to Cost Ratio at Current Rates 1.00 0.95 1.12 1.05 0.96 1.02 0.98 0.96
Functional Cost Components at Proposed Return by Schedule
22 Production 141.940,496 50,716,869 14,270,729 29.186.793 10,467,952 34,722,455 2,099.362 476,336
23 Transmission 24.556,998 9,634,635 2,839,902 4.866.641 1,573,050 5,303,498 274.259 64.812
24 Distribution 57.347,513 27,135,233 9,735,994 14,643,384 1,289,764 330,870 1.819,651 2,392,616
25 Common 31,52,993 16,592,262 4,269,375 5,049,982 1,209.234 3,315,17 572,727 534,235
26 Total Proposed Rate Revenue 255.388,000 104,079,000 31,116,000 53.747,000 14,540,000 43,672,000 4,766,000 3,468,000
Expressed as $JkWh
27 Production $0.04226 $0.04413 $0.04644 $0.04295 $0.03939 $0.03904 $0.03892 $0.03446
28 Transmission $0.00731 $0.00838 $0.00924 $0.00716 $0.00592 $0.00596 $0.00508 $0.00469
29 Distribution $0.01707 $0.02361 $0.03168 $0.02155 $0.00485 $0.00037 $0.03374 $0.17310
30 Common $0.00939 $0.0144 $0.01389 $0.00743 $0.00455 $0.00373 $0.01062 $0.03865
31 Total Proposed Melded Rates $0.07603 $0.09057 $0.10125 $0.07910 $0.05472 $0.04910 $0.08836 $0.25090
Functional Cost Components at Uniform Requested Return
32 Production 141,451.580 52,424,603 13,345,311 28,79,865 10,739,574 33,847,363 2.126.202 488,663
33 Transmission 24,525.072 10.614,003 2,373,662 4,547,131 1,694,441 4,941,606 284,430 69,799
34 Distribution 57,732.025 29.929,606 8.059,717 13,588,986 1,393,486 308,085 1,894,030 2,558,115
35 Common 31,679.323 17.221,528 3.958.080 4,904,223 1,246,620 3,216,920 581,351 550,601
36 Total Uniform Cost 255,388.000 110,189,739 27,736,769 51,520,205 15,074.121 42.313,975 4,886,013 3,667,178
Expressed as $/kWh
37 Production $0.04211 $0.04562 $0.04343 $0.04191 $0.04041 $0.03805 $0.03942 $0.03535
38 Transmission $0.00730 $0.00924 $0.0077 $0.00669 $0.00638 $0.00556 $0.00527 $0.00505
39 Distribution $0.01719 $0.02604 $0.02623 $0.02000 $0.00524 $0.00035 $0.03512 $0.18507
40 Common $0.00943 $0.01499 $0.01288 $0.00722 $0.00469 $0.00382 $0.01078 $0.03983
41 Total Uniform Melded Rates $0.07603 $0.09589 $0.09025 $0.07582 $0.05673 $0.04757 $0.09059 $0.26531
42 Revenue to Cost Ratio at Proposed Rates 1.00 0.94 1.12 1.04 0.96 1.03 0.98 0.95
43 Current Revenue to Proposed Cost Ratio 0.96 0.91 1.08 1.01 0,93 1.00 0,94 0.91
44 Target Revenue Increase 9,009,000 9,781,000 (2,281,000)(333,000)1,047,000 186,000 287,000 322,000Exhibit No. 12
Case No. AVU-E-11-01
T. Knox. Avista
Schedule 3, p. 2 of 4
Sumcost AVISTA UTILITIES Idaho Jurisdiction
Scenario: Company Base Case Revenue to Cost By Classifcation Summary Electric Utility 06-15-11
AVU-E-11-D1 Proposed Method For the Twelve Months Ended December 31. 2010
Prod by LF PC & Trans By Demand W12 CP
(b)(c) (d) (e)(I)(g)(h)(i)ul (k)(I)(m)
Residential General Large Gen Extra Large Extra Large pumping Street &
System Service Servce Service Gen Service Service Potlatch Service Area Lights
Description Total Sch 1 Sch 11-12 Sch 21-22 Sch25 Sch 25P Sch 31-32 Sch 41-9
Cost Classifications at Current Return by Schedule
1 Energy 94,714,876 31,711,603 9,376,66 19,824,937 7.205,637 24.686.946 1,523,248 386,038
2 Demand 127,473,558 52,209,821 15,922,721 31,239.225 6,778.357 17,434,969 2,730,654 1,157,811
3 Customer 24.190,566 16,487,575 4,718,813 788,838 43.005 6.086 345,098 1,801.151
4 Total Current Rate Revenue 246,379.000 100,409,000 30,018,000 51,853,000 14,027,000 42,128,000 4.599,000 3,345,000
Exprssed as Unit Cost
5 Energy $/kWh $0.02820 $0.02760 $0.03051 $0.02918 $0.02712 $0.0276 $0.02824 $0.02793
6 Demand $/kW/mo $17.46 $19.22 $21.74 $17.83 $14.03 $12.84 $12.50 $27.97
7 Customer $/Custlmo $16.46 $13.72 $20.21 $45.53 $447.97 $507.14 $21.67 $1.206.02
Cost Classifications at Uniform Current Return
8 Energy 94,407,41 32,745,695 8,756,967 19,319,309 7,420,355 24,234.357 1,536,899 393,859
9 Demand 127,413.173 55.967,498 13,807,180 29.531,685 7.153.076 16,939,069 2,791.199 1.223,465
10 Customer 24,558.386 17,424,586 4,120,021 731,458 44,521 5,938 352,560 1,879,303
11 Total Uniform Currnt Cost 246,379.000 106.137,779 26,684,168 49,582,452 14,617,953 41.179,363 4,680.658 3,496,627
Expressed as Unit Cost
12 Energy $/kWh $0.02811 $0.02849 $0.02849 $0.02843 $0.02792 $0.02725 $0.02849 $0.02849
13 Demand $/kW/mo $17.45 $20.60 $18.85 $16.86 $14.81 $12.48 $12.78 $29.55
14 Customer $/Custlmo $16.71 $14.50 $17.65 $42.21 $463.76 $494.82 $22.14 $1,260.43
15 Revenue to Cost Ratio at Currnt Rates 1.00 0.95 1.12 1.05 0.96 1.02 0.98 0.96
Cost Classifications at Proposed Return by Schedule
16 Energy 96,960,526 32,374,105 9,580,509 20,246,734 7,392,037 25,423.591 1,551,167 392,383
17 Demand 133.311.347 54,617,047 16,619,467 32,663.565 7,103,641 18,242.082 2,854,475 1,211,069
18 Customer 25,116.127 17,087,848 4,916,024 836,701 44,321 6.326 360,359 1,884,548
19 Total Proposed Rate Revenue 255,388,000 104,079.000 31,116,000 53,747.000 14.540,000 43,672,000 4,766,000 3,468,000
Expressed as Unit Cost
20 Energy $/kWh $0.02887 $0.02817 $0.03117 $0.02980 $0.02782 $0.02858 $0.02876 $0.02839
21 Demand $/kW/mo $18.26 $20.10 $22.69 $18.65 $14.70 $13.44 $13.07 $29.25
22 Customer $/Custlmo $17.08 $14.22 $21.06 $48.29 $461.68 $527.19 $22.63 $1,250.54
Cost Classifications at Uniform Requested Return
23 Energy 96,516,243 33,477,144 8,952,573 19,750,849 7,586,105 24,77.685 1,571,229 402,657
24 Demand 133,304,580 58,625,264 14,475,118 30,988,930 7,42,324 17.532,175 2,943,458 1,297,312
25 Customer 25,567,17 18,087,332 4,309.077 780,426 45.692 6,115 371,326 1,967,209
26 Total Uniform Cost 255.388,000 110,189.739 27,736.769 51,520,205 15.074.121 42,313,975 4,886,013 3,667,178
Expressed as Unit Cost
27 Energy $/kWh $0.02873 $0.02913 $0.02913 $0.02907 $0.02855 $0.02786 $0.02913 $0.02913
28 Demand $/kW/mo $18.26 $21.58 $19.76 $17.69 $15.40 $12.92 $13.47 $31.34
29 Customer $/Custlmo $17.39 $15.05 $18.46 $45.04 $475.95 $509.55 $23.32 $1,319.39
30 Revenue to Cost Ratio at Proposed Rates 1.00 0.94 1.12 1.04 0.96 1.03 0.98 0.95
31 Current Revenue to Proposed Cost Rallo 0.96 0.91 1.08 1.01 0.93 1.00 0.94 0.91
32 Annual Consumption (mWh's)3,358,927 1,149,17 307.317 679,496 265.733 889,47 53.936 13,822
33 Monthly Average NCP Demand (kW)608,472 226,417 61,038 145.985 40.262 113.115 18,205 3,450
34 Monthly Average Number of Customers 122,507 100.148 19,455 1,444 8 1 1,327 124
Exhibit No. 12
Case No. AVU-E-11-01
T. Knox, Avista
Schedule 3. p. 3 of 4
Sumcost AVISTA UTILITIES Idaho Jurisdiction
Scenario: Company Base Case Customer Cost Analysis Electric Utility 06.15.11
AVU.E.11001 Proposed Method For the Twelve Months Ended December 31. 2010
Prod by LF PC & Trans By Demand W12 CP
(b)(c) (d) (e)(Q (g)(h)(i)ul (k)(I)(m)
Residential General Large Gen Extra Large Extra Large Pumping Street &
System Service Service Servce Gen Service ServceCP Servce Area Lights
Description Total Sch 1 Sch 11.12 Sch 21.22 Sch 25 Sch 25P Sch 31.32 Sch4149
Meter, Services, Meter Reading & Biling Costs by Schedule at Requested Rate of Return
Rate Base
1 Servces 44,540.000 36,58,642 7,082,504 515.824 0 0 483,030 0
2 Servces Accum. Depr.(16,606,000)(13.593.000)(2,640.594)(192,317)0 0 (180,090)0
3 Total Services 27,934,000 22.865,642 4,41,910 323,508 0 0 302,940 0
4 Meter 28,803,000 16,321,800 7,990.151 3,391,026 74,135 11,710 1,014,178 0
5 Meter Accum. Depr.(2.142,000)(1.213,807)(594,206)(252,181)(5,513)(871)(75,22)0
6 Total Meters 26,661,000 15,107,993 7,395.945 3.138.645 68.622 10,839 938,757 0
7 Total Rate Base 54,595.000 37.973.635 11.837,855 3,462,353 68,622 10,839 1,241,697 0
8 Return on Rate Base ~ 8.49%4,635,169 3,223,999 1,005,046 293.957 5,826 920 105,421 0
9 Revenue Conversion Factor 0.63778 0.6377 0.63778 0.63778 0.63778 0.63778 0.63778 0.63778
10 Rate Base Revenue Requirement 7,267,639 5,055,017 1,575,845 460,905 9,135 1,443 165,294 0
Expenses
11 Servs Depr Exp 725.000 593,456 115,285 8.396 0 0 7,863 0
12 Meters Depr Exp 686,000 388,736 190,301 80,764 1,766 279 24.155 0
13 Services Operations Ex 415.000 339,702 65,991 4,806 0 0 4,501 0
14 Meters Operating Exp 234,000 132,601 64,913 27,549 602 95 8,239 0
15 Meters Maintenance Exp 26,000 14,733 7,213 3,061 67 11 915 0
16 Meter Reading 454,000 354,576 68,880 5,112 18,430 2,304 4,698 0
17 Biling 2,606,000 2,128,245 413,436 30,685 2,486 311 28,196 2,640
18 Total Expenses 5,146,000 3,952,049 926,020 160,374 23.352 2,999 78.567 2,640
19 Revenue Conversion Factor 0.996296 0.996296 0.996296 0.996296 0.996296 0.996296 0.996296 0.996296
20 Expense Revenue Requirement 5,165,132 3,966,742 929,462 160,970 23,439 3,010 78,859 2,650
21 Total Meter, Service, Meter Reading, and 12,432,770 9,021,759 2,505,307 621,875 32,573 4,453 244,152 2,650
22 Total Customer Bils 1,70,085 1,201,778 233,459 17,327 96 12 15,922 1,491
23 Average Unit Cost per Month $8.46 $7.51 $10.73 $35.89 $339.31 $371.10 $15.33 $1.78
Distribution Fixed Costs per Customer
24 Total Customer Related Cost 25,567,177 18,087,332 4.309.077 780,426 45,692 6,115 371.326 1,967,209
25 Customer Reiated Unit Cost per Month $17.39 $15.05 $18.6 $45.04 $475.95 $509.55 $23.32 $1,319.39
26 Total Distrbutin Demand Related Cost 49,476,832 23,465,005 6,328,510 14,804,775 1,541,039 340,66 1,892,713 1.104.143
27 Dist Demand Related Unit Cost per Month $33.66 $19.53 $27.11 $854.43 $16,052.49 $28,387.19 $118.87 $740.54
28 Total Distribution Unit Cost per Month $51.5 $34.58 $45.57 $899.47 $16,528.45 $28,896.75 $142.20 $2,059.93
Exhibit No. 12
Case No. AVU-E.11.01
T. Knox, Avista
Schedule 3, p. 4 of 4
Avista Utilities
Cost of Service Workshop
February 8, 2011 IPUC Workshop
~''

'STAe
Exhibit No. 12
Case No. AVU-E-11-01 & AVU-G-11-01
T. Knox, Avista
Schedule 4, Page 1 of 15
Workshop Topics
Item # 1- Peak Credit Classification Method
Item # 2 - Allocation of Transmission Costs
2 ,J;;VISTII'
Exhibit No. 12
Case No. AVU-E-11-01 & AVU-G-11-01
T. Knox. Avista
Schedule 4. Page 2 of 15
Item #1- Peak Credit Classification Method
1. Review Previous Peak Credit Methodology
2. Proposed Peak Credit Methodology
3. Why it is preferable from Avista's viewpoint
4. Is the Proposed Peak Credit Methodology stable over time?
3 .J:11i1'Srli'
Exhibit No. 12
Case No. AVU-E-11-01 & AVU-G-11-01
T. Knox. Avista
Schedule 4, Page 3 of 15
Item #1- Peak Credit Classification Method (continued)
Traditionally, both production and transmission costs have been classified into
energy-related and demand-related components by the peak credit ratio method.
In prior cost of service studies, 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 plants (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.
4 ,J~;ilISTA'
Exhibit No. 12
Case No. AVU-E-11-01 & AVU-G-11-01
T. Knox, Avista
Schedule 4, Page 4 of 15
Item #1 - Peak Credit Classification Method (continued)
Proposed Methodology - link the classification methodology to the Integrated
Resource Plan (IRP).
· The IRP process is an exercise to meet customer load growth in a least-cost
fashion. Central to the equation is the level of our customers' coincident
peak demand.
· Use the incremental capacity resource from our latest IRP-a gas-fired CCCT.
· Using IRP models, the Company calculated the costs of capacity and energy
from this resource, and used that figure to allocate overall production costs.
5 .J:::VIST4'
Exhibit No. 12
Case No. AVU-E-11-01 & AVU-G-11-01
T. Knox, Avista
Schedule 4, Page 5 of 15
Item #1 - Peak Credit Classification Method (continued)
For the IRP the Company models the Western Interconnect wholesale power
marketplace using AURORAxmp.
· AURORAxmp dispatches available resources against electricity loads on an
hourly basis.
· The IRP uses AURORAxmp to look at costs out 20 years and "mark-to-market"
(MTM) each potential resource option reasonably available to the Company
in the future.
· The dispatched value of the CCCT (Le., market sales price less fuel and
variable maintenance and operation costs) is tracked hourly over the 20-year
IRP timeframe.
· Additionally, for the IRP the Company models the 20-year future over 250 to
500 Monte Carlo iterations to reflect volatility created by various factors
including natural gas prices, load variabilty and forced outage rates.
6 .J::VISTII'
Exhibit No. 12
Case No. AVU-E-11-01 & AVU-G-11-01
T. Knox, Avista
Schedule 4. Page 6 of 15
Item #1- Peak Credit Classification Method (continued)
For each of the 20 years evaluated for the IRP there are 250 to 500 MTM values
for the CCCT.
· The annual average MTM figures represent the energy value generated by
the plant.
· Remaining costs not recovered in the wholesale marketplace are defined as
capacity.
The ratio of those costs remaining after dispatch into the wholesale marketplace
(MTM values) relative to the entire cost of the CCCT plant equals the share of
production costs then attributable to demand in the cost of service models.
7 ~:lrìl'ST4"
Exhibit No. 12
Case No. AVU-E-11-01 & AVU-G-11-01
T. Knox, Avista
Schedule 4, Page 7 of 15
Item #1 - Peak Credit Classification Method (continued)
Net effect - increases the overall production costs that are classified as demand-
related.
· Using the prior method, (with the Settlement power supply costs)
approximately 27% of total production costs were classified as demand-
related
· 41% of total production costs would be classified as demand-related under
the revised method
8 .J\\:."STA'
Exhibit No. 12
Case No. AVU-E-11-01 & AVU-G-11-01
T. Knox, Avista
Schedule 4, Page 8 of 15
Item #1- Peak Credit Classification Method (continued)
Why is this methodology preferable?
· Tied to the Company's IRP
· Market based modeling represents how the system is actually used vs
historical replacement cost analysis entirely based on vintage investments
· less complicated single ratio applied to all production costs vs multiple ratios
applied 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
9 .J::VIST4'
Exhibit No. 12
Case No. AVU-E-11-01 & AVU-G-11-01
T. Knox, Avista
Schedule 4, Page 9 of 15
Item #1- Peak Credit Classification Method (continued)
Will the new methodology provide a listable" demand/energy classification over
time?
· We believe it will be more consistent over time than the present method.
· 2007 IRP Result - 40.9% Demand
· 2009 IRP Result - 40.6% Demand
· 2011 Draft IRP Result - 46.8% Demand
· Present method overall assignment results vary from 23% to 34% Demand
depending on the cost of fuel and shifting proportionate replacement costs
10 ~:I:iI'STA'
Exhibit No. 12
Case No. AVU.E-11-01 & AVU-G.11-01
T. Knox, Avista
Schedule 4, Page 10 of 15
Item #2 - Allocation of Transmission Costs
Historically, transmission costs were included in the production peak credit
classification
.50/50 weighting of thermal and hydro peak credit ratios applied to all
transmission costs
.Transmission system considered extension of generation facilities
Demand classified portion allocated to customer classes by 12 CP
(average of the 12 monthly system coincident peak hours)
.
11 .J:liVISTA'
Exhibit No. 12
Case No. AVU-E-11-01 & AVU-G-11-01
T. Knox, Avista
Schedule 4. Page 11 of 15
Item #2 - Allocation of Transmission Costs (continued)
In AVU-E-10-01, Avista proposed to change methodologies and classified
transmission costs as 100% demand.
.Consistent with traditional NARUC approach (100% Demand-related)
Proposed 7 CP (four winter, three summer monthly system coincident
peak hours)
.
· Based on the rationale that lower customer demands in the off-peak
fall and spring seasons do not impose the same capacity utilization of
transmission facilities as the higher demand winter and summer
months
· Settlement approved transmission classification - 100% demand, but
used 12 CP allocation and set up this workshop to discuss alternatives
12 "¡:IJiI'STll
Exhibit No. 12
Case No. AVU-E-11-01 & AVU-G-11-01
T. Knox, Avista
Schedule 4, Page 12 of 15
Item #2 - Allocation of Transmission Costs (continued)
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 throughoutthe year
Aligns with FERC Open Access transmission cost methodology.
2. Weighted 12 CP - see Handout
· Weighted by Relative Monthly Planning Peaks
3. 7 CP (average of 4 winter and 3 summer monthly system coincident
peaks)
· Assumes no transmission demand cost in shoulder months
4. Other
13 ~:i"'ST4'
Exhibit No. 12
Case No. AVU-E-11-Q1 & AVU-G-11-Q1
T. Knox, Avista
Schedule 4, Page 13 of 15
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1
5
NATURAL GAS COST OF SERVICE STUDY
2 A cost of service study is an engineering-economic study, which apportions the revenue,
3 expenses, and rate base associated with providing natual gas service 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 determining the appropriate rate spread
6 among the groups of customers.
7 There are three basic steps involved in a cost of service study: functionalization,
8 classification, and allocation. See flow chart.
9 First, the expenses and rate base associated with the natual 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 distribution. Traditionally customer accounting,
12 customer information, and sales expenses are included in the distrbution function and
13 administrative and general expenses and general plant rate base are allocated to all fuctions. 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 fuctions have been placed in this
16 category.
17 Second, the expenses and rate base items are classified into three primary 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
23 factors such as relative cost of metering equipment. In addition to these three cost components,
24 any revenue related expense is allocated based on the proportion of revenues by rate schedule.
Exhibit No. 12
Case No. AVU-G-11-01
T. Knox, Avista
Schedule 5, p, 1 of9
NATURAL GAS COST OF SERVICE STUDY FLOWCHART
Production /
Purchased Gas
Cost
UndergroundStorage
Distribution and
CustomerRelations Common
Energy i
Commodity
Related
Demand I
Capacity Related
Customer
Related
Residential Interruptible
Pro Forma Results of Operations by Customer Group 1
Customer classes shown in this flowchart are ilustrative and may not match the Company's actual rate schedules.
Exhibit No. 12
Case No. AVU-G-ll-01
T. Knox, Avista
Schedule 5, p. 2 of9
The final step is allocation of the costs to the various 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 - Purchased Gas Costs
6 The Company has no natual gas production facilties to serve its retail customers. The
7 natual gas costs included in the production fuction include the cost of gas purchased to serve
8 sales customers, pipeline transporttion to get it to our system, and expenses of the gas supply
9 deparent.
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 November 1,2010. The November 1, 2010 gas cost reduction
13 to customer charges was accomplished though Schedule 155 which is excluded from base
14 revenues. The allocation of these costs agrees with the gas costs computation used to determine
15 pro forma results of operations.
16 The expenses of the gas supply departent recorded in account 813 are classified as
17 commodity related costs. The gas scheduling process includes transporttion customers, so
18 estimated scheduling dispatch labor expenses are allocated by throughput. The remaining 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 Utilties Commission in Case No.
24 AVU-G-04-0L.
Exhibit No. 12
Case No. A VU-G-11-01
T. Knox, A vista
Schedule 5, p. 3 of9
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 distribution
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 anual throughput by 365 (days in
6 the year). The average daily 10ad is divided by peak load to arive at the system 10ad factor of
7 33.01 %. This proporton is classified as commodity related. The remaining 66.99% is classified
8 as demand related. Meters, services and industrial measuring & regulating equipment are
9 classified as customer related distrbution plant. Distribution operating and maintenance expenses
10 are 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 distrbution 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 any Demand Side Management
16 amortization expense recorded in Account 908. Any demand side management investment costs
17 and amortization expense included in base rates would be included with the distrbution function
18 and classified to demand and commodity by the peak and average ratio. At this point in time, the
19 Company's demand side management investments in base rates have been fully amortzed. All
20 current demand side management costs are managed through the Schedule 191 Public Purpose
21 Tariff Rider balancing account which is not included in this cost study.
22 Distribution Cost Allocation
23 Demand related distribution costs are allocated to customer groups (rate schedules) by each
24 groups' contribution to the thee year average five-day sustained peak. Commodity related
Exhibit No. 12
Case No. A VU-G-11-01
T. Knox, Avista
Schedule 5, p. 4 of9
distribution costs are allocated to customer groups by annual throughput. Distribution main
2 investment has been segregated into large and small mains. Small mains are defined as less than
3 four inches, with large mains being four inches or greater. The small main costs use the same
4 demand and commodity data, but large usage customers (Schedules 131, and 146) that connect to
5 large system mains have been excluded from the allocations.
6 Most customer related costs are allocated by the anualized number of customers biled
7 during the test period. Meter investment costs are allocated using the number of customers
8 weighted by the relative curent cost of meters in service at December 31, 201 O. Services
9 investment costs are allocated using the number of customers weighted by the relative current cost
10 of tyical service installations. Industral measuring and regulating equipment investment costs
11 are allocated by number of tubine meters which effectively excludes small usage customers.
12 Administrative and General Costs
13 General and intangible rate base items are allocated by the sum of Underground Storage
14 and Distrbution plant. Administrative and general expenses are segregated into plant related,
15 labor related, revenue related and other. The plant related items are allocated based on total plant
16 in service. Labor related items are allocated by operating and maintenance labor expense.
17 Revenue related items are allocated by pro forma revenue. Other administrative and general
18 expenses are allocated 50% by anual throughput (classified commodity related) and 50% by the
19 sum of operating and maintenance expenses not including purchased gas cost or administrative &
20 general expenses. Whenever costs are allocated by sums of other items within the study,
21 classifications are imputed from the relationship embedded in the summed items.
22 Special Contract Customer Revenue
23 Three special contract customers receive transportation service from the Company. Rates
24 for these customers were individually negotiated to cover any incremental costs and retain some
Exhibit No, 12
Case No. AVU-G-1l-01
T. Knox, Avista
Schedule 5, p. 50f9
contribution to margin. The rates for these customers are not being adjusted in this case. The
2 revenue from these special contract customers has been segregated from general rate revenue and
3 allocated back to all the other rate classes by relative rate base. In treating these revenues like
4 other operating revenues their system contrbution reduces costs for all rate schedules.
5 Revenue Conversion Items
6 In this study uncollectible accounts and commission fees have been classified as revenue
7 related and are allocated by pro forma revenue. These items vary with revenue and are included in
8 the calculation of the revenue conversion factor. Income tax expense items are allocated to
9 schedules by net income before income tax less interest expense.
10 For the fuctional summaries on pages 2 and 3 of the cost of service study, these items are
11 assigned to the component cost categories. The revenue related expense items have been reduced
12 to a percent of all other costs and loaded onto each cost category b that ratio. Similarly, income
13 tax items have been assigned to cost categories by relative rate base (as is net income).
14 The following matrix outlines the methodology applied in the Company Base Case natual
15 gas cost of service study.
Exhibit No. 12
Case No. AVU-G-ll-01
T. Knox, Avista
Schedule 5, p. 6of9
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Sumcost AVISTA UTILITIES Natural Gas Utility
Company Base Case Cost of Service General Summary Idaho Jurisdiction 05-Jul.ll
AVU-G-Q4-01 Method For the Year Ended December 31, 2010
(b)(c)(d)(e)(f)(g)(h)0)(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 10,735.000 8,136,564 2,280,62 44.332 273,642
3 Distribution Plant 152.795,000 128.629.327 22,636.021 361,680 1,167,972
4 Intangible Plant 2.596.000 2.172.123 394,779 6.424 22.673
5 General Plant 17,443.000 14.588.194 2,657,728 43,307 153,770
6 Total Plant In Service 183,569,000 153.526,208 27.968,990 455.743 1.618.059
Accum Depreciation
7 Production Plant
8 Underground Storage Plant (3,819,000)(2,894,601)(811.279)(15,771)(97,349)
9 Distribution Plant (54.974.000)(47.046.745)(7,418,277)(117,553)(391,424)
10 Intangible Plant (1.264.000)(1,057.309)(192,452)(3,134)(11,104)
11 General Plant (5.654.000)(4,728.639)(861,480)(14,038)(49,843)
12 Total Accumulated Depreciation (65,711.000)(55.727,294)(9,283,488)(150,497)(549,721)
13 Net Plant 117,858.000 97,798,914 18.685,502 305.247 1.068.338
14 Accumlulated Deferred FIT (23.672.000)(19,797,855)(3,606.720)(58,770)(208,656)
15 Miscellaneous Rate Base 9.216.000 7.089.075 1,880,208 35,807 210.910
16 Total Rate Base 103,402,000 85.090.134 16,958,990 282,283 1,070,592
17 Revenue From Retail Rates 70,514,000 54,493.548 15,13,796 274,603 332,053
18 Other Operating Revenues 130.000 107.243 21,099 350 1,308
19 Total Revenues 70,644.000 54,600,791 15,434,896 274.953 333.361
Operating Expenses
20 Purchased Gas Costs 41,884,000 30.760.161 10,917,996 202.857 2,986
21 Underground Storage Expenses 318.000 241,027 67,554 1,313 8,106
22 Distribution Expenses 4,305,000 3.660,598 589,569 7,677 47,156
23 Customer Accounting Expenses 2,008,000 1,953,072 53,717 493 718
24 Customer Information Expenses 373,000 343.522 26,166 415 2,897
25 Sales Expenses 7,000 6.897 102 0 1
26 Admin & General Expenses 5,034,000 4,015,966 893.990 17,569 106,475
27 Total O&M Expenses 53,929,000 40,981.245 12,549,093 230,324 168,338
28 Taxes Other Than Income Taxes 978,000 816,055 150,456 2,468 9.022
29 Depreciation Expense
30 Underground Storage Plant Depr 182,000 137,946 38.663 752 4.639
31 Distribution Plant Depreciation 3.567.000 3.076.759 458,312 6.544 25,386
32 General Plant Depreciation 1,285,000 1.074.691 195,791 3.190 11.328
33 Amortization of Intangible Plant 425,000 355,64 64.739 1.055 3,742
34 Total Depr & Amort Expense 5,459,000 4.644.860 757,504 11.540 45,095
35 Income Tax 2.724,000 2.127,688 557.987 8,412 29,913
36 Total Operating Expenses 63,090,000 48,569.848 14,015,040 252.744 252,368
37 Net Income 7,554,000 6,030,943 1,419.855 22,209 80,993
38 Rate of Return 7.31%7.09%8.37%7.87%7.57%
39 Return Ratio 1.00 0.97 1.15 1.08 1.04
40 Interest Expense 3,123.000 2,569,936 512,204 8.526 32.335
Exhibit No. 12
Case No. AVU.G-11-o1
T. Knox, Avista
Schedule 6, p. 1 of 4
Sumcost
Company Base Case
AVU-G.04.01 Method
AVISTA UTILITIES
Summary by Function with Margin Analysis
For the Year Ended December 31, 2010
(b)(c) (d) (e)
Line Description
Functional Cost Components at Current Rates
1 Production
2 Underground Storage
3 Distribution
4 Common
5 Total Current Rate Revenue
6 Exclude Cost of Gas w I Revenue Exp.
7 Total Margin Revenue at Current Rates
Margin per Therm at Current Rates
8 Production
9 Underground Storage
10 Distribution
11 Common
12 Total Current Margin Melded Rate per Therm
(I)
System
Total
42,042,597
1,908,309
18,697,876
7,865,217
70,514,000
41,642,086
28,871,914
$0.00521
$0.02483
$0.24329
$0.10234
$0,37566
Functional Cost Components at Uniform Currnt Return13 Production 42,042,59714 Underground Storage 1,893,14215 Distribution 18,709,97116 Common 7,868,29017 Total Uniform Current Cost 70,514,000
18 Exclude Cost of Gas w I Revenue Exp. 41,642,08619 Total Uniform Current Margin 28,871,914
Margin per Therm at Uniform Current Return
20 Production
21 Underground Storage
22 Distribution
23 Common
24 Total Current Uniform Margin Melded Rate per
25 Margin to Cost Ratio at Current Rates
$0.00521
$0.02463
$0.24344
$0.10238
$0.37566
(g)
Residential
Servic
Sch 101
30,876,637
1,399,405
15,857,806
6,359,699
54,493,548
30,584,995
23,908,553
$0.00538
$0.02583
$0.29269
$0.11738
$0.44129
30,876,637
1,434.902
16,087,390
6,394,950
54,793,879
30,584,995
24,208,884
$0.00538
$0.02648
$0.29693
$0.11803
$0.44683
1.00
Natural Gas Utility
Idaho Jurisdiction
(h)
Large Firm
Service
Sch 111
10,959,337
450,905
2,655,467
1,348,087
15,413,796
10,855,822
4,557,974
$0.00538
$0.02345
$0.13809
$0.07010
$0.23702
10,959,337
402,165
2,442,420
1,316,622
15,120,545
10,855,822
4,264,723
$0.00538
$0.02091
$0.12701
$0.06847
$0.22177
0.99
ül
Interrupt
Service
Sch 131
203,625
8,317
37,972
24,689
274,603
201,269
73,334
$0.00538
$0.01901
$0.08677
$0.05641
$0.16757
203,625
7,818
36,170
24,418
272,031
201,269
70,762
$0.00538
$0.01786
$0.08265
$0.05580
$0.16169
1.07
05.Jul.11
(k)
Transport
Service
Sch 146
2,997
49,682
146,631
132,743
332,053
o
332,053
$0.00100
$0.01651
$0.04874
$0.04412
$0.11038
2,997
48,257
143,991
132,300
327,545
o
327,545
$0.00100
$0.01604
$0.04786
$0.04398
$0.10888
1.04 1,01
Functional Cost Components at Proposed Rates
26 Production
27 Underground Storage
28 Distribution
29 Common
30 Total Proposed Rate Revenue
31 Exclude Cost of Gas w I Revenue Exp.
32 Total Margin Revenue at Proposed Rates
Margin per Therm at Proposed Rates
33 Production
34 Underground Storage
35 Distribution
36 Common
37 Total Proposed Margin Melded Rate per Therm
42,042,454
2,139,672
20,162,728
8,090,147
72,435,000
41,641,944
30,793,056
$0.00521
$0.02784
$0.26235
$0.10526
$0.0066
Functional Cost Components at Uniform Proposed Return38 Production 42,042,454
39 Underground Storage 2,139,67240 Distribution 20,162,72841 Common 8,090,14742 Total Uniform Proposed Cost 72,435,00043 Exclude Cost of Gas w I Revenue Exp. 41,641,94444 Total Uniform Proposed Margin 30,793,056
Margin per Therm at Uniform Proposed Return
45 Production
46 Underground Storage
47 Distribution
48 Common
49 Total Proposed Uniform Margin Melded Rate pi
50 Margin to Cost Ratio at Proposed Rates
51 Current Margin to Proposed Cost Ratio
$0.00521
$0.02784
$0.26235
$0.10526
$0.40066
30,876,532
1,621,758
17,295,903
6,580,494
56,374,687
30,584,890
25,789,796
$0.00538
$0.02993
$0.31924
$0.12146
$0.47601
30,876,532
1,621,758
17.295,908
6,580,495
56,374,693
30,584,890
25,789,802
$0.00538
$0.02993
$0.31924
$0.12146
$0.47601
1.00
0.94
10,959,300
454,537
2,671,339
1,350,428
15,435,604
10,855.785
4,579,819
$0.00538
$0.02364
$0.13891
$0.07022
$0.23816
10,959,300
454,536
2,671,334
1,350,427
15,435,597
10,855,785
4,579,812
$0.00538
$0.02364
$0.13891
$0.07022
$0.23816
1.00
0.93
203,624
8,836
39,845
24,969
277,274
201,269
76,006
$0.00538
$0.02019
$0.09105
$0.05706
$0.17368
203,624
8,836
39,845
24,969
277,275
201,269
76,006
$0.00538
$0.02019
$0.09105
$0.05706
$0.17368
1.00
1.00
2,997
54,541
155.640
134,255
347,435
o
347,435
$0.00100
$0.01813
$0.05174
$0.04463
$0.11549
2,997
54,542
155,641
134,256
347,436
o
347,436
$0.00100
$0.01813
$0.05174
$0.04463
$0.11549
1.00 1,00
0.96 0.96
Exhibit No. 12
Case No. AVU.G.11.01
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 05-Jul-11
AVU-G-04-01 Method For the Year Ended December 31, 2010
(b)(c)(d)(e)(I)(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 42,449,821 30,973,589 11,025,802 247,875 202,556
2 Demand 14,994,089 11,246,356 3,651,587 25,425 70,721
3 Customer 13,070,090 12,273,603 736,08 1,304 58,775
4 Total Current Rate Revenue 70,514,000 54,493,548 15,413,796 274,603 332,03
Revenue per Therm at Current Rates
5 Commodity $0.55233 $0.57169 $0.57335 $0.56640 $0.06733
6 Demand $0.19509 $0.20758 $0.18989 $0.05810 $0.02351
7 Customer $0.17006 $0.22654 $0.03829 $0.00298 $0.01954
8 Total Revenue per Therm at Current Rates $0.91749 $1.00580 $0.80154 $0.62748 $0.11038
Cost per Unit at Current Rates
9 Commodity Cost per Therm $0.55233 $0.57169 $0.57335 $0.56640 $0.06733
10 Demand Cost per Peak Day Therms $23.50 $22.94 $27.93 $12.18 $4.78
11 Customer Cost per Customer per Month $14.68 $13.99 $56.80 $108.69 $816.32
Cost by Classification at Uniform Current Return
12 Commodity 42,398,967 31,055,515 10,897,094 246,421 199,937
13 Demand 14,961,942 11,343,446 3,524,781 24,349 69,367
14 Customer 13,153,090 12,394,918 698,671 1,261 58,241
15 Total Uniform Current Cost 70,514,000 54,793,879 15,120,545 272,031 327,545
Cost per Therm at Current Return
16 Commodity $0.55167 $0.57320 $0.56666 $0.56308 $0.06646
17 Demand $0.19468 $0.20937 $0.18329 $0.05564 $0.02306
18 Customer $0.1714 $0.22878 $0.03633 $0.00288 $0.01936
19 Total Cost per Therm at Current Return $0.91749 $1.01135 $0.78629 $0.62160 $0.10888
Cost per Unit at Uniform Current Return
20 Commodity Cost per Therm $0.55167 $0.57320 $0.56666 $0.56308 $0.06646
21 Damand Cost per Peak Day Therms $23.45 $23.13 $26.96 $11.66 $4.69
22 Customer Cost per Customer per Month $14.77 $14.13 $53.89 $105.06 $808.90
23 Revenue to Cost Ratio at Current Rates 1.00 0.99 1.2 1.01 1.1
Cost by Classification at Proposed Return by Schedule
24 Commodity 42,982,919 31,486,684 11,035,359 249,383 211,494
25 Demand 15,617,416 11,854,504 3,661,027 26,542 75,343
26 Customer 13,834,665 13,033,99 739,218 1,349 60,598
27 Total Proposed Rate Revenue 72,435,000 56,374,687 15,435,604 277,274 347,435
Revenue per Therm at Proposed Rates
28 Commodity $0.55927 $0.58116 $0.57385 $0.56985 $0.07030
29 Demand $0.20320 $0.21880 $0.19038 $0.06065 $0.02504
30 Customer $0.18001 $0.24056 $0.03844 $0.00308 $0.02014
31 Total Revenue per Therm at Proposed Rates $0.94248 $1.04052 $0.80267 $0.63358 $0.11549
Cost per Unit at Proposed Rates
32 Commodity Cost per Therm $0.55927 $0.58116 $0.57385 $0.56985 $0.07030
33 Demand Cost per Peak Day Therms $24.48 $24.18 $28.01 $12.71 $5.09
34 Customer Cost per Customer per Month $15.54 $14.85 $57.02 $112.45 $841.64
Cost by Classification at Uniform Proposed Return
35 Commodity 42,982,919 31,486,685 11,035,355 249,384 211,494
36 Demand 15,617,415 11,854,506 3,661,024 26,542 75,343
37 Customer 13,834,666 13,033,501 739,217 1,349 60,599
38 Total Uniform Proposed Cost 72,435,000 56,374,693 15,35,597 277,275 347,436
Cost per Therm at Proposed Return
39 Commodity $0.55927 $0.58116 $0.57385 $0.56985 $0.07030
40 Demand $0.20320 $0.21880 $0.19038 $0.06065 $0.02504
41 Customer $0.18001 $0.24056 $0.03844 $0.00308 $0.02014
42 Total Cost per Therm at Proposed Return $0.94248 $1.04052 $0.80267 $0.63359 $0.11549
Cost per Unit at Uniform Proposed Return
43 Commodity Cost per Therm $0.55927 $0.58116 $0.57385 $0.56985 $0.07030
44 Demand Cost per Peak Day Therms $24.48 $24.18 $28.01 $12.71 $5.09
45 Customer Cost per Customer per Month $15.54 $14.85 $57.02 $112.45 $841.65
46 Revenue to Cost Ratio at Proposed Rates 1.00 1.00 1.00 1.00 1.00
47 Current Revenue to Proposed Cost Ratio 0.97 0.97 1.00 0.99 0.96
Exhibit No. 12
Case No. AVU-G-11-01
T. Knox, Aviste
Schedule 6, p. 3 of 4
Sumcost AVISTA UTILITIES Natural Gas Utility
Company Base Case Customer Cost Analysis Idaho Jurisdicion 05-Jul-11
AVU-G-04-01 Method For the Year Ended December 31, 2010
(b)(c)(d)(e)(I)(g)(h)Ol (k)
Residential Large Firm Interrupt Transport
System Service Service Service Service
Line Description Total Sch 101 Sch 111 Sch 131 Sch 146
Meter, Services, Meter Reading & BIllng Costs by Schedule at Requested Rate of Return
Rate Base
1 Services 47,354,000 46,636,256 689,043 1,913 26,788
2 Services Accum. Depr.(22.086,000)(21,751,243)(321,371)(892)(12,494)
3 Total Services 25,268,000 24,885,013 367,672 1,021 14,294
4 Meters 19,748,000 17,209,262 2,430,764 5,496 102,479
5 Meters Accum. Depr.(4,844,000)(4,221,271 )(596,244)(1,348)(25,137)
6 Total Meters 14,904,000 12,987,991 1,834,520 4,148 77,342
7 Total Rate Base 40,172,000 37,873,004 2.202,192 5,169 91.636
8 Return on Rate Base 118.55%3,410,603 3,215,418 186,966 439 7,780
9 Revenue Conversion Factor 0.63778 0.63778 0.63778 0.63778 0.63778
10 Rate Base Revenue Requirement 5,347,616 5,041,579 293,151 688 12,198
Expenses
11 Services Depr Exp 1,359,000 1,338,402 19,775 55 769
12 Meters Depr Exp 673,000 586,481 82,839 187 3,492
13 Services Maintenance Exp 345,000 339,771 5,020 14 195
14 Meters Maintenance Exp 301,000 262,304 37,050 84 1,562
15 Meter Reading 228,000 224,659 3,319 3 18
16 Biling 1,505,000 1,482,948 21,910 20 122
17 Total Expenses 4,411,000 4,234,565 169,913 363 6,158
18 Revenue Conversion Factor 0.996296 0.996296 0.996296 0.996296 0.996296
19 Expense Revenue Requirement 4,427,399 4,250,308 170,545 365 6,181
20 Total Meter, Service, Meter Reading, and 9,775,016 9,291,887 463,696 1,053 18,380
21 Total Customer Bils 890,86 877,438 12.964 12 72
22 Average Unit Cost per Month $10.98 $10.59 $35.77 $87.72 $255.27
Fixed Costs per Customer
23 Total Customer Related Cost 13,834,666 13,033,501 739.217 1,349 60,599
24 Customer Related Unit Cost per Month $15.54 $14.85 $57.02 $112.45 $841.65
25 Other Non-Gas Costs 16.958,390 12,756,301 3,840,594 74,657 286,837
26 Other Non-Gas Unit Cost per Month $19.04 $14.54 $296.25 $6,221.41 $3,983.85
27 Total Fixed Unit Cost per Month $34.58 $29,39 $353.27 $6,333.86 $4,825.50
Exhibit No. 12
Case No. AVU-G-11-01
T. Knox, Avista
Schedule 6, p. 4 of 4