20080403Knox Direct.pdf

DAVID J. MEYER
VICE PRESIDENT, GENERA COUNSEL,
GOVERNENTAL AFFAIRS
AVISTA CORPORATION
P.O. BOX 3727
1411 EAST MISSION AVENUE
SPOKAE, WASHINGTON 99220-3727
TELEPHONE: ( 509 ) 495 - 4 316
FACSIMILE: [phone]
Fu::r¡:I\/l'D""-V£.. 'Ie
REGULATO~I) ïnn
lUiJü ¡'' I"~ -3 P.!l fi \ lï I: IfJ
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF AVISTA CORPORATION FOR THE
AUTHORITY TO INCREASE ITS RATES
AN CHARGES FOR ELECTRIC AND
NATURAL GAS SERVICE TO ELECTRIC
AN NATURA GAS CUSTOMERS IN THE
STATE OF IDAHO
CASE NO. AVU-E-08-01
CASE NO. AVU-G-08-01
DIRECT TESTIMONY
OF
TAR L. KNOX
FOR AVISTA CORPORATION
(ELECTRIC AND NATURA GAS)
1
2
I. INTRODUCTION
Q.Please state your name, business address and
3 present position with Avista Corporation?
4 A.My name is Tara L. Knox and my business address
5 is 1411 East Mission Avenue, Spokane, Washington.I am
6 employed as a Senior Rate Analyst in the State and Federal
7 Regulation Department.
8
9
Q.Would you briefly describe your duties?
A.I am responsible for preparing the regulatory
10 cost of service models for the Company, as well as
11 providing support for the preparation of results of
12 operations reports.
13 Q.Would you describe your educational background
14 and professional exerience?
15 A.Yes.I am a 1982 graduate of Washington State
16 University with a Bachelor of Arts degree in General
17 Humanities, and a Master of Accounting degree in 1990. As
18 an employee in the Rate Department at Avista since 1991, i
19 have attended several ratemaking classes, including the EEI
20 Electric Rates Advanced Course that specializes in cost
21 allocation and cost of service issues. I have also been a
22 member of the Cost of Service Working Group since 1999,
23 which is a discussion group made up of technical
24 professionals from utilities throughout the United States
25 and Canada concerned with cost of service issues.
Knox, Di 1
Avista Corporation
1 Q.What is the scope of your testimony in these
2 proceedings?
3 A.My testimony and exhibits will cover the
4 Company's electric and natural gas cost of service studies
5
6
performed for this proceeding.Addi tionally,I am
sponsoring the electric and natural gas revenue
7 normalization adjustments and the production property
8 adjustment to the test year results of operations.
9 Table of Contents
10
11
12
13
14
15
16
Revenue Normalization
Electric Revenue Normalization
Natural Gas Revenue Normalization
Production Property Adjustment
Electric Cost of Service
Natural Gas Cost of Service
Page 3
Page 3
Page 8
Page 11
Page 15
Page 22
Q.Are you sponsoring any Exibits with your pre-
17 filed testimony?
18 A.Yes.I am sponsoring Exhibi t No. 14 composed of
19 five schedules as follows: Schedule 1, production property
20 adjustment calculation; Schedule 2, electric cost of
21 service study process description; Schedule 3, electric
22 cost of service study sumary results; Schedule 4, natural
23 gas cost of service study process description; and Schedule
24 5, natural gas cost of service sumary results.
25 Q.Were these exhibits prepared by you or under your
26 direction?
27 A.Yes.
Knox, Di 2
Avista Corporation
1
2
3
II. RE NORMLIZATION
Electric Revenue Normlization
Q.Would you please describe the electric revenue
4 adjustment included in Company witness Ms. Andrews pro
5 for.a results of operations?
6 A.Yes.The electric revenue normalization
7 adjustment represents the difference between the Company's
8 actual recorded retail revenues during the 2007 test period
9 and retail revenues on a normalized (pro forma) basis. The
10 total revenue normalization adjustment decreases Idaho net
11 operating income by $632,000 as shown in colum (u) on page
6 of Ms. Andrews Exhibit No. 13, Schedule 1.The revenue12
13 normalization adjustment consists of three primary
14 components: 1) re-pricing customer usage (adjusted for any
15 known and measurable changes) at present base tariff rates
16 in effect,2) adjusting customer loads and revenue to a
17 calendar-year basis (unbilled revenue adj ustment), and 3)
18 weather normalizing customer usage and revenue.
19 Q.Would you please briefly discuss electric weather
20 normlization?
21 A.Yes.The Company's weather normalization
22 adjustment calculates the change in kWh usage required to
23 adjust actual loads during the 2007 test period to the
24 amount expected if weather had been normal.This
25 adjustment incorporates the effect of both heating and
Knox, Di 3
Avista Corporation
1 cooling on weather-sensitive customer groups.The weather
2 adjustment is developed from regression analysis of five or
3 ten years (as explained later) of billed usage per customer
4 and billing period heating and cooling degree-day data.
5 The resulting seasonal weather sensitivity factors are
6 applied to monthly test period customers and the difference
7 between normal heating/cooling degree-days and monthly test
8 period observed heating/cooling degree-days.
9 In addition to its use as a component of the revenue
10 normalization adjustment,Company witness Mr.Kalich
11 includes the combined Washington and Idaho adjustment with
12 2007 loads to reflect the normal load shape for 2009 pro
13 forma loads in the modeling for the Pro Forma Power Supply
14 costs.
15 Q.How are nor.al heating and cooling degree days
16 defined?
17 A.Normal heating and cooling degree days are based
18 on a rolling 25-year average of heating and cooling degree-
19 days reported for each month by the National Weather
20 Service for the Spokane Airport weather station.For
21 heating, the 25 years are included on a heating season
22 basis, July through June, so (for example) the October
23 average reflects all the Octobers beginning in 1982 and
24 through 2006 whereas the May average reflects all of the
25 Mays beginning in 1983 and through 2007. For cooling, the
Knox, Di 4
Avista Corporation
1 25 years reflect the cooling season calendar years
2 beginning in 1983 and through 2007.Each year the normal
3 values will be adjusted to capture the next heating and
4 cooling season with the oldest data dropping off, thereby
5 encapsulating the most recent information available at the
6 end of each calendar year.
7 Q.What revisions have you made to the weather
8 adjustment methodology since the company's last general
9 rate case in idaho?
10 A. In prior cases, annual average sensitivity factors
11 were derived and applied uniformly to all heating and
12 cooling degree days throughout the year.In this new
13 process the definition of the independent variables has
14 been adjusted to produce seasonal sensitivity factors.
15 Seasonal sensitivity factors change depending on the time
16 of year, therefore it is important to determine when the
17 deviations from heating and cooling degree days occurred,
18 which is why we now use a monthly calculation to determine
19 the adjustment volumes.This modification addressed
20 concerns that applying the annual factors on a monthly
21 basis produced some counter-intuitive results during
22 shoulder and sumer months,as well as concerns
23 (particularly for natural gas) that the baseload value
24 should approximate observed sumer usage.
KnOx, Di 5
Avista Corporation
1 Also, we re-examined the question of whether five
2 years of data included enough data points. Based on trend
3 variables testing for systematic changes over time, we were
4 comfortable with the use of ten year data sets for electric
5 residential customers and all weather-sensitive natural gas
6 customer groups in Idaho (as well as all electric and
7 natural gas weather-sensi ti ve customer groups in
8 Washington) .However, in response to visual inspection of
9 graphed residuals (error values) over time, a marked change
10 appeared to occur in Idaho electric general service
11 customer groups about halfway through the ten year period.
12 Consequently, the Idaho residential customer group utilizes
13 a ten year regression analysis whereas the weather-
14 sensitive general service customer groups utilize a five
15 year regression analysis.
16 Finally, in the methodology utilized in prior cases,
17 two statistical tests were used to determine whether a
18 regression result was acceptable.Namely, the t-statistic
19 for all independent variables must be greater than the
20 absolute value of two, and the adjusted R-square statistic
21 must be greater than sixty percent.For the new method we
22 have added a third test to satisfy concerns that auto-
23 correlation of error terms may have been present in the
24 data.Now in addition to the first two tests, the
Knox, Di 6
Avista Corporation
1 regression result must also pass the Durbin-Watson test for
2 auto-correlation at five percent significance.
3 Q. How has the definition of norml heating and
4 cooling degree days changed?
5 A. In prior cases the Company has used NOAA (National
6 Oceanographic and Atmospheric Administration) published
7 Monthly Station Normals for the Spokane airport weather
8 station which represents a 30-year average.As mentioned
9 above, in this case the Company is proposing a 25-year
10 average instead.
11 Q.Why are you proposing to change from a 30-year to
12 a 25-year average for norml degree days?
13 A.The NOAA normal publication utilizes the same
14 National Weather Service data to develop their 30-year
15 average or "normal", but it is only updated every ten
16 years, so those statistics now reflect 1971 to 2000 data,
17 which does not include the most current weather.During
18 the years since the last NOAA publication, the Inland
19 Northwest has experienced consistently warmer weather.
20 Therefore, use of the outdated 30-year average may tend to
21 overstate expected heating requirements and understate
22 expected cooling requirements. Moving to a shorter average
23 period, and maintaining the rolling average to keep current
24 with the weather that has been experienced in Avista' s
Knox, Di 7
Avista Corporation
1 service territory, helps to overcome the limitations of the
2 published "normal" data.
3 Q.What was the impact of electric weather
4 normlization on the 2007 test year?
5 A.Weather was warmer than normal during the 2007
6 test year, especially during the month of July, resulting
7 in a net reduction to usage.The adjustment to normal
8 required the addition of 77 heating degree-days and the
9 deduction of 139 cooling degree-days.The net adjustment
10 to Idaho sales volumes was a reduction of 14,411,360 kWhs
11 which is slightly less than one-half of one percent of
12 billed usage.
13 Natural Gas Revenue Nor.alization
14 Q.Would you please describe the natural gas revenue
15 adjustment included in Ms. Andrews pro form results of
16 operations?
17 A.Yes.The natural gas revenue normalization
18 adjustment is similar to the electric adjustment and
19 represents the difference between the Company's actual
20 recorded retail revenues during the 2007 test period and
21 retail revenues on a normalized (pro forma) basis.The
22 adjustment includes the re-pricing of pro forma sales and
23 transportation voiumes at present rates using pro forma
24 sales volumes that have been adjusted for unbilled sales,
25 abnormal weather, and any material customer load or
Knox, Di 8
Avista Corporation
1 schedule changes.The rates used exclude:1) Temporary
2 Gas Rate Adjustment Schedule 155, which reflects the
3 approved amortization rate for deferred gas costs approved
4 in the Company's last PGA filing and 2) Public Purposes
5 Rider Adjustment Schedule 191.
6 Q.Does the Revenue Normlization Adjustment contain
7 a component reflecting normlized gas costs?
8 A.Yes. Purchase gas costs are normalized using the
9 gas costs approved by the Commission in Case No. AVU-G-07-
10 02, the Company's 2007 PGA filing, as set forth under
11 Schedule 150. Those gas costs are then applied to the pro
12 forma retail sales volumes so that there is a matching of
13 revenues and gas costs.
14
15
The total net amount of the natural gas revenue
normalization,which includes the purchase gas cost
16 adjustment, is a decrease to net operating income of
17 $42,000, as shown in colum (i), page 5 of Ms. Andrews
18 Exhibit No.13, Schedule 2.
19 Q.Would you please briefly discuss natural gas
20 weather normlization?
21 A.,Yes.The natural gas weather adjustment is
22 developed from a regression analysis of ten years of billed
23 usage per customer and billing period heating degree-day
24 data.The resulting seasonal weather sensitivity factors
25 are applied to monthly test period customers and the
Knox, Di 9
Avista Corporation
1 difference between normal heating degree-days and monthly
2 test period observed heating degree-days. This calculation
3 produces the change in therm usage required to adj us t
4 existing loads to the amount expected if weather had been
5 normal.
6 Q.How are nor.al heating and cooling degree days
7 defined?
8 A.Normal heating degree-days are based on a rolling
9 25-year average of heating degree-days reported for each
10 month by the National Weather Service for the Spokane
11 Airport weather station.The 25 years are included on a
12 heating season basis, July through June, so (for example)
13 the October average reflects all the Octobers beginning in
14 1982 and through 2006 whereas the May average reflects all
15 of the Mays beginning in 1983 and through 2007. Each year
16 the normal values will be adjusted to capture the next
17 heating season with the oldest data dropping off, thereby
18 encapsulating the most recent information available at the
19 end of each calendar year.
20 Q.Does this proposed weather adjustment methodology
21 reflect the same revisions that were discussed regarding
22 electric service?
23 A. Yes, both the revisions to the process for
24 determining the weather sensitivity factors and the change
25 to the definition of "normal" are reflected in the
Knox, Di 10
Avista Corporation
1 Company's weather normalization adjustment to natural gas
2 usage.
3 Q.What was the impact of natural gas weather
4 normlization on the 2007 test year?
5
6
A.Weather was warmer than normal during the 2007
test year.A colder than normal January was offset by
7 warmer than normal February, March, and December resulting
8 in a relatively small annual weather adjustment.The
9 adjustment to normal required the addition of 77 heating
10 degree-days.The adjustment to sales volumes was an
11 addition of 331,196 therms which is less than one-third of
12 one percent of billed usage.
13 III. PRODUCTION PROPERTY ADJUSTMNT
14 Q. What is the purpose of a Production Property
15 Adjustment?
16 A. The purpose of using a Production Property
17 Adjustment is to avoid an over-collection of fixed and
18 variable production costs resulting from an increase in
19 retail load from the historical test period to the pro
20 forma rate period.In this general rate case Avista is
21 using a 2007 historical test period, and a 2009 pro forma
22 rate year.The illustration below shows, for Avista' s
23 present case: 1) the 2007 historical test year, 2) the date
24 of the current rate case filing, and 3) the pro forma rate
Knox, Di 11
Avista Corporation
1 year (calendar year 2009) in which new rates, if approved,
2 will be in place.
3
4
4/2107
Filng Date
5
6
7
8
2009 Pro forma
Rate Year
In a rate case, the revenue requirement is spread to
9 historical test year loads to establish new retail rates,
10 which for Avista' s present rate case is 2007 retail loads.
11 When a rate case is developed to include the fixed and
12 variable power supply costs during the 2009 pro forma rate
13 year to serve 2009 rate year loads, we need to ensure that
14 those fixed and variable costs are not over-collected as
15 the load grows from the 2007 test year to the 2009 pro
16 forma rate year. The Production Property Adjustment serves
17 this purpose. The use of a Production Property Adjustment
18 was approved by the Washington Utilities and Transportation
19 Commission in the Company's recently-concluded 2007 rate
20 case.
21 Q. Why is Avista proposing a production Property
22 Adjustment in this case?
23 A. We believe a Production Property Adjustment, in
24 conjunction with pro forma rate year loads for power
25 supply, results in a better matching of revenues and
Knox, Di 12
Avista Corporation
1 expenses during the period that new retail rates from this
2 rate case will be in effect.The use of 2009 pro forma
3 loads will result in pro forma revenues and expenses in
4 this filing that are much closer to what is expected to
5 occur during the 2009 rate year, and the Production
6 Property Adjustment will ensure that the Company does not
7 over-collect its fixed and variable production costs. The
8 Retail Revenue Credit (incremental load) adjustments in the
9 PCA would be relatively small, since any true-ups would be
10 based on a comparison of actual load for 2009 versus the
11 2009 pro forma load included in base rates.
12 We have also applied the same theory to transmission
13 fixed and variable costs in the development of the
14 Production Property Adjustment.As loads grow, new
15 customers (new retail KWH sales) will contribute toward the
16 recovery of these transmission costs, and we have applied
17 the same adjustment to transmission costs. Therefore, the
18 proposed Production Property Adjustment ensures that both
19 production costs and transmission costs are not over-
20 collected during the year that rates go into effect.
21
22
Q. How is the production Property Adjustment applied?
A. The production and transmission costs, both fixed
23 and variable, that are included in the proposed retail
24 rates in this case are factored down by the ratio of the
25 Idaho 2007 test period loads and the Idaho 2009 pro forma
Knox, Di 13
Avista Corporation
1 rate year loads.The retail load associated with the
2 directly assigned purchase of Potlatch generation (which is
3 tracked through the PCA at 100%) has been excluded from
4 both 2007 and 2009 in order to match the proposed
5 authorized retail load used to determine incremental load
6 adjustments in the PCA. This ratio is then applied to the
7 Production and Transmission operating and maintenance
8 expenses, including depreciation and amortization expense,
9 as well as net Production and Transmission rate base.
10 Company witness Mr. Kalich included the 2009 pro forma
11 rate year loads in the AURORA model so that the costs
12 associated with serving the loads are reflected in this
13 case, and he provides further explanation of these loads in
14 his testimony.
15 Q. Do you have an exhibit that shows the calculation
16 of the production property adjustment?
17 A. Yes.Exhibi t No. 14, Schedule 1 begins with the
18 identification of the production and transmission revenue,
19 expense and rate base amounts included in each of Ms.
20 Andrews actual, restating, and pro forma adjustments to
21 2007 results of operations (not including the production
22 property adjustment).The values on line 39, labeled Pro
23 Forma Total, reflect production and transmission revenues,
24 expenses, and rate base necessary to serve 2009 retail
25 loads.The values on line 43,labeled 2007
Knox, Di 14
Avista Corporation
1 Production/Transmission Costs, are the amounts on line 39
2 multiplied by the production factor (calculated on line 42)
3 in order to reflect the proportion of those costs required
4 to be recovered by 2007 retail loads.The difference
5 between the 2007 and 2009 values (shown on line 44), is the
6 production property adjustment Ms. Andrews included in her
7 calculation of revenue requirement in this case.
8
9
Q. What is shown on page 2 of Exhibit 14, Schedule 1?
A. Page 2 of Exhibit No. 14, Schedule 1 shows the
10 calculation of the proposed revenue requirement associated
11 wi th production and transmission costs in this case.The
12 rate of return and debt cost percentages on line 2 are
13 inputs from the proposed cost of capital.The rate base
14 and net expense values are the same costs calculated on
15 page 1 to determine the production property adjustment.
16 The value of the Potlatch Generation purchase has been
17 excluded from net expense consistent with the exclusion of
18 the related load for PCA purposes.Line 10 shows the
19 average Production and Transmission cost per kWh proposed
20 to be embedded in customer rates.
21
22
iv. ELECTRIC COST OF SERVICE
Q.Please briefly sumrize your testimony related
23 to the electric cost of service study.
24 A.I believe the Base Case cost of service study
25 presented in this case is a fair representation of the
Knox, Di 15
Avista Corporation
1 costs to serve each customer group. The Base Case study
2 shows Residential Service Schedule 1, Extra Large General
3 Service Schedule 25 and 25P, and Street and Area Lighting
4 provide less than the overall rate of return under present
5 rates. General Service Schedule 11, Large General Service
6 Schedule 21 and pumping Service Schedule 31 provide more
7 than the overall rate of return under present rates but
8 less than the requested return.
9 Q.What is an electric cost of service study and
10 what is its purpose?
11 A.An electric cost of service study is an
12 engineering-economic study, which separates the revenue,
13 expenses, and rate base associated with providing electric
14 service to designated groups of customers. The groups are
15 made up of customers with similar load characteristics and
16 facilities requirements. Costs are assigned in relation to
17 each group's characteristics, resulting in an evaluation of
18 the cost of the service provided to each group.The rate
19 of return by customer group indicates whether the revenue
20 provided by the customers in each group recovers the cost
21 to serve those customers. The study results are used as a
22 guide in determining the appropriate rate spread among the
23 groups of customers.Exhibi t No. 14, Schedule 2 explains
24 the basic concepts involved in performing an electric cost
25 of service study. It also details the specific methodology
Knox, Di 16
Avista Corporation
1 and assumptions utilized in the Company's Base Case cost of
2 service study.
3 Q.What is the basis for the electric cost of
4 service study provided in this case?
5 A.The electric cost of service study provided by
6 the Company as Exhibit No. 14, Schedule 2 is based on the
7 2007 test year pro forma results of operations presented by
8 Company witness Ms. Andrews in Exhibit No. 13, Schedule 1.
9 Q.Would you please explain the cost of service
10 study presented in Exhibit No. 14, Schedule 3?
11 A.Yes. Exhibi t No. 14, Schedule 3 is composed of a
12 series of sumaries of the cost of service study results.
13 The sumary on page 1 shows the results of the study by
14 FERC account category. The rate of return by rate schedule
15 and the ratio of each schedule's return to the overall
16 return are shown on Lines 39 and 40.This sumary was
17 provided to Mr. Hirschkorn for his work on rate spread and
18 rate design. The results will be discussed in more detail
19 later in my testimony.
20 Pages 2 and 3 are both sumaries that show the revenue
21 to cost relationship at current and proposed revenue.
22 Costs by category are shown first at the existing schedule
23 returns (revenue); next the costs are shown as if all
24 schedules were providing equal recovery (cost).These
25 comparisons show how far current and proposed rates are,
Knox, Di 17
Avista Corporation
1 from rates that would be in alignment with the cost study.
2 Page 2 shows the costs segregated into production,
3
4
transmission,distribution,and common functional
categories.Page 3 segregates the costs into demand,
5 energy, and customer classifications.
6 The Excel model used to calculate the cost of service
7 and supporting schedules have been included in their
8 entirety both electronically and hard copy in the
9 workpapers accompanying this case.
10 Q.Does the Comany's electric Base Case cost of
11 service study follow the methodology accepted in the
12 Company's last electric general rate case in Idaho?
13 A.Yes.The Base Case cost of service study was
14 prepared using the methodology accepted by the Idaho
15 commission in Case No. AVU-E-04-01.
16 Q.Given that the specific details of this
17 methodology are described in Exhibit No. 14, Schedule 2,
18 would you please give a brief overview of the key elements
19 and the history associated with those elements?
20 A.Production and transmission costs are classified
21 to energy and demand by a peak credit analysis. Avista has
22 been using the peak credit classification process for cost
of service studies in both washington and Idaho23
24 jurisdictions since the 1980' s.Distribution costs are
Knox, Di 18
Avista Corporation
1 classified and allocated by the basic customer theoryl
2 accepted by the Idaho commission in Case No. WWP-E-98-11.
3 Additional direct assignent of demand related distribution
4 plant has been incorporated to reflect improvements
5 accepted by the commission in Case No. AVU-E-04-01.
6 Administrative and general costs are first directly
7 assigned to production, transmission, distribution, or
8 customer relations functions. The remaining administrative
9 and general costs are categorized as common costs and have
10 been assigned to customer classes by the four-factor
11 allocator accepted by the Idaho commission in Case No. AVU-
12 E-04-01.
13 Q.What are the results of the Company's Base Case
14 cost of service study?
15 A.The following table shows the rate of return and
16 the relationship of the customer class return to the
17 overall return (relative return ratio) at present rates for
18 each rate schedule:
i Basic customer theory classifies only meters, serces and street lights as customer-related plant; all other
distrbution facilties are considered demand-related.
Knox, Di 19
Avista Corporation
1 Table 1
Customer Class
Residential Service Schedule 1
General Service Schedule 11
Large General Service Schedule 21
Extra Large General Service Schedule 25
Ex. Lg. Gen. Service Potlatch Schedule 25P
Pumping Service Schedule 31
Lighting Service Schedules 41 - 49
Total Idaho Electric System
Rate of Return Return Ratio
4.35%
7.49%
6.02%
2.88%
3.71%
6.71%
4.48%
4.97%
0.87
1. 51
1.21
0.58
0.75
1.35
0.90
1. 00
2 As can be observed from the above table, residential,
3 extra large general service, and lighting service schedules
4 (1, 25, 25P, and 41-49) show under-recovery of the costs to
5 serve them, while the general, large general, and pumping
6 service schedules (11, 21, and 31) show over-recovery of
7 the costs to serve them.However, all customer groups are
8 currently providing a rate of return lower than the rate of
9 return requested in this case. The sumary results of this
10 study were provided to Mr. Hirschkorn as an input into
11 development of the proposed rates.
12 Q Does the Company have recent load research study
13 informtion to use in the deter.ination of demnd-related
14 allocations?
15 A.No.The load shape estimates included the
16 calculation of the demand allocation factors for this cost
17 of service study were derived from load research performed
18 in the early 1980' s and statistically updated in 1993. The
19 estimation process used to develop the demand allocation
Knox, Di 20
Avista Corporation
1 factors for most customer groups (rate schedules) utilizes
2 current billing system statistics and predicted daily
3 volumes from the current weather sensitivity analysis in
4 conjunction with load shape relationships produced by the
5 prior load research data. The extra large general service
6 schedules are not estimated, as current actual hourly
7 demand data is available for them.
8 Q How does the load shape informtion affect the
9 cost of service study results?
10 A.Slightly more than one-third of the costs in
11 this study are demand-related and therefore affected by the
12 coincident peak or non-coincident peak allocation factors.
13 Even though I believe the study as a whole provides a
14 reasonable representation of the cost of service, the
15 results should not be used with a high level of precision.
16 In addition, because of the absence of a recent demand
17 study, reliable data was not available to conduct adequate
18 analysis of demand-metered Schedule 11 customers to
19 evaluate the reasonableness of segregating them into a
20 separate schedule, as briefly addressed in Mr. Hirschkorn's
21 testimony.
22
23
24
Q.IS the Company conducting a new demnd study?
A.Yes. Currently the Company is in the process of
developing an hourly load research study.Under the
25 current timeline, load research meters will be installed on
Knox, Di 21
Avista Corporation
1 a statistical sample of customers from each of the customer
2 groups later this year in order to collect a full year of
3 hourly data.
4
5
V. NATU GAS COST OF SERVICE
Q.Please describe the natural gas cost of service
6 study and its purpose.
7 A.A natural gas cost of service study is an
8 engineering-economic study which separates the revenue,
9 expenses, and rate base associated with providing natural
10 gas service to designated groups of customers. The groups
11 are made up of customers with similar usage characteristics
12 and facility requirements.Costs are assigned in relation
13 to each groups' characteristics, resulting in an evaluation
14 of the cost of the service provided to each group.The
15 rate of return by customer group indicates whether the
16 revenue provided by the customers in each group recovers
17 the cost to serve those customers.The study resul ts are
18 used as a guide in determining the appropriate rate spread
19 among the groups of customers.Exhibi t No. 14, Schedule 4
20 explains the basic concepts involved in performing a
21 natural gas cost of service study.It also details the
22 specific methodology and assumptions utilized in the
23 Company's Base Case cost of service study.
24 Q.What is the basis for the natural gas cost of
25 service study provided in this case?
Knox, Di 22
Avista Corporation
1 A.The cost of service study provided by the Company
2 as Exhibit No. 14, Schedule 5 is based on the 2007 test year
3 pro forma results of operations presented by Ms. Andrews in
4 Exhibi t No. 13, Schedule 2.
5 Q.Would you please explain the cost of service
6 study presented in Exhibit No. 14, Schedule 5?
7 A.Yes. Exhibit No. 14, Schedule 5 is composed of a
8 series of sumaries of the cost of service study results.
9 Page 1 shows the results of the study by FERC account
10 category.The rate of return and the ratio of each
11 schedule's return to the overall return are shown on lines
12 38 and 39. This sumary is provided to Mr. Hirschkorn for
13 his work on rate spread and rate design. The results will
14 be discussed in more detail later in my testimony.The
15 additional sumaries show the costs organized by functional
16 category (page 2) and classification (page 3), including
17 margin and unit cost analysis at current and proposed
18 rates.
19 The Excel model used to calculate the cost of service
20 and supporting schedules have been included in their
21 entirety both electronically and hard copy in the
22 workpapers accompanying this case.
23 Q.Does the Natural Gas Base Case cost of service
24 study utilize the methodology from the Company's last
25 natural gas case in Idaho?
Knox, Di 23
Avista Corporation
1 A.Yes.The Base Case cost of service study was
2 prepared using the methodology accepted by the Idaho
3 commission in Case No. AVU-G-04-01.
4 Q.What are the key elements that define the cost of
5 service methodology?
6
7
A.Purchased gas costs are derived from the current
purchased gas tracker methodology .underground storage
8 costs are allocated by normalized winter throughput.
9 Natural gas main investment has been segregated into large
10 and small mains.Large usage customers that take service
11 from large mains do not receive an allocation of small
12 mains.Meter installation and services investment is
13 allocated by numer of customers weighted by the relative
14 current cost of those items. System facilities that serve
15 all customers are classified by the peak and average ratio
16 that reflects the system load factor, then allocated by
17 coincident peak demand and throughput,respectively.
18 Demand side management costs are treated in the same way as
19 system facilities. General plant is allocated by the sum
20 of all other plant. Administrative & general expenses are
21 segregated into labor related, plant related, revenue
22 related, and "other".The costs are then allocated by
23 factors associated with labor, plant in service, or
24 revenue, respectively.The "other" A&G amounts get a
25 combined allocation that is one-half based on O&M expenses
Knox, Di 24
Avista Corporation
1 and one-half based on throughput.A detailed description
2 of the methodology is included in Exhibit No. 14, Schedule
3 4.
4 Q.What are the results of the Company's natural gas
5 cost of service study?
6 A.I believe the Base Case cost of service study
7 presented in this filing is a fair representation of the
8 costs to serve each customer group.The study indicates
9 that Large Firm and Interruptible Service schedules (121
10 and 131) are providing less than the overall return
11 (unity), while Transportation Service Schedule 146 is
12 providing more than unity. Small Firm is also above unity,
13 but below the requested return, and Residential Service is
14 only slightly below unity.
15 The following table shows the rate of return and the
16 relative return ratio at present rates for each rate
17 schedule:
18 Table 2
Customer Class Rate of
Return
Return Ratio
Residential Service Schedule 101
Small Firm Service Schedule 111
Large Firm Service Schedule 121
Interruptible Service Schedule 131
Transportation Service Schedule 146
Total Idaho Natural Gas System
4.93%
7.14%
2.40%
3.21%
11. 22%
5.21%
0.95
1.37
0.46
0.62
2.15
1. 00
Knox, Di 25
Avista Corporation
1 The sumary results of this study were provided to Mr.
2 Hirschkorn as an input into development of the proposed
3 rates.
4 Q.Does this conclude your pre-filed direct
5 testimony?
6 A. Yes.
Knox, Di 26
Avista Corporation
DAVID J. MEYER
VICE PRESIDENT, GENERAL COUNSEL, REGULATORY &
GOVERNENTAL AFFAIRS
AVISTA CORPORATION
P.O. BOX 3727
1411 EAST MISSION AVENUE
SPOKANE, WASHINGTON 99220-3727
TELEPHONE: (S09) 49S-4316
FACSIMILE: (S09) 49S-88S1
Rr:J"r-~.",Lf" Ir-~Di0081$po¡ 11-3
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION ) CASE NO. AVU-E-08-01
OF AVISTA CORPORATION FOR THE ) CASE NO. AVU-G-08-01
AUTHORITY TO INCREASE ITS RATES )
AND CHARGES FOR ELECTRIC AND )
NATURAL GAS SERVICE TO ELECTRIC ) EXHIBIT NO. 14
AND NATURAL GAS CUSTOMERS IN THE )STATE OF IDAHO ) TARA L. KNOX
)
FOR AVISTA CORPORATION
(ELECTRIC AND GAS)
ißDû ì: 1 Ð
CONFIDENTIA
A vista Utities
Production Propert Adjustment Calculation
Idaho Electric
Twelve Months Ended December 31, 2007
THIS PAGE ALLEGEDLY CONTAIS TRAE SECRETS OR CONFIDENTIA
MATERIS AN IS SEPARTELY FILED.
Exhbit No. 14
Case No. A VU-E-08-01
T. Knox, Avista
Schedule 1, p.lof2
Proposed Production and Trasmission Revenue Requirement
Calculation of Retail Revenue Credit Rate at Proposed Retrn
2007 2009 Debt Cost
Prodrans Pro Forma Rate Base $298,570 $313,996
2 Proposed Rate of Retu 8.740%8.740%3.56%
3 Rate Base Net Operating Income Requirement $26,095 $27,443
4 Tax Effect Net Operg Income Requiement ($3,720)($3,912)
(Rate Base x Debt Cost x -35%)
5 Net Expene Net Operating Income Requiement $95,600 100,539
(Expense - Revenue)
6 Tax Effect Net Opertig Income Requirement ($33,460)($35,189)
(Net Expene x -.35%)
7 Total Prodran Net Operating Income Requirement $84,515 $88,881
8 1 - Tax Rate Conversion Factor (Excl. Rev. ReI. Exp.0.65 0.65
9 Prodra Revenue Requirement $130,023 ~$136,740 I $6,718
10 Prod/rans Rev Requirement per kWh $ 0.04383 $0.04383 6,718
Potlatch Generation Purchase of$19,861 Passed through PCA at 100%
11 Excluded from Net Expense on Line 5 18,885 19,861 976
Exhibit No. 14
Case No. AVU-E-08-01
T. Knox, Avista
Schedule 1, p. 2 of 2
ELECTRIC COST OF SERVICE
A cost of service study is an engieerig-economic study, which apportions the revenue,
expenses, and rate base associated with providing electrc serce to designated groups of
customers. It indicates whether the revenue provided by the customers recovers the cost to serve
those customers. The study results are used as a guide in determining the appropriate rate spread
among the groups of customers.
There are thee basic steps involved in a cost of servce study: fuctionalization,
classification, and allocation. See flow char.
First, the expenses and rate base associated with the electrc system under study are
assigned to fuctional categories. The unform system of accounts provides the basic segregation
into production, transmission, and distrbution. Traditionally customer accounting, customer
information, and sales expenses are included in the distrbution fuction and administrative and
general expenses and general plant rate base are allocated to all fuctions. In this study I have
created a separate fuctional category for common costs. Admnistrative and general costs that
canot be directly assigned to the other fuctions have been placed in ths category.
Second, the expenses and rate base items that canot be directly assigned to customer
groups are classified into thee primar cost components: energy, demand or customer related.
Energy related costs are allocated based on each rate schedule's share of commodity consumption.
Demand (capacity) related costs are allocated to rate schedules on the basis of each schedule's
contrbution to peak demand. Customer related items are allocated to rate schedules based on the
number of customers withn each schedule. The number of customers may be weighted by
appropriate factors such as relative cost of meterng equipment. In addition to these thee cost
components, any revenue related expense is allocated based on the proportion of revenues by rate
schedule.
Exhbit No. 14
Case No. A VU-E-08-01
T. Knox, Avista
Schedule 2, p. I of 9
ELECTRIC COST OF SERVICE STUDY FLOWCHART
Functionalization/
Production Transmission
Distribution and
Customer
Relations Common
Energy I
Commodity
Related
Demand I
Capacity Related
Customer
Related
Direct Assignment
Generation Level mWh's
Customer Level mWh's
Residential Small General Extra Large
General
Pumping Street & Area
Lights
Pro Forma Results of Operations by Customer Group
Exhbit No. 14
Case No. A VU-E-08-0l
T. Knox, A vista
Schedule 2, p. 2 of 9
The final step is allocation of the costs to the varous rate schedules utilzing the allocation
factors selected for each specific cost item. These factors are derived from usage and customer
information associated with the test perod results of operations.
BASE CASE COST OF SERVICE STUDY
Production and Transmission Classifcation (peak Credit)
This study utilizes a Peak Credit methodology to classify production and transmission costs
into demand and energy classifications. The Peak Credit method acknowledges that baseload
production facilities provide energy thoughout the year as well as capacity durng system peak
and likewise the transmission system is built not only for peak use, but also for everday delivery
of energy. The demand/energy ratio is determined by the relationship of the curent replacement
cost per kW generating capacity of the Company's peakng unts to the curent replacement cost
per kW generating capacity of the Company's thermal or hydro plant. The peak credit ratio for
thermal plant is 33.57% to demand and 66.43% to energy. The peak credit ratio for hydro plant is
26.82% to demand and 73.18% to energy. As an intermediate resource (between peakng and
baseload), Coyote Sprigs IT has been included with the thermal plant costs, whereas all other
plants in the 340 to 349 FERC plant accounts are considered peakng units.
Transmission costs are classified by fift-fift weighting of the thermal and hydro peak
credit ratios resulting in the transmission peak credit ratio of 30.19% to demand and 69.81 % to
energy. Fuel and load dispatching expenses are classified entirely to energy. Peaking plant related
costs are classified entirely to demand. Purchased Power and Other Power Supply expenses are
classified to demand and energy by the relative amounts of assigned and allocated Production Plant
in Serce.
Exhbit No. 14
Case No. A VU-E-08-01
T. Knox, A vista
Schedule 2, p. 3 of9
Production and Transmission Alocation
Production and transmission demand related costs are allocated to the customer classes by
class contribution to the average of the twelve monthy system coincident peak loads. Although
the Company is usually technically a winter peakg utility, it experences high sumer peaks and
careful management of capacity requirements is requIred thoughout the year. The use of the
average of twelve monthly peaks recognzes that customer capacity needs are not limited to the
heating season.
Energy related costs are allocated to class by pro forma anual kilowatthour sales adjusted
for losses to reflect generation level consumption.
Distribution Facilties Classifcation (Basic Customer)
The Basic Customer method considers only serces and meters and directly assigned
Street Lighting apparatus (FERC Accounts 369, 370, and 373 respectively) to be customer related
distrbution plant. All other distrbution plant is then considered demand related. Ths division
delineates plant which benefits an individual customer from plant which is par of the system. The
basic customer method provides a reasonable, clearly definable division between plant that
provides service only to individual customers from plant that is par of the interconnected
distrbution network.
Customer Relations Distribution Cost Classifcation
Customer serice, customer information and sales expenses are the core of the customer
relations fuctional unt which is included with the distrbution cost category. For the most par
they are classified as customer related. Exceptions are sales expenses which are classified as
energy related and uncollectible accounts expense which is considered separately as a revenue
conversion item. Demand Side Management expenses recorded in Account 908 are also
considered separately from the other customer information costs.
Exhbit No. 14
Case No. A VU-E-08-01
T. Knox, A vista
Schedule 2, p. 4of9
The demand side management investment and amortzation are classified implicitly to
demand and energy by the sum of production plant in servce, then allocated to rate schedules by
coincident peak demand and energy consumption respectively.
Distribution Cost Alocation
Distrbution demand related costs which canot be directly assigned are allocated to
,
customer class by the average of the twelve monthly non-coincident peaks for each class.
Distrbution facilties that sere only secondar voltage customers are allocated by the non-
coincident peak excluding priar voltage customers or number of customers excluding primar
voltage customers. This includes line transformers, servces, and secondar voltage overhead or
underground conductors and devices. The costs of specific substations and related primar voltage
distrbution facilities are directly assigned to Extra Large General Service customers based on thei
load ratio share of the substation capacity from which they receive serice.
Most customer costs are allocated by average number of customers. Weighted customer
allocators have been developed using tyical curent cost of meters, estimated meter reading time,
and direct assignent of biling costs for hand-biled customers. Street and area light customers
are excluded from metering and meter reading expenses as their serice is not metered.
Admiistrative and General Costs
Administrative and general costs which are directly associated with production,
transmission, distrbution, or customer relations fuctions are directly assigned to those fuctions
and allocated to customer class by the relevant plant or number of customers. The remainder of
administrative and general costs are considered common costs, and have been left in their own
functional category. These common costs are classified by the implicit relationship of energy,
demand and customer within the four-factor allocator applied to them. The four-factor allocator
consists of a 25% weighting of each of the following: 1) operating & maintenance expenses
Exhbit No. 14
Case No. A VU-E-08-0l
T. Knox, Avista
Schedule 2, p. 50f9
excluding resource costs, labor expenses, and administrative and general expenses; 2) operating
and maintenance labor expenses excluding administrative and general labor expenses; 3) net
production, transmission, and distrbution plant; and 4) number of customers.
Revenue Conversion Items
il this study uncollectible accounts and commission fees have been classified as revenue
related and are allocated by pro forma revenue. These items var with revenue and are included in
the calculation of the revenue conversion factor. ilcome ta expense items are allocated to
schedules by net income before income tax adjusted by interest expense.
For the fuctional sumares on pages 2 and 3 of the cost of serice study, these items are
assigned to component cost categories. The revenue related expense items have been reduced to a
percent of all other costs and loaded onto each cost category by that ratio. Similarly, income tax
items have been reduced to a percent of net income before tax then assigned to cost categories by
relative rate base (as is net income).
The following matrx outlines the methodology applied in the Company Base Case cost of
servce study.
Exhbit No. 14
Case No. A VU-E-08-01
T. Knox, Avista
Schedule 2, p. 6of9
lP
U
C

C
a
s
e

N
o
.

A

V
U
-
E
-
0
8
-
0

1

M
e
t
h
o
d
o
l
o
g
y

M
a
t
r
x
Av
i
s
t

U
t
i
l
i
t
i
e
s

I
d
o

J
u
r
s
d
c
t
i
o
n
El
e
c
t
r
c

C
o
s
t

o
f
S
e
i
i
c
e

M
e
t
h
o
d
o
l
o
g
y
Ac
c
u
n
t
Fu
n
c
t
i
o
n
a

C
a
t
e
g
o
r
y
Cl
a
s
s
f
i
c
a
t
i
o
n
Al
l
o
c
t
i
o
n
Pr
o
d
u
c
t
i
o
n

P
l
a
Th
e
n

P
r
o
u
c
t
i
o
n
Hy
d
r

P
r
o
u
c
t
i
o
n
Ot
h
e
r

P
r
o
u
c
t
i
o
n

(
C
o
y
o
t
e

S
p
r
i
n
g
s
)
Ot
h

P
r
o
u
c
t
i
o
n
Tr
a
m
i
i
o
n

P
l
a
n
t
Al
l

T
r
a
s
s
o
n
Di
s
t
n
b
u
t
i
o
n

P
l
a
n
t
36
0
L
a
36
1

S
t
i
c
t
u
36
2

S
t
a
t
i
o
n

Eq
p
m
e
n
t
36
4

P
o
l
e
s

T
o
w
e

&

F
i
x
t
u
s
36
5

O
v
e
r
e
a
d

C
o
n
d
u
c
t
o
r
s

&

D
e
i
c
e
36
6

U
n
d
e
r
u
n
d

C
o
n
d
u
i
t
36
7

U
n
d
e
r
u
n
d

C
o
n
d
u
c
t
o
r
s

&

D
e
i
c
e
36
8

L
i
n
e

T
r
a
o
n
u
r
s
36
9

S
e
r
v
c
e
s
37
0

M
e
t
e
r
s
37
3

S
t
r
t

a
n
d

A
r

L
i
g
h
t
i
n
g

S
y
s
t
m
s
Ge
n
e
r
a

P
l
a
t
Al
l

G
e
n
e
r
a
In
a
n
g
i
b
l
e

P
l
a
n
t
30
1

O
r
g
3
1
z
a
t
i
o
n
30
2

F
r
a
c
h
i
s
e
s

&

C
o
n
s
t
s
30
3

M
i
s
e

I
n
t
a
b
l
e

P
l
a
n
t

-

G
r
a
t

C
o

T
r
a
s
s
o
n
30
3

M
i
s
e

I
n
t
a
b
l
e

P
l
a
n
t

-

S
o
f
t
Re
s
e
r
v
e

f
o
r

D
e
p
r
e
c
i
t
i
o
n
f
A
m
o
r
t
i
m
t
i
o
n
In
t
a
b
l
e
Pr
o
u
c
t
i
o
n
Tr
a
s
s
o
n
Di
s
t
b
u
t
i
o
n
Ge
n
e
i
Ot
h
e
r

R
a
t
e

B
a
s
e
25
2

C
u
s
t
m
e

A
d
v
a
n
s

f
o
r

C
o
n
s
c
t
i
o
n
28
2
1
1
9
0

A
c
c
u
l
a
t
e

D
e
f
e
r
r

I
n
m
e

T
a
x
Ga
i
n

o
n

S
a
l
e

o
f

G
e
n
e
r
a

O
f
f
c
e

B
u
i
l
d
i
n
g
Hy
d
r

R
e
l
a
t
e

D
e
f
e
r

B
a
l
a
n
c
e
De
m
a
d

S
i
d
e

M
a
n
g
e
m
t

I
n
e
s
t
e
n
t
Pr
d
u
d
i
o
n

O
&
M
Th
e
n
Th
e
n

F
u
e
l

(
5
0
1
)
Hy
d
r
P
=

P
r
o
u
c
t
i
o
n
P
=

P
r
o
u
c
t
i
o
n
P =

P
r
o
d
u
c
t
i
o
n
P
=

P
r
o
u
c
t
i
o
n
T
=

T
r
a
s
s
o
n
D
=

D
i
s
t
b
u
t
i
o
n
D
=

D
i
s
t
b
u
t
i
o
n
D
=

D
i
s
t
b
u
t
i
o
n
D
=

D
i
s
t
b
u
t
i
o
n
D
=

D
i
s
t
b
u
t
i
o
n
D
=

D
i
s
t
b
u
t
i
o
n
D
=

D
i
s
t
b
u
t
i
o
n
D
=

D
i
s
t
b
u
t
i
o
n
D
=

D
i
s
t
b
u
t
i
o
n
D
=

D
i
s
t
b
u
t
i
o
n
D
=

D
i
s
t
b
u
t
i
o
n
û=
t
h
e
r
û=
t
h
e
r
P
=

P
r
o
u
c
t
i
o
n
T
=

T
r
a
s
s
o
n
O=
O
t
h
e
r
Pf
l
l
O
P
=

P
r
o
u
c
t
i
o
n
T
=

T
r
a
s
s
o
n
D
=

D
i
s
t
b
u
t
i
o
n
O=
O
t
h
D
=

D
i
s
t
b
u
t
i
o
n
Pf
l
i
D
/
O

b
y

P
l
a
n
t

B
a
l
a
n
c
e
s
O=
O
t
h
P
=

P
r
o
u
c
t
i
o
n
DS
M
P
=

P
r
o
u
c
t
i
o
n
P
=

P
r
o
u
c
t
i
o
n
P
=

P
r
o
u
c
t
i
o
n
De
n
u
i
n
e
r
g

b
y

T
h
e
r
n

P
e
a

C
r
e
i
t
De
n
i
a
n
d
Æ
e
r
g

b
y

H
y
d
r

P
e
a
k

C
r
e
t
De
n
i
a
n
d
Æ
n
e
r
g

b
y

T
h
e
r
n

P
e
a

C
r
e
t
De
m
a
n
d
De
m
d
Æ
n
e
r
g

b
y

T
r
a

P
e
a
k

C
r
e
t
De
d
De
m
a
d
De
m
d
De
m
a
n
d
De
m
a
d
De
d
De
n
d
De
m
a
n
d
Cu
s
t
m
e
r
Cu
s
t
m
e
r
Cu
s
t
m
e
r
De
n
i
n
e
r
g
/
C
u
s
t
o
m
e
r

b
y

C
o
i
p

C
o
s
t

A
l
l
o
c
t
o
r
En
e
r
/
C
u
s
t
m
e
r

b
y

C
o
i
p

C
o
s
t

A
l
l
o
c
t
o
r
De
m
a
d
Æ
n
e
r
g

b
y

H
y
d
r

P
e
a

C
r
e
t
De
m
d
Æ
e
r

b
y

T
r
a
s

P
e
a

C
r
e
t
De
m
a
d
Æ
n
e
r
/
C
u
s
t
m
e
r

b
y

C
o
i
p

C
o
s
t

A
l
l
o
c
t
o
r
Fo
l
l
o
w
s

R
e
l
a
t
e
d

P
l
a
n
t
Fo
l
l
o
w
s

R
e
l
a
t
e

P
l
a
n
t
Fo
l
l
o
w
s

R
e
l
a
t
e

P
l
a
n
t
Fo
l
l
o
w
s

R
e
l
a
t
e

P
l
a
n
t
De
n
n
d
Æ
e
r
/
C
u
s
t
m
e
r

b
y

C
o
i
p

C
o
s
t

A
l
l
o
c
t
o
r
Cu
s
t
m
e
r
Fo
l
l
o
w
s

R
e
l
a
t
e

P
l
a
n
t
De
m
a
d
Æ
e
r
g
/
C
u
s
t
m
e
r

b
y

C
o
i
p

C
o
s
t

A
l
l
o
c
t
o
De
m
a
n
d
Æ
n
e
r

b
y

H
y
d
r

P
e
a

C
r
e
t
De
n
n
e
r
g

f
r
m

P
r
o
u
c
t
i
o
n

P
l
a
n
t
De
m
a
d
Æ
n
e
r

b
y

T
h
e
n

P
e
a

C
r
e
t
En
e
r
g
De
m
a
n
d
l
r
g

b
y

H
y
d
r

P
e
a

C
r
e
t
D0
1
1
E
0
2

C
o
i
n
c
i
d
e
n
t

Pe
a

De
m
a
n
d
/
A
n
u
a
l

G
e
n
e
r
t
i
o
n

L
e
e
l

C
o
n
s
t
i
o
n
DO

1
Æ
0
2

C
o
i
n
c
i
d
e
n
t

P
e
a

D
e
n
i
a
d
/
A
m

G
e
n
e
r
t
i
o
n

L
e
e
l

C
o
n
s
m
p
t
i
o
n
DO

1
1
E
0
2

C
o
i
n
c
i
d
e
n
t

P
e
a

D
e
m
a
d
/
A
n
u
a

G
e
n
e
r
a
t
i
o
n

L
e
e
l

C
o
n
s
u
t
i
o
n
DO

1

C
o
i
n
c
i
d
e
n
t

P
e
a

D
e
m
a
d
DO

1
1
E
0
2

C
o
i
n
c
i
d
e
n
t

P
e
a

D
e
d
/
A
n
a
l

G
e
n
e
r
a
t
i
o
n

L
e
e
l

C
o
n
s
m
p
t
i
o
n
D0
2

N
o
n
-
c
o
i
n
c
i
d
e
n
t

Pe
a

De
m
a
d

(
N
C
P
)
D0
3
1
D
4
1
D
5

D
i
r
e
t

A
s
g
n

L
a
e

1

N
o
n
-
c
o
i
n
c
i
d
e
n
t

P
e
a

D
e
d

E
x
c
l

D
A
D0
3
1
D
4
1
D
5

D
i
r
e
t

A
s
g
n

L
a
e

1

N
o
n
-
c
o
i
n
c
i
d
e
n
t

P
e
a
k

D
e
m
a
d

E
x
c
l

D
A
D0
3
/
C
0
4
1
D
6
i
D
0
7

D
i
r
e
t

A
s
g
n

L
a
e

&

L
i
g
h
t
s

1

N
C
P

E
x
c
l

D
A
I

N
C
P

S
e
c
n
d
a
D0
3
/
C
0
4
1
D
6

D
i
r
e
t

A
s
g
n

L
a
e

1

N
C
P

E
x
c
l

D
A

1

N
C
P

S
e
c
n
d
a
D0
3
/
C
0
4
1
D
6

D
i
r
e
t

A
s
g
n

L
a
e

1

N
C
P

E
x
c
l

D
A

1

N
C
P

S
e
c
n
d
D0
3
/
C
0
4
1
D
6

D
i
r
e
t

A
s
g
n

L
a
e

1

N
C
P

E
x
c
l

D
A

1

N
C
P

S
e
c
d
a
D0
6

N
o
n
-
c
o
i
n
c
i
d
e
n
t

Pe
a

De
d

S
e
c
n
d
a
C0
2

S
e
c
n
d
a

C
u
s
t
o
m
e
r

u
n
w
e
i
g
h
t
e

E
x
c
l

L
i
g
h
t
i
n
g
C0
4

C
u
s
t
m
e
r
s

w
e
i
g
h
t
e

b
y

C
u
n
t

T
y
i
c
a

M
e
t
e
r

C
o
s
t
C0
5

D
i
r
e
t

A
s
g
n
e
n
t

t
o

S
t
r
t

a
n

A
r

L
i
g
h
t
s
S2
3

2
5
%

d
i
r
e
t

O
&
M
,

2
5
%

d
i
r
e
t

l
a
b
o
r
,

2
5
%

n
e
t

d
i
r
e
t

p
l
a
n
t
,

2
5
%

n
u
m

o
f

c
u
m
e
r
s
S2
3

2
5
%

d
i
r
e
t

O
&
M
,

2
5
%

d
i
r
e
t

l
a
b
o
r
,

2
5
%

n
e
t

d
i
r
e
t

p
l
a
n
t
,

2
5
%

n
u

o
f

c
u
s
t
m
e
D0
1
Æ
0
2

C
o
i
n
c
i
d
e
n
t

Pe
a

D
e
i
n
A
m

G
e
n
e
r
t
i
o
n

L
e
e
l

C
o
n
s
t
i
o
n
DO

1
1
E
0
2

C
o
i
n
c
i
d
e
n
t

P
e
a
k

D
e
m
a
d
/
A
m

G
e
n
e
r
t
i
o
n

L
e
e
l

C
o
n
s
m
p
t
i
o
n
S2
3

2
5
%

d
i
r
e
t

O
&
M
,

2
5
%

d
i
r
e
t

l
a
b
o
r
,

2
5
%

n
e
t

d
i
r
e
t

p
l
a
n
t
,

2
5
%

n
u

o
f

c
u
s
t
m
e
r
SO
l
1
8
0
2
1
8
2
3

S
u

o
f

Pr
o
u
c
t
i
o
n

Pl
a
n
t

1
S
u
m

o
f

Tr
a
n
s
s
s
o
n

Pla
n
t

1
C
o
i
p

C
o
s

Al
l
o
c
t
o
r
DO

1
Æ
0
2

C
o
i
n
c
i
d
e
n
t

P
e
a

D
e
d
/
A
m

G
e
n
r
a
t
i
o
n

L
e
e
l

C
o
n
s
t
i
o
n
D0
1
1
E
2

C
o
i
n
c
i
d
e
n
t

Pe
a

De
m
a
d
/
A
m

G
e
n
e
r
t
i
o
n

Le
e
l

C
o
n
t
i
o
n
D0
2
/
D
3
/
D
4
1
D
5
/
D
6
1
D
7
/
D
8
/
C
0
2
/
C
0
4
/
C
0
5

-

S
e
e

R
e
l
a
t
e

P
l
a
n
t
S2
3

2
5
%

d
i
r
e
t

O
&
M
,

2
5
%

d
i
r
e
t

l
a
b
o
r
,

2
5
%

n
e
t

d
i
r
e
t

p
l
a
n
t
,

2
5
%

n
u

o
f

c
u
s
t
o
m
e
r
s
S1
3

S
u
m

of

Ac
c
u
n
t

36
9

S
e
i
v
i
c
e
s
P
l
a
n
t
SO

1
/
S
0
2
/
S
0
3
/
S
0
4

S
u

o
f

Pr
o
u
c
t
i
o
n

1

T
r
a
s
s
o
n

1

D
i
s
t
b
u
t
i
o
n

1

G
e
n
e
i

P
l
a
n
t
S2
3

2
5
%

d
i
r
e
t

O
&
M
,

2
5
%

d
i
r
e
t

l
a
b
o
r
,

2
5
%

n
e
t

d
i
r
e
t

p
l
a
n
t
,

2
5
%

n
u

o
f

c
u
m
e
r
DO

1
1
E
0
2

C
o
i
n
c
i
d
e
n
t

P
e
a

D
e
m
a
d
/
A
n
u
a
l

G
e
n
t
i
o
n

L
e
e
l

C
o
n
s
m
p
t
i
o
n
SO

1

S
u
m

o
f

Pr
o
c
t
i
o
n

P
l
a
n
t
DO

1
1
E
0
2

C
o
i
n
c
i
d
e
n
t

P
e
a

D
e
d
/
A
n
u
a

G
e
n
e
r
t
i
o
n

L
e
e
l

C
o
n
s
t
i
o
n
E0
2

A
n
a
l

G
e
n
e
r
a
t
i
o
n

L
e
e
l

C
o
n
s
m
p
t
i
o
n
DO

1
Æ
0
2

C
o
i
n
c
i
d
e
n
t

P
e
a

D
e
A
n
a
l

G
e
n
e
r
t
i
o
n

L
e
e
l

C
o
n
s
t
i
o
n
Ex
h
i
b
i
t

No
.

14
Ca
s
e

N
o
.

A
V
U
-
E
-
0
8
-
0
1
T.

K
n
o
x
,

A
v
i
s
t
Sc
h
e
d
u
l
e

2
,

p
.

7

o
f
9
:š
~j
.g
.£ ßi~ s õ.. t 1
'i 'i 4)
~.a ::p! .. 8~ o.E
~ ~ Jì
ô ~ ~z:-: ~
~:¡ u
,"':: ()
c: 11 'S
:: .~ 8!' .( ii
s.;:
ru
s.;:
8
~
.g
§'
~U
"i
~
S.;:
e
i:4)c: c:
-l 11 11~:t ~ :t ~
8 g 8 i 8
~ ¿i "il i: "i
i~~~~~
l1î .~ 11i"~i= :s 8 i: :- 8ugui$gu
c: .~ c: .g .~ c:i8 l~ 8llN~8Nl~ ~N.. N.... N~8&HS8~
~
s""
55
s.;:
~f.
'12.!u
1u
~~
7l
~
¡:È
~ ~
~ ""~
~g~gg~
&i ¿i &i ¿i ¿i &i
3~
.g
l~
J
o
~u
1.;:
§~
.~~~.g~.~
o Q C) 0 CJ C)iiiiii~~~~~~
II II II II II II~~~~~~
§
j
~vivi
1vivi~
l~ &i ;;o l~g .,'l ~'W 0 ¡;~ ~ ~ "".~"" vi .1: :ã ::e,¡~~ i;o'i:~2~ ~:g
~ 0 -- ø. i=
¡"'' 1 0tŠ 8 ., u~ '¡~ ~ ~~~~~å~~ooo~£
~jII"~
lu
"i
~
S.;:
~c:
L
~
~
¿i
~~
1
8
§ ~g ~18
~ 1
~ ~
i: 4)o ~
~ o'
M.š ä
." "8 .¡fn ~..8 £ fn
L ..I 1~l Li; ¡¡ £- ti i;~ a r. 1 ~
:= .~ ~ -g - :=
l ;a~::ih e""~:g~;: ¡' 8."8
Js",,,..r:¡¡OSII """""" 2.E S ë., .fq;il~4)",¿i.6~tI""'OtI,.ti .,~"C Õ ~ '0 \0 ~ t: ~ ~ Õlii:MMMMMMi;~is¡;~'å'å==''HS=.. 4) 8 8 :; :; :; :; .. 4)~l~~jjjj~l~ s~~~~~~~ SÉls§ease¡;es&P~ti.¡ö5ö5ö5~ö5zN
~
8 ~~gs=~:t~~Sti ~ ti ti ti ti ti ti ti ~
1u
~~
~È
~
~
J
It Iti; i;8' 8'tJ tJis is~ ~o 0J J~ ~i i~ .. .. .. 8
~1111llll1i:i:i:~i:uuui:!
.1'~
~
II
£-
~~~.g.g~.~~.~.giillllllll
is is is is is is is is is is
II II II II II II II II II IIi: i: i: i: i: i: i: i: i: i:
~
.~
.~
l
~
II
~ ~~.g § ~.. == rn.~ ~
Š '¡; ~...i: .! i;¡J;i~ri;: i~s 4).S"" ZI .;:o'..lti-~ih e8.~i;ß e;: !l iL"~s-,e¡..r:a6"ti"""," 4) R2$ì ¡;ZI§j~6~~~8~!
0"' NM "'V\\Oi:oo 0\00000000000000000000'" V" V\ V' V' V' '" "" V" V"
S
'12
.1£-
~
§
~ g
.g 1s u
11
ii 4)Ö ~
~ o'M'š l~ ZI .~ 1 ¡, ~
! ¡¡ ~ U ti !&i~ ri 1 &i8eil~~~i: 8
~I8.l'.g~l ~.~ o' .it ~ ¿5 i ~ .~;¡ l3 il'vi.. ë'~ ;¡::,ã S~~£-i: r:::II () """""" 4) R 2 =
.,§ S s ;i ;i .s s ~ .,.6~~""'O~~o.6¡~~~~~~t;.'¡
~1111111~O~~~~~~~O~~"S~~'"~~tg
~~~~~~~~~
i:ooO\o..N"1'Vi:.. 0 o............ti ti ti ti ti ti ti ti ti
! !~ ~tJ tJis is~ ~o 0J J~ ~i ~
~~1""1"8 ~ ~~J"~ä g5~io¿i¿ii:¿ii:¿i88
.g.g~~~~~~~illlillll
is is is is is is is is is
II II II II II II II II IIi: i: i: i: i: i: i: i: i:
." .. rJ f' ~.g ~~;3ê 8.
.~ .. i;: 1 1 l &i!M=ß~~;:r:i." () .0 "" Ii "" .. 2 2
.. S :: ¡¡"" 4) R 4) =g,tI~ö¿5;3~::';¡.¡~~~~~~~~
~~~~~~~~~o~N~"d\I\Ot"OO0\ 0\ 0\ 0\ 0\ 0\ 0\ 0\ 0\\I 't i. '" '" l. i. V\ '"
ri:s""
Jl ~
1 is
~.§ ~J~
:a £-., ~~:a 5ii; ~ ~
B 1l ..
~ 4) ~
i;:: is
ZI 1..
~ ~ 1
j~~ 1"" ~ ~_ ..~ ~ ~ 4).'"
l I ~ § It, ,3 i ~ r:~ ~ ., fl ~o~e~~i..0 -, _ .,i"":5 ua., 4)-õ5u~~:;
l'OOM....-e~ 8 8 ~ 8
.. .... !l~ ~ ~ 4) a
i l i § i8 u 8 ~ 8
§ § § .~ §.;:.;:.;: ¡¡ ""
to Cl Cl ~ as'ü"ü'ü="û~ ~ ~ 8 ~
l l l ~ l888 ~ 8
II II II II II
U U U ~ U
l,~ .... !ll jS "õ.: u ZI
~ ~ ! i
" ~ 1 ~ s~ ii:a~~.(
:~ ~ a j:3
i1l~8 ¡;õ5~8t5~.. Ñ M "l '"000000\ 0\ 0\ 0\ 0\
11 'ä II
:t~¡; .~ .~
l~.~§~r: f' g ~ ~
~ ~ ~ ~ ~
l l~ ~ ~
~ ~ õ5:;:;
'I 1"......
8 8 ~ 8 8
'ä
¡;
.g
l~
J
~
~ ~ ~ ~ ~
l l l l l
§ § § §,;:.;: .;: ""
~ ~ ~~
~ ~ ~ ~l l l l
II II ¡¡ II II
U U i: u u
li! ..
i l ~~ ~ S ~~ .u ~ .~
s =~.~ ~ti
å:~ ~ ~ l ~
ll~~~i:00000\00000..0\ 0\ 0\ 0\ 0\
~ c: l ~i .- 0~~.(oo
.~ ~ ~"' ~~:: 0 '
~ ~ ~ ~i; ~ .-¡ó £- isz '8~ ti..U
.~
l"i
~
.~
~
~
I
N
~
~
J
.j
~
!l
l
II
U
Ii
~
'0..0\.....0\
lP
U
C

C
a
s
e

N
o
.

A

V
U
-
E
-
0
8
-
0

1

M
e
t
h
o
l
o
g
y

M
a
t
r
Av
i
s
t

U
t
i
l
i
t
i
e
s

I
d
a
h
o

J
u
r
s
d
c
t
i
o
n
El
e
c
t
r
c

C
o
s
t

o
f

S
e
i
c
e

M
e
t
h
o
d
o
l
o
g
y
Ac
c
u
n
t
Ad
m
i
n

&

G
e
n
e
r
a

E
x
p
e
n
s
e
s
92
0

-

9
2
7

&

9
3
0

-
9
3
5

A
s
g
n
e
d

t
o

P
r
o
u
c
t
i
o
n
92
0

-

9
2
7

&

9
3
0

-
9
3
5

A
s
g
n
e
d

t
o

T
r
a
n
S
l
s
s
o
n
92
0

-

9
2
7

&

9
3
0

-

9
3
5

A
s
g
n
e
d

t
o

D
i
s
t
b
u
t
i
o
n
92
0

-

9
2
7

&

9
3
0

-

9
3
5

A
s
g
n
e
d

t
o

C
u
s
m
e
r

R
e
l
a
t
i
o
n
s
92
0

-

9
3
5

A
s
g
n
e
d

t
o

O
t
h
e
r
92
8

F
E
R
C

C
o
m
m
s
s
o
n

Fe
e
s
92
8
L
P
U
C

C
o
m
m
s
s
o
n

Fe
e
s
De
p
r
e
c
i
a
t
i
o
n

&

A
m
o
r
t
t
i
o
n

E
x
p
e
n
s
e
In
t
a
b
l
e
Pr
o
u
c
t
i
o
n
Tr
a
s
s
o
n
Di
s
t
b
u
t
i
o
n
Ge
n
e
r
a
l
Ta
x
e
s
Pr
o
I
1

T
a
x
St
a
t
e

k
W
h

G
e
n
e
r
t
i
o
n

T
a
x
e
s
Mi
s
e

P
r
o
u
c
t
i
o
n

T
a
x
e
s
Mi
s
e

D
i
s
t
b
u
t
i
o
n

T
a
x
e
s
Id
o

S
t
a
t
e

I
n
c
o
m
e

T
a
x
Fe
d
e
r
a

I
n
c
o
m
e

T
a
x
De
f
e
r

F
I
T
Ot
h
e
r

I
n
c
o
m
e

R
e
l
a
t
e
d

I
t
e
m
s
CS
2

L
e
e
l
i
z
e

R
e
b
i

a
n
d

B
o
u
d
e
r

W
n
t
e
o
f
f

A
m
o
r
t
Op
e
r
a
t
i

R
e
v
e
n
n
e
s
Sa
l
e
s

o
f
E
l
e
c
t
r
c
i
l
¥
-

R
e
t
a
Sa
l
e
s

f
o
r

R
e
s
a
e

(
4
4
7
)
Mi
s
e

S
e
i
c
e

R
e
v
e
n
u
e

(
4
5
1
)
Sa
l
e
s

o
f

Wa
t
e

&
W
a
t
e
P
o
w
e

(4
5
3
)
Re
n
t

f
r
m

P
r
o
u
c
t
i
o
n

P
r
o
I
1

(
4
5
4
)
Re
n
t

f
r

D
i
s
t
b
u
t
i
o
n

P
r
o
I
1

(
4
5
4
)
Ot
h
e
r

E
l
e
c
t
r
c

R
e
v
e
n

-

G
e
n
e
r
t
i
o
n

(
4
5
6
)
Ot
h
e
r

E
l
e
c
t
r
c

R
e
v
e
n
e
s

-

W
h
e
l
i
n
g

(
4
5
6
)
Ot
h
e
r

E
l
e
c
t
r
c

R
e
v
e
n
u
e
s

-

E
n
e
r
g

D
e
l
i
v
e
r
y

(
4
5
6
)
Op
t
i
o
n
a

R
e
n
e
w
b
l
e

R
e
v
e
n
u
e

(
S
c
h

9
5
)
Mo
n
t
a

R
e
t
a

R
e
v
e
n
u
e
Sa
l
r
i
e
s

&

W
a
g
e
s

(
a
l
o
c
a
t
i
o
n

f
a
c
t
o
r

i
n
p
u
t
)
Op
e
t
i
o
n

&

M
a
i
n
t
e
c
e

E
x
p
e
n
s
Pr
o
u
c
t
i
o
n

T
o
t
a
Tr
a
n
s
s
s
o
n

T
o
t
a
Di
s
t
b
u
t
i
o
n

T
o
t
a
Cu
s
t
e
r

A
c
c
t
s

T
o
t
a
Cu
s
m
e

S
e
i
c
e

T
o
t
a
Sa
l
e
s

To
t
a
Ad
m
i
n

&

G
e
n
e
r
a

T
o
t
a
Fu
n
c
t
i
o
n
a
l

C
a
t
e
g
o
r
y
P
=

P
r
o
u
c
t
i
o
n
T
=

T
r
a
s
s
o
n
D
=

D
i
s
t
b
u
t
i
o
n
C
=

C
u
s
t
m
e
r

R
e
l
a
t
i
o
n
s
O=
D
t
h
e
r
P
=

P
r
o
u
c
t
i
o
n
R
=

R
e
v
e
n
u
e

C
o
n
v
e
r
o
n
Pt
r
O
P
=

P
r
o
u
c
t
i
o
n
T
=

T
r
a
u
s
s
o
n
D
=

D
i
s
t
b
u
t
i
o
n
O=
D
t
h
e
r
PI
f
I
D
I
O
P
=

P
r
o
u
c
t
i
o
n
P
=

P
r
o
u
c
t
i
o
n
D
=

D
i
s
t
b
u
t
i
o
n
R
=

R
e
v
e
n
u
e

C
o
n
v
e
r
o
n
R
=

R
e
v
e
n
u
e

C
o
n
v
e
r
s
o
n
R
=

R
e
v
e
n
e

C
o
n
v
e
r
s
o
n
P
=

P
r
o
c
t
i
o
n
R
=

R
e
v
e
n
e

f
r
m

R
a
t
e
s
P
=

P
r
o
u
c
t
i
o
n
D
=

D
i
s
t
b
u
t
i
o
n
P
=

P
r
o
u
c
t
i
o
n
P
=

P
r
o
u
c
t
i
o
n
D
=

D
i
s
t
b
u
t
i
o
n
P
=

P
r
o
u
c
t
i
o
n
T
=

T
r
a
s
s
o
n
D
=

D
i
s
t
b
u
t
i
o
n
P
=

P
r
o
u
c
t
i
o
n
P
=

P
r
o
u
c
t
i
o
n
P
=

P
r
o
u
c
t
i
o
n
T
=

T
r
a
s
s
o
n
D
=

D
i
s
t
b
u
t
i
o
n
C
=

C
u
s
t
m
e
r

R
e
l
a
t
i
o
n
s
C
=

C
u
m
e
r

R
e
l
a
t
i
o
n
s
C
=

C
u
s
t
m
e

R
e
l
a
t
i
o
n
s
O=
D
t
h
e
r
Cl
a
s
s
f
i
c
a
t
i
o
n
De
m
a
d
Æ
n
e
r

f
r
m

P
r
o
d
u
c
t
i
o
n

P
l
a
n
t
De
m
a
d
Æ
n
e
r

f
r
m

T
r
a
u
s
s
o
n

P
l
a
n
t
De
m
a
d
/
C
u
s
t
m
e

f
r
m

D
i
s
t
b
u
t
i
o
n

P
l
a
n
t
Cu
s
t
m
e
r
De
m
a
d
Æ
n
e
r
/
C
u
s
m
e
r

b
y

C
o
i
p

C
o
s
t

A
l
l
o
c
t
o
r
En
e
r
g
Re
v
e
n
u
e
De
m
a
d
Æ
n
e
r
g
/
C
u
s
t
m
e
r

a
s

i
n

r
e
l
a
t
e

P
l
a
n
t
De
d
Æ
e
r

a
s

i
n

r
e
l
a
t
e

P
l
a
n
t
De
d
Æ
n
e
r

a
s

i
n

r
e
l
a
t
e
d

P
l
a
n
t
De
m
a
d
/
C
u
s
m
e
r

a
s

i
n

r
e
l
a
t
e

P
l
a
n
t
De
m
a
n
d
e
r
/
C
u
s
t
m
e
r

b
y

C
o
i

C
o
s
t

A
l
l
o
c
t
o
r
De
m
a
d
Æ
n
e
r
/
C
u
s
t
m
e
r

f
r
m

R
e
l
a
t
e

P
l
a
n
t
De
m
d
Æ
n
e
r
g

b
y

C
o
m
b

P
e
a

C
r
e
t
s

&

E
n
e
r
De
i
d
Æ
n
e
r
g

b
y

C
o
m
b
o

P
e
a

C
r
e
t
s

&

E
n
e
r
De
d
/
C
u
s
t
m
e
r

f
r
m

D
i
s
t
b
u
t
i
o
n

P
l
a
n
t
Re
v
e
n
e
Re
v
e
n
u
e
Re
v
e
n
u
e
De
m
d
Æ
e
r
g

a
s

i
n

r
e
l
a
t
e

P
l
a
n
t
Re
v
e
n
u
e
De
m
d
Æ
e
r
g

f
r
m

P
r
o
u
c
t
i
o
n

P
l
a
n
t
De
m
a
n
d
/
C
u
o
m
e
r

f
r
m

D
i
s
t
b
u
t
i
o
n

P
l
a
n
t
De
m
a
d
De
i
n
n
e
r
g

f
r
m

P
r
o
u
c
t
i
o
n

P
l
a
n
t
De
C
u
s
t
m
e
r

f
r
m

D
i
s
t
b
u
t
i
o
n

P
l
a
n
t
De
m
a
d
Æ
e
r

f
r
m

P
r
o
u
c
t
i
o
n

P
l
a
n
t
De
m
a
e
r
g

f
r
m

T
r
a
i
u
s
s
o
n

P
l
a
n
t
De
d
/
C
u
s
t
m
e
r

f
r
m

D
i
s
t
b
u
t
i
o
n

P
l
a
n
t
De
d
/
e
r
g

f
r
m

P
r
o
u
c
t
i
o
n

P
l
a
n
t
De
m
a
d
De
m
a
d
Æ
r
g

f
r
m

P
r
o
u
c
t
i
o
n

P
l
a
n
t
De
i
n
n
e
r
g

f
r
m

T
r
a
s
s
o
n

P
l
a
n
t
De
d
/
C
u
m
e

f
r
m

D
i
s
t
b
u
t
i
o
n

P
l
a
n
t
Cu
s
t
m
e
r
Cu
s
t
m
e
r
En
e
r
En
e
r
g
/
C
u
s
t
m
e
r

b
y

C
o
i
p

C
o
s
t

A
l
o
c
t
o
r
Al
l
o
c
a
t
i
o
n
SO

i

S
u
m

o
f

Pr
o
u
c
t
i
o
n

P
l
a
n
t
S0
2

S
u

o
f

Tr
a
n
s
s
s
o
n

Pl
a
n
t
S0
3

S
u
m

o
f

Dis
t
b
u
t
i
o
n

Pl
a
n
t
CO

i

A
l
l

C
u
s
t
m
e
r
s

u
n
w
e
i
g
h
t
e
d
S2
3

2
5
%

d
i
r
e
t

O
&
M
,

2
5
%

d
i
r
e
t

l
a
b
o
r
,

2
5
%

n
e
t

d
i
r
e
t

p
l
a
n
t
,

2
5
%

n
u
m
b
e
r

o
f

c
u
s
t
m
e
r
E0
2

A
n
u
a
l

G
e
n
e
r
a
t
i
o
n

L
e
e
l

C
o
n
s
t
i
o
n
RO

i

R
e
t
a
l

S
a
l
e
s

R
e
v
e
n
u
e
SO

1
/
S
0
2
/
S
2
3

S
u
m

o
f

Pr
o
u
c
t
i
o
n

P
l
a
n
t

1

S
u
m

o
f

Tr
a
S
l
s
s
o
n

P
l
a
n
t

1

C
o
i
p

C
o
s
t

A
l
l
o
c
t
o
r
DO

1
Æ
0
2

C
o
i
n
c
i
d
e
n
t

P
e
a
k

D
e
m
a
d
/
A
n
u
a

G
e
n
e
r
t
i
o
n

L
e
e
l

C
o
n
s
m
p
t
i
o
n
DO

1
Æ
0
2

C
o
i
n
c
i
d
e
n
t

P
e
a
k

D
e
m
a
d
/
A
n
u
a

G
e
n
e
r
t
i
o
n

L
e
e
l

C
o
n
s
m
p
t
i
o
n
D0
2
1
D
3
1
D
4
1
D
5
I
D
0
6
1
D
7
1
D
8
/
C
0
2
/
C
0
4
/
C
0
5

-

S
e
e

R
e
l
a
t
e

P
l
a
n
t
S2
3

2
5
%

d
i
r
e
t

O
&
M

2
5
%

d
i
r
e
t

l
a
b
o
r
,

2
5
%

n
e
t

d
i
r
e
t

p
l
a
n
t
,

2
5
%

n
u
m
b

o
f

c
u
m
e
r
SO

1
/
S
0
2
/
S
0
3
/
S
0
4

S
u

o
f

Pr
o
u
c
t
i
o
n

1

T
r
a
s
s
o
n

1

D
i
s
t
b
u
t
i
o
n

1

G
e
n
e
r
a

P
l
a
n
t
D0
1
Æ
0
2

C
o
i
n
c
i
d
e
n
t

Pe
a

De
A
n
u
a

G
e
n
e
r
t
i
o
n

L
e
e
l

C
o
n
s
m
p
t
i
o
n
DO

1
Æ
0
2

C
o
i
n
c
i
d
e
n
t

P
e
a

D
e
A
n

G
e
n
e
r
t
i
o
n

L
e
e
l

C
o
n
s
m
p
t
i
o
n
S0
3

S
u
m

o
f

Di
s
t
b
u
t
i
o
n

P
l
a
n
t
R0
3

R
e
v
e
n
u
e

l
e
s
s

E
x
n
s
s

B
e
f
o
r
e

I
n
c
o
m
e

T
a
x
e
s

l
e
s
s

I
n
t
e
s
t

E
x
p
e
n
s
R0
3

R
e
v
e
n
u
e

l
e
s
s

E
x
p
s

B
e
f
o
r
e

I
n
c
o
m
e

T
a
x
e
s

l
e
s

I
n
t
e

E
x
p
e
n
s
R0
3

R
e
v
e
n
u
e

l
e
s
s

E
x
p
n
s
s

B
e
f
o
r

I
n
c
o
m
e

T
a
x
e
s

l
e
s
s

I
n
t
e
r
e
s
t

E
x
p
e
n
s
DO

1
Æ
2

C
o
i
n
c
i
d
e
t

P
e
a
k

D
e
A
n

G
e
n
e
r
a
t
i
o
n

L
e
e
l

C
o
n
s
u
t
i
o
n
In
t
SO
L
S0
3
DO
l
SO
L
S0
3
SO
L
S0
2
S0
3
SO
L
DO
l
Pr
o

F
o
n
u
a

R
e
v
e
n
u
e

p
e

R
e
v
e
n
e

S
t
u
d
y
Su
m

o
f

Pr
o
u
c
t
i
o
n

P
l
a
n
t
Su
m

o
f

Di
s
t
b
u
t
i
o
n

P
l
a
n
t
Co
i
n
c
i
d
e
n
t

P
e
a

D
e
d
Su
m

o
f

Pr
o
u
c
t
i
o
n

P
l
a
n
t
Su
m

o
f

Di
s
t
b
u
t
i
o
n

Pl
a
n
t
Su
m

o
f

Pr
o
u
c
t
i
o
n

P
l
a
n
t
Su

o
f

Tr
a
s
s
o
n

P
l
a
n
t
Su
m

o
f

Dis
t
b
u
t
i
o
n

Pl
a
n
t
Su

o
f

Pr
o
u
c
t
i
o
n

P
l
a
n
t
Co
i
n
c
i
d
e
n
t

P
e
a
k

D
e
m
d
SO
L

S
u
m

of

Pr
o
u
c
t
i
o
n

Pl
a
n
t
S0
2

S
u
m

o
f

Tr
a
s
s
o
n

P
l
a
n
t
S0
3

S
u
m

o
f

Di
s
t
b
u
t
i
o
n

Pl
a
n
t
S1
8

S
u
m

o
f

Ot
h
e
r

C
u
s
t
m
e
r

A
c
c
u
n
t
s

E
x
s

E
x
c
l
u
d
i
n
g

U
n
c
o
l
l
e
c
t
i
b
l
e
s
CO

1

A
l
l

C
u
s
t
e
r

u
n
g
h
t
e
E0
2

A
n
l

G
e
n
e
r
t
i
o
n

L
e
e
l

C
o
n
s
t
i
o
n
S2
3

2
5
%

d
i
r
e
t

O
&
M
,

2
5
%

d
i
t

l
a
b
o
r
,

2
5
%

n
e
t

d
i
r
e
t

p
l
a
n
t
,

2
5
%

n
u

o
f

c
u
s
t
m
e
r
Ex
h
b
i
t

No
.

14
Ca
s
e

No
.

A
V
U
-
E
-
0
8
-
0
1
T.

K
n
o
x
,

A
v
i
s
t
Sc
h
e
u
l
e

2
,

p
.

9
0
f
9
Sumcost AVIST A UTILITIES Idaho Jurisdiction
Scenario: Company Base Case Cost of Service Basic Summary Electc Utiit 03-18-08
AVU-E-04-01 Method For the Year Ended December 31, 2007
(b)(c)(d)(e)(n (g)(h)(i)0)(k)(I)(m)
Residential General Large Gen Exta Large Extra Large Pumping Street &
System Service Service Service Gen Service Service PoUatch Service Area Lights
Description Total Sch 1 Schll.12 Sch 21-22 Sch25 Sch 25P Sch 31.32 Sch 41-49
Plant In Service
1 Production Plant 349,419,000 123,948,683 35,008,568 70,179,596 30,627,751 82,600,694 5,905,485 1,148,222
2 Transmission Plant 153,519,000 53,811,223 15,204,909 30,833,976 13,554,024 36,979,568 2,608,315 526,984
3 Distribution Plant 365,131,000 183,065,950 58,338,616 83,921,796 11,469,208 2,105,462 8,085,480 18,144,488
4 Intangible Plant 23,nO,000 9,447,400 2,548,292 4,458,737 1,844,839 4,897,055 398,384 175,291
5 General Plant 55,533,000 29,356,229 7,246,227 8,430,323 2,672,657 5,946,234 890,769 990,562
6 Total Plant In Service 947,372,000 399,629,485 118,34,611 197,824,428 60,168,480 132,529,014 17,888,433 20,985,548
Accum Depreciation
7 Producton Plant (134,749,000)(47,635,747)(13,456,014) (27,063,925) (11,835,886)(32,028,093)(2,280,844)(448,491)
8 Transmission Plant (51,662,000)(18,108,478)(5,116,735) (10,376,207)(4,561,181)(12,44,313)(877,747)(17,340)
9 Distributon Plant (111,662,000)(55,324,436)(16,812,884) (25,432,107)(3,115,642)(574,733)(2,316,497)(8,085,701)
10 Intangible Plant (4,540,000)(2,198,979)(556,724)(743,985)(263,667)(637,755)(73,927)(64,963)
11 General Plant (24,058,000)(12,717,702)(3,139,210)(3,652,183)(1,157,848)(2,576,027)(385,899)(429,131)
12 Total Accumulated Depreciation (326,671,000) (135,985,342)(39,081,567) (67,268,407) (20,934,224)(48,260,921)(5,934,914)(9,205,626)
13 Net Plant 620,701,000 263,64,143 79,265,044 130,556,021 39,234,257 84,268,094 11,953,519 11,n9,923
14 Accumulated Deferred FIT (88,531,000)(37,017,203)(10,836,262) (18,236,718)(5,810,553)(13,221,784)(1,643,787)(1,764,693)
15 Miscellaneous Rate Base 16,096,00 5,212,821 1,535,993 3,392,291 1,503,131 4,118,703 278,963 54,097
16 Total Rate Base 548,266,000 231,839,762 69,96,n5 115,711,593 34,926,835 75,165,013 10,588,696 10,069,327
17 Revenue From Retail Rates 193,270,00 75,282,000 24,573,000 40,085,000 13,077,000 34,045,000 3,690,000 2,518,000
18 Other Operating Revenues 31,389,000 11,319,081 3,221,092 6,342,676 2,678,443 7,125,315 537,623 164,77
19 Total Revenues 224,659,000 86,601,081 27,794,092 46,427,676 15,755,443 41,170,315 4,227,623 2,682,77
Operating Expnses
20 Production Expenses 118,970,000 41,385,697 11,697,037 23,894,986 10,551,358 28,993,533 2,028,014 419,375
21 Transmission Expenses 8,348,000 2,926,127 826,807 1,676,679 737,036 2,010,861 141,834 28,656
22 Distibution Expnses 8,537,000 4,069,514 1,138,788 2,003,212 34,837 70,502 156,467 749,679
23 Customer Accounting Expnses 3,291,000 2,465,581 547,061 127,538 28,470 72,962 41,367 8,021
24 Customer Information Expenses 1,518,000 649,075 165,574 259,923 112,222 302,587 24,160 4,459
25 Sales Expenses 276,000 92,283 26,119 55,436 25,041 71,235 4,784 1,103
26 Admin & General Expenses 20,109,000 10,345,438 2,612,430 3,195,884 1,006,053 2,252,631 330,565 365,998
27 Total O&M Expenses 161,049,000 61,933,715 17,013,815 31,213,658 12,809,018 33,774,312 2,727,191 1,577,291
28 Taxes Other Than Income Taxes 6,413,000 2,544,288 749,790 1,335,626 458,229 1,099,714 118,113 107,239
29 Oter Income Related Items (158,000)(59,188)(16,687)(31,733)(13,375)(34,004)(2,604)(410)
Depreciation Exense
30 Production Plant Depreciation 9,073,000 3,237,319 914,179 1,822,274 792,430 2,124,699 152,941 29,157
31 Transmission Plant Depreciation 3,112,000 1,090,813 308,220 625,039 274,755 749,617 52,873 10,683
32 Distribution Plant Depreciation 9,159,000 4,502,933 1,488,388 2,199,909 320,557 50,232 210,580 386,400
33 General Plant Depreciation 3,842,000 2,030,984 501,324 583,244 184,905 411,385 61,627 68,531
34 Amortzation Expnse 637,000 229,264 64,722 127,938 55,337 147,064 10,696 1,978
35 Total Depreciation Expnse 25,823,00 11,091,314 3,276,834 5,358,04 1,627,984 3,482,997 488,718 496,750
36 Income Tax 4,290,000 1,013,249 1,528,184 1,582,752 (132,046)61,225 185,417 51,219
37 Total Operating Expenses 197,417,000 76,523,379 22,551,936 39,458,708 14,749,810 38,384,244 3,516,834 2,232,089
38 Net Income 27,242,000 10,077,702 5,242,156 6,968,968 1,005,633 2,786,071 710,789 450,682
39 Rate of Return 4.97%4.35%7.49%6.02%2.88%3.71%6.71%4.48%
40 Return Ratio 1.00 0.87 1.51 1.21 0.58 0.75 1.35 0.90
41 Interest Expense 19,518,000 8,253,382 2,490,712 4,119,276 1,243,378 2,675,837 376,952 358,463
Exhibit No. 14
Case No. AW-E-08-01
r. Knox, Avista
Schedule 3, p. 1 of 3
Sumcest AVISTA UTILITIES Idaho Jurisdiction
Scenario: Company Base Case Revenue to Cost by Functional Component Summary Electric Utiit 03.18-08
AVU-E.04.01 Method For the Year Ended December 31, 2007
0
(b)(c)(d)(e)(0 (g)(h)(i)ü)(k)(I)(m)
Residential General Large Gen Exta Large Extra Large Pumping Street &
System Service Service Service Gen Service Service Potlatch Service Area Lights
Description Total Sch 1 Sch 11-2 Sch 21.22 Sch25 Sch25P Sch 31-32 Sch 41-49
Functional Cost Components at Currnt Retum by Schedule
1 Production 117,314,335 40,313,386 12,416,443 24,385,897 9,873,346 27,806,569 2,107,399 411,296
2 Transmission 15,109,239 5,099,767 1,871,804 3,387,609 1,Hl5,369 3,291,359 302,n6 50,555
3 Distribution 38,245,594 18,043,94 7,197,848 8,811,528 1,050,641 579,955 905,478 1,656,202
4 Common 22,600,832 11,824,903 3,086,906 3,499,967 1,047,645 2,367,116 374,347 399,948
5 Total Current Rate Revenue 193,270,000 75,282,000 24,573,000 40,085,00 13,077,00 34,045,000 3,690,000 2,518,000
Expressed as $IkWh
6 Production $0.03421 $0.03546 $0.03859 $0.03563 $0.03128 $0.03096 $0.03576 $0.03028
7 Transmission $0.00441 $0.0049 $0.00582 $0.00495 $0.00350 $0.00366 $0.00514 $0.00372
8 Distribution $0.01115 $0.01587 $0.02237 $0.01288 $0.00333 $0.005 $0.01537 $0.12193
9 Common $0.00659 $0.01040 $0.00959 $0.00511 $0.00332 $0.00264 $0.0035 $0.0294
10 Total Current Melded Rates $0.05636 $0.06623 $0.07638 $0.05858 $0.04143 $0.03790 $0.06262 $0.18537
Functional Cost Components at Uniform Currnt Return
11 Producton 117,995,190 41,028,867 11,596,359 23,699,203 10,467,579 28,774,853 2,011,773 416,556
12 Transmission 15,409,177 5,401,199 1,526,164 3,09,902 1,360,459 3,711,754 261,805 52,895
13 Distribution 37,241,883 19,145,624 5,738,999 7,950,640 1,300,608 618,486 764,953 1,722,572
14 Common 22,623,750 11,959,519 2,952,061 3,434,454 1,088,821 2,422,454 362,893 403,548
15 Total Uniform Current Cost 193,270,000 77,535,210 21,813,583 38,179,198 14,217,468 35,527,546 3,401,424 2,595,571
Exressed as $/kh
16 Production $0.0341 $0.03609 $0.03604 $0.034 $0.03316 $0.03203 $0.0314 $0.03067
17 Transmission $0.0049 $0.00475 $0.00474 $0.00452 $0.00431 $0.00413 $0.0044 $0.00389
18 Distribution $0.01086 $0.01684 $0.01784 $0.01162 $0.00412 $0.0009 $0.01298 $0.12681
19 Common $0.0060 $0.01052 $0.00918 $0.00502 $0.00345 $0.00270 $0.00616 $0.02971
20 Total Current Uniform Melded Rates $0.05636 $0.06821 $0.06780 $0.05579 $0.04504 $0.03955 $0.05n2 $0.19108
21 Revenue to Cos Ratio at Currnt Rates 1.00 0.97 1.13 1.05 0.92 0.96 1.08 0.97
Functional Cost Components at Proposed Return by Schedule
22 Producton 130,110,384 44,338,438 13,646,603 26,818,145 11,018,412 31,535,243 2,313,306 440,238
23 Transmission 20,514,455 6,n6,019 2,384,762 4,412,867 1,591,n6 4,895,805 390,013 63,213
24 Distribution 50,830,925 24,169,376 9,361,742 11,825,050 1,527,225 727,466 1,204,470 2,015,596
25 Common 24,142,236 12,589,166 3,290,894 3,733,938 1,127,587 2,581,486 399,211 419,953
26 Total Proposed Rate Revenue 225,598,00 87,873,000 28,684,000 46,790,000 15,265,000 39,740,000 4,307,000 2,939,000
Expressed as $/Wh
27 Producton $0.03794 $0.03901 $0.04242 $0.03919 $0.03491 $0.03511 $0.03926 $0.03241
28 Transmission $0.00598 $0.00596 $0.00741 $0.00645 $0.00504 $0.00545 $0.00662 $0.0065
29 Distibuton $0.01482 $0.02126 $0.02910 $0.01728 $0.0084 $0.00081 $0.0204 $0.14839
30 Common $0.00704 $0.01108 $0.01023 $0.00546 $0.00357 $0.00287 $0.00677 $0.03092
31 Total Proposed Melded Rates $0.06579 $0.07730 $0.08916 $0.06837 $0.04836 $0.0424 $0.07309 $0.21637
Functional Cost Components at Uniform Requestd Return
32 Producton 130,308,838 45,394,422 12,829,408 26,172,357 11,547,280 31,688,330 2,219,937 457,104
33 Transmission 20,600,662 7,220,909 2,040,341 4,137,601 1,818,810 4,962,276 350,009 70,716
34 Distrbution 50,497,809 25,795,375 7,908,043 11,015,458 1,749,698 733,558 1,067,261 2,22,416
35 Common 24,190,691 12,787,846 3,156,524 3,672,327 1,164,234 2,590,235 388,027 431,498
36 Total Uniform Cost 225,598,000 91,198,552 25,934,316 44,997,742 16,280,022 39,974,399 4,025,234 3,187,735
Expressed as $/kWh
37 Producton $0.03800 $0.03993 $0.03988 $0.03825 $0.03658 $0.03528 $0.03767 $0.03365
38 Transmission $0.00601 $0.0035 $0.00634 $0.00605 $0.00576 $0.00552 $0.00594 $0.00521
39 Distrbuton $0.01473 $0.02269 $0.02458 $0.01610 $0.00554 $0.00082 $0.01811 $0.16405
40 Common $0.0705 $0.01125 $0.00981 $0.00537 $0.0069 $0.00288 $0.0058 $0.0317
41 Total Uniform Melded Rates $0.06579 $0.08023 $0.08061 $0.06575 $0.05158 $0.040 $0.06831 $0.23468
42 Revenue to Cos Ratio at Proposd Rat 1.00 0.96 1.11 1.04 0.94 0.99 1.07 0.92
43 Current Revnue to Propos Cos Ratio 0.86 0.83 0.95 0.89 0.80 0.85 0.92 0.79
Exhibit No. 14
Case No. AVU-E-QS-01
T. Knox, Avista
Schedule 3, p. 2 of 3
Sumcost AVISTAUTILITIES Idaho Jurisdiction
Scenario: Company Base Case Revenue to Cost By Classification Summary Electc Utilit 03.18.08
AVU.E-D-D1 Method For the Year Ended December 31 , 2007
0
(b)(c)(d)(e)(n (g)(h)(i)ü)(k)(i)(m)
Residential General Large Gen Exa Large Exta Large Pumping Street &
System Service Service Service Gen Service Service Potlatch Service Area Lights
Description Total Sch 1 Sch 11-2 Sch 21-22 Sch25 Sch 25P Sch 31-32 Sch 41-49
Cost Classifications at Currnt Return by Schedule
1 Energy 106,334,253 35,159,428 10,881,403 22,172,428 9,124,553 26,623,905 1,950,780 421,757
2 Demand 69,137,127 27,848,290 10,237,132 17,427,091 3,946,973 7,420,441 1,449,996 807,205
3 Customer 17,798,620 12,274,282 3,454,465 485,481 5,474 654 289,224 1,289,038
4 Total Current Rate Revenue 193,270,00 75,282,000 24,573,000 40,085,000 13,077,000 34,045,000 3,690,00 2,518,000
Expressd as Unit Cost
5 Energy $/kWh $0.03101 $0.03093 $0.03382 $0.03240 $0.02891 $0.0296 $0.03311 $0.03105
6 Demand $//mo $8.69 $9.23 $10.68 $9.52 $6.62 $5.41 $10.18 $19.69
7 Customer $/CusVmo $12.54 $10.55 $15.51 $28.66 $35.09 $54.53 $19.19 $854.23
Cost Classifications at Uniform Currnt Return
8 Energy 107,098,144 35,809,128 10,135,170 21,511,023 9,716,872 27,641,706 1,856,335 427,911
9 Demand 68,533,320 29,083,623 8,705,851 16,232,748 4,492,959 7,885,43 1,292,795 840,300
10 Customer 17,638,536 12,642,458 2,972,562 435,427 7,637 798 252,295 1,327,360
11 Total Uniform Current Cost 193,270,000 77,535,210 21,813,583 38,179,198 14,217,468 35,527,546 3,401,424 2,595,571
Expressed as Unit Cost
12 Energy $/h $0.03123 $0.03150 $0.03150 $0.03143 $0.03079 $0.03077 $0.03150 $0.03150
13 Demand $/W/mo $8.61 $9.64 $9.09 $8.87 $7.53 $5.75 $9.07 $20.50
14 Customer $/CusVmo $12.42 $10.87 $13.35 $25.70 $48.95 $66.8 $16.74 $879.63
15 Revenue to Cost Raio at Currnt Rates 1.00 0.97 1.13 1.05 0.92 0.96 1.08 0.97
Cost Classifications at Propose Return by Schedule
16 Energy 118,738,279 38,812,046 12,000,099 24,512,943 10,264,753 30,538,985 2,153,931 455,521
17 Demand 85,820,646 34,729,336 12,512,866 21,616,404 4,990,656 9,199,815 1,785,187 986,383
18 Customer 21,039,076 14,331,618 4,17,035 660,653 9,591 1,201 367,883 1,497,096
19 Total Proposed Rate Revenue 225,598,000 87,873,000 28,684,000 46,790,000 15,265,000 39,740,000 4,307,00 2,939,000
Expressd as Unit Cost
20 Energy $/h $0.03463 $0.03414 $0.03730 $0.03582 $0.03252 $0.0300 $0.03655 $0.03353
21 Demand $//mo $10.79 $11.51 $13.06 $11.81 $8.37 $6.71 $12.53 $24.06
22 Customer $/CusVmo $14.82 $12.32 $18.73 $38.99 $61.48 $100.06 $24.41 $992.11
Cost Classifications at Uniform Requeste Return
23 Energy 118,947,168 39,770,945 11,256,495 23,890,939 10,791,918 30,699,903 2,061,714 475,254
24 Demand 85,506,864 36,552,591 10,986,989 20,493,223 5,476,588 9,273,273 1,631,695 1,092,504
25 Customer 21,143,968 14,875,016 3,690,832 613,581 11,516 1,223 331,825 1,619,976
26 Total Uniform Cost 225,598,000 91,198,552 25,934,316 44,997,742 16,280,022 39,974,399 4,025,234 3,187,735
Expressed as Unit Cost
27 Energy $/kWh $0.03469 $0.03499 $0.03499 $0.03491 $0.03419 $0.03418 $0.03499 $0.03499
28 Demand $/k/mo $10.75 $12.11 $11.47 $11.19 $9.18 $6.77 $11.45 $26.65
29 Customer $/CusVmo $14.89 $12.79 $16.57 $36.22 $73.82 $101.94 $22.02 $1,073.54
30 Revenue to Cost Ratio at Propos Rates 1.00 0.96 1.11 1.04 0.94 0.99 1.07 0.92
31 Current Revenue to Proposd Cos Ratio 0.86 0.83 0.95 0.89 0.80 0.85 0.92 0.79
Exhibit No. 14
Case No. AVU-E-08-1
T. Knox, Avista
Schedule 3, p. 3 of 3
NATUR GAS COST OF SERVICE STUDY
A cost of serce study is an engieerng-economic study, which apportions the revenue,
expenses, and rate base associated with providing natual gas servce to designated groups of
customers. It indicates whether the revenue provided by the customers recovers the cost to sere
those customers. The study results are used as a guide in determining the appropriate rate spread
among the groups of customers.
There are three basic steps involved in a cost of serce study: functionalization,
classification, and allocation. See flow char.
First, the expenses and rate base associated with the natual gas system under study are
assigned to fuctional categories. The uniform system of accounts provides the basic segregation
into production, underground storage, and distrbution. Traditionally customer accounting,
customer information, and sales expenses are included in the distrbution fuction and
administrative and general expenses and general plant rate base are allocated to all fuctions. In
ths study I have created a separate fuctional category for common costs. Administrative and
general costs that canot be directly assigned to the other fuctions have been placed in ths
category.
Second, the expenses and rate base items are classified into thee primar cost components:
Demand, commodity or customer related. Demand (capacity) related costs are allocated to rate
schedules on the basis of each schedule's contrbution to system peak demand. Commodity
(energy) related costs are allocated based on each rate schedule's share of commodity
consumption. Customer related items are allocated to rate schedules based on the number of
customers withn each schedule. The number of customers may be weighted by appropriate factors
such as relative cost of metering equipment. In addition to these thee cost components, any
revenue related expense is allocated based on the proportion of revenues by rate schedule.
Exhbit No. 14
Case No. AVU-G-08-01
T. Knox, Avista
Schedule 4, p. 1 of9
NATURAL GAS COST OF SERVICE STUDY FLOWCHART
Production /
Purchased Gas
Cost
Distribution and
Customer Relations
Underground
Storage Common
Energy I
Commodity
Related
Demand I Customer Related
Capacity Related
Residential Interruptible Transportation
Pro Forma Results of Operations by Customer Group
Exhbit No. 14
Case No. A VU-G-08-01
T. Knox, A vista
Schedule 4, p. 2of9
The final step is allocation of the costs to the varous rate schedules utilizing the allocation
factors selected for each specific cost item. These factors are derived from usage and customer
information associated with the test period results of operations.
BASE CASE COST OF SERVICE STUDY
Production - Purchased Gas Costs
The Company has no natual gas production facilities serving the Idaho jursdiction. The
natural gas costs included in the production function include the cost of gas purchased to serve
sales customers, pipeline transportation to get it to our system, and expenses of the gas supply
deparent.
The demand and commodity components of account 804 have been determined directly
from the weighted average cost of gas (W ACOG) approved in the most recent purchased gas
adjustment (pGA) fiing effective November 1, 2007. The allocation of these costs agrees with the
gas costs computation used to deterne pro forma results of operations.
The expenses of the gas supply deparent recorded in account 813 are classified as
commodity related costs. The gas scheduling process includes transportation customers, so
estimated scheduling dispatch labor expenses are allocated by throughput. The remaining gas
supply deparent expenses are allocated by sales volumes.
Underground Storage
Underground storage rate base, operating and maitenance expenses are classified as
commodity related and allocated to customer groups by winter thoughput. This approach was
proposed by commission Staff and accepted by the Idaho Public Utilities Commission in Case No.
A VU-G-04-0 1.
Exhbit No. 14
Case No. A VU-G-08-01
T. Knox, A vista
Schedule 4, p. 3 of9
Distribution Facilties Classifcation (peak and Average)
Distrbution mais and regulator station equipment (both general use and city gate stations)
are classified Demand and Commodity using the peak and average ratio for the distrbution system.
Peak demand is defined as the average of the five~day sustained peaks from the most recent three
years. Average daily load is calculated by dividing anual throughput by 365 (days in the year).
The average daily load is divided by peak load to arve at the system load factor of 38%. This
proportion is classified as commodity related. The remaining 62% is classified as demand related.
Meters, serices and industral measurg & regulating equipment are classified as customer
related distribution plant. Distrbution operating and maintenance expenses are classified (and
allocated) in relation to the plant accounts they are associated with.
Customer Relations Distribution Cost Classification
Customer service, customer information and sales expenses are the core of the customer
relations functional unit which is included with the distrbution cost category. For the most par
these costs are classified as customer related. Exceptions include uncollectible accounts expense,
which is considered separately as a revenue conversion item, and Demand Side Management
amortization expense recorded in Account 908. The demand side management investment costs
and amortization expense are included with the distrbution fuction and classified to demand and
commodity by the peak and average ratio.
Distribution Cost Alocation
Demand related distrbution costs are allocated to customer groups (rate schedules) by each
groups' contrbution to the thee year average five-day sustained peak. Commodity related
distrbution costs are allocated to customer groups by annual throughput. Distrbution main
investment has been segregated into large and small mains. Small mains are defined as less than
four inches, with large mains being four inches or greater. The small main costs use the same
Exhbit No. 14
Case No. A VU-G-08-01
T. Knox, Avista
Schedule 4, p. 4 of 9
demand and commodity data, but large usage customers (Schedules 121, 131, and 146) that
connect to large, system mains have been excluded from the allocations.
Most customer related costs are allocated by the anualized number of customers biled
durng the test period. Meter investment costs are allocated using the number of customers
weighted by the relative current cost of meters in serice at December 31, 2007. Serces
investment costs are allocated using the number of customers weighted by the relative current cost
of tyical servce installations. Industral measurng and regulating equipment investment costs are
allocated by number of customers excluding the small usage customer groups (Schedulesl0l and
111).
Admiistrative and General Costs
General and intangible rate base items are allocated by the sum of Underground Storage
and Distrbution plant. Administrative and general expenses are segregated into plant related,
labor related, revenue related and other. The plant related items are allocated based on total plant
in service. Labor related items are allocated by operating and maintenance labor expense.
Revenue related items are allocated by pro forma revenue. Other administrative and general
expenses are allocated 50% by anual thoughput (classified commodity related) and 50% by the
sum of operating and maintenance expenses not including purchased gas cost or administrative &
general expenses. Whenever costs are allocated by sums of other items withn the study,
classifications are imputed from the relationship embedded in the sumed items.
Special Contract Customer Revenue
Thee special contract customers receive transportation servce from the Company. Rates
for these customers were individually negotiated to cover any incremental costs and retain some
contrbution to margin. The rates for these customers are not being adjusted in ths case. The
revenue from these special contract customers has been segregated from general rate revenue and
Exhbit No. 14
Case No. A VU-G-08-01
T. Knox, Avista
Schedule 4, p. 5 of 9
allocated back to all the other rate classes by relative rate base. In treating these revenues like
other operating revenues their system contrbution reduces costs for all rate schedules.
Revenue Conversion Items
In this study uncollectible accounts and commission fees have been classified as revenue
related and are allocated by pro forma revenue. These items var with revenue and are included in
the calculation of the revenue conversion factor. Income tax expense items are allocated to
schedules by net income before income tax less interest expense.
For the fuctional sumares on pages 2 and 3 of the cost of serce study, these items are
assigned to the component cost categories. The revenue related expense items have been reduced
to a percent of all other costs and loaded onto each cost category b that ratio. Similarly, income tax
items have been assigned to cost categories by relative rate base (as is net income).
The following matrx outlines the methodology applied in the Company Base Case natual
gas cost of servce study.
Exhbit No. 14
Case No. A VU-G-08-01
T. Knox, A vista
Schedule 4, p. 6 of 9
IP
U
C

C
a
s
e

N
o
.

A

V
U
-
G
-
u
8
-
u

1

M
e
t
h
o
d
o
l
o
g
y

M
a
t
r
x
Av
i
t
a

U
t
i
l
i
t
i
e
s

I
d
a
o

J
u
r
s
d
i
c
t
i
o
n
Na
t
u
r
a
l

G
a
s

C
o
s
t

o
f

S
e
r
v
c
e

M
e
t
h
o
d
o
l
o
g
y
Ac
c
u
n
t
Un
d
e
r
g
r
o
u
n
d

S
t
o
r
a
g
e

P
l
a
n
t
35
0

-

3
5
7

U
n
d
e
r
g
r
o
u
n
d

S
t
o
r
a
g
e
Di
s
t
r
i
b
u
t
i
o
n

P
l
a
n
t
37
4

L
a
d
37
5

S
t
r
c
t
u
e
s
37
6
(
S
)

S
m
a

M
a
i
s
37
6
(
L
)

L
a
g
e

M
a
i
37
8

M
&
R

G
e
n
e
r
a
l
37
9

M
&
R

C
i
t
y

G
a
t
e
38
0

S
e
r
c
e
s
38
1

M
e
t
e
r
s
38
5

h
i
d
u
s
t
r
a
l

M
&
R
38
7

O
t
h
e
r
Ge
n
e
r
a
l

P
l
a
n
t
38
9
-
3
9
9

A
l
l

G
e
n
e
r
a
l

P
l
a
n
t
In
t
a
n
g
i
b
l
e

P
l
a
n
t
30
3

M
i
s
c

h
i
t
a
g
i
b
l
e

P
l
a
n
t
30
3

C
o
m
p
u
t
e
r

S
o
f
t
a
r
e
Re
s
e
r
v
e

f
o
r

D
e
p
r
e
c
i
a
t
i
o
n
Un
d
e
r
g
r
o
u
n
d

S
t
o
r
a
g
e
Di
s
t
r
i
b
u
t
i
o
n
Ge
n
e
r
a
l
hi
t
a
n
g
i
b
l
e
Ot
h
e
r

R
a
t
e

B
a
s
e
Ac
c
w
n
u
l
a
t
e
d

D
e
f
e
r
r
e
d

F
I
T
Co
n
s
t
u
c
t
i
o
n

A
d
v
a
c
e
s
Ga
s

h
i
v
e
n
t
o
r
y
Ga
i
n

o
n

S
a
l
e

o
f

Of
f
c
e

B
l
d
g
DS
M

h
i
v
e
s
t
m
e
n
t
Pu
r
c
h
a
s
e
d

G
a
s

E
x
p
e
n
s
e
s
80
4

P
u
c
h
e
d

G
a
s

C
o
s
t
81
3

O
t
e
r

G
a
s

E
x
p
e
n
s
e
s
Un
d
e
r
g
r
o
u
n
d

S
t
o
r
a
g
e

O
&
M
8
1
4

-

8
3
7

U
n
d
e
r
g
r
o
u
n
d

S
t
o
r
a
g
e

E
x
p
Fu
n
c
t
i
o
n
a
l

C
a
t
e
g
o
r
y
Un
d
e
r
g
r
o
u
n
d

S
t
o
r
a
g
e
Di
s
t
r
i
b
u
t
i
o
n
Di
s
t
r
b
u
t
i
o
n
Di
s
t
r
b
u
t
i
o
n
Di
s
t
r
b
u
t
i
o
n
Di
s
t
r
b
u
t
i
o
n
Di
s
t
r
b
u
t
i
o
n
Di
s
t
r
b
u
t
i
o
n
Di
s
t
r
i
b
u
t
i
o
n
Di
s
t
r
b
u
t
i
o
n
Di
s
t
r
b
u
t
i
o
n
Co
m
m
o
n
Di
s
t
r
b
u
t
i
o
n
Co
m
m
o
n
Un
d
e
r
g
r
o
u
n
d

S
t
o
r
a
g
e
Di
s
t
r
b
u
t
i
o
n
Co
m
m
o
n
Di
s
t
r
b
u
t
i
o
n
/
C
o
m
m
o
n
Al
l
Di
s
t
r
b
u
t
i
o
n
Un
d
e
r
g
r
o
u
n
d

S
t
o
r
a
g
e
Co
m
m
o
n
Di
s
t
r
b
u
t
i
o
n
Pr
o
d
u
c
t
i
o
n
Pr
o
d
u
c
t
i
o
n
Un
d
e
r
g
r
o
u
n
d

S
t
o
r
a
g
e
Cl
a
s
s
i
f
i
c
a
t
i
o
n
Co
m
m
o
d
i
t
y
De
m
a
n
d
/
C
o
m
m
o
d
i
t
y
/
C
u
s
t
o
m
e
r

f
r
o
m

O
t
h
e
r

D
i
s
t

P
l
a
n
t
De
m
a
n
d
/
C
o
m
m
o
d
i
t
y
/
C
u
s
t
o
m
e
r

f
r
o
m

O
t
h
e
r

D
i
s
t

P
l
a
n
t
De
m
a
n
d
/
C
o
m
m
o
d
i
t
y

b
y

P
e
a
k

&

A
v
e
r
a
g
e
De
m
a
n
d
/
C
o
m
m
o
d
i
t
y

b
y

P
e
a
k

&

A
v
e
r
a
g
e
De
m
a
n
d
/
C
o
m
m
o
d
i
t
y

b
y

P
e
a
k

&

A
v
e
r
a
g
e
De
m
a
n
d
/
C
o
m
m
o
d
i
t
y

b
y

P
e
a
k

&

A
v
e
r
a
g
e
Cu
s
t
o
m
e
r
Cu
s
t
o
m
e
r
Cu
s
t
o
m
e
r
De
m
a
d
/
C
o
m
m
o
d
i
t
y
/
C
u
s
t
o
m
e
r

f
r
o
m

O
t
h
e
r

D
i
s
t

P
l
a
n
t
De
m
a
n
d
/
C
o
m
m
o
d
i
t
y
/
C
u
s
t
o
m
e
r

f
r
o
m

U
G

&

D

P
l
a
n
t
De
m
a
n
d
/
C
o
m
m
o
d
i
t
y
/
C
u
s
t
o
m
e
r

f
r
o
m

D
i
s
t

P
l
a
n
t
De
m
a
n
d
/
C
o
m
m
o
d
i
t
y
/
C
u
s
t
o
m
e
r

f
r
o
m

U
G

&

D

P
l
a
n
t
Co
m
m
o
d
i
t
y

s
a
m
e

a
s

r
e
l
a
t
e
d

p
l
a
n
t
De
m
a
d
/
C
o
m
m
o
d
i
t
y
/
C
u
s
t
o
m
e
r

s
a
m
e

a
s

r
e
l
a
t
e
d

p
l
a
n
t
De
m
a
n
d
/
C
o
m
m
o
d
i
t
y
/
C
u
s
t
o
m
e
r

s
a
m
e

a
s

r
e
l
a
t
e
d

p
l
a
n
t
De
m
a
n
d
/
C
o
m
m
o
d
i
t
y
/
C
u
s
t
o
m
e
r

s
a
m
e

a
s

r
e
l
a
t
e
d

p
l
a
n
t
De
m
a
n
d
/
C
o
m
m
o
d
i
t
y
/
C
u
s
t
o
m
e
r

f
r
o
m

P
l
a
n
t

i
n

S
e
r
v
c
e
Cu
s
t
o
m
e
r
Co
m
m
o
d
i
t
y

f
r
o
m

U
n
d
e
r
g
r
o
u
n
d

S
t
o
r
a
g
e

P
l
a
t
De
m
a
n
d
/
C
o
m
m
o
d
i
t
y
/
C
u
s
t
o
m
e
r

f
r
o
m

U
G

&

D

P
l
a
n
t
De
m
a
n
d
/
C
o
m
m
o
d
i
t
y

b
y

P
e
a
k

&

A
v
e
r
a
g
e
De
m
a
n
d
/
C
o
m
m
o
d
i
t
y

f
r
o
m

P
G
A

T
r
a
c
k
e
r

W
A
C
O
G
Co
m
m
o
d
i
t
y
Co
m
m
o
d
i
t
y
Al
l
o
c
a
t
i
o
n
E0
8

W
i
n
t
e
r

t
h
r
o
u
g
h
p
u
t
S0
5

S
w
n

o
f

ac
c
u
n
t
s

3
7
6
-
3
8
5
S0
5

S
w
n

o
f

a
c
c
u
n
t
s

3
7
6
-
3
8
5
D0
2
Æ
0
6

C
o
i
n
c
i
d
e
n
t

p
e
a
k

a
n
u
a

t
h
e
n
n
s

(
b
o
t
h

e
x
c
1

1
9

u
s
e

c
u
s
t
)
DO
l
l
E
O
l

C
o
i
n
c
i
d
e
n
t

p
e
a
k

(
a
l
l
)
,

a
n
u
a

t
h
o
u
g
h
p
u
t

(
a
l
l
)
DO
l
l
E
O
l

C
o
i
n
c
i
d
e
n
t

p
e
a
k

(
a
l
l
)
,

a
n
u
a

t
h
o
u
g
h
p
u
t

(
a
l
l
)
DO
l
l
E
O
l

C
o
i
n
c
i
d
e
n
t

p
e
a
k

(
a
l
l
)
,

a
n
u
a

t
h
o
u
g
h
p
u
t

(
a
l
l
)
C0
2
,

C
u
s
t
o
m
e
r
s

w
e
i
g
h
t
e
d

b
y

c
u
e
n
t

t
y
i
c
a

s
e
r
v
c
e

c
o
s
t
C0
3
,

C
u
s
t
o
m
e
r
s

w
e
i
g
h
t
e
d

b
y

av
e
r
a
g
e

c
u
e
n
t

m
e
t
e
r

c
o
s
t
C0
6
,

L
a
g
e

u
s
e

c
u
s
t
o
m
e
r
s
S0
5

S
w
n

o
f

a
c
c
u
n
t
s

3
7
6
-
3
8
5
S0
3

S
w
n

o
f

Un
d
e
r
g
r
o
u
n
d

S
t
o
r
a
g
e

a
n
d

D
i
s
t
r
b
u
t
i
o
n

P
l
a
n
t

i
n

S
e
r
c
e
S1
5

S
w
n

o
f

Di
s
t
r
i
b
u
t
i
o
n

P
l
a
n
t

i
n

S
e
r
v
c
e
S0
3

S
w
n

o
f

Un
d
e
r
g
r
o
u
n
d

S
t
o
r
a
g
e

a
n
d

D
i
s
t
r
b
u
t
i
o
n

P
l
a
n
t

i
n

S
e
r
v
c
e
Al
l
o
c
a
t
i
o
n
s

l
i
n
e
d

t
o

r
e
l
a
t
e
d

p
l
a
n
t

a
c
c
u
n
t
s
Al
l
o
c
a
t
i
o
n
s

l
i
n
e
d

t
o

r
e
l
a
t
e
d

p
l
a
n
t

a
c
c
u
n
t
s
Al
l
o
c
a
t
i
o
n
s

l
i
n
e
d

t
o

r
e
l
a
t
e
d

p
l
a
n
t

a
c
c
u
n
t
s
Al
l
o
c
a
t
i
o
n
s

l
i
n
e
d

t
o

r
e
l
a
t
e
d

p
l
a
t

a
c
c
u
n
t
s
S1
7

S
w
n

o
f

To
t
a

P
l
a
t

i
n

S
e
r
v
c
e
CL
O

R
e
s
i
d
e
n
t
i
a
l

o
n
l
y
S1
4

S
w
n

o
f

Un
d
e
r
g
r
o
u
n
d

S
t
o
r
a
g
e

P
l
a
t

i
n

S
e
r
v
c
e
S0
3

S
w
n

o
f

Un
d
e
r
g
r
o
u
n
d

S
t
o
r
a
g
e

a
n
d

D
i
s
t
r
b
u
t
i
o
n

P
l
a
n
t

i
n

S
e
r
v
c
e
DO
l
l
E
O
l

C
o
i
n
c
i
d
e
n
t

p
e
a
k

(
a
l
l
)
,

a
n
u
a
l

t
h
o
u
g
h
p
u
t

(
a
l
l
)
D0
5
1
E
0
7

P
G
A

D
e
m
a
n
d

/

P
G
A

C
o
m
m
o
d
i
t
y
EO

l
l
E
0
4

A
n
u
a
l

T
h
o
u
g
h
p
u
t

/

A
n
u
a

S
a
l
e
s

T
h
e
r
B0
8

W
i
n
t
e
r

t
h
o
u
g
h
p
u
t
Ex
h
b
i
t

No
.

14
Ca
s
e

No
.

A
V
U
-
G
-
0
8
-
0
1
T.

K
n
o
x
,

A
v
i
s
t
Sc
h
e
d
u
l
e

4
,

p
.

7

o
f
9
lP
U
C

C
a
s
e

N
o
.

A

V
U
-
G
-
U
8
-
U
L

M
e
t
h
o
d
o
l
o
g
y

M
a
t
r
x
Av
i
s
t
a

U
t
i
l
i
t
i
e
s

I
d
o

J
u
r
s
d
i
c
t
i
o
n
Na
t
u
r
a
l

G
a
s

C
o
s
t

o
f

Se
r
v
c
e

M
e
t
h
o
d
o
l
o
g
y
Ac
c
u
n
t
Di
s
t
r
i
b
u
t
i
o
n

O
&
M
87
0

O
P

S
u
p
e
r

&

E
n
g
i
e
e
r
i
g
87
1

L
o
a
d

D
i
s
p
a
t
c
h
g
87
4

M
a
i
s

&

S
e
r
v
c
e
s
87
5

M
&
R

S
t
a
t
i
o
n

-

G
e
n
e
r
a
l
87
6

M
&
R

S
t
a
t
i
o
n

-

I
n
d
u
s
t
r
a
l
87
7

M
&
R

S
t
a
t
i
o
n

-

C
i
t
y

G
a
t
e
87
8

M
e
t
e
r

&

H
o
u
s
e

R
e
g
u
l
a
t
o
r
87
9

C
u
s
t
o
m
e
r

I
n
s
t
a
l
l
a
t
i
o
n
s
88
0

O
t
h
e
r

O
P

E
x
p
e
n
s
e
s
88
1

R
e
n
t
s
88
5

M
T

S
u
p
e
r

&

E
n
g
i
e
e
r
i
g
88
6

M
T

o
f

S
t
r
c
t
u
r
e
s
88
7

M
T

o
f

Ma
i
s
88
9

M
T

o
f
M
&
R

G
e
n
e
r
a
l
89
0

M
T

o
f
M
&
R

I
n
d
u
s
t
i
a
l
89
1

M
T

o
f
M
&
R

C
i
t
y

G
a
t
e
89
2

M
T

o
f

S
e
r
c
e
s
89
3

M
T

o
f

Me
t
e
r
s

&

H
s

R
e
g
89
4

M
T

o
f

Ot
h
e
r

E
q
u
i
p
m
e
n
t
Cu
s
t
o
m
e
r

A
c
c
o
u
n
t
i
n
g

E
x
p
e
n
s
e
s
90

1

S
u
p
e
r
v
s
i
o
n
90
2

M
e
t
e
r

R
e
a
d
i
g
90
3

C
u
s
t
o
m
e
r

R
e
c
o
r
d
s

&

C
o
l
l
e
c
t
i
o
n
s
90
4

U
n
c
o
l
l
e
c
t
i
b
l
e

A
c
c
u
n
t
s
90
5

M
i
s
c

C
u
s
t

A
c
c
u
n
t
s
Cu
s
t
o
m
e
r

S
e
r
v
i
c
e

&

I
n
f
o

E
x
p
e
n
s
e
s
90
7

S
u
p
e
r
v
s
i
o
n
90
8

C
u
s
t
o
m
e
r

A
s
s
i
s
t
a
c
e
90
8

D
S
¥

A
m
o
r
t
z
a
t
i
o
n
90
9

A
d
v
e
r
t
s
i
n
g
91
0

M
i
s
c

C
u
s
t

S
e
r
v
c
e

&

I
n
f
o
Sa
l
e
s

E
x
p
e
n
s
e
s
91
1

-

9
1
6

S
a
l
e
s

E
x
p
e
n
s
e
s
Fu
n
c
t
i
o
n
a
l

C
a
t
e
g
o
r
y
Di
s
t
r
i
b
u
t
i
o
n
Di
s
t
r
i
b
u
t
i
o
n
Di
s
t
r
i
b
u
t
i
o
n
Di
s
t
r
i
b
u
t
i
o
n
Di
s
t
r
b
u
t
i
o
n
Di
s
t
r
b
u
t
i
o
n
Di
s
t
r
b
u
t
i
o
n
Di
s
t
r
b
u
t
i
o
n
Di
s
t
r
i
b
u
t
i
o
n
Di
s
t
r
b
u
t
i
o
n
Di
s
t
r
b
u
t
i
o
n
Di
s
t
r
b
u
t
i
o
n
Di
s
t
r
b
u
t
i
o
n
Di
s
t
r
b
u
t
i
o
n
Di
s
t
i
b
u
t
i
o
n
Di
s
t
i
b
u
t
i
o
n
Di
s
t
r
b
u
t
i
o
n
Di
s
t
r
b
u
t
i
o
n
Di
s
t
r
b
u
t
i
o
n
Cu
s
t
o
m
e
r

R
e
l
a
t
i
o
n
s
Cu
s
t
o
m
e
r

R
e
l
a
t
i
o
n
s
Cu
s
t
o
m
e
r

R
e
l
a
t
i
o
n
s
Re
v
e
n
u
e

C
o
n
v
e
r
s
i
o
n
Cu
s
t
o
m
e
r

R
e
l
a
t
i
o
n
s
Cu
s
t
o
m
e
r

R
e
l
a
t
i
o
n
s
Cu
s
t
o
m
e
r

R
e
l
a
t
i
o
n
s
Di
s
t
r
b
u
t
i
o
n
Cu
s
t
o
m
e
r

R
e
l
a
t
i
o
n
s
Cu
s
t
o
m
e
r

R
e
l
a
t
i
o
n
s
Cu
s
t
o
m
e
r

R
e
l
a
t
i
o
n
s
Cl
a
s
s
i
f
i
c
a
t
i
o
n
Al
l
o
c
a
t
i
o
n
De
m
a
n
d
/
C
o
m
m
o
d
i
t
y
/
C
u
s
t
o
m
e
r

f
r
o
m

D
i
s
t

P
l
a
n
t

S
i
S

S
u
m

o
f

D
i
s
t
r
b
u
t
i
o
n

P
l
a
n
t

i
n

S
e
r
v
c
e
Co
m
m
o
d
i
t
y

E
O

1

A
n
u
a
l

t
h
r
o
u
g
h
p
u
t
De
m
a
n
d
/
C
o
m
m
o
d
i
t
y
/
C
u
s
t
o
m
e
r

f
r
o
m

r
e
l
a
t
e
d

p
l
a
n
t

S
0
6

S
u
m

o
f

Ma
i
n
s

a
n
d

S
e
r
v
c
e
s

P
l
a
n
t

i
n

S
e
r
v
c
e
De
m
a
n
d
/
C
o
m
m
o
d
i
t
y

f
r
o
m

r
e
l
a
t
e
d

p
l
a
n
t

S
0
8

S
u
m

o
f
M
e
a

&

R
e
g

S
t
a
t
i
o
n

-

G
e
n
e
r
a
l

P
l
a
n
t

i
n

S
e
r
v
c
e
Cu
s
t
o
m
e
r

f
r
o
m

r
e
l
a
t
e
d

p
l
a
n
t

S

i

9

S
u
m

o
f

Me

as

&

R
e
g

S
t
a
t
i
o
n

-

I
n
d
u
s
t
r
a
l

P
l
a
n
t

i
n

S
e
r
v
c
e
De
m
a
n
d
/
C
o
m
m
o
d
i
t
y

f
r
o
m

r
e
l
a
t
e
d

p
l
a
n
t

S
0
9

S
u
m

o
f

Me

as

&

R
e
g

S
t
a
t
i
o
n

-

C
i
t
y

G
a
t
e

P
l
a
n
t

i
n

S
e
r
v
c
e
Cu
s
t
o
m
e
r

f
r
o
m

r
e
l
a
t
e
d

p
l
a
n
t

S
0
7

S
u
m

o
f

Me
t
e
r

a
n
d

I
n
t
a
l
l
a
t
i
o
n

P
l
a
n
t

i
n

S
e
r
v
c
e
Cu
s
t
o
m
e
r

C
O
S
,

C
u
s
t
o
m
e
r
s

w
e
i
g
h
t
e
d

b
y

av
e
r
a
g
e

c
u
e
n
t

m
e
t
e
r

c
o
s
t
De
m
a
n
d
/
C
o
m
m
o
d
i
t
y
/
C
u
s
t
o
m
e
r

f
r
o
m

o
t
h
e
r

d
i
s
t

e
x
p
e
n
s
e

S
0
4

S
u
m

o
f

A
c
c
u
n
t
s

8
7
0

-

8
7
9

a
n
d

8
8
1

-

8
9
4
De
m
a
n
d
/
C
o
m
m
o
d
i
t
y
/
C
u
s
t
o
m
e
r

f
r
o
m

o
t
h
e
r

d
i
s
t

e
x
p
e
n
s
e

S
0
4

S
u
m

o
f

A
c
c
u
n
t
s

8
7
0

-

8
7
9

a
n
d

8
8
1

-

8
9
4
De
m
a
n
d
/
C
o
m
m
o
d
i
t
y
/
C
u
s
t
o
m
e
r

f
r
o
m

D
i
s
t

P
l
a
n
t

S
i
S

S
u
m

o
f

D
i
s
t
r
b
u
t
i
o
n

P
l
a
n
t

i
n

S
e
r
v
c
e
De
m
a
n
d
/
C
o
m
m
o
d
i
t
y
/
C
u
s
t
o
m
e
r

f
r
o
m

O
t
h
e
r

D
i
s
t

P
l
a
n
t

S
0
5

S
u
m

o
f

ac
c
u
n
t
s

3
7
6
-
3
8
5
De
m
a
n
d
/
C
o
m
m
o
d
i
t
y

f
r
o
m

r
e
l
a
t
e
d

p
l
a
n
t

S
2
l

S
u
m

o
f

Di
s
t
r
b
u
t
i
o
n

M
a
i
s

P
l
a
t

i
n

S
e
r
v
c
e
De
m
a
n
d
/
C
o
m
m
o
d
i
t
y

f
r
o
m

r
e
l
a
t
e
d

p
l
a
n
t

S
0
8

S
u
m

o
f

Me

as

&

R
e
g

S
t
a
t
i
o
n

-

G
e
n
e
r
a
l

P
l
a
n
t

i
n

S
e
r
v
c
e
Cu
s
t
o
m
e
r

f
r
o
m

r
e
l
a
t
e
d

p
l
a
n
t

S

1
9

S
u
m

o
f

Me

as

&

R
e
g

S
t
a
t
i
o
n

-

I
n
d
u
s
t
r
a
l

P
l
a
n
t

i
n

S
e
r
v
c
e
De
m
a
d
/
C
o
m
m
o
d
i
t
y

f
r
o
m

r
e
l
a
t
e
d

p
l
a
n
t

S
0
9

S
u
m

o
f

Me

as

&

R
e
g

S
t
a
t
i
o
n

-

C
i
t
y

G
a
t
e

P
l
a
n
t

i
n

S
e
r
v
c
e
Cu
s
t
o
m
e
r

f
r
o
m

r
e
l
a
t
e
d

p
l
a
n
t

S
2
0

S
u
m

o
f

S
e
r
v
c
e
s

P
l
a
n
t

i
n

S
e
r
c
e
s
Cu
s
t
o
m
e
r

f
r
o
m

r
e
l
a
t
e
d

p
l
a
n
t

S
0
7

S
u
m

o
f

Me
t
e
r

a
n
d

I
n
s
t
a
l
l
a
t
i
o
n

P
l
a
n
t

i
n

S
e
r
v
c
e
De
m
a
n
d
/
C
o
m
m
o
d
i
t
y
/
C
u
s
t
o
m
e
r

f
r
o
m

D
i
s
t

P
l
a
n
t

S
i
S

S
u
m

o
f

Di
s
t
b
u
t
i
o
n

P
l
a
t

i
n

S
e
r
v
c
e
Cu
s
t
o
m
e
r
Cu
s
t
o
m
e
r
Cu
s
t
o
m
e
r
Re
v
e
n
u
e
Cu
s
t
o
m
e
r
CO
L

A
l
l

c
u
s
t
o
m
e
r
s

(
u
n
w
e
i
g
h
t
e
d
)
CO
l

A
l
l

c
u
s
t
o
m
e
r
s

(
u
n
w
e
i
g
h
t
e
d
)
CO
L

A
l
l

c
u
t
o
m
e
r
s

(
u
n
w
e
i
g
h
t
e
d
)
R0
3

R
e
t
a
i
l

S
a
l
e
s

R
e
v
e
n
u
e
CO
L

A
l
l

c
u
s
t
o
m
e
r
s

(
u
n
w
e
i
g
h
t
e
d
)
Cu
s
t
o
m
e
r
Cu
s
t
o
m
e
r
De
m
a
n
d
/
C
o
m
m
o
d
i
t
y

b
y

P
e
a
k

&

A
v
e
r
a
g
e
Cu
s
t
o
m
e
r
Cu
s
t
o
m
e
r
CO
L

A
l
l

c
u
s
t
o
m
e
r
s

(
u
n
w
e
i
g
h
t
e
d
)
CO
L

A
l

c
u
t
o
m
e
r
s

(
u
n
w
e
i
g
h
t
e
d
)
DO
l
/
E
O
l

C
o
i
n
c
i
d
e
n
t

p
e
a

(
a
l
l
)
,

a
n
u
a

t
h
o
u
g
h
p
u
t

(
a
l
l
)
CO
L

A
l
l

c
u
t
o
m
e
r
s

(
u
n
w
e
i
g
h
t
e
d
)
CO
L

A
l
l

c
u
s
t
o
m
e
r
s

(
u
n
w
e
i
g
h
t
e
d
)
Cu
s
t
o
m
e
r
CO
L

A
l
l

c
u
s
t
o
m
e
r
s

(
u
n
w
e
i
g
h
t
e
d
)
Ex
h
b
i
t

No
.

1
4
Ca
s
e

N
o
.

A

V
U
-
O
-
0
8
-
0

1
T.

K
n
o
x
,

A
v
i
s
t
Sc
h
e
d
u
l
e

4
,

p
.

8

o
f
9
IP
U
C

C
a
s
e

N
o
.

A
V
U
-
G
-
û
8
-
û
l

M
e
t
h
o
d
o
l
o
g
y
M
a
t
r
i
x
Av
i
s
t
a

U
t
i
l
i
t
i
e
s

I
d
a
h
o

J
u
r
i
s
d
i
c
t
i
o
n
Na
t
u
a
l

G
a
s

C
o
s
t

o
f

Se
r
v
c
e

M
e
t
h
o
d
o
l
o
g
y
Ac
c
u
n
t
Fu
c
t
i
o
n
a
l

C
a
t
e
g
o
r
y
Cl
a
s
s
i
f
i
c
a
t
i
o
n
Al
l
o
c
a
t
i
o
n
Ad
m
i
n

&

G
e
n
e
r
a
l

E
x
p
e
n
s
e
s
92
0

S
a
l
e
s
92
1

O
f
f
c
e

S
u
p
p
l
i
e
s
92
3

O
u
t
s
i
d
e

S
e
r
v
c
e
s
92
4

P
r
o
p
e
r
t

I
n
s
u
r
a
n
c
e
92
5

I
n
j
u
r
i
e
s

&

D
a
m
g
e
s
92
6

P
e
n
s
i
o
n
s

&

B
e
n
e
f
i
t
s
92
7

F
r
a
n
c
h
i
s
e

R
e
q
u
i
e
m
e
n
t
s
92
8

R
e
g
u
a
t
o
r
y

C
o
m
m
s
i
o
n
92
8

C
o
m
m
s
s
i
o
n

F
e
e
s
93
0

M
i
s
c
e
l
l
a
n
e
o
u
s

G
e
n
e
r
a
l
93
1

R
e
n
t
s
93
5

M
T

o
f

Ge
n
e
r
a
l

P
l
a
t
De
p
r
e
c
i
a
t
i
o
n

E
x
p
e
n
s
e
Un
d
e
r
g
r
o
u
n
d

S
t
o
r
a
g
e
Di
s
t
r
i
b
u
t
i
o
n
Ge
n
e
r
a
l
In
t
a
n
g
i
b
l
e
Ta
x
e
s
Pr
o
p
e
r
t

T
a
x
Mi
s
c
e
l
l
a
n
e
o
u
s

D
i
s
t

T
a
x
St
a
t
e

I
n
c
o
m
e

T
a
x
Fe
d
e
r
a
l

I
n
c
o
m
e

T
a
x
De
f
e
r
r
e
d

F
I
T
IT
C
Op
e
r
a
t
i
n
g

R
e
v
e
n
u
e
s
Re
v
e
n
u
e

f
r
o
m

R
a
t
e
s
Sp
e
c
i
a
l

C
o
n
t
r
a
c
t

R
e
v
e
n
u
e
Of
f

Sy
s
t
e
m

S
a
l
e
s
Mi
s
c
e
l
l
a
n
e
o
u
s

S
e
r
v
c
e

R
e
v
e
n
u
e
Re
n
t

F
r
o
m

G
a
s

P
r
o
p
e
r
t
Ot
h
e
r

G
a
s

R
e
e
n
u
e
Co
m
m
o
n
Co
m
m
o
n
Co
m
m
o
n
Co
m
m
o
n
Co
m
m
o
n
Co
m
m
o
n
Co
m
m
o
n
Co
m
m
o
n
Re
v
e
n
u
e

C
o
n
v
e
r
s
i
o
n
Co
m
m
o
n
Co
m
m
o
n
Co
m
m
o
n
Un
d
e
r
g
r
o
u
n
d

S
t
o
r
a
g
e
Di
s
t
r
b
u
t
i
o
n
Co
m
m
o
n
Di
s
t
r
b
u
t
i
o
n
/
C
o
m
m
o
n
Al
l Di
s
t
r
b
u
t
i
o
n
Re
v
e
n
u
e

C
o
n
v
e
r
s
i
o
n
Re
v
e
n
u
e

C
o
n
v
e
r
s
i
o
n
Re
e
n
u
e

C
o
n
v
e
r
s
i
o
n
Re
v
e
n
u
e

C
o
n
v
e
r
s
i
o
n
Re
v
e
n
u
e
Al
l
Pr
o
d
u
c
t
o
n
Cu
s
t
o
m
e
r

R
e
l
a
t
i
o
n
s
Al
l
Un
d
e
r
g
r
o
u
n
d

S
t
o
r
a
g
e
De
m
a
n
d
/
C
o
m
m
o
d
i
t
y
/
C
u
s
t
o
m
e
r

f
r
o
m

O
t
h
e
r

O
&
M
De
m
a
n
d
/
C
o
m
m
o
d
i
t
y
/
C
u
s
t
o
m
e
r

f
r
o
m

O
t
h
e
r

O
&
M
De
m
a
n
d
/
C
o
m
m
o
d
i
t
y
/
C
u
s
t
o
m
e
r

f
r
o
m

O
t
h
e
r

O
&
M
De
m
a
n
d
/
C
o
m
m
o
d
i
t
y
/
C
u
s
t
o
m
e
r

f
r
o
m

P
l
a
n
t

i
n

S
e
r
v
c
e
De
m
a
n
d
/
C
o
m
m
o
d
i
t
y
/
C
u
s
t
o
m
e
r

f
r
o
m

O
t
h
e
r

O
&
M
De
m
a
n
d
/
C
o
m
m
o
d
i
t
y
/
C
u
s
t
o
m
e
r

f
r
o
m

L
a
b
p
r

O
&
M
De
m
a
n
d
/
C
o
m
m
o
d
i
t
y
/
C
u
s
t
o
m
e
r

f
r
o
m

O
t
h
e
r

O
&
M
De
m
a
n
d
/
C
o
m
m
o
d
i
t
y
/
C
u
s
t
o
m
e
r

f
r
o
m

O
t
h
e
r

O
&
M
Re
v
e
n
u
e
De
m
a
n
d
/
C
o
m
m
o
d
i
t
y
/
C
u
s
t
o
m
e
r

f
r
o
m

O
t
h
e
r

O
&
M
De
m
a
n
d
/
C
o
m
m
o
d
i
t
y
/
C
u
s
t
o
m
e
r

f
r
o
m

O
t
h
e
r

O
&
M
De
m
a
n
d
/
C
o
m
m
o
d
i
t
y
/
C
u
s
t
o
m
e
r

f
r
o
m

P
l
a
n
t

i
n

S
e
r
v
c
e
Co
m
m
o
d
i
t
y

s
a
m
e

a
s

r
e
l
a
t
e
d

p
l
a
n
t
De
m
a
n
d
/
C
o
m
m
o
d
i
t
y
/
C
u
s
t
o
m
e
r

s
a
m
e

a
s

r
e
l
a
t
e
d

p
l
a
n
t
De
m
a
n
d
/
C
o
m
m
o
d
i
t
y
/
C
u
s
t
o
m
e
r

s
a
m
e

a
s

r
e
l
a
t
e
d

p
l
a
n
t
De
m
a
n
d
/
C
o
m
m
o
d
i
t
y
/
C
u
s
t
o
m
e
r

s
a
m
e

a
s

r
e
l
a
t
e
d

p
l
a
n
t
De
m
a
n
d
/
C
o
m
m
o
d
i
t
y
/
C
u
s
t
o
m
e
r

f
r
o
m

r
e
l
a
t
e
d

p
l
a
n
t
De
m
a
n
d
/
C
o
m
m
o
d
i
t
y
/
C
u
s
o
m
e
r

f
r
o
m

D
i
s
t

P
l
a
n
t
Re
v
e
n
u
e
Re
v
e
n
u
e
Re
v
e
n
u
e
Re
v
e
n
u
e
Re
v
e
n
u
e
De
m
a
n
d
/
C
o
m
m
o
d
i
t
y
/
C
u
s
t
o
m
e
r

f
r
o
m

R
a
t
e

B
a
s
e
Co
m
m
o
d
i
t
y

f
r
o
m

P
G
A

T
r
a
c
k
e
r
Cu
s
t
o
m
e
r
De
m
d
/
C
o
m
m
o
d
i
t
y
/
C
u
s
t
o
m
e
r

f
r
o
m

R
a
t
e

B
a
s
e
Co
m
m
o
d
i
t
y

f
r
o
m

U
n
d
e
r
g
r
o
u
n
d

S
t
o
r
a
g
e

P
l
a
n
t
S0
2
f
E
O
I

5
0
%

O
&
M

e
x
c
l

G
a
s

P
u
r
c
h
a
s
e
s

a
n
d

A
&
G

/
5
0
%

t
h
o
u
g
h
u
t
S0
2
/
E

i

5
0
%

O
&
M

e
x
c
l

G
a
s

P
u
r
c
h
a
s
e
s

a
n
d

A
&
G

/

5
0
%

t
h
o
u
g
h
p
u
t
S0
2
l
0
1

5
0
%

O
&
M

e
x
c
l

G
a
s

P
u
r
c
h
a
s
e
s

a
n
d

A
&
G

/

5
0
%

t
h
o
u
g
h
p
u
t
S
i

7

S
u
m

o
f

T
o
t
a

P
l
a
n
t

i
n

S
e
r
v
c
e
S0
2
l
0

i

5
0
%

O
&
M

e
x
c
l

G
a
s

P
u
c
h
a
s
e
s

a
n
d

A
&
G

/

5
0
%

t
h
r
o
u
g
h
p
u
t
S1
3

O
&
M

L
a
b
o
r

E
x
p
e
n
s
e
SO
Z
f
E
O
l

5
0
%

O
&
M

e
x
c
l

G
a
s

P
u
r
c
h
s
e
s

a
n
d

A
&
G

/
5
0
%

t
h
o
u
g
h
p
u
t
SO
Z
f
E
O
l

5
0
%

O
&
M

e
x
c
l

G
a
s

P
u
r
c
h
a
s
e
s

a
n
d

A
&
G

/

5
0
%

t
h
o
u
g
h
p
u
t
RO

1

R
e
t
a
i
l

S
a
l
e
s

R
e
v
e
n
u
e
S0
2
l
0

1

5
0
%

O
&
M

e
x
c
l

G
a
s

P
u
c
h
e
s

a
n
d

A
&
G

/

5
0
%

t
h
o
u
g
h
p
u
t
SO
Z
f
E
O
I

5
0
%

O
&
M

e
x
c
l

G
a
s

P
u
c
h
e
s

a
n
d

A
&
G

/

5
0
%

t
h
o
u
g
h
p
u
t
S
1
7

S
u
m

o
f

To
t
a
l

P
l
a
n
t

i
n

S
e
r
v
c
e
Al
l
o
c
a
t
i
o
n
s

l
i
n
e
d

t
o

r
e
l
a
t
e
d

p
l
a
n
t

a
c
c
u
n
t
s
Al
l
o
c
a
t
i
o
n
s

l
i
n
e
d

t
o

r
e
l
a
t
e
d

p
l
a
t

a
c
c
u
n
t
s
Al
l
o
c
a
t
i
o
n
s

l
i
n
k
e
d

t
o

r
e
l
a
t
e
d

p
l
a
n
t

a
c
c
u
n
t
s
Al
l
o
c
a
t
i
o
n
s

l
i
n
e
d

t
o

r
e
l
a
t
e
d

p
l
a
t

a
c
c
u
n
t
s
S1
4
/
S
l
5
/
S
1
6

S
u
m

o
f
U
G

P
l
a
n
t
/
S
u
m

o
f
D
i
s
t

P
l
a
n
t
/
S
u
m

o
f
G
e
n

P
l
a
t
Si
S

S
u
m

o
f

Di
s
t
r
b
u
t
i
o
n

P
l
a
n
t

i
n

S
e
r
v
c
e
RO
Z

N
e
t

I
n
c
o
m
e

b
e
f
o
r
e

T
a
x
e
s

l
e
s
s

I
n
t
e
r
e
s
t

E
x
p
e
n
s
e
RO
Z

N
e
t

I
n
c
o
m
e

b
e
f
o
r
e

T
a
x
e
s

l
e
s
s

I
n
t
e
r
e
s
t

E
x
p
e
n
s
e
RO
Z

N
e
t

I
n
c
o
m
e

b
e
f
o
r
e

T
a
x
e
s

l
e
s
s

I
n
t
e
r
e
s
t

E
x
p
e
n
s
e
RO
Z

N
e
t

I
n
c
o
m
e

b
e
f
o
r
e

T
a
x
e
s

l
e
s
s

I
n
t
e
r
e
s
t

E
x
p
e
n
s
e
Pr
o

F
o
r
m

R
e
v
e
n
u
e

p
e
r

R
e
v
e
n
u
e

S
t
u
d
y
SO
L

S
u
m

o
f

Ra
t
e

B
a
s
e
E0
4

S
a
l
e
s

T
h
e
r
m
s
CO
L

A
l
l

c
u
s
t
o
m
e
r
s

(
u
n
w
e
i
g
h
t
e
d
)
SO
L

S
u
m

of
Ra
t
e

Ba
s
e
S1
4

S
u
m

o
f

Un
d
e
r
g
r
o
u
n
d

S
t
o
r
a
g
e

P
l
a
n
t

i
n

S
e
r
c
e
Ex
h
b
i
t

N
o
.

1
4
Ca
s

N
o
.

A

V
U
-
G
-
0
8
-
O

1
T.

K
n
o
x
,

A
v
i
s
t
Sc
h
e
u
l
e

4
,

p
.

9

o
f
9
Sumcost AVISTA UTILITIES Natural Gas Utilty
Company Base Case Cost of Service General Summary Idaho Jurisdicton 24-Mar-08
AVU-G-D4-01 Method For the Year Ended December 31, 2007
(b)(c)(d)(e)(f)(g)(h)(i)G)(k)
Residential Small Firm Large Firm Interrpt Transport
System Service Service Service Service Service
Descrption Total Sch 101 Sch 111 Sch 121 Sch 131 Sch 146
Plant In Service
1 Producton Plant
2 Underground Storage Plant 8,709,000 6,588,047 1,677,480 143,935 34,633 264,905
3 Distrbuton Plant 121,478,000 102,470,164 16,129,186 1,414,545 338,017 1,126,088
4 Intangible Plant 1,281,000 1,074,031 174,572 15,283 3,654 13,461
5 General Plant 10,990,000 9,206,370 1,503,186 131,562 31,458 117,424
6 Total Plant In Service 142,458,000 119,338,613 19,484,424 1,705,325 407,762 1,521,877
Accm Depreciation
7 Production Plant
8 Underground Storage Plant (3,066,000)(2,319,319)(590,556)(50,672)(12,192)(93,260)
9 Distribution Plant (41,788,000)(35,326,980)(5,416,809)(514,266)(128,603)(401,342)
10 Intangible Plant (445,000)(372,907)(60,778)(5,320)(1,272)(4,724)
11 General Plant (3,644,000)(3,052,595)(498,418)(43,623)(10,431)(38,935)
12 Total Accmulated Depreciation (48,943,000)(41,071,800)(6,566,561 )(613,880)(152,498)(538,260)
13 Net Plant 93,515,000 78,266,813 12,917,862 1,091,444 255,263 983,617
14 Accmlulated Deferrd FIT (14,155,000)(11,857,797)(1,936,023)(169,446)(40,516)(151,218)
15 Miscellaneous Rate Base 6,330,000 4,759,473 1,237,389 108,280 25,729 199,129
16 Total Rate Base 85,690,000 71,168,489 12,219,228 1,030,278 240,476 1,031,529
17 Revenue From Retail Rates 81,860,000 63,207,000 15,950,000 1,919,000 367,000 417,000
18 Other Operating Revenues 252,000 209,451 35,817 3,025 707 3,000
19 Total Revenues 82,112,000 63,416,451 15,985,817 1,922,025 367,707 420,000
Operating Expenses
20 Purchased Gas Costs 61,321,000 46,178,952 13,140,727 1,676,123 320,330 4,868
21 Underground Storage Expenses 174,000 131,625 33,515 2,876 692 5,293
22 Distribution Expenses 3,535,000 2,938,902 445,279 82,368 12,436 56,015
23 Customer Accunting Expenses 1,770,000 1,710,934 52,761 4,446 830 1,030
24 Customer Information Expenses 232,000 205,050 20,476 2,256 447 3,771
25 Sales Expenses 212,000 209,593 2,359 30 3 15
26 Admin & General Expenses 4,440,000 3,549,883 669,330 88,156 17,327 115,304
27 Total O&M Expenses 71,684,000 54,924,938 14,364,447 1,856,255 352,065 186,295
28 Taxes Other Than Income Taxes 702,000 584,294 98,612 8,615 2,061 8,417
29 Depreciation Expense
30 Underground Storage Plant Depr 152,000 114,983 29,277 2,512 604 4,623
31 Distrbution Plant Depreciation 2,618,000 2,250,371 308,465 31,864 5,173 22,128
32 General Plant Depreciation 683,000 572,152 93,419 8,176 1,955 7,298
33 Amortzation of Intangible Plant 234,000 196,046 31,990 2,800 669 2,495
34 Total Depr & Amort Expense 3,687,000 3,133,551 463,151 45,352 8,402 36,543
35 Income Tax 1,572,000 1,178,319 328,573 (13,089)(1,780)79,977
36 Total Operating Expenses 77,645,000 59,821,103 15,254,783 1,897,133 360,748 311,233
37 Net Income 4,467,000 3,595,347 731,033 24,893 6,959 108,768
38 Rate of Return 5.21%5.05%5.98%2.42%2.89%10.54%
39 Return Ratio 1.00 0.97 1.15 0.46 0.56 2.02
40 Interest Expense 3,051,000 2,636,146 336,763 37,765 6,307 34,020
Exhibit No. 14
Case No. AVU-G-QS-Q1
T. Knox, Avista
Schedule 5, p. 1 of 3
Sumcost AVISTA UTILITIES Natural Gas Utilty
Company Base Case Summary by Function with Margin Analysis Idaho Jurisdiction 24-ar-Q8
AVU-G-Q4-1 Method For the Year Ended December 31, 2007
(b)(c)(d)(e)(f)(g)(h)(i)0)(k)
Residential Small Firm Large Firm Interrpt Transport
Sysem Service Service Service Service Service
Description Total Sch 101 Sch 111 Sch 121 Sch 131 Sch 146
Functional Cost Components at Current Rates
1 Production 61,613,790 46,399,443 13,203,470 1,684,126 321,859 4,891
2 Underground Storage 1,189,584 846,332 257,529 8,445 2,472 72,805
3 Distribution 13,397,259 11,392,635 1,649,516 130,672 23,111 201,325
4 Common 5,659,368 4,566,590 839,465 95,757 19,558 137,979
5 Total Current Rate Revenue 81,860,000 63,207,000 15,950,000 1,919,000 367,000 417,000
6 Exclude Cost of Gas w I Revenue Exp.61,210,875 46,099,857 13,118,219 1,673,252 319,547 0
7 Total Margin Revenue at Current Rates 20,649,125 17,107,143 2,831,781 245,748 47,453 417,000
Margin per Therm at Current Rates
8 Production $0.005292 $0.005494 $0.005494 $0.005494 $0.005494 $0.001326
9 Underground Storage $0.015624 $0.015556 $0.016596 $0.004267 $0.005872 $0.019741
10 Distribution $0.175957 $0.208912 $0.106297 $0.066018 $0.05497 $0.054590
11 Common $0.074329 $0.083740 $0.054098 $0.048378 $0.046457 $0.037413
12 Total Currnt Margin Melded Rate per Then $0.271202 $0.313702 $0.1824 $0.124156 $0.112720 $0.113071
Functional Cost Components at Uniform Current Return
13 Production 61,613,790 46,399,443 13,203,470 1,684,126 321,859 4,891
14 Underground Storage 1,158,755 876,557 223,193 19,151 4,608 35,246
15 Distributon 13,426,260 11,588,246 1,499,465 176,286 31,853 130,410
16 Common 5,661,195 4,585,839 824,467 100,533 20,505 129,851
17 Total Uniform Current Cost 81,860,000 63,450,086 15,750,595 1,980,096 378,825 300,399
18 Exclude Cost of Gas w I Revenue Exp.61,210,875 46,099,857 13,118,219 1,673,252 319,547 0
19 Total Uniform Current Margin 20,649,125 17,350,22 2,632,376 306,843 59,278 300,399
Margin per Therm at Uniform Current Return
20 Production $0.005292 $0.005494 $0.005494 $0.005494 $0.005494 $0.001326
21 Underground Storage $0.015219 $0.016074 $0.014383 $0.009675 $0.010946 $0.009557
22 Distribution $0.176338 $0.212499 $0.096627 $0.089063 $0.075663 $0.035361
23 Common $0.074353 $0.084093 $0,053130 $0,050791 $0.048706 $0.035209
24 Total Current Uniform Margin Melded Rate I $0.271202 $0.318159 $0.169634 $0.155022 $0.140808 $0.081454
25 Margin to Cost Ratio at Current Rates 1.00 0.99 1.08 0.80 0.80 1.39
Functional Cost Components at Proposed Rates
26 Production 61,613,466 46,399,199 14,887,518 0 321,858 4,891
27 Underground Storage 1,773,719 1,325,735 368,328 0 5,681 73,974
28 Distribution 17,166,253 14,701,257 2,225,219 0 36,246 203,532
29 Common 6,031,563 4,892,166 980,186 0 20,980 138,231
30 Total Proposed Rate Revenue 86,585,000 67,318,357 18,461,250 0 384,765 420,628
31 Exclude Cost of Gas w I Revenue Exp.61,210,553 46,099,614 14,791,394 0 319,545 0
32 Total Margin Revenue at Proposed Rate 25,374,447 21,218,742 3,669,857 0 65,220 42D,28
Margin per Therm at Proposed Rates
33 Production $0.005292 $0.005494 $0.005494 $0.000000 $0.005494 $0.001326
34 Underground Storage $0.023296 $0.024311 $0.021051 $0.000000 $0.013495 $0.020058
35 Distnbution $0.22548 $0.269584 $0.127175 $0.000000 $0.086097 $0.055188
36 Common $0.079217 $0.089710 $0.056019 $0.000000 $0.049837 $0.037482
37 Total Proposed Margin Melded Rate per Thi $0.333263 $0.389098 $0.209738 $0.000000 $0.15422 $0.114054
Functional Cost Components at Uniform Proposed Return
38 Production 61,613,466 46,399,199 14,887,518 0 321,858 4,891
39 Underground Storage 1,761,141 1,332,240 368,328 0 7,003 53,569
40 Distribution 17,178,223 14,746,343 2,225,219 0 41,656 165,005
41 Common 6,032,170 4,896,602 980,186 0 21,567 133,815
42 Total Uniform Proposed Cost 86,585,000 67,374,384 18,461,250 0 392,084 357,281
43 Exclude Cost of Gas w I Revenue Exp.61,210,553 46,099,614 14,791,394 0 319,545 0
44 Total Uniform Proposed Margin 25,374,447 21,274,770 3,669,857 0 72,539 357,281
Margin per Therm at Uniform Proposed Return
45 Production $0.005292 $0.005494 $0.005494 $0.000000 $0.005494 $0.001326
46 Underground Storage $0.023130 $0.024430 $0.021051 $0.000000 $0.016636 $0.014525
47 Distribution $0.225615 $0.270411 $0.127175 $0.000000 $0.098950 $0.044742
48 Common $0.079225 $0.089791 $0.056019 $0.000000 $0.051229 $0.036284
49 Total Proposed Uniform Margin Melded Rat $0.333263 $0.390126 $0.209738 $0.000000 $0.172308 $0.096878
50 Margin to Cost Ratio at Proposed Rates 1.00 1.00 1.00 0.00 0.90 1.18
51 Current Margin to Proposed Cost Ratio 0.81 0.80 0.84 0.00 0.65 1.17
Exibit No. 14
Case No. AVU-G-8-Q1
T. Knox, Avista
Schedule 5, p. 2 of 3
Sumcost
Company Base Case
AVU-G-Q4-1 Method
AVISTA UTILITIES
Summary by Classifcation with Unit Cost Analysis
For the Year Ended December 31, 2007
(b)(c) (d) (e)
Description
(f)
System
Total
Cost by Classification at Current Return by Schedule1 Commodity 61,244,3772 Demand 10,406,5043 Customer 10,209,1194 Total Current Rate Revenue 81,860,000
Revenue per Therm at Current Rates
5 Commodity
6 Demand
7 Customer
8 Total Revenue per Therm at Current Rates
Cost per Unit at Current Rates
9 Commodity Cost per Therm
10 Demand Cost per Peak Day Therms
11 Customer Cost per Customer per Month
Cost by Classification at Uniform Current Return
12 Commodity
13 Demand
14 Customer
15 Total Uniform Current Cost
Cost per Therm at Current Return
16 Commodity
17 Demand
18 Customer
19 Total Cost per Therm at Current Return
Cost per Unit at Uniform Current Return
20 Commodity Cost per Therm
21 Demand Cost per Peak Day Therms
22 Customer Cost per Customer per Month
23 Revenue to Cost Ratio at Current Rates
$0.804372
$0.136677
$0.134085
$1.075133
$0.804372
$18.80
$12.10
61,188,875
10,390,202
10,280,923
81,860,000
$0.803643
$0.136463
$0.135028
$1.075133
$0.803643
$18.77
$12.18
1.00
(g)
Residential
Service
Sch 101
45,912,258
7,936,479
9,358,263
63,207,000
$0.841915
$0.145535
$0.171607
$1.159057
$0.841915
$18.69
$11,22
45,978,165
8,000,144
9,471,777
63,450,086
$0.843124
$0.146702
$0.173689
$1.163515
$0.843124
$18.84
$11.35
1.00
(h)
Small Firm
Service
Sch 111
13,138,531
2,178,520
632,949
15,950,000
$0.846664
$0.140387
$0.040788
$1.027839
$0.846664
$21.99
$67.43
13,053,131
2,107,569
589,895
15,750,595
$0.841161
$0.135815
$0.038014
$1.014989
$0.841161
$21.28
$62.84
1.01
Natural Gas Utility
Idaho Jurisdiction
(i)
Large Firm
Service
Sch 121
1,600,679
202,479
115,842
1,919,000
$0.808690
$0.102296
$0.058525
$0.969511
$0.808690
$18.44
$965.35
1,624,233
217,356
138,507
1,980,096
$0.820590
$0.109812
$0.069976
$1.000378
$0.820590
$19.80
$1,154.22
0.97
ul
Interrpt
Service
Sch 131
346,154
11,637
9,209
367,000
$0.822247
$0.027643
$0.021875
$0.871765
$0.822247
$5.63
$767.41
352,436
16,127
10,262
378,825
$0.837171
$0.038307
$0.024375
$0.899854
$0.837171
$7.80
$855.14
0.97
24-Mar-08
(k)
Transport
Service
Sch 146
246,756
77,388
92,856
417,000
$0.066908
$0.020984
$0.025178
$0.113071
$0.066908
$4.59
$1,547.60
180,910
49,006
70,483
300,399
$0.049054
$0.013288
$0.019112
$0.081454
$0.049054
$2.91
$1,174.71
1.39
Cost by Classifcation at Proposed Return by Schedule24 Commodity 62,618,97725 Demand 11,688,46526 Customer 12,277,55827 Total Proposed Rate Revenue 86,585,000
Revenue per Therm at Proposed Rates
28 Commodity
29 Demand
30 Customer
31 Total Revenue per Therm at Proposed RatE
Cost per Unit at Proposed Rates
32 Commodity Cost per Therm,
33 Demand Cost per Peak Day Therms
34 Customer Cost per Customer per Month
$0.822425
$0.153514
$0.161251
$1.137190
$0.822425
$21.11
$14.55
Cost by Classifcation at Uniform Proposed Return35 Commodity 62,602,28436 Demand 11,690,49837 Customer 12,292,21838 Total Uniform Proposed Cost 86,585,000
Cost per Therm at Proposed Return
39 Commodity
40 Demand
41 Customer
42 Total Cost per Therm at Proposed Return
Cost per Unit at Uniform Proposed Retum
43 Commodity Cost per Therm
44 Demand Cost per Peak Day Therms
45 Customer Cost per Customer per Month
46 Revenue to Cost Ratio at Proposed Rates
47 Current Revenue to Proposed Cost Ratio
$0.822206
$0.153541
$0.16144
$1.137190
$0.822206
$21.12
$14.57
1.00
0.95
47,026,802
9,013,303
11,278,252
67,318,357
$0.862353
$0.165281
$0.206815
$1.23449
$0.862353
$21.23
$13.52
47,041,993
9,027,977
11,304,415
67,374,384
$0.862632
$0.165550
$0.207294
$1.235476
$0.862632
$21.26
$13.55
1.00
0.94
14,987,779
2,578,508
894,964
18,461,250
$0.856575
$0.147366
$0.051149
$1.055089
$0.856575
$23.43
$94.14
14,987,779
2,578,508
894,964
18,461,250
$0.856575
$0.147366
$0.051149
$1.055089
$0.856575
$23.3
$94.14
1.00
0.97
$0.000000
$0.00000
$0.000000
$0.000000
$0.000000
$0.00
$0.00
$0.000000
$0.000000
$0.000000
$0.000000
$0.000000
$0.00
$0.00
0.00
0.00
o
o
o
o
355,592
18,383
10,791
384,765
248,804
78,271
93,552
420,628
$0.067464
$0.021223
$0.025367
$0.114054
$0.067464
$4.64
$1,559.20
213,032
62,852
81,397
357,281
$0.057764
$0.017042
$0.022071
$0.096878
$0.057764
$3.73
$1,356.2
1.18
0.94 1.17
Exhibit No. 14
Case No. AVU-G-Q8-01
T. Knox, Avista
Schedule 5, p. 3 of 3
$0.84466
$0.043666
$0.025632
$0.913964
$0.84466
$8.89
$899.23
o
o
o
o
359,480
21,161
11,442
392,084
$0.853903
$0.050266
$0.027180
$0.931349
$0.853903
$10.23
$953.53
0.98