20090707Vol IV (Boise) Pgs 319-612.pdf

ORIGINAL
-BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF AVISTA CORPORATION FOR THE
AUTHORITY TO INCREASE ITS RATES
AND CHARGES FOR ELECTRIC AND
NATURAL GAS SERVICE TO ELECTRIC
AND NATURAL GAS CUSTOMERS IN THE
STATE OF IDAHO.
CASE NOS.
AVU-E-09-01
AVU-G-09-01
TECHNICAL HEARING
HEARING BEFORE
c:-lr_::o
rn~m--('~0"_C -0~O:l~r :x
(p("'") ~~ s:O \D
:;:;
~
fi
l0"
COMMISSIONER MACK A. REDFORD (Presiding)
COMMISSIONER MARSHA H. SMITH
COMMISSIONER JIM D. KEMPTON
e
PLACE:Commission Hearing Room
472 West Washington Street
Boise, Idaho
DATE:June 29, 2009
VOLUME IV - Pages 319-612
'-'Is ?--1!iF POST OFFICE BOX 578
BOISE. IDAHO 83701
208-336-9208
e HEDRICK
COURT REPORTING
s'el1f th ~ N)/ffH/t¡ ol,fiJ 19
;:morn~mo
e
e
20
21
22
23
24
e 25
1 APPEARANCES
2
3 For the Staff:DONALD L. HOWELL, II, Esq.
-and-
KRISTINE A. SASSER, Esq.
Deputy Attorneys General
472 West Washington
Boise, Idaho 83702
4
5
6
For Avista:DAVID J. MEYER, Esq.
Avista Corporation
Post Office Box 3727
Spokane, Washington 99220-3727
7
8
9 For Idaho Forest Group:MCDEVITT & MILLER, LLP
by DEAN J. MILLER, Esq.
420 West Bannock Street
Boise, Idaho 83702
10
11
For Clearwater Paper Corp.:GIVENS PURSLEY, LLP
by MICHAEL C. CREAMER, Esq.
601 West Bannock Street
Boise, Idaho 83702
12
13
14 For Idaho Cons. League:BETSY BRIDGE
Idaho Conservation League
710 North Sixth Street
Boise, Idaho 83702
15
16
For CAPAI:BRAD M. PURDY, Esq.
Attorney at Law
2019 North Seventeenth Street
Boise, Idaho 83702
17
18
19
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
APPEARANCES
e
e
20
21
22
23
1 I N D E X
2
WITNESS EXAMINATION BY PAGE
3
4
Elizabeth M. Andrews
(Avista)
320Prefiled Direct
5 Tara L. Knox
(Avista)
Prefiled Direct 385
6
7
Brian J. Hirschkorn
(Avista)
421Prefiled Direct
8 Bruce W. Folsom
(Avista)
Prefiled Direct 451
9
10
Randy Lobb
(Staff)
470Prefiled Direct
11 Lynn Anderson
(Staff)
Prefiled Direct 494
12
13
Kei th Hessing
(Staff)
508Prefiled Direct
14 Rick Sterling
(Staff)
Prefiled Direct 526
15
16
Joe Leckie
(Staff)
540Prefiled Direct
17 Donn English
(Staff)
Prefiled Direct 557
18
19
Cecily Vaughn
(Staff)
602Prefiled Direct
EXHIBITS
24 (No exhibits were marked.)
e 25
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
INDEX
EXHIBITS
~
e 13
14
15
16
17
18
19
20
21
22
23
24
e 25
1 BOISE, IDAHO, MONDAY, JUNE 29, 2009, 9:33 A.M.
2
3
4 (The following prefiled testimony was
5 spread upon the record.)
6
7
8
9
10
11
12
319
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
COLLOQUY
.1
2
I. INTRODUCTION
Q.Please state your name, business address, and
3 present ,position with Avista Corporation.
4 A.My name is Elizabeth M. Andrews.I am employed
5 by Avista Corporation as Manager of Revenue Requirements in
6 the State and Federal Regulation Department. My business
7 address is 1411 East Mission, Spokane, washington.
8 Q.Would you please describe your education and
9 business experience?
10 A.I am a 1990 graduate of Eastern washington
11 Uni versi ty with a Bachelor of Arts Degree in Business
12 Administration, majoring in Accounting. That same year, I
13 passed the Novemer Certified Public Accountant exam,.14 earning my CPA License in August 1991.I worked for
15 Lemaster & Daniels, CPAs from 1990 to 1993, before joining
16 the Company in August 1993. I served in various positions
17 wi thin the sections of the Finance Department, including
18 General Ledger Accountant and Systems Support Analyst until
19 2000.In 2000, i was hired into the State and Federal
20 Regulation Department as a Regulatory Analyst until my
21 promotion to Manager of Revenue Requirements in early 2007.
22 i have also attended several utility accounting, ratemaking
23 and leadership courses.
24 Q.As Manager of Revenue Requirements, what are your
25 responsibilities?.
320 Andrews, Di 2
Avista Corporation
.1
2
A. As Manager of Revenue Requirements, aside from
special projects, I am responsible for the preparation of
3 normalized revenue requirement and pro forma studies for
4 the various jurisdictions in which the Company provides
5 utility services. During the last eight and a half years I
6 have assisted or lead the Company's electric and/or natural
7 gas general rate filings in Idaho, Washington, and Oregon.
8 Q.What is the scope of your testimony in this
9 proceeding?
10 A.My testimony and exhibits in this proceeding will
11 generally cover accounting and financial data in support of
12 the Company's need for the proposed increase in rates.I
13 will explain pro formed operating results including expense.14 and rate base adjustments made to actual operating results
15 and rate base.
16
17
I incorporate the Idaho share of the proposed
adjustments of several witnesses in this case.For
18 example, Company witnesses Mr. DeFelice sponsors and
19 describes the Company's pro forma 2008 and 2009 capital
20 addi tions adjustments, and Mr. Storro explains other issues
21 impacting the Company, such as the increased generation
22 plant capital and operating and maintenance (O&M) expenses,
23 including the Colstrip mercury emissions O&M expense.
24 Company witness Mr. Kinney discusses the transmission net
25 expenses, Asset Management Program expenses, and the.
321 Andrews, Di 3
Avista Corporation
.1
2
transmission and distribution capital expenditures included
in Mr. DeFelice's pro forma capital adjustments.Lastly,
3 Company witness Mr. Johnson prepared the total system pro
4 forma power supply adjustment, while Ms. Knox sponsors the
5 revenue normalization adjustment.
6 Q.Are you sponsoring any exhibits to be introduced
7 in this proceeding?
8 A.Yes. I am sponsoring Exhibi t No. i 0 , Schedul e i
9 (Electric) and Schedule 2 (Natural Gas), which were
10 prepared under my direction.These Exhibi t Schedules
11 consist of worksheets, which show actual 2008 operating
12 results (twelve-month period ending Septemer ~O, 2008),
13 pro forma, and proposed electric and natural gas operating.14
15
results and rate base for the State of Idaho, the Company's
calculation of the general revenue requirement,the
16 derivation of the net operating income to gross revenue
17 conversion factor, and the pro forma adjustments proposed
18 in this filing.
19
20
21
II.COMBINED RE RBOUIRE S'Y
Q.Would you please sumrize the results of the
22 Comany's pro form study for both the electric an natural
23 gas operating systems for the Idaho jurisdiction?
24 A.Yes.After taking into account all standard
25 Commission Basis adjustments, as weii as additional pro.
322 Andrews, Di 4
Avista Corporation
.1
2
forma and normalizing adjustments, the pro forma electric
and natural gas rates of return ("ROR") for the Company's
3 Idaho jurisdictional operations are 5.34% and 6.87%,
4 respectively.Both return levels are below the Company's
5 requested rate of return of 8.80%. The incremental revenue
6 requirement for base retail rates, necessary to give the
7 Company an opportunity to earn its requested ROR is
8 $31,233,000 for the electric operations and $2,740,000 for
9 the natural gas operations.The overall base electric
10 increase associated with the Company's request is 14.18%1.
11 However, as explained by Company witness Mr. Hirschkorn,
12 with the reduction of a portion of the Power cost
13 Adjustment (PCA) surcharge of 5.6% planned at the same time.14 the general rate increase will go into effect for
15 customers, the net impact on the residential customers'
16 bill is anticipated to be approximately 8.6%.The base
17 natural gas increase is 2.99%.
18 Q.Wht is the Company's rate of return that was
19 last authorized by this Commission for it's electric and
20 natural gas operations in Idaho?
21 A.The Company's currently authorized rate of return
22 for its Idaho operations is 8.45%, effective October 1,
23 2008 for both our electric and natural gas systems.
1 Percentages reflect the proposed increase to base tariff rates, Mr.
Hirschkorn describes the effect based on present billing rates..
323 Andrews, Di 5
Avista Corporation
.
.
.
1
2
3
III. BLBCTRIC SBCTION
Changes Since the 2007 Test Period
Q.On what test period is the Comany basing its
4 need for additional electric revenue?
5 A., The test period being used by the Company is the
6 twelve-month period ending Septemer 30, 2008, presented on
7 Currently authorized rates are baseda pro forma basis.
8 upon the 2007 test year utilized in Case No. AVU-E-08-01,
9 adjusted on a pro forma basis.
10 By way of sumry, could you please explain theQ.
11 different rates of return that you will be presenting in
12 your testimony?
13
14
Yes. As shown in Illustration No. 1 below, thereA.
are three different rates of return that will be discussed.
15 The actual ROR earned by the Company during the test
16
17
18
19
20
21
22
period, the Pro Forma ROR determined in my Exhibit No. 11,
Schedule 1, and the requested ROR.
Illustration No.1:
Avista Corp
Rates of Retu
lO.üO%
8.üO%
6.üO%
4.üO%
2.üO%
23
24
O.üO%
Actual ProFon Requeste
324 Andrews, Di 6
Avista Corporation
.1 Q.What are the primary factors driving the
2 Comany~ s need for an electric increase?
3 A.Illustration No. 2 below, shows the primary
4 factors driving the electric revenue requirement in this
5 case.Additional details regarding these items are
6 provided later in my testimony.
7
8
Illustration No.2:
Primary Components of Electric Revenue Requirement
9
16 Distrbution & Oter
Expense
11%
Distrbution Operation &
Maintenance Costs
Administrative & Generl Expenses
Production &
Transmission
Expense
380/0
Increased Loads
Mid Columbia Purchases
Production O&M . Plant Exp.
& Mercur Abatement Exp.
10
12
Increased Net Plant
Investment1
35%
Generation Upgrades
-Hydro & Theral
Tramission Upgrdes
Distrbution
Proper Tax on CS2
11
13.14
15
17
19 Ilncludes return on investment, depeciation and
taes, offset by the ta beefit of intet.
Hydro ReUcensing &
Compliance Issues
16%
Spokane River Relicesing
CDA Tnbe Settement
18
20
21 Q.Please describe the primary factors driving the
22 Comany's need for an electric increase?
23 A. There are numerous factors that have impacted the
24 Company's Idaho electric results of operations sincè the
25 last rate case.Net Operating Income ("NOI") has declined.
325 Andrews, Di 7
Avista Corporation
.1
2
approximately $6 million, or l3. 4%, and total rate base has
increased approximately $47.1 million, or 8.9%.During
3 this same time period, the average numer of customers has
4 increased by nearly 2%. The Company's electric request is
5 driven by changes in various operating cost components as
6 shown by the pie chart (Illustration No. 2 above),
7 primarily power supply costs, plant investment or rate base
8 growth associated with generation,transmission and
9 distribution plant (including pro forma capital spending
10 requirements during 2009) and by various hydro relicensing
11 efforts impacting the Utility.
12 Q.Please explain each of the four comonents or
13 segments shown in Chart No. 2 above..14
15
A.The first segment, Production and Transmission
Expense increases,as explained below,comprise
16 approximately 35% of the overall request. The next largest
17 segment is Increased Net Plant Investment.As already
18 noted, net rate base for the Idaho jurisdiction increased
19 approximately $47.1 million, or 8.9%, of which $15.1
20 million comprise of additional "gross" generation plant,
21 both hydro and thermal, and transmission plant.In
22 addition, gross distribution plant increased $26.2 million,
23 or 7.2%, partially due to the 2% customer growth.The
24 depreciation recovery, taxes associated with plant, and the
25 return on additional plant investment offset by the tax.
326 Andrews, Di 8
Avista Corporation
.1
2
benefit of interest (excluding rate base associated with
hydro relicensing efforts noted below) ,make up
3 approximately 35% of the overall Company request.
4 Additional plant investment relating to the hydro
5 relicensing and compliance efforts pro formed into this
6 case make up approximately 19% of the overall request, and
7 include the intangible net rate base and expenses
8 associated with the Spokane River relicensing and Coeur
9 d'Alene Tribe (CDA Tribe) Settlement agreement.The
10 majority of these charges were reviewed in the Company's
11 previous general electric rate case proceeding, Case No.
12 AVU-E-08-01, and were approved for deferral and later
13 recovery following completion of the agreement with the CDA.14 Tribe, and receipt of the new license for the Spokane
15 River. Specifically, the Company was allowed to defer the
16 amortization of these charges, including a carrying charge
17 on the deferrals and unamortized balance, and include
18 recovery of these costs in its next general rate case. (See
19 Order No. 30647 )As explained further in my testimony,
20 these amounts have been included for recovery in this
21 general rate case filing.
22 The remaining cost category, Distribution and Other
23 Expense, which includes increases to all other operating
24 categories,such as distribution expenses,customer
.
327 Andrews, Di 9
Avista Corporation
service,and administrative and general,totals.1
2
3
approximately 11% of the overall request.
Q.Could you please provide additional details
4 related to the chages in Production and Transmission
5 expense?
6 A.As discussed in Mr. Johnson's testimony, the
7 level of Idaho's share of power supply expense has
8 increased by approximately $11.8 million ($33.2 million on
9 a system basis) from the level currently in base rates.
10 This increase in pro forma power supply expense over
11 the expense currently in base rates is based on numerous
12 factors, including higher retail loads, reduced hydro
13 generation due to the elimination of the rate mitigation.14 adjustment (included in the Company's last Idaho electric
15 general rate case in Docket No. AVU-E-08-01) and the
16 expiration of the Mid-Columia (wanapum) contract in
17 Novemer 2009.
18 Pro forma retail loads are 22.7 aM higher than loads
19 that current rates are based on.The increased loads are
20 due to two factors. One is the natural increase in retail
21 loads of approximately 14.3 aM. The other 8.4 aM of load
22 increase is due to the reduction in Potlatch generation.
23 Hydro generation is also lower than the level in current
24 base rates by a reduction of 29.8 aM (system).Mr.
.
328 Andrews, Di 10
Avista Corporation
.Johnson discusses these differences in detail in his1
2
3
testimony.
Q.Could you please identify the main comonents of
4 the "Distribution &: Other" segment shown in the chart
5 above?
6
7
A.Yes.A numer of expense items have increased
since 2007, which have been included in this case.For
8 example, employee benefits such as wages, pension and
9 medical insurance expenses have increased, as well as other
10 administrative and general expenses such as those related
11 to the Company's information services.
12 We are utilizing a twelve-month ending September 30,
13 2008 test year, since that is the most recent normalized.14 financial information the Company has available; however,
15 new general electric rates resulting from this filing are
16 not expected to go into effect until mid-2009.
17 Accordingly, the Company has included a numer of pro forma
18 adjustments to capture some of the measurable cost changes
19 that the Company will experience from the test year.
20 Q.Wht were the major comonents of the $47.2
21 million increase in total rate base?
22 A.Looking at the changes to "gross" plant in
23 service shows that gross plant increased almost $75.7
24 million (Idaho), or 7.9%, as compared to what is currently
25 included in rates. Included in this "gross" plant total is.
329 Andrews, Di i 1
Avista Corporation
.$28.6 million of pro forma capital recorded in intangible1
2
3
plant, ~ainly associated with the Spokane River relicensing
and Coeur d'Alene Tribe Settlement agreement or
4 approximately 37.8% of the total change to "gross" plant.
5 To continue to meet the energy and reliability needs
6 of our customers, the Company has invested additional
7 amounts in thermal and hydro generating facilities, as well
8 as additional transmission inves tment .The total
9 production and transmission plant investment included in
10 this case (discussed later in my testimony) totaled
11 approximately $15.1 million or 20% of the total change to
12 "gross" plant.
13 The specific pro forma capital expenditures undertaken.14
15
by the Company to upgrade its generation and transmission
facilities and improve operating efficiency and
16 reliability, are discussed further by Mr. Storro regarding
17 production assets, and Mr. Kinney regarding transmission
18 assets.Mr. Kinney also discusses the pro forma
19 distribution projects.
20 Q.What other rate base additions are included in
21 Total Rate Base?
22 A.Distribution "gross"plant increased $26.2
23 million or 7.2% above the current level included in rates,
24 in part due to the approximate 2% average customer growth
25 from 2007 through 2008, while general ~gross" plant.
330 Andrews, Di 12
Avista Corporation
.increased $5.7 million or 10.3% above the current level1
2
3
included in rates.
Later in my testimony, I will address the Spokane
4 River relicensing and Coeur d'Alene Tribe Settlement
5 agreement pro forma adjustments, and the additional net
6 rate base adjustments labeled "Pro Forma Capital Additions
7 2008" and "Pro Forma Capital Additions 2009" included in
8 Exhibi t No. 10 , Schedul e 1 pages 8 and 9.This exhibi t
9 explains the detail behind the normalizing and pro forma
10 net operating income and rate base adjustments.
11 The figures listed above are "gross" plant investment
12 changes.Again,taking into account increases to
13 Accumulated Depreciation and Amortization and Deferred.14 Federal Income Tax offsets, this produces the net $47.2
15 million, or 8.9% increase to Total Rate Base. Depreciation
16 expense, which has largely followed the 7.9% growth in
17 gross plant-in-service, has increased $4.2 million.
18
19
Q.Mr. DePelice sponsors the pro form capi tal
adjustments included in this case.Could you please
20 briefly describe the conclusions drawn by Mr. DePelice
21 regarding the increased capital investment?
22 A.Yes.As described in Mr. DeFelice's testimony,
23 the Company is making substantial levels of capital
24 investment in its electric and natural gas system
25 infrastructure to address customer growth, replacement and.
331 Andrews, Di 13
Avista Corporation
.1
2
maintenance of Avista' s aging system, and to provide for
increased reliability and safety requirements. As soon as
3 this new plant is placed in service, the Company must start
4 depreciating the new plant and incur other costs related to
5 the investment. Unless this new investment is reflected in
6 retail rates in a timely manner, it has a negative impact
7 on Avista' s earnings, particularly because the new plant is
8 typically far more costly to install than the cost of
9 similar plant that was embedded in rates decades earlier.
10 As plant is completed and is providing service to
11 customers, it is appropriate for the Company to receive
12 timely recovery of the costs associated with that plant.
13.14
15
Revenue Requiremnt
Q.Would you please exlain what is shown in Exibit
16 No. 10, Schedule 1?
17 A.Yes. Exhibit No. 10, Schedule 1 shows actual and
18 pro forma electric operating results and rate base for the
19 test period for the State of Idaho. Colum (b) of page 1
20 of Exhibit No. 10, Schedule 1 shows 2008 (twelve-month
21 ending Septemer 30, 2008) operating results and components
22 of the average-of-monthly-average rate base as recorded;
23 colum (c) is the total of all adjustments to net operating
24 income and rate base; and colum (d) is pro forma results
25 of operations, all under existing rates. Colum (e) shows.
332 Andrews, Di 14
Avista Corporation
.1
2
the revenue increase required which would allow the Company
to earn an 8.80% rate of return. Colum (f) reflects pro
3 forma electric operating results with the requested
4 increase of $31,233,000.The restating adjustments shown
5 in colums c through w, of pages 4 through 7 of Exhibit No.
6 10, Schedule 1, are consistent with the treatment reflected
7 in the prior Commission Orders in Case Nos. AVU-E-04-01,
8 AVU-E-08-01 and current regulatory principles.
9 Q.Would you please explain page 2 of Exibit No.
10 10, Schedule 1?
11 A.Yes.Page 2 shows the calculation of the
12 $3l, 233, 000 revenue requirement at the requested 8.80% rate
13 of return..14 Q.Would you now please explain page 3 of Exibit
15 No. 10, Schedule 1?
16 A.Yes.Page 3 shows the derivation of the net
17 operating income to gross revenue conversion factor. The
18 conversion factor takes into account uncollectible accounts
19 receivable, Commission fees and idaho State excise taxes.
20 Federal income taxes are reflected at 35%.
21 Q.Now turning to pages 4 through 9 of your Exibit
22 No. 10, Schedule 1, would you please explain what those
23 pages show?
24 A.Yes. Page 4 begins with actual operating results
25 and rate base for the twelve-month period ending September
.
333 Andrews, Di 15
Avista Corporation
.1
2
30, 2008 test period in colum (b). Individual normalizing
adjustments consistent with prior regulatory treatment
3 (standard Commission Basis adjustments) begin in colum (c)
4 on page 4 and continue through colum (w) on page 7.
5 Individual pro forma and additional normalizing adjustments
6 begin in colum (PF1) on page 7 and continue through colum
7 (PF22) on page 11.The final colum on page 11 (PFT) is
8 the total pro forma operating results and rate base for the
9 test period. Additional details related to each adjustment
10 described below are provided in accompanying workpapers.
11
12 Standard Comission Basis Adjustments
.13
14
Q.would you please explain each of these
adjustments, the reason for the adjustment and its effect
15 on test period State of Idaho net operating incom and/or
16 rate base?
17 A.Yes, but before I begin, I will note that in
18 addition to the explanation of adjustments provided herein,
19 the Company has also provided workpapers outlining
20 additional details related to each of the adjustments.
21 The first adjustment, colum (c) on page 4, entitled
22 Deferred FIT Rate Base, reflects the rate base reduction
23 for Idaho's portion of deferred taxes.The adj us tmen t
24 reflects the deferred tax balances arising from accelerated
25 tax depreciation (Accelerated Cost Recovery System, or.
334 Andrews, Di 16
Avista Corporation
.ACRS, and Modified Accelerated Cost Recovery, or MACRS),1
2
3
bond refinancing premiums, and contributions in aid of
construction.These amounts are reflected on the average
4 of monthly average balance basis. The effect on Idaho rate
5 base is a reduction of $82,407,000.
6 The adjustment in colum (d), Deferred Gain on Office
7 Building, reflects the rate base reduction for Idaho's
8 portion of the net of tax, unamortized gain on the sale of
9 the Company's general office facility.The facility was
10 sold in Decemer 1986 and leased back by the Company.
11 Al though the Company repurchased the building in Novemer
12 2005, the Company opted to continue to amortize the
13 deferred gain over the remaining amortization period.14 scheduled to end in 2011. The effect on Idaho rate base is
15 a reduction of $164,000.
16
17
The adjustment in colum (e) , Colstrip 3 AF
Blimination,is a real loca tion of rate base and
18 depreciation expense between jurisdictions. In Cause Nos.
19 U-81-15 and U-82-10,the Washington Utilities and
20 Transportation Commission (WUTC) allowed the Company a
21 return on a portion of Colstrip Unit 3 construction work in
22 progress (~CWIP"). A much smaller amount of Colstrip Unit
23 3 CWIP was allowed in rate base in Case U-1008-144 by the
24 IPUC. The Company eliminated the AFUDC associated with the
25 portion of CWIP allowed in rate base in each jurisdiction..
335 Andrews, Di 1 7
Avista Corporation
.
.
.
1
2
3
allocated theSince ,production facilities are on
Production/Transmission formula, the allocation of AFUDC is
reversed and a direct assignent is made.The rate base
4 adjustment reflects the average of monthly averages amount
5
6
The effect on Idaho net operatingfor the test period.
income is a decrease of $202,000.The effect of the
7 reallocation on Idaho rate base is an increase of
8 $1,956,000.
9 The adjustment in colum (f), Colstrip Comn AF,
10 is also associated with the Colstrip plants in Montana, and
11 increases rate base. Differing amounts of Colstrip common
12 facilities were excluded from rate base by this Commission
13 and the WUTC until Colstrip Unit 4 was placed in service.
14 The Company was allowed to accrue AFUDC on the Colstrip
15 common facilities during the time that they were excluded
16 It is necessary to directly assign thefrom rate base.
17 AFUDC because of the differing amounts of common facilities
18 excluded from rate base by this Commission and the WUTC.
19 In Septemer 1988, an entry was made to comply with a
20 Federal Energy Regulatory Commission ("FERC" )Audit
21 Exception, which transferred Colstrip common AFUDC from the
22 These amounts reflect aplant accounts to account 186.
23 direct assignent of rate base for the appropriate average
24 of monthly averages amounts of Colstrip common AFUDC to the
25 Amortization expenseWashington and Idaho jurisdictions.
336 Andrews, Di 18
Avista Corporation
.1
2
associated with the Colstrip common AFUDC is charged
directly to the Washington and Idaho jurisdictions through
3 Account 406 and is a component of the actual results of
4 operations. The rate base adjustment reflects the average
5 of monthly averages amount for the test period. The effect
6 on Idaho rate base is an increase of $925,000.
7 The adjustment in colum (g), Kettle Palls &: Boulder
8 Park Disallowances, decreases rate base.The amounts
9 reflect the Kettle Falls generating plant disallowance
10 ordered by this Commission in Case No. U-1008-18-5 and the
11 Boulder Park plant disallowance ordered by the IPUC in case
12 No. AVU-E-04-1.This Commission disallowed a rate of
13 return on $3,009,445 of investment in Kettle Falls, and.14 $2,600,000 million of investment in Boulder Park.The
15 disallowed investment and related accumulated depreciation
16 are removed.These amounts are a component of actual
17 resul ts of operations. The effect on Idaho rate base is a
18 decrease of $2,233,000.
19 The adjustment in colum (h), Customer Advances,
20 decreases rate base for moneys advanced by customers for
21 line extensions, as they will most likely be recorded as
22 contributions in aid of construction at some future time.
23 The effect on Idaho rate base is a decrease of $885,000.
24 Q.Please turn to page 5 and explain the adjustments
25 shown there..
337 Andrews, Di 19
Avista Corporation
.1
2
A. Page 5 starts with the adjustment in colum (i),
Weatherization and DSM Investment, which includes in rate
3 base balances (net of amortization) of weatherization
4 grants, the model conservation program costs and electric
5 demand side management (DSM) program costs upon which AFUCE
6 is no longer being accrued and full amortization was
7
8
implemented beginning August 1994.These amounts are a
component of actual results of operations.The effect on
9 Idaho rate base is an increase of $1,669,000.
10 Q.Would you please explain how energy efficiency-
11 related expenditures impact the revenue requirement in this
12 case?
.13
14
A.Yes.The unamortized balance of energy
efficiency management investment incurred prior to 1995 is
15 included in the results of operations and is a rate base
16 item in the colum (i) adjustment just described.DSM
17 expenditures incurred after March 13, 1995 have been offset
18 by revenues from the Company's energy efficiency tariff
19 rider, Schedule 91, and are not included in the revenue
20 requirement.
21 As the Commission is aware, the Company's tariff rider
22 under Schedule 91 was the first non-bypassable distribution
23 charge in the United States to fund energy efficiency. Mr.
24 Folsom provides additional detail and addresses the
25 prudence of the expenditures under this tariff.
.
338 Andrews, Di 20
Avista Corporation
.1
2
3
Q. Please continue with your exlanation of the
adjustments on page 5.
A.' The next colum entitled Subtotal Actual
4 represents actual operating results and rate base plus the
5 standard rate base adjustments.
6 The adjustment in colum (j), Depreciation True-up,
7 reflects a decrease in depreciation expense due to the
8 utilization of new depreciation rates effective January 1,
9 2008 as approved by Order No. 30498 in Case No. AVU-E-07-
10 11.These rates became effective after the three months
11 (October through December 2007) included in the test
12 period.This adjustment annualizes the current effective
13 rates for the test period. This adjustment increases Idaho.14 net operating income by $119,000.
15 The adjustment in colum (k), Bliminate B & 0 Taxes,
16 eliminates the revenues and expenses associated with local
17 business and occupation (B & 0) taxes, which the Company is
18 allowed to pass through to its Idaho customers.The
19 adjustment eliminates any timing mismatch that exists
20 between the revenues and expenses by eliminating the
21 revenues and expenses in their entirety.B & 0 taxes are
22 passed through on a separate schedule, which is not part of
23 this proceeding. The effect of this adjustment is to
24 decrease Idaho net operating income by $3,000.
.
339 Andrews, Di 21
Avista Corporation
.1
2
The adjustment in colum (l), Property Tax, restates
the test period accrued levels of property taxes to the
3 most cùrrent information available and eliminates any
4 adjustments related to the prior year.This adjustment
5 includes the increase in property taxes in 2009 related to
6 the Company's Coyote Springs plant located in Oregon.
7 Previously the Company had been excluded from this property
8 tax assessment for five years under a tax abatement as a
9 result of the plant being located in the Columia River
10 Enterprise Zone in Oregon.The effect of this particular
11 adjustment is to decrease Idaho net operating income by
12 $1,171,000.
.13
14
15
The adjustment in colum (m), uncollectible Exense,
restates the accrued expense to the actual level of net
write-offs for the test period.The effect of this
16 adjustment is to increase Idaho net operating income by
17 $37,000.
18 The adjustment in colum (n), Regulatory Exense,
19 restates recorded 2008 regulatory expense to reflect the
20 IPUC assessment rates applied to expected revenues for the
21 2008 period and the actual levels of FERC fees paid during
22 the test period.The effect of this adjustment is to
23 decrease Idaho net operating income by $26,000.
24 Q.Please turn to page 6 and explain the adjustmnts
25 shown there..
340 Andrews, Di 22
Avista Corporation
.1
2
A. The adjustment in colum (0) , injuries an
Damges, is a restating adjustment that replaces the
3 accrual with the six-year rolling average of actual
4 injuries and damages payments not covered by insurance2. A
5 six-year rolling average and the reserve method of
6 accounting for injuries and damages, net of insurance
7 proceeds, is a practical methodology to deal with these
8 normal utility operating expenses that happen to occur on
9 an irregular basis and differ markedly in materiality.
10 This methodology was accepted by the Idaho Commission in
11 Case No. WWP-E-98-11. The effect of this adjustment is to
12 decrease Idaho net operating income by $15,000.
.13
14
The adjustment in colum (p), PIT, adjusts the FIT
calculated at 35% within Results of Operations by removing
15 the effect of certain Schedule M items, matching the
16 jurisdictional allocation of other Schedule M items to
17 related Results of Operations allocations and to adjust the
18 production tax credits for pro forma qualified generation.
19 This adjustment also reflects the proper level of deferred
20 tax expense for the test period.The net effect of this
21 adjustment, all based upon a Federal tax rate of 35%, is to
22 increase Idaho net operating income by $454,000.
2 Due to the twelve months ending Septemer 30, 2008 test period
utilized in this case, the Company computed the six-year average using
twelve-months ended actuals through Novemer 2008 (most current data
available at time of adjustment) for its 2008 electric and natural gasbalances..
341 Andrews, Di 23
Avista Corporation
.1
2
3
The adjustment in colum (q), Idaho PCA, removes the
effects of the financial accounting for the Power Cost
Adjustment (PCA).The PCA normalizes and defers certain
4 power sùpply costs on an ongoing basis between general rate
5 filings. Certain differences in actual power supply costs,
6 compared to those included in base retail rates are
7 deferred and then surcharged or rebated to customers in a
8 future period. Revenue adjustments due to the PCA and the
9 power cost deferrals affect actual results of operations
10 and need to be eliminated to produce a normal period.
11 Actual revenues and power supply costs are normalized in
12 adjustments in colum (u) and colum (PF1), respectively.
13 The effect of this adjustment is to decrease Idaho net.14
15
operating income by $9,591,000.
The adjustment in colum (r), Nez Perce Settlemnt
16 Adjustment, reflects a decrease in Production operating
17 expenses.An agreement was entered into between the
18 Company and the Nez Perce Tribe to settle certain issues
19
20
regarding earlier owned and operated hydroelectric
generating facilities of the Company.This adj us tment
21 directly assigns the Nez Perce Settlement expenses to the
22 Washington and Idaho jurisdictions. This is necessary due
23 to differing regulatory treatment in Idaho Case No. WWP-E-
24 98-11 and Washington Docket No. UE-991606.The effect of
.
342 Andrews, pi 24
Avista Corporation
.this adjustment is to increase Idaho net operating income1
2
3
by $8,000.
The adjustment in colum (s), Bliminate AIR Exenses,
4 A/R representing Accounts Receivable, removes expenses
5 associated with the sale of customer accounts receivable.
6 The effect of this adjustment is to increase Idaho net
7 operating income by $190,000.
8 The adjustment in colum (t), Miscellaneous Restating
9 Adjustmnts, removes a numer of non-operating or non-
10 utility expenses associated with advertising, sponsorships
11 and dues and donations included in error in the test period
12 actual resul ts .The effect of this adjustment is to
13 increase Idaho net operating income by $73,000..14 The adjustment in colum (u), Revenue Normlization,
15 is a 3-fold adjustment taking into account known and
16 measurable changes that include revenue repricing
17 (including the current authorized rates approved in Case
18 No. AVU-E-08-01), weather normalization and a recalculation
19 of unbilled revenue. Schedule 91 Tariff Rider and Schedule
20 59 Residential Exchange are excluded from pro forma
21
22
revenues,and the related amortization expense is
eliminated as well.Ms. Knox is sponsoring this
23 adjustment. The effect of this particular adjustment is to
24 increase Idaho net operating income by $14,065,000.
.
343 Andrews, Di 25
Avista Corporation
.1
2
3
Q. Please continue on page 7 with your explanation
"
of the adjustments.
A.The adjustment in colum (v), Clark Fork PM&:B,
4 adjusts the level of amortization expense included in the
5 test period based on the balancing account method
6 previously authorized by the Commission for the Clark Fork
7 Protection, Mitigation, and Enhancement (PM&E) expenses, to
8 the Company's current authorized level of expense based on
9 the flow through of actual expenditures plus one-fifth of
10 the 5-year amortization of the remaining outstanding
11 balance in the balancing account at Septemer 30, 2008, as
12 approved in Case No. AVU-E-08-01. This adjustment uses the
13 level of PM&E expenses planned for the 2009/2010 rate.14
15
period for the amount of flow through of actual
expendi tures .Mr. Storro discusses in his testimony the
16 additional PM&E expenditures planned for the rate period.
17 The effect of this adjustment is to decrease Idaho net
18 operating income by $649,000.
19 The adjustment in the colum (w) Restate Debt
20 Interest, restates debt interest using the Company's pro
21 forma weighted average cost of debt, as outlined in the
22 testimony and exhibits of Company witness Mr. Theis, and
23 applied to Idaho's pro forma level of rate base, produces a
24 pro forma level of tax deductible interest expense.The
25 Federal income tax effect of the restated level of interest.
344 Andrews, Di 26
Avista Corporation
.1
2
for the test period decreases Idaho net operating income by
$1,985,000.
3 The colum entitled Restated Total, subtotals all the
4 preceding colums (b) through colum (w), exclusive of the
5 previously discussed subtotal colum.These totals
6 represent actual operating results and rate base plus the
7 standard normalizing adjustments that the Company includes
8 in its Commission Basis reports except power supply3.
9
10 Pro Form Adjustmnts
11 Q.Please explain the significance of the 22 colums
12 subsequent to the colum entitled Restated Total that
13 begins at page 7 in your Exibit No. 10, Schedule 1..14 A.The adjustments subsequent to the Restated Total
15 colum are pro forma adjustments that recognize the
16 jurisdictional impacts of items that will impact the pro
17 forma operating period levels for known and measurable
18 changes. They encompass revenue and expense items as well
19 as additional capital proj ects .These adjustments bring
20 the operating results and rate base to the final pro forma
21 level for the rate year.
3 The restated total also includes the additional property tax on CS2
required starting in 2009 included in the property tax restating
adjustment colum (l), and additional PM&E expenses above the test
period planned for the rate period in colum (v)..
345 Andrews, Di 27
Avista Corporation
.
.
.
1
2
Q. Please continue wi th your exlanation of the
adjustmnts starting on page 7, subsequent to the Restated
3 Total colum.
4 The adjustment in colum (PF1), Pro For. PowerA.
5 Supply, was made under the direction of Mr. Johnson and is
6 This adjustmentexplained in detail in his testimony.
7 includes pro forma power supply related revenue and
8 expenses to reflect the twelve-month period July 1, 2009
9 Mr. Johnson's testimony outlinesthrough June 30, 2010.
10 the system level of pro forma power supply details that are
11 This adjustment calculatesincluded in this adjustment.
12 the Idaho jurisdictional share of those figures included in
13
14
The net effect of thethe base Results of Operations.
power supply adjustments decreases Idaho net operating
15 income by $6,285,000.
16 The adjustment in colum (PF2), Pro Form Production
17 Property Adjustmnt, adjusts pro formed production and
18 transmission revenues, expenses, and rate base by a factor
19 that reflects the ratio of 2008 Idaho test year retail load
20 divided by the pro forma period Idaho retail load. Capital
21 additions have been pro formed to Decemer 2009 whereas the
22 remainder of the pro forma adjustments reflect costs for
23 the twelve months ended June 2010 level.Therefore a
24 factor reflecting 2009 calendar Idaho retail load was used
25 to determine the factor for pro formed capital costs and
346 Andrews, Di 28
Avista Corporation
.1
2
3
determine the factor for all. other pro formed production
the 2009/2010 rate year Idaho retail load was used to
and transmission costs.The adjustment is made to avoid
4 the over-recovery of pro formed production and transmission
5 costs, since the revenue requirement associated with those
6 costs is being spread to test year retail load. The use of
7 a production property adjustment in conjunction with pro
8 forma rate year loads for power supply results in a better
9 matching of revenues and expenses during the period that
10 new retail rates from the case will be in effect.The
11 effect of this adjustment on Idaho net operating income is
12 an increase of $3,336,000.The effect on Idaho rate base
13 is a decrease of $10,202,000..14 The adjustment in colum (PF3), Pro Form Labr-Non-
15 Exec, reflects known and measurable changes to test period
16 union and non-union wages and salaries, excluding executive
17 salaries, which are handled separately in PF4. Test period
18 wages and salaries are restated as if the wage and salary
19 increase in March 2009 were in place for 8 months and the
20 March 2010 increase was in place for 4 months of the pro
21 forma period ending June 30, 2010. The methodology behind
22 this adjustment is consistent with that used in Case No.
23 AVU-E-04-01.The effect of this adjustment on Idaho net
24 operating income is a decrease of $694,000.
.
347 Andrews, Di 29
Avista Corporation
.1
2
The adjustment in colum (PF4), Pro Form Labor-
Executive, reflects known and measurable changes to
3 executive compensation. Test period wages and salaries are
4 restated to the 2010 expected level. This adjustment takes
5 into account changes in executive staffing made during 2008
6 and includes compensation for the planned executive team in
7 the pro forma period only.Compensation costs for non-
8 utility operations are excluded as executives routinely
9 charge a portion of their time to non-utility operations,
10 commensurate with the amount of time spent on such
11 activities. The current executives' salary allocations are
12 set at their expected pro forma test period utility/non-
.13
14
utility percentage splits.The methodology behind this
adjustment is consistent with that used in the last general
15 case, Case No. AVU-E-08-01. The impact of this adjustment
16 on Idaho net operating income is a decrease of $83,000.
17 Q.Please turn to page 8 an exlain the adjustments
18 show there.
19 A.The adjustment in colum (PF5) , Pro Form
20 Transmssion Rev/Bx, was made under the direction of Mr.
21 Kinney and is explained in detail in his testimony. This
22 adjustment includes pro forma transmission-related revenues
23 and expenses to reflect the twelve-month period July l,
24 2009 through June 30, 2010.The net effect of the
.
348 Andrews, Di 30
Avista Corporation
.transmission revenue and expense adjustments increases1
2
3
Idaho net operating income by $5,000.
The adjustment in colum (PF6), Pro Form Capital
4 Additions 2008, pro forms in the capital cost and expenses
5 associated with adjusting the twelve-month ending Septemer
6 2008 average-monthly-average plant related balances to
7 expected end-of-period balances for plant in service at
8 Decemer 31, 2008.The capital costs have been included
9 for the December 31, 2008 pro forma period with the
10 associated depreciation expense and property tax, as well
11 as the appropriate accumulated depreciation and deferred
12 income tax rate base offsets.This adjustment was made
13 under the direction of Mr. DeFelice and is described.14 further in his testimony.This adjustment is also
15 consistent with that approved in the most recent Idaho
16 general rate case proceeding, Case No. AVU-E-08-01, which
17 approved the Company's expected net rate base balance as of
18 Decemer 31, 2008.The production property adjustment is
19 also applied to the production and transmission components
20 of these additions as discussed further by Ms. Knox. This
21 adjustment decreases Idaho net operating income by $160,000
22 and increases rate base by $3,658,000.
23 The adjustment in colum (PF7), Pro Form Capital
24 Additions 2009, pro forms in the capital cost and expenses
25 associated with pro forming in capital expenditures for.
349 Andrews, Di 31
Avista Corporation
.
.
.
1
2
This adjustment includes projects expected to be2009.
completed and transferred to plant-in-service by Decemer
3 31, 2009, and thus were normalized to reflect annual
4
5
The capital costs have been included for theamounts.
with the associatedappropriateproformaperiod
6 depreciation expense and property tax, as well as the
7 appropriate accumulated depreciation and deferred income
8 This adjustment also reduces thetax rate base offsets.
9 2008 vintage plant net rate base (including accumulated
10 depreciation and deferred FIT) to an end of period Decemer
11 This adjustment was also made31, 2009 adjusted balance.
12 under the direction of Mr. DeFelice and is described
13
14
The production propertyfurther in his testimony.
adjustment is also applied to the production and
15 transmission components of these additions as discussed
16 This adjustment decreases Idaho netfurther by Ms. Knox.
17 operating income by $1,692,000 and increases rate base by
18 $16,896,000.
19 The adjustment in colum (PF8), Pro Form Informtion
20 Services, pro forms in the administrative and general (A&G)
21 expenses associated with incremental known and measureable
22 changes for labor and non-labor informational services
23 costs planned for 2009 above the test period. As explained
24 by Company wi tness Mr. Kopczynski, these expenditures are
25 related to 1) additional labor dollars required to support
350 Andrews, Di 32
Avista Corporation
.1
2
applications utilized by the Company in recent years, such
as the mobile dispatch and outage management applications,
3 improved web application support, and additional required
4 security and compliance requirements; and 2) additional
5 non-labor dollars required for hosting fees, application
6 fees, software maintenance and license fees, and new and
7
8
replacement software and hardware for business
applications.This adjustment decreases Idaho net
9 operating income by $448,000.
10 The adjustment in colum (PF9) , Pro Form Asset
11 Managemnt, pro forms in the O&M expense associated with
12 the Asset Management Program as described further by Mr.
13 Kinney. This adjustment is consistent with the methodology.14 approved in Case No. AVU-E-08-01.This adjustment
15 decreases Idaho net operating income by $481,000.
16 The adjustment in colum (PF10), Pro Form Spokane
17 River Relicensing, includes the costs associated with the
18 Company's Spokane River relicensing efforts and the CDA
19 Tribe settlement 4 (e) relicensing conditions and accrued
20 interest as described further in my workpapers.These
21 costs include actual life-to-date expenditures from April
22 2001 through Decemer 31, 2008, and 2009 pro forma
23 expendi tures through June 30 , 2009 .Company witness Mr.
24 Storro provides additional details regarding the status of
25 the Spokane River Relicensing efforts and explains that the.
351 Andrews, Di 33
Avista Corporation
.1
2
Company anticipates a final license approved by the Federal
Energy Regulatory Commission (FERC) by June 30, 2009. The
3 majority of these charges were reviewed in the Company's
4 previous general electric rate case proceeding, Case No.
5 AVU-E-08-01. Through the Settlement agreement approved by
6 the Commission in that case, the Company was allowed to
7 defer the amortization of these charges, including a
8 carrying charge on the deferrals and unamortized balance,
9 and include recovery of these costs in its next general
10 rate case.
11 Subsequent to the conclusion of Case No. AVU-E-08-01,
12 and during review of the total current actual expenditures
13 to-date for the Spokane River Relicensing efforts, it was.14 discovered that the Company had inadvertently failed to
15 continue to compute and accrue AFUDC after Decemer 31,
16 2004 on the certain expenditures that had been recorded for
17 the years 1999 to 2004. (In other words, AFUDC was not
18 recorded for the period January 2005 through November 2008
19 on amounts spent in 1999 through 2004.)This error was
20 discovered in Decemer 2008 and corrected, accruing an
21 additional amount of approximately $3.0 million.This
22 correction caused an increase in costs included in this
23 case, above that approved in Case No. AVU-E-08-01, of
24 approximately $1.1 million (Idaho share) to accrue for the
25 missed AFUDC from January 2005 through Novemer 2008 on the.
352 Andrews, Di 34
Avista Corporation
.1
2
1999 through 2004 balance. This adjustment, including the
AFUDC correction, decreases Idaho net operating income by
3 $1,348,000 and increases rate base by $12,184,000.
4 Q.Please turn to page 9 and explain the adjustmnts
5 shown there.
6 A.The adjustment in colum (PF11), Pro Form Coeur
7 d' Alene Tribe Settlement, includes costs associated with
8 the Lake Coeur d' Alene Tribe (CDA Tribe) settlement
9
10
agreement.Mr. Storro describes further the final
agreement between the Company and the CDA Tribe.The
11 settlement includes the payment of $25.0 million in
12 December 2008, $10.0 million in 2009 and $4.0 million in
13 2010 for resolution of the past trespass and §10 (e).14 charges.The future §10 (e) payments are $400,000 flat
15 annual payments for the first 21 years of the new Spokane
16 River license, starting in Decemer 2008, and $700,000 flat
17 annual payments for the remaining years of the license.
18 The agreed upon settlement and payments were reviewed in
19 the company's previous electric general rate case
20 proceeding, Case No. AVU-E-08-01.As approved by the
21 Commission's Order No. 30647, the Company is allowed to
22 defer the amortization of the initial 2008 payments,
23 including a carrying charge on the deferrals and
24 unamortized balance, and include recovery of these costs in
25 its next general rate case.These deferred payments,.
353 Andrews, Di 35
Avista Corporation
.
.
.
1
2
3
including a return on the balance, are planned to be
amortized over the average remaining life of the Post Falls
project, or 45 years.The pro forma adjustment includes
4 one year amortization of the deferred balance, and the 2009
5 annual payment of $400,000.This adjustment decreases
6 Idaho net operating income by $257,000 and increases rate
7 base by $7,861,000.
8 The adjustment in colum (PF12), Pro Form Montana
9 Riverbed Lease, includes costs associated with the Montana
10 Riverbed lease settlement. In this settlement, the Company
11 agreed to pay the State of Montana $4.0 million anually
12 beginning in 2007, with annual inflation adjustments, for a
13 10-year period for leasing the riverbed under the Noxon
14
15
16
Rapids Proj ect and the Montana portion of the Cabinet Gorge
Project.The first two annual payments were deferred by
Avista as approved in Case No. AVU-E-07-10.In Case No.
17 AVU-E-08-01 (see Order No. 30647), the Commission approved
18 the Company's proposed accounting treatment of the deferred
19 payments, including accrued interest, to be amortized over
20 the remaining eight years of the agreement starting October
21 This adjustment includes one-eighth of the1, 2008.
22 deferred balance amortization and the annual lease payment
23 This adjustment decreases Idaho net operatingexpense.
24 income by $1,231,000 and increases rate base by $1,583,000.
354 Andrews, Di 36
Avista Corporation
.1
2
The adjustment in colum (PF13), Pro Porm Colstrip
Mercury Bmission O&:M, includes the pro forma period O&M
3 costs associated with the mercury control project at
4 Colstrip as further described by Mr. Storro.This
5 adjustment decreases Idaho net operating income by
6 $383,OOG.
7 The adjustment in colum (PF14), Pro Porm incentives,
8 adjusts the test year incentive expense to the 2008
9 incentive expense expected to be paid in 2009 for the 2008
10 incentive plan. The Company's main employee incentive plan
11 uses Customer Satisfaction and Reliability targets as the
12 initial step in issuing incentive payouts. Actual payouts
.13
14
are dictated by utility O&M cost savings.Since the
executive plan is slightly different than the main employee
15 incentive plan, this adjustment removes any part of the
16 2008 executive incentive payout that was "not" based on the
17 Customer Satisfaction and Reliability targets.This pro
18 forma adjustment further adjusts incentive expenses to a 6
19 year average. The impact of this adjustment on Idaho net
20 operating income is a decrease of $189,000.
21 Q.Please explain how the Comany computed its 6-
22 year average.
23 A.Actual incentives paid and the associated payroll
24 taxes accrued for years 2003 through 2007 were adjusted by
25 the Consumer Price Index (CPI) annual average for the.
355 Andrews, Di 37
Avista Corporation
.1
2
calendar year the incentives were paid, to reflect those
costs in 2008 dollars.The computed six-year average of
3 2003 through 2008 incentives was compared to incentive
4 expense included in the test period to determine the pro
5 forma adjustment.
6 Q.Why did the Coman choose to use a 6-year
7 average?
8 A.Since annual Company incentive plan payouts can
9 often vary year-to-year, the Company has chosen to propose
10 an average of annual payouts.Often where there are
11 revenues or expenses that can vary significantly from year-
12 to-year and therefore uncertain as to the appropriate
13 level, the Commission has utilized or approved averages to.14
15
properly reflect a fair and reasonable level of revenue or
expense to be included in customers' rates.In 2002 the
16 Company changed its incentive plan to be based on Customer
17 Satisfaction and Reliability targets, and the requirement
18 that O&M savings must occur in order for there to be any
19 payout.This is significantly different than the plans
20 prior to 2002 based on earnings targets of the Company.
21 Utilizing a 6-year average, using years 2003 through 2008,
22 includes common incentive plans that are comparable from
23 year-to-year, and is consistent with other average methods
24 utilized by this Commission.
.
356 Andrews, Di 38
Avista Corporation
.1
2
Q. Please explain other exales where the use of an
average has been used by the Comany to determne the
3 appropriate level of revenue or expense to include in its
4 general rate case filings?
5 A.A few examples come to mind regarding
6 transmission revenue adjustments. For example, the Company
7 uses a five-year average for OASIS wheeling revenues
8 because these revenues vary year to year depending on
9 electric energy market conditions.Avis ta has, in the
10 current and previous rate cases, used the most recent five-
11 year average as being representative of future expectations
12 unless there are known events or factors that occurred
13 during the period that would cause the average to not be.14
15
representative of future expectations.
A second transmission revenue example includes the
16 adjustment for Dry Gulch revenue. The current methodology
17 used to normalize Dry Gulch revenue is a five-year average
18 of actual revenue. A five-year average is used since the
19 revenue can vary from year to year.The revenue is
20 calculated using a 12-month rolling ratchet based on
21 monthly peak demands.Load peaks are very sensitive to
22 temperatures, which vary from year to year.
23
24
A third example, regarding injuries and damages
expense,includes the restating adjustment described
25 earlier in my testimony that replaces the amount accrued in.
357 Andrews, Di 39
Avista Corporation
.the test period with a six-year rolling average of actual1
2
3
payments for injuries and damages not covered by insurance.
Q.Please continue your explanation of the
4 adjustment colums on page 9.
5 A.The adjustment in colum (PF15), Pro Form CS2
6 Levelized Adjustment, defers a portion of the return on
7 Coyote Springs 2 (CS2) in early years for recovery in later
8 years in order tö levelize the revenue requirement on CS2
9 plant investment over a ten-year period. In the Company's
10 electric general rate case, Case No. AVU-E-04-l, this
11 method was approved by the IPUC in Order No. 29602. This
12 adjustment restates the test period amount of. negative
13 amortization expense, inclusive of the carrying charge on.14 the deferred return, to the amount that will be recorded in
15 the rate year. The change in deferred income tax exense
16 from the test period to the rate period is also reflected.
17 In the 2009 rate year the deferred return begins to be
18 recovered, although the carrying cost on the deferred
19 return exceeds the recovery of the deferred return for that
20 period.The levelization adjustment is necessary, since
21 the CS2 net plant upon which the levelization adjustment is
22 based, is proformed to the rate period.Hence, the
23 levelization adjustment also needs to be pro formed to the
24 rate period. This adjustment reduces net operating income
25 by $129,000..
358 Andrews, Di 40
Avista Corporation
.1
2
3
Q. Please turn to page 10 and exlain the
adjustments shown there.
A.The adjustment in colum (PF16), Pro Form Idaho
4 Advanced Meter Reading (AM), includes the capital costs
5 associated with the Company's Idaho AM project.In the
6 I PUC ' s Order No. 29602, in Case No. AVU-E-04-0l, the
7 Commission supported the Company's plans to install AM and
8
9
authorized the Company-requested deferred accounting
treatment for its related investment.In the Company's
10 most recent case, Case No. AVU-E-08-01 in Order No. 30647,
11 the Commission reviewed and approved these deferred costs
12 associated with the Company's investment in AM as prudent.
13 This adjustment includes the amortization of the AMR.14 investment, including actual life-to-date expenditures from
15 January 2005 through Novemer 30, 2008 and expected charges
16 for December 2008.This adjustment decreases Idaho net
17 operating income by $689,000 and increases rate base by
18 $21,436,000.
19 The adjustment in colum (PF17), Pro Form O&M plant
20 expense, adjusts for incremental non-labor generation plant
21 O&M costs planned for 2009/2010 above the test period. As
22 further explained by Mr.Storro,these addi tional
23 expendi tures are mainly due to maj or O&M expendi tures
24 planned for the Company's two thermal generation plants,
25 Colstrip and Kettle Falls, and its Rathdrum CT peaking.
359 Andrews, Di 41
Avista Corporation
generation plant.This adjustment decreases Idaho net.1
2
3
operating income by $899,000.
The adjustment in colum (PF18), Pro Form Bmloyee
4 Benefits, adjusts for changes in both the Company's pension
5 and medical insurance expense and decreases Idaho net
6 operating income by $944,000.
7 Q.please describe the pension expense portion of
8 the Bmloyee Benefits adjustment and Idaho's share of this
9 expense.
10 A.The Company's pension expense portion of this
11 adjustment is determined in accordance with Financial
12 Accounting Standard 87 ("FAS-87"), and has increased on a
13 system basis from $12.1 million for the actual test year.14 costs for the twelve months ended Septemer 30, 2008, to
15 $18.4 million for 2009. At this time the amounts included
16 in this case are estimated with the most current available
17 data as of Decemer 2008.Preliminary Pension expense is
18 determined by an outside actuarial firm, in accordance with
19 FAS-87, and provided to the Company late in the first
20 quarter of each year.These calculations and assumptions
21 are reviewed by the Company's outside accounting firm
22 annually for reasonableness and comparability to other
23 companies.Due to the timing of this report, additional
24 information may become known during the course of these
.
360 Andrews, Di 42
Avista Corporation
.1
2
3
proceedings that may require a modification to this
adjustment.
As explained by Company witness Mr. Thies, the
4 increase in pension expense is due primarily to the
5 investmant performance of plan assets during the major
6 downturn in the financial markets experienced during the
7 past year.In addition, the Pension Protection Act (PPA)
8 of 2006 requires companies to annually increase the funding
9 level of their pension plans in order to eventually achieve
10 a fully funded plan.
11 As explained by Mr. Thies, Avista is very disciplined
12 in its plan asset allocation and believes that its approach
13 has helped to arrest what could have been an even greater.14 decline in plan assets value. Many companies with Defined
15 Benefit Pension Plans have experienced similar asset value
16 declines and increased funding levels as a result of
17 general market condi tions, as discussed by Mr. Thies.
18 The pension levels noted above are for the Company as
19 a whole. Pension expense, as with other employee benefits,
20 is "loaded" onto actual labor costs, which are then
21 assigned to various functional expense categories and
22 accounts through the payroll process.Historically,
23 approximately 60% of labor is recorded as O&M expense and
24 40% is recorded as capital. In our adjustment, a detailed
25 analysis of labor charges was performed to more accurately.
361 Andrews, Di 43
Avista Corporation
.1
2
determine the Idaho O&M percentage of overall labor. Based
on this analysis, Idaho's share of the electric pension
3 expense (pre-tax) amount included in this adjustment is
4 approximately $940,000.
5 Q.Please now describe the medical insurance exense
6 portion of the Emloyee Benefits adjustment an Idaho's
7 share of this exense.
8 A.The Company's medical insurance expense portion
9 of this adjustment adjusts for the medical insurance costs
10 planned for 2009 above the test period. Medical insurance
11 expense has increased on a system basis from $14.3 million
12 for the actual test year costs for the twelve months ended
13 September 30, 2008 to $17.9 million projected for 2009..14 This increased cost is mainly due to increased large claims
15 activity driven by various diagnostic categories such as
16 cancer and heart disease, and an increase in the average
17 age of our membership.
18 Avista has taken measures to decrease its self-funded
19 plan costs.These measures include increasing the stop
20 loss insurance reimbursement level, which decreases the
21 premium expense with Avista's third party administrator.
22 Avista also negotiated a new contract with its prescription
23 benefit administrator and its third party administrator
24 (TPA) to pass through the drug manufacturer rebates (in the
25 past these rebates were left with the TPA). Also, Avista.
362 Andrews, Di 44
Avista Corporation
.1
2
is converting to a Preferred Provider Organization (PPO)
program for its dental plan that provides savings to the
3 participant, similar to medical plans with a PPO program.
4 In addition to these current measures, Avista has made
5 changes to co-pay levels and out of pocket maximums over
6 the past five years to help reduce plan costs.
7 Again, as with other employee benefits, medical
8 insurance expense is "loaded" onto actual labor costs,
9 which are then assigned to various functional expense
10 categories and accounts through the payroll process.
11 Historically, approximately 60% of labor is recorded as O&M
12 expense and 40% is recorded as capital.Idaho's share of
13 the electric medical insurance expense (pre-tax) amount.14
15
included in this adjustment is approximately $530,000.
Q.please continue your explantion of the
16 adjustment colums on page 10.
17 The adjustment in Colum (PF19), Pro Form Insurance,
18 adjusts the test period insurance expense for general
19 liability, directors and officers ("D&O") liability, and
20 property to the actual cost of insurance policies that are
21 in effect for 2009.Costs of system-wide insurance
22 policies for 2009 varied from 2008, mainly for General
23 Liability and Property insurance cost, which increased
24 approximately $730,000 (system expense), due to increased
25 coverage, Avista' s growth, and higher premium rates..
363 Andrews, Di 45
Avista Corporation
.
.
.
1
2
Property insurance rates were volatile because of extensive
energy industry property damage in 2008 and adverse
3 investment returns at insurance companies. Insurance costs
4 that are properly charged to non-utility operations have
5 been excluded from this adjustment. This adjustment
6 decreases Idaho net operating income by $97,000.
7 The adjustment in Colum (PF20), Pro Form Chicago
8 Climate Exchange, adjusts other revenue for Idaho's share
9 of the revenues, net of expenses, from the sales of Carbon
10
11
on the Chicago ClimateFinancial Instruments (CFIs)
Exchange.In Order No. 30647 (Case No. AVU-E-08-01), the
12 Commission approved the amortization of the net revenues
13
14
over a two-year period beginning in October 2008.This
adjustment increases Idaho net operating income by
15 $273,000.
16 Please turn to page 11 and explain theQ.
17 adjustmts shown there.
18 The adjustment in colum (PF21) , Pro FormA.
19 Wartsila Amortization, reflects a five-year amortization of
20 the estimated unrecovered investment in two 4 MW
21 reciprocating engine generators originally planned to be
22 installed at Boulder Park, a small natural gas-fired
23 During the period Decemer 2004generating facility.
24 through February 2005 Avista and Commission Staff discussed
25 possible accounting treatment related to the planned sale
364 Andrews, Di 46
Avista Corporation
.1
2
of the Wartsila units. In February 2005 the Staff
indicated by letter that it would support a five-year
3 amortization of the unrecovered costs, with no return on
4 the unamortized balance, and that the inclusion of the
5 amortization expense in rates would be addressed in a
6 future proceeding.
7 In 2008 a buyer agreed to purchase the units for net
8 proceeds to the Company of $1 million, as compared to the
9 book value of $3.65 million. However, the buyer defaulted
10 and only one unit was delivered with net proceeds to the
11 Company of $670,000. The second unit remains unsold. The
12 buyer is trying to raise the remaining $330,000 to purchase
13 the second unit. The amortization amount in the adjustment.14 assumes that the second unit will be sold for the $330,000.
15 Addi tional information may become known during the course
16 of these proceedings that may require a modification to the
17 adjustment. This adjustment decreases Idaho net operating
18 income by $120,000.
19 The adjustment in colum (PF22), Pro Form Colstrip
20 Lawsuit Settlemnt, reflects a two-year amortization of the
21 Company's share of the lawsuit settlement amount.On May
22 22, 2008, the Company filed an application seeking an
23 accounting order to defer the settlement payment.On
24 September 12, 2008, the Commission authorized deferred
25 accounting treatment in Order No. 30638, Case No. AVU-E-08-.
365 Andrews, Di 47
Avista Corporation
.1
2
03. Staff's recommendation No. 4 on page 3 of the Order
recommends delaying any recovery for the amount of the
3 deferral until the next general rate case or other
4 proceeding as the Commission deems appropriate.
5 Avista may recover a portion of the settlement amount
6 under relevant insurance policies.The amount and timing
7 of any insurance proceeds is not known at this time. The
8 adjustment can be revised as additional information
9 regarding insurance proceeds becomes known.This
10 adjustment decreases Idaho net operating income by
11 $240,000.
12 The last colum, Pro Forma Total, reflects total pro
13 forma results of operations and rate base consisting of.14 test period actual results (twelve-months ending Septemer
15 30, 2008) and the total of all adjustments.
16 Q.Referring back to page 1, line 42, of Exibit No.
17 10, Schedule 1, what was the actual an pro form electric
18 rate of return realized by the Company during the test
19 period?
20 A.For the State of Idaho, the actual test period
21 rate of return was 6.99%. The pro forma rate of return is
22 5.34% under present rates. Thus, the Company does not, on
23 a pro forma basis for the test period, realize the 8.80%
24 rate of return requested by the Company in this case.
.
366 Andrews, Di 48
Avista Corporation
.1
2
Q. How much additional net operating incom would be
required for the State of Idaho electric operations to
3 allow the Comany an opportunity to earn its proposed 8.80%
4 rate of return on a pro for. basis?
5 A.The net operating income deficiency amounts to
6 $19,951,000, as shown on line 5, page 2 of Exhibit No. 10,
7 Schedule 1. The resulting revenue requirement is shown on
8 line 7 and amounts to $31,233,000, or an increase of 14.18%
9 over pro forma general business revenues.
10
11
12
IV.NATU GAS SBCTION
Q.On what test period is the Comany basing its
13 need for additional natural gas revenue?.14 A.The test period being used by the Company is the
15 twelve-month period ending Septemer 30, 2008, presented on
16 a pro forma basis.Currently authorized rates are based
17 upon the 2007 test year utilized in case No. AVU-G-08-01,
18 as adjusted on a pro forma basis.
19 Q.Could you please exlain the different rates of
20 return show in your natural gas results presented in your
21 testimony?
22
23
24
A.Yes.As discussed previously in the Electric
Section,there are three different rates of return
calculated.The actual ROR earned by the Company during
25 the test period, the Pro Forma ROR determined in my Exhibit
.
367 Andrews, Di 49
Avista Corporation
.1
2
No. 10, Schedule 2, and the reques ted ROR. For convenience
of comparison, please refer to Illustration No. 3 below
3 depicting these results for the Natural Gas Section:
45 Illustration No.3:
6
7
Avista Corp
Rates of Retu
.
8
9
10
11
12
13
14
15
10.00%
8.00%
6.00%
4.00%
2.00%
0.00%
Actual ProForma Request
Q.Wht are the primary factors driving the
Comany's need for additional natural gas revenues?
A.The Company's natural gas request is driven by
16 changes in various operating cost components, mainly
17 distribution operation and maintenance and administrative
18
19
and general expendi tures .This causes an increase in the
fixed costs of providing gas service to customers.I
20 describe the pro forma adjustments included in this case
21 later in my testimony.
22
23 Revenue Requiremnt
24 Q.Would you please explain what is show in Exibit
25 No. 10, Schedule 2?.
368 Andrews, Di 50
Avista Corporation
.1
2
3
A. Exhibit No. 10, Schedule 2 shows actual and pro
forma gas operating results and rate base for the test
period for the State of Idaho.Colum (b) of page 1 of
4 Exhibit No. 10, Schedule 2 shows test period operating
5 results (twelve-months ended Septemer 30, 2008) and
6 components of the average-monthly-average rate base as
7 recorded; colum (c) is the total of all adjustments to net
8 operating income and rate base; and colum (d) is pro forma
9 resul ts of operations, all under existing rates.Colum
10 (e) shows the revenue increase required which would allow
11 the Company to earn" an 8.80% rate of return.Colum (f)
12 reflects pro forma gas operating results with the requested
13 increase of $2,740,000..14 Q.Would you please exlain page 2 of Bxibi t No.
15 10, Schedule 2?
16 A.Yes.Page 2 shows the calculation of the
17 $2,740,000 revenue requirement at the requested 8.80% rate
18 of return.
19 Q.Would you now please explain page 3 of Bxibi t
20 No. 10, Schedule 2?
21
22
A.Yes.Page 3 shows the derivation of the net
operating income to gross revenue conversion factor.The
23 conversion factor takes into account uncollectible accounts
24 receivable, Commission fees and Idaho State excise taxes.
25 Federal income taxes are reflected at 35%..
369 Andrews, Di 51
Avista Corporation
.1
2
Q. Now turning to pages 4 through 8 of your Bxibi t
No. 10, Schedule 2, would you please exlain what .those
3 pages show?
4 A.Yes. Page 4 begins with actual operating results
5 and rate base for the test period (twelve-months ending
6 September 30, 2008) in colum (b). Individual normalizing
7 adjustments consistent with prior regulatory treatment
8 (standard Commission Basis adjustments) begin in colum (c)
9 on page 4 and continue through colum (r) on page 6.
10 Individual pro forma and additional normalizing adjustments
11 begin in colum (PF1) on page 6 and continue through colum
12 (PF10) on page 8. The final colum on page 8 is the total
13 pro forma operating results and rate base for the test.14 period.Additional details related to each adjustment
15 described below are provided in accompanying work papers.
16
17 Standard Comission Basis Adjustments
18 Q.Would you please explain each of these
19 adjustments, the reason for the adjustment and its effect
20 on test period State of Idaho net operating income and/or
21 rate base?
22 A.Yes, the restating adjustments shown in colums c
23 through r are consistent with methodologies employed in our
24 prior cases and current regulatory principles.
.
370 Andrews, Di 52
Avista Corporation
.1
2
3
The first adjustment, colum (c) on page 4, entitled
Deferred FIT Rate Base, reflects the rate base reduction
for Idaho's portion of deferred taxes.The adjustment
4 reflects the deferred tax balances arising from accelerated
5 tax depreciation (Accelerated Cost Recovery System, or
6 ACRS, and Modified Accelerated Cost Recovery, or MACRS),
7 bond refinancing premiums, and contributions in aid of
8 construction.These amounts are reflected on the average
9 of monthly average balance basis. The effect on Idaho rate
10 base is a reduction of $14,220,000.
11 The adjustment in colum (d), Deferred Gain on Office
12 Building, reflects the rate base reduction for Idaho's
13 portion of the net of tax, unamortized gain on the sale of.14 the Company's general office facility.The facility was
15 sold in Decemer 1986 and leased back by the Company.
16 Although the Company repurchased the buildirig in Novemer
17 2005, the Company opted to continue to amortize the
18 deferred gain over the remaining amortization period
19 scheduled to end in 2011. The effect on Idaho rate base is
20 a reduction of $53,000.
21 The adjustment in colum (e), Gas Inventory, reflects
22 the adjustment to rate base for the average of monthly
23 average value of gas stored at the Company's Jackson
24 Prairie underground storage facility through the test
.
371 Andrews, Di 53
Avista Corporation
.1
2
3
$4,535,000.
period.The effect on Idaho rate base is an increase of
Thè adjustment in colum (f), Weatherization an DSY
4 Investment, includes in rate base the balance (net of
5 amortization) of company investments in natural gas demand
6
7
side management (DSM) program costs.These amounts are a
component of actual results of operations.The effect of
8 this adjustment is to increase Idaho rate base by $279,000.
9 The adjustment in colum (g) , entitled Customer
10 Advances, decreases rate base for funds advanced by
11 customers for line extensions, as they are generally
12 recorded as contributions in aid of construction at some
13 future time. The effect of this adjustment on Idaho rate.14 base is a decrease of $73,000.
15 The colum labeled Subtotal Actual, is a subtotal of
16 colums (b) through (g) and reflects the standard rate base
17 adjustments.
18 Q.Please turn to page 5 an exlain the adjustments
19 shown there.
20 A.The first adjustment on page 5 in colum (h),
21 entitled Depreciation True-up, reflects a decrease in
22 depreciation expense due to the utilization of new
23 depreciation rates effective January 1, 2008 as approved in
24 Order No. 30498 in Case No. AVU-G-07-03.These rates
25 became effective after the three months October through.
372 Andrews, Di 54
Avista Corporation
.1
2
Decemer 2007 included in the test period. This adjustment
annualizes the current effective rates for the test period.
3 This adjustment increases Idaho net operating income by
4 $25,000.
5 The adjustment in colum (i),enti tled Weather
6 Normlization & Gas Cost Adjustment, is a 3-fold adjustment
7 taking. into account known and measurable changes that
8 include revenue normalization ( inc 1 uding the curren t
9 authorized rates approved in Case No. AVU-G-08-01), which
10 reprices customer usage under presently effective rates, as
11 well as weather normalization and an unbilled revenue
12 calculation.Associated gas costs are replaced with gas
13 costs computed using normalized volumes at the currently.14 effective "weighted average cost of gas," or WACOG rates.
15 Revenues associated with the temporary Gas Rate Adjustment
16 Schedule 155 and Schedule 191 Tariff Rider are excluded
17 from pro forma revenues, and the related amortization
18 expenses are eliminated as well.The January 6, 2009 gas
19 cost reduction to customer charges was accomplished through
20
21
Schedule 155, which is excluded from base revenues.Ms.
Knox is sponsoring this adjustment.The effect of this
22 particular adjustment is to increase Idaho net operating
23 income by $2,359,000.
24 The adjustment in colum (j), Bliminate B & 0 Taxes,
25 eliminates the .revenues and expenses associated with local.
373 Andrews, Di 55
Avista Corporation
.1
2
business and occupation taxes, which the Company passes
through to customers. The adjustment eliminates any timing
3 mismatch that exists between the revenues and expenses by
4 eliminating the revenues and expenses in their entirety.
5 B & 0 Taxes are passed through on a separate schedule,
6 which is not part of this proceeding. The effect of this
7 adjustment is zero to Idaho net operating income.
8 The adjustment in colum (k), Property Tax, restates
9 the test period accrued levels of property taxes to the
10 most current information available and eliminates any
11 adjustments related to the prior year. The effect of this
12 particular adjustment is to decrease Idaho net operating
13 income by $104,000..14 The adjustment in colum (l), uncollectible Exense,
15 restates the accrued expense to the actual level of net
16 write-offs for the test period.The effect of this
17 adjustment is to increase Idaho net operating income by
18 $81,000.
19 The adjustment in colum (m), entitled Regulatory
20 Exense Adjustment, restates recorded 2008 regulatory
21 expense to reflect the IPUC assessment rates applied to
22 revenues for the test period.The effect of this
23 adjustment is to decrease Idaho net operating income by
24 $8,000.
.
374 Andrews, Di 56
Avista Corporation
.1
2
3
Q. Please turn to page 6 an explain the adjustments
show there.
A.The first adjustment on page 6 in colum (n),
4 entitled injuries an Damges, is a restating adjustment
5 that replaces the accrual with the six-year rolling average
6 of actual injuries and damages payments not covered by
7
8
. 4insurance.This methodology was accepted by the Idaho
Commission in Case No. WWP-E-98-11.The effect of this
9 adjustment is to increase Idaho net operating income by
10 $1,000.
11 The adjustment in colum (0), entitled PIT, adjusts
12 the FIT calculated at 35% within Results of Operations by
13 removing the effect of certain Schedule M items and matches.14 the jurisdictional allocation of other Schedule M items to
15 related Results of Operations allocations. This adjustment
16 also reflects the proper level of deferred tax exense for
17 the test period. The effect of this adjustment, all based
18 upon a Federal tax rate of 35%, is to increase Idaho net
19 operating income by $10,000.
20 The adjustment in colum (p), Bliminate AIR Exenses,
21 A/R representing Accounts Receivable, removes expenses
22 associated with the sale of customer accounts receivable.
4 Due to the twel ve months ending Septemer 30, 2008 test period
utilized in this case, the Company computed the six-year average using
twelve-months ended actuals through November 2008 (most current data
available at time of adjustment) for its 2008 balance..
375 Andrews, Di 57
Avista Corporation
.1
2
3
The effect of this adjustment is to increase Idaho net
operating income by $27,000.
The adjustment in colum (q), Miscellaneous Restating
4 Adjustment, removes a numer of non-operating or non-
5 utility expenses associated with advertising, sponsorships
6 and dues and donations included in error in the test period
7 actual resul ts .The effect of this adjustment is to
8 increase Idaho net operating income by $31,000.
9 The adjustment in colum (r), Restate Debt Interest,
10 restates debt interest using the Company's pro forma
11 weighted average cost of debt, as outlined in the testimony
12 and exhibits of Mr. Thies, and applied to Idaho'~ pro forma
13 level of rate base, produces a pro forma level of tax.14 deductible interest expense. The federal income tax effect
15 of the restated level of interest for the test period
16 decreases Idaho net operating income by $292,000.
17 The next colum on page 6, entitled Restated Total,
18 subtotals all the preceding colums (b) through colum (r),
19 exclusive of the previously discussed subtotal colum.
20 These totals represent actual operating results and rate
21 base plus the standard normalizing adjustments.
.
376 Andrews, Di 58
Avista Corporation
.1
2
Pro Form Adjustmnts
Q. Please exlain the significance of the 10 colums
3 subsequent to the Restated Total colum on pages 6 through
4 8 of your Exibit No. 10, Schedule 2.
5 A.The adjustments starting on page 6 are pro forma
6 adjustments to reflect known and measurable changes between
7 the test period and the pro forma period.In this case,
8 they encompass revenue and expense items, and natural gas
9 capi tal proj ects .These adjustments bring the operating
10 results and rate base to the final pro forma level for the
11 test year.
12 Q.Please continue with your explanation of the
13 adjustments on page 6..14 A.The adjustment in colum (PF1), Pro Form Labor-
15 Non-Exec, reflects known and measurable changes to test
16 period union and non-union wages and salaries, excluding
17 executive salaries, which are handled separately in PF2.
18 Test period wages and salaries are restated as if the wage
19 and salary increase in March 2009 were in place for 8
20 months and the March 2010 increase was in place for 4
21 months of the pro forma period ending June 30, 20l0. The
22 methodology behind this adjustment is consistent with that
23 used in Case No. AVU-G-08-1. The effect of this adjustment
24 on Idaho net operating income is a decrease of $179,000.
.
377 Andrews, Di 59
Avista Corporation
.
.
.
1
2
3
Q. Please turn to page 7 an explain the adjustments
show there.
A.The first adjustment on page 7, in colum (PF2)
4 is Pro Form Labr-Executive, which reflects known and
5 measurable changes to executive compensation. Test period
6 wages and salaries are restated to the 2010 expected level.
7 This adjustment takes into account changes in executive
8 staffing made during 2008 and includes compensation for the
9 planned executive team in the pro forma period only.
10 Compensation costs for non-utility operations are excluded
11 as executives routinely charge a portion of their time to
12 non-utility operations, commensurate with the amount of
13
14
15
The current executives'time spent on such acti vi ties.
salary allocations are set at their expected pro forma test
period utility/non-utility percentage splits.The impact
16 of this adjustment on Idaho net operating income is a
17 decrease of $21,000.
18 The adjustment in colum (PF3), Pro Form capital
19 Additions 2008, pro forms in the capital cost and expenses
20 associated with adjusting the test period average-monthly-
21 average plant related balances at Septemer 30, 2008, to
22 actual end-of-period balances for plant in service at
23 The capital costs have been includedDecemer 31, 2008.
24 for December 31, 2008 pro forma period with the associated
25 depreciation expense and property tax, as well as the
378 Andrews, Di 60
Avista Corporation
.1
2
appropriate accumulated depreciation and deferred income
tax rate base offsets. This adjustment was made under the
3 direction of Mr. DeFelice and is described further in his
4 testimony.This adjustment increases Idaho net operating
5 income ny $71,000 and increases rate base by $445,000.
6 The adjustment in colum (PF4), Pro Form Capital
7 Additions 2009, pro forms in the capital cost and expenses
8 associated with pro forming in capital expenditures for
9 2009.This adjustment includes proj ects completed during
10 2009, and thus were normalized to reflect annual amounts,
11 and proj ects expected to be completed and transferred to
12 plant-in-service by Decemer 31, 2009.The capital costs
13 have been included for their appropriate pro forma period.14 with the associated depreciation expense and property tax,
15 as well as the appropriate accumulated depreciation and
16 deferred income tax rate base offsets.This adjustment
17 also reduces the 2008 vintage plant net rate base
18 (including accumulated depreciation and deferred FIT) to an
19 end of period Decemer 31, 2009 adjusted balance.This
20 adjustment was also made under the direction of Mr.
21 DeFelice and is described further in his testimony.This
22 adjustment decreases Idaho net operating income by $198,000
23 and decreases rate base by $691, 000.
24 The adjustment in colum (PF5), entitled Pro Form
25 Informtion Services, pro forms in the administrative and.
379 Andrews, Di 61
Avista Corporation
.
.
.
1
2
general (A&G) expenses associated with incremental known
and changes for labor and non-labormeasureable
3 informational services costs planned for 2009 above the
4 test period, as further explained in the Electric Section.
5 The impact of this adjustment on Idaho net operating income
6 is a decrease of $10l, 000.
7 The adjustment in colum (PF6), entitled Pro Form
8 Incentives, adjusts the test year incentive expense to the
9 2008 incentive expense expected to be paid in 2009 for the
10 2008 (as further explained in the Electric Section). This
11 adjustment also pro forms in a 6 year average (as further
12 explained in the Electric Section).The impact of this
13 adjustment on Idaho net operating income is a decrease of
14
15
$47, 000.
The adjustment in colum (PF7), Pro For. JP Storage,
16 pro forms revenues, expenses, capital investment and
17 increased capacity andinventoryforthestorage
18 deliverability associated with the Jackson Prairie (JP)
19 Storage facility that was approved by the Commission in
20 Order No. 30647 (Case No. AVU-G-08-01).In 2008, Avista
21 ended its natural gas storage release contract with Terasen
22
23
The revenues of $1,060,000 from the release of thisGas.
contract have been eliminated from the test period.Gas
24 inventory has been increased by $289,000, due to the
25 In addition, a multi-year expansionrecouped storage.
380 Andrews, Di 62
Avista Corporation
.1
2
project at the facility was in service in October 2008,
which increased deliverability, increasing depreciation and
3 property taxes expense by approximately $117,000, and
4 increasing net rate base by $3,302,000.The total net
5 impact of these adjustments decreases Idaho net operating
6 income by $752,000 and increases rate base by $3,591,000.
7 Q.Please turn to page 8 and exlain the adjustmnts
8 shown there.
9 A.The first adjustment on page 8, in colum (PF8)
10 is Pro Form Idaho Advanced Meter Reading (AM), includes
11 the capital costs associated with the Company's Idaho AM
12 project.These costs include actual life-to-date
13 expenditures from January 2005 through December 31, 2008.14 (as explained further in the Electric Section).This
15 adjustment decreases Idaho net operating income by $229,000
16 and increases rate base by $6,142,000.
17 The adjustment in colum (PF9), Pro Form Bmloyee
18 Benefits, adjusts for changes in both the Company's pension
19 and medical insurance expense planned for 2009 as further
20 explained in the Electric Section above. This adjustment
21 decreases Idaho net operating income by $242,000
22 The adjustment in colum (PF10), Pro For. Insurance,
23 updates the test period insurance expense for general
24 liability,directors and officer ("D&O" )liability,
25 property and other policies, to the actual cost of.
381 Andrews, Di 63
Avista Corporation
.1
2
insurance policies planned for 2009 as described further in
the Electric Section above.This adjustment decreases
3 Idaho net operating income by $25,000
4 The last colum on page 8, Pro Porm Total, reflects
5 total pro forma results of operations and rate base
6 consisting of twelve-months ended September 30, 2008 actual
7 results and the total of all normalizing and pro forma
8 adjustments.
9 Q.Referring back to page 1, line 43, of Exibit No.
10 10, Schedule 2, what was the actual and pro form gas rate
11 of return realized by the Comany during the test period?
12 A.For the State of Idaho, the actual test period
13 rate of return was 6.41%. The pro forma rate of return is.14 6.87% under present rates. Thus, the Company does not, on
15 a pro forma basis for the test period, realize the 8.80%
16 rate of return requested by the Company in this case.
17 Q.How much additional net operating incom would be
18 required for the State of Idaho gas operations to allow the
19 Comany an opportunity to earn its proposed 8.80% rate of
20 return on a pro form basis?
21 A.The net operating income deficiency amounts to
22 $1,750,000, as shown on line 5, page 2 of Exhibit No. 10,
23 Schedule 2. The resulting revenue requirement is shown on
24 line 7 and amounts to $2,740,000, or an increase of 2.99%
.
382 Andrews, Di 64
Avista Corporation
.
.
.
1 forma general business and transportationover pro
2
3
4
5
revenues.
v.ALLOATION PROCBDURS
Q.Have there been any changes to the Company's
6 system and jurisdictional procedures since the Company's
7 last general electric and natural gas cases, Case Nos. AVU-
8 E-08-01 and AVU-G-08-01?
9 For ratemaking purposes,the CompanyA.No.
10 allocates revenues, expenses and rate base between electric
11 and gas services and between Washington, Idaho, and Oregon
12
13
14
jurisdictions where electric and/or gas service is
provided.The current methodology was implemented in 1994
and has not changed.The allocation factors used in this
15 case have been provided with my workpapers.
16
17
18
VI. OTHBR
filing requirements asQ.Please address the
19 required in Order No. 29962.
20 In Order No. 29962 (Case Nos. AVU-E-05-9 and AVU-A.
21 G-05-3), the Commission directed the Company to record
22 regulatory assets or liabilities associated with the
23
24
implementation of of Financial AccountingStatement
Standards (SFAS) 143.As a result of the Order, the
25 Company is required to file annually, and as part of any
383 Andrews, Di 65
Avista Corporation
.1
2
rate case filing, all journal entries made under the
requirements of SFAS 143. These ARO transactions have been
3 removed from the test year (twelve months ended September
4 30, 2008) Results of Operations and have no impact on the
5 Company's earnings or rate request in this case.The
6 journal entries for the calendar year 2008 will be filed
7 with the Commission in our upcoming compliance filing.
8 Q.Does that conclude your pre-filed direct
9 testimony?
10 A.Yes, it does.
.
.
384 Andrews, Di 66
Avista Corporation
.1
2
I. INTRODUCTION
Q.Please state your nae, business address and
3 present position with Avista Corporation?
4
5
A.My name is Tara L. Knox and my business address
is 1411 East Mission Avenue, Spokane, Washington.I am
6 employed as a Senior Rate Analyst in the State and Federal
7 Regulation Department.
8
9
Q.Would you briefly describe your duties?
A.I am responsible for preparing the regulatory
10 cost of service models for the Company, as well as
11 providing support for the preparation of results of
12 operations reports.
.13
14
15
Q.Would you describe your educational background
and professional experience?
A.Yes.I am a 1982 graduate of Washington State
16 university with a Bachelor of Arts degree in General
17 Humanities, and a Master of Accounting degree in 1990. As
18 an employee in the Rate Department at Avista since 1991, I
19 have attended several ratemaking classes, including the EEI
20 Electric Rates Advanced Course that specializes in cost
21 allocation and cost of service issues. I have also been a
22 member of the Cost of Service Working Group and the
23 Northwest Pricing and Regulatory Forum,which are
24 discussion groups made up of technical professionals from
25 regional utilities and utilities throughout the united.
385 Knox, Di 1
Avista Corporation
.1
2
States and Canada concerned with c;ost of service issues.
Q., What is the scope of your testimny in these
3 proceedings?
4 A.My testimony and exhibits will cover the
5 Company~s electric and natural gas cost of service studies
Addi tionally,I am6
7
performed for this proceeding.
natural gas revenuesponsoringtheelectricand
8 normalization adjustments to the test year results of
9 operations and the proposed retail revenue credit rate to
10 be used in the Power Cost Adjustment mechanism.
11 Table of Contents
.
12
13
14
15
16
17
18
19
20
21
22
23
24
25 Q.
26 filed testimony?
Yes. I am sponsoring Exhibit No. 11 composed of
i.
II.
III.iv.
v.
VI.
27 A.
Introduction
Table of Contents
Revenue Normalization
Electric Revenue Normalization
Natural Gas Revenue Normalization
Proposed Retail Revenue Credit Rate
Electric Cost of Service
Demand Study
Scenario 1
Scenario 2
Scenario 3
Scenario 4
Natural Gas Cost of Service
Page 1
Page 2
Page 3
Page 3
Page 7
page 11Page l2
Page 17
Page 20
Page 22
Page 25
Page 27
Page 32
Are you sponsoring any Exibits with yor pre-
28 six schedules as follows: Schedule 1, retail revenue credit
29 rate calculation; Schedule 2, electric cost of service
30 study process description; Schedule 3, electric cost of
31 service.study sumary resul ts ;Schedule 4,Demand
386 Knox, Di 2
Avista Corporation
.1
2
Sensitivity Results sumary; Schedule 5, natural gas cost
of service study _ process description; and Schedule 6,
3 natural gas cost of service sumary results.
4 Q.Were these exhibits prepared by you or uner your
5 direction?
6
7
8
9
A.Yes.
II. RB NO:RIZATION
Blectric Revenue Normlization
Q.Would you please describe the electric revenue
10 adjustment included in Comany witness Ms. Andrews pro
11 for. results of operations?
12 A.Yes.The electric revenue normalization
13 adjustment represents the difference between the Company's.14 actual recorded retail revenues during the twelve months
15 ended Septemer 2008 test period and retail revenues on a
16 normalized (pro forma)basis.The total revenue
17 normalization adjustment increases Idaho net operating
18 income by $14,065,000 as shown in colum (u) on page 6 of
19
20
Ms . Andrews Exhibi t No.1 0, Schedule 1 .The revenue
normalization adjustment consists of three primary
21 components: 1) re-pricing customer usage (adjusted for any
22 known and measurable changes) at present base tariff rates
23 in effect,2) adjusting customer loads and revenue to a
24 12-month calendar basis (unbilled revenue adjustment), and
25 3) weather normalizing customer usage and revenue..
387 Knox, Di 3
Avista Corporation
.1
2
Q. Since these three elements are comined into a
single adjustment, would you please identify the impact
3 (before taxes and revenue related expenses) of each
4 comonent?
5
6
A.' Yes.The re-pricing of billed usage comprises
the maj ori ty of the change in test year revenue.The
7 combined impact of the rate increase effective October 1,
8 2008 and the elimination of revenue and amortization
9 expense from adder schedules, (Schedule 59 Residential
10 Exchange, and Schedule 91 Public purpose Tariff Rider1) is
11 an increase of $23,880,000.The impact of the pro forma
12 unbilled revenue compared to the amount included in results
13 of operations is a reduction of $31,000, and the weather.14
15
normalization adjustment reduces revenue by $1,837,000.
The resulting net operating income adjustment is
16 $14,065,000.
17 Q.Would you please briefly discuss electric weather
18 normlization?
19 A.Yes.The Company's weather normalization
20 adjustment calculates the change in kWh usage required to
21 adjust actual loads during the twelve months ended
22 September 2008 test period to the amount expected if
23 weather had been normal. This adjustment incorporates the
24 effect of both heating and cooling on weather-sensitive
i City Franchise Fee and Power Cost Adjustment revenues are elimated in separate adjustments..
388 Knox, Di 4
Avista Corporation
.1
2
customer groups. The weather adjustment is developed from
regression analysis of five years of billed usage per
3 customer and billing period heating and cooling degree-day
4 data.The resulting seasonal weather sensitivity factors
5 (use per customer per heating degree day and use per
6 customer per cooling degree day) are applied to monthly
7 test period customers and the difference between normal
8 heating/cooling degree-days and monthly test period
9 observed heating/cooling degree-days.
10 Q.How are norml heating and cooling degree days
11 defined?
12 A.Normal heating and cooling degree days are based
13 on a rolling 30-year average of heating and cooling degree-.14
15
days reported for each month by the National Weather
Service for the Spokane Airport weather station.For
16 heating, the 30 years are included on a heating season
17 basis, July through June, so, for example, the October
18 average reflects all the Octobers beginning in 1978 and
19 through 2007, whereas the May average reflects all of the
20 Mays beginning in 1979 and through 2008. For cooling, the
21 30 years reflect the cooling season calendar years
22 beginning in 1979 and through 20082.Each year the normal
2 The National Climtic Data Center publication used to acquie the fil quaty controlled data for the
Spokane Airort weather station did not include cooling degree day information prior to 1980.
Consequently, the 30 year average is actually a 29 year average including the year 1980 though 2008.
As a rolling average, in all futue year it would contain a full 30 year of data. Heatig degree day
informtion was available for all the desired year..
389 Knox, Di 5
Avista corporation
.
.
.
1
2
values will be adjusted to capture the next heating and
cooling season with the oldest data dropping off, thereby
3 encapsulating the most recent information available at the
4 end of each calendar year.
5 Are there any changes in the weather adjustmentQ.
6 methodology since the comany's last general rate case in
7 Idaho?
8 In Case No. AVU-E-08-01 the Company used aA. Yes.
9 twenty-five year rolling average to determine normal
10 heating and cooling degree days for each month.As
11 mentioned above, in this case an additional five years have
12
13
14
15
rolling calculation.included in thebeen average
3same as the methodistheOtherwise,the process
introduced in Case No. AVU-E-08-01.
Q.Why are you proposing to change from a 25-year to
16 a 30-year average for norml degree days?
17 In response to concerns in another jurisdictionA.
18 that twenty-five years may be insufficient to determine
19 "normal," I performed additional analysis on how the
20 rolling averages change over time.Specifically,I
21 compared twenty-five year rolling averages to thirty year
22 rolling averages for all data available from the NOAA
23 published Anual Climatological Sumary for the Spokane
3 The regression analysis presented in Case No. A VU-E-08-01 used ten year of data for Schedule 1 and
five years for all other schedules. In the updated analysis Schedule 1 no longer met all the statistical tests
with ten year of data. The five year anlysis passed all the tests and was used in th anysis.
390 Knox, Di 6
Avista Corporation
.1
2
Airport weather station. This analysis revealed that while
both a thirty-year average and a twenty-five year average
3 captures the long term trend in regional temperatures, the
4 thirty-year averages showed less variability.
5 The proposed averaging process maintains the advantage
6 of reflecting current weather trends by updating the values
7 annually, while providing a less volatile statistic through
8 the use of additional years of data.
9 Q.Wht was the impact of electric weather
10 normlization on the twelve months ended Septemer 2008
11 test year?
12 A.Weather was colder than normal during the winter
13 and spring, and warmer than normal during the sumer of the.14 test year. The adjustment to normal required the deduction
15 of 294 heating degree-days and 45 cooling degree-days. The
16 total adjustment to Idaho sales volumes was a reduction of
17 24,948,329 kWhs which is approximately 0.7 percent of
18 billed usage.
19 Natural Gas Revenue Normlization
20 Q.would you please describe the natural gas revenue
21 adjustment included in Ms. Andrews pro forma results of
22 operations?
23 A.Yes.The natural gas revenue normalization
24 adjustment is similar to the electric adjustment and
25 represents the difference between the Company's actual
.
391 Knox, Di 7
Avista Corporation
.1
2
recorded retail revenues during the twelve months ended
September 2008 test period and retail revenues on a
3 normalized (pro forma) basis. The adjustment includes the
4 re-pricíng of pro forma sales and transportation volumes at
5 present rates. (effective October i, 2008) using pro forma
6 sales volumes that have been adjusted for unbilled sales,
7 abnormal weather, and any material customer load or
8 schedule changes.The rates used exclude:1) Temporary
9 Gas Rate Adjustment Schedule 155, which reflects the
10 approved amortization rate for deferred gas costs approved
11 in the Company's last PGA filing and 2) Public Purposes
12 Rider Adjustment Schedule 191.
.13
14
15
Q.Does the Revenue Nor.lization Adjustment contain
a comonent reflecting nor.lized gas costs?
A.Yes. Purchase gas costs are normalized using the
16 gas costs approved by the Commission in Case No. AVU-G-08-
17 03, the Company's 2008 PGA filing4, as set forth under
18 Schedule 150. Those gas costs are then applied to the pro
19 forma retail sales volumes so that there is a matching of
20 revenues and gas cos ts .
21 The total net amount of the natural gas revenue
22 normalization, which includes the purchase gas cost
23 adjustment, is an increase to net operating income of
4 The Janua 6,2009 gas cost reduction to customer charges was accomplished though Schedule 155
whch is excluded from base revenues..
392 Knox, Di 8
Avista Corporation
.1 $2,359, ÔOO, as shown in colum (i), page 5 of Ms. Andrews
2 Exhibit No. 10, Schedule 2.
3 Q.Would you please briefly discuss natural gas
4 weather normlization?
5 A.Yes.The natural gas weather adjustment is
6 developed from a regression analysis of ten years of billed
7 usage per customer and billing period heating degree-day
8 data.The resulting seasonal weather sensitivity factors
9 (use per customer per heating degree day) are applied to
10 monthly test period customers and the difference between
11 normal heating degree-days and monthly test period observed
12 heating degree-days. This calculation produces the change
13 in therm usage required to adjust existing loads to the.amount expected if weather had been normal.14
15
16
Q.Bow are norml heating degree days defined?
Normal heating degree-days are based on a rollingA.
17 30-year average of heating degree-days reported for each
18 month by the National Weather Service for the Spokane
19 Airport weather station.The 30 years are included on a
20 heating season basis, July through June, so, for example,
21 the October average reflects all the Octobers beginning in
22 1978 and through 2007 whereas the May average reflects all
23 of the Mays beginning in 1979 and through 2008. Each year
24 the normal values will be adjusted to capture the next
25 heating season with the oldest data dropping off, thereby.
393 Knox, Di 9
Avista Corporation
.encapsulating the most recent information available at the1
2
3
end of each calendar year.
Q.Other than the change from a 25-year rolling
4 average to a 30-year rolling average discussed with regards
5 to electric weather normlization, were any changes made to
6 the gas weather normlization methodology?
7 A. No, the process for determining the weather
8 sensitivity factors and the monthly adjustment calculation
9 are the same as the method introduced in Case No. AVU-G-08-
10 01.
11 Q.What was the impact of natural gas weather
12 normlization on the twelve months ended Septemer 2008
13 test year?.14
15
A.Weather was colder than normal during the
2007/2008 heating season.The adjustment to normal
16 required the deduction of 352 heating degree-days from
17 October through June.Warmer than normal wea ther that
18 occurred during the sumer months did not impact gas usage
19 as customers are at baseload during that time.The
20 adjustment to sales volumes was a reduction of 2,827,731
21 therms which is approximately 2.3 percent of billed usage.
22 The margin impact (revenue less gas cost) of the weather
23 adjustment was a reduction of $834,000.
24
25.
394 Knox, Di 10
Avista Corporation
.1
2
III. PROPOSBD RETAIL RB CREDIT RATB
Q. Comany witness Mr. Johnson discusses using the
3 average cost of production and transmission for the retail
4 revenue credit rate in the Power Cost Adjustment (PCA).
5 How is that rate determined?
6
7
A. The retail revenue credit rate is determined by
computing the proposed revenue requirement on the
8 production and transmission subset of Ms. Andrews Idaho
9 Electric Pro forma Total Results of Operations.The
10 production/transmission revenue requirement amount is then
11 divided by the Idaho Normalized Retail Load used to set
12 rates in order to arrive at the average production and
13 transmission cost per kwh embedded in proposed rates..14
15
Q. Is this process illustated in an Exibit?
A. Yes.Exhibit No. 11, Schedule 1 begins with the
16 identification of the production and transmission revenue,
17 expense and rate base amounts included in each of Ms.
18 Andrews actual, restating, and pro forma adjustments to
19 results of operations. The "Pro Forma Total" at the bottom
20 of page 1 shows the resulting subset of these components.
21 Page 2 shows the revenue requirement calculation on
22 the production and transmission cost components. The rate
23 of return and debt cost percentages on line 2 are inputs
24 from the proposed cost of capital.The normalized retail
25 load on Line 10 comes from the workpapers to the revenue.
395
Knox, Di 11
Avista Corporation
.1
2
normalization adjustment.The proposed retail revenue
credit rate is shown on Line 11 and represents the average
3 Production and Transmission cost per kWh proposed to be
4 emedded in Idaho customer retail rates.
5
6
iv. BLECTRIC COST OF SBRVICB
Q.Please briefly sumrize your testimony related
7 to the electric cost of service study.
8 A.I believe the Base Case cost of service study
9 presented in this case is a fair representation of the
10 costs to serve each customer group.The Base Case study
11 shows Residential Service Schedule 1, Extra Large General
12 Service Schedule 25 and 25P, and Street and Area Lighting
13 provide less than the overall rate of return under present.14 rates. General Service Schedule 11, Large General Service
15 Schedule 21 and Pumping Service Schedule 31 provide more
16 than the overall rate of return under present rates but
17 less than the requested return.
18 Q.What is an electric cost of service study and
19 what is its purpose?
20 A.An electric cost of service study is an
21 engineering-economic study, which separates the revenue,
22 expenses, and rate base associated with providing electric
23 service to designated groups of customers. The groups are
24 made up of customers with similar load characteristics and
25 facili ties requirements. Costs are assigned in relation to
.
396 Knox, Di 12
Avista Corporation
.1
2
each group i s characteristics, resulting in an evaluation of
the cost of the service provided to each group. The rate
3 of return by customer group indicates whether the revenue
4 provided by the customers in each group recovers the cost
5 to serve those customers. The study results are used as a
6 guide in determining the appropriate rate spread among the
7 groups of customers.Exhibit No. 11, Schedule 2 explains
8 the basic concepts involved in performing an electric cost
9 of service study. It also details the specific methodology
10 and assumptions utilized in the Company's Base Case cost of
11 service study.
12 Q.Wht is the basis for the electric cost of
13 service study provided in this case?.14 A.The electric cost of service study provided by
15 the Company as Exhibit No. 11, Schedule 3 is based on the
16 twelve months ended Septemer 2008 test year pro forma
17 results of operations presented by Company witness Ms.
18 Andrews in Exhibi t No. lO , Schedul e 1.
19 Q.Would you please explain the cost of service
20 study presented in Bxibi t No. 11, Schedule 3?
21 A.Yes. Exhibit No. 11, Schedule 3 is composed of a
22 series of sumaries of the cost of service study results.
23 The sumary on page i shows the results of the study by
24 FERC account category. The rate of return by rate schedule
25 and the ratio of each schedule's return to the overall.
397
Knox, Di 13
Avista Corporation
.1
2
return are shown on Lines 39 and 40.This sumary was
provided to Mr. Hirschkorn for his work on rate spread and
3 rate design. The results will be discussed in more detail
4 later in my testimony.
5 Pages 2 and 3 are both sumaries that show the revenue
6 to cost relationship at current and proposed revenue.
7 Costs by category are shown first at the existing schedule
8 returns (revenue); next the costs are shown as if all
9 schedules were providing equal recovery (cost).These
10 comparisons show how far current and proposed rates are,
11 from rates that would be in alignent with the cost study.
12 Page 2 shows the costs segregated into production,
.13
14
transmission,distribution,and common functional
categories.Page 3 segregates the costs into demand,
15 energy, and customer classifications.
16 The Excel model used to calculate the cost of service
17 and supporting schedules have been included in their
18 entirety both electronically and hard copy in the
19 workpapers accompanying this case.
20 Q.Does the Compan's electric Base Case cost of
21 service study follow the methodology accepted in the
22 Company's last electric general rate case in Idaho?
23 A.Yes.The Base Case cost of service study was
24 prepared using the methodology accepted by the Idaho
.
398 Knox, Di 14
Avista Corporation
.commission in Case No. AVU-E-04-01 and used in Case No.1
2
3
AVU-E-08-01.
Q.Given that the specific details of this
4 methodology are described in Bxibi t No. 11, Schedule 2,
5 would you please give a brief overview of the key elemnts
6 and the history associated with those elements?
7 A.Yes.Production and transmission costs are
8 classified to energy and demand by a peak credit analysis.
9 Avista has been using the peak credit classification
10 process for cost of service studies in both washington and
11 Idaho jurisdictions since the 1980' s.Distribution costs
12 are classified and allocated by the basic customer theory5
13 accepted by the Idaho commission in Case No. WWP-E-98-l1..14 Additional direct assignment of demand related distribution
15 plant has been incorporated to reflect improvements
16 accepted by the commission in Case No. AVU-E-04-01.
17 Administrative and general costs are first directly
18 assigned to production, transmission, distribution, or
19 customer relations functions. The remaining administrative
20 and general costs are categorized as common costs and have
21 been assigned to customer classes by the four-factor
22 allocator accepted by the Idaho commission in Case No. AVU-
23 E-04-01.
5 Basic customer theory classifies only meters, serces and the direct assignment of stree light fixtues as customer-
related plant; all other distrbution facilties are considered demand-related..
399 Knox, Di 15
Avis ta Corporation
.1
2
3
Q. What are the results of the Comany's Base Case
cost of service study?
A.The following table shows the rate of return and
4 the relationship of the customer class return to the
5 overall return (relative return ratio) at present rates for
6 each rate schedule:
7 Illustration 1:
Customer Class
Residential Service Schedule 1
General Service Schedule 11
Large General Service Schedule 21
Extra Large General Service Schedule 25
Ex. Lg. Gen. Service Potlatch Schedule 25P
Pumping Service Schedule 31
Lighting Service Schedules 41 - 49
Total Idaho Electric System
Rate of Return
4.56%
7.89%
6.74%
3.15%
3.93%
7.64%
4.89%~
Return Ratio
0.85
1.48
1.26
0.59
0.73
1.43~~.8 As can be observed from the above table, residential,
9 extra large general service, and lighting service schedules
10 (l, 25, 25P, and 41-49) show under-recovery of the costs to
11 serve them, while the general, large general, and pumping
12 service schedules (11, 21, and 31) show over-recovery of
13 the costs to serve them. However, all customer groups are
14 currently providing a rate of return lower than the rate of
15 return requested in this case. The sumary results of this
16 study were provided to Mr. Hirschkorn as an input into
17 development of the proposed rates.
.
400
Knox, Di l6
Avista Corporation
.1
2
V. DEM STUY
3 regarding the load data used to develop demnd allocations
Q. An issue was raised in Case No. AVU-B-08-0l
4 in the electric cost of service. Please elaborate on this
5 issue.
6 A.In the last rate case, the Company indicated
7 that, while the estimation process used to create the
8 demand allocators in the cost of service study provides a
9 reasonable assignment of cost to the existing customer
10 groups, the Company's load data was in the process of being
11 updated.Accordingly,the Commission provided the
12 following directive on page 13 of its Order No. 30647:
.13
14
15
16
17
18
19
20
21
In this case the Commission finds the Company-filed
cost of service study to be sufficient to determine
rate design in this case. We direct the Company .in its
next general rate case to provide updated load data as
part of its COS study or, in the alternative, show how
the lack of such an update affects COS-based revenue
allocations to customer classes. (emphasis added)
Q Has the Comany provided updated load data as
22 part of the cost of service study in this case?
23 No. While an electric demand study is currentlyA.
24 underway, with nearly all sample meters in place collecting
25 data (and the last few expected to be in place shortly), g
26 full year of hourly load data is necessary to make use of
27 the information in the cost of service demand allocations.
28 The first full year of sample data will be collected over
29 the calendar year 2009. Consequently, the earliest that a.
401 Knox, Di 17
Avista Corporation
.1
2
3
general rate filing could incorporate updated load study
data would be sometime in 20l0.
Q.Have you perfor.ed a sensitivity analysis to
4 deter.ine the potential impact of updated load informtion
5 on cost of service based revenue allocations to customer
6 classes?
7
8
A.Yes. There are two types of demand allocations,
namely coincident peak and non-coincident peak.The
9 coincident peak allocations are applied to demand-related
10 production and transmission costs. The non-coincident peak
11 allocations are applied to demand-related distribution
12 costs.
13 i ran two sensitivity cases to determine how changes.14 in non-coincident demand for each customer class, i. e. ,
15 from a new load study, would affect the allocation of
16 demand cos ts .I also ran two sensitivity cases to
17 determine how changes in coincident demand for each
18 customer class would affect the allocation of demand costs.
19 Before I walk through the four sensitivity studies, it
20 is important to have some context for what we are trying to
21 test with the studies. Colum (a) in the table below shows
22 the relative rates of return for each customer class from
23 our Base Case cost of service study under present retail
24 rates.Colum (b) shows the relative rates of return by
25 schedule after application of the proposed rate increase in.
402
Knox, Di l8
Avista Corporation
.1 this case.As Mr. Hirschkorn explains in his testimony,
2 the spread of the revenue increase to each customer class
3 was designed to move each customer class closer to unity
4 (wi th the exception of Street and Area Lights) .
.
5
6
7
8
9
10
11
12
13
14
15
16
17
Residential Sch. 1
General Srvc. Sch. 11
Lg. Gen. Srvc. Sch. 21
Ex. Lg. Gen. Srvc. Sch. 25
Potlatch-Lewiston Sch. 25P
Pumping Srvc. Sch. 31
Street & Area Lgt. Schs.
Overall
Present
Relative ROR
(a)
0.85
1. 48
1.26
0.59
0.73
1. 43
0.92
1. 00
Proposed
Relative ROR
(b)
0.86
1.27
1. 17
0.84
0.99
1.28
0.73
1. 00
The table shows that the relative rate of return for
some customer schedules is above unity (1.0) for both
18 present rates and proposed rates, and others are below
19 unity.The purpose of the sensitivity studies is to
20 determine whether demand data from a new load study would
21 likely cause us to spread the revenue increase to customer
22 classes differently than that proposed by the Company in
23 this case.
24 Q.Wht was your conclusion after ruing the four
25 sensitivity studies?
26 A.The results of each of the studies, that I will
27 explain below, show that while an updated load study may
28 fine tune the cost relationships among the customer groups,.
403
Knox, Di 19
Avista Corporation
.1 we can expect relatively small changes in the overall cost
2 of service results.Therefore,we believe the current cost
3 of service study provides a sound foundation for rate
4 spread purposes.
5
6
7
8
9
10
11
12.13
14
15
16
17
18
19
20
21
22
23
24
25.
Scenario 1
Q. What did you test in the first sensi ti vity ru,
and what did the results show?
A. The first sensitivity run, which I will refer to
as Scenario 1, was designed to examine how a change in the
non-coincident peak for each customer class would affect
the allocation of demand-related distribution costs. For
this scenario I simply took the non-coincident peak demand
for each customer class emedded in the cost of service
study, and doubled the demand for each class, with the
exception of Schedules 25 and 25P. By doubling the demand
for each class, we will see what happens to demand
allocations if a new load study were to show that the non-
coincident peak demand for each class were to increase in
the same proportion.
Q. Wh did you not double the peak demnd for
Schedules 25 and 25P?
A. We already have hourly metering, and hourly data,
for Schedules 25 and 25P, so we already know what their
actual non-coincident peak demand is without a new load
study.
404
Knox, Di 20
Avista Corporation
.1
2
It is also important to note, as I mentioned earlier,
that the non-coincident peak demand analysis is used
3 entirely to allocate demand-related distribution costs.
4 Nearly all demand-related distribution costs for Schedules
5 25 and 25P are directly assigned, and therefore, a change
6 in the non-coincident peak demand for these Schedules would
7 result in essentially no change in the allocation of
8 distribution costs to these Schedules.
9
10
Q.Wht were the results from this first scenario?
A.The results from Scenario 1, compared with the
11 Base Case cost of service study filed in this case, are
12 sumarized on Exhibit 11, Schedule 4, lines 1 through 8.
13 Although the rate base and net income values change.14 slightly, the relative rates of return for Scenario 1 are
15 virtually the same as our Base Case study for all customer
16 classes, as shown in the Illustration 2 below.
17 Illustration 2 :
Customer Class Base Case Scenario 1
Rate of Return Rate of Return
Residential Service Schedule 1 4.56%0.85 4.56%0.85
General Service Schedule 11 7.89%1.48 7.89%1.48
Large General Service Schedule 21 6.74%1.26 6.74%1.26
Extra Large General Service Schedule 25 3.15%0.59 3.16%0.59
Ex.Lg.Gen.Service Potlatch Schedule 25P 3.93%0.73 3.94%0.74
Pumping Service Schedule 31 7.64%1.43 7.64%1.43
Lighting Service Schedules 41 -49 4.89%0.92 4.89%0.92
Total Idaho Electric System 5.34%1. 00 5.34%1.00
18
.
405
Knox, Di 21
Avista Corporation
.
.
.
1
2
Therefore, if a new load study were to show a
significant increase in non-coincident peak demand across
3 all schedules, it would result in very little change in our
4 cost of service results.
5 Scenario 2
6 Wht did you test in Scenario 2, and what did theQ.
7 results show?
8 The first scenario explored what would happen ifA.
9 the non-coincident peak demand was higher for all schedules
10 than our Base Case demand data. In Scenario 2 I wanted to
11 test what would happen if a new load study were to indicate
12 that some schedules have higher non-coincident peak demand
13
14
than our Base Case, and other schedules have lower demand.
For Scenario 2 I made the following adjustments to the
15 Base Case non-coincident peak demand data:
16
17
18
19
20
21
22
23
24
25
26
1.For customer classes that have a relative rate of
return above unity (1.0) in the Base Case study, I
increased the non-coincident peak demand for the class
by 15%.
2.For customer classes that a have a relative rate of
return below unity (1.0), I decreased the non-
coincident peak demand for the class by 15%.
Q.What were you trying to measure by making these
27 adjustments?
28 In this filing we are proposing a rate spreadA.
29 that is designed to move each customer class closer to
406
Knox, Di 22
Avista Corporation
.
.
.
1
2
3
unity.For example, for those customer classes that are
above uhity, we are proposing a lower percentage base rate
increase in order to accomplish this movement.If a new
4 load study were to show an increased non-coincident peak
5 demand -for these customer classes (above unity), and a
6 lower non-coincident peak demand for the customer classes
7 below unity, it would result in the following changes to
8 the cost of service study:
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
1.The increase in non-coincident peak demand for
customer classes above unity would result in an
increased allocation of demand-related distribution
costs to these customer classes, which would lower the
relative rate of return for these classes (move themcloser to uni ty) .
2.The decrease in non-coincident peak demand for
customer classes below unity would result in a
decreased allocation of demand-related distribution
costs to these customer classes, which would increase
the relative rate of return for these classes (movethem closer to unity) .
24 The purpose of this Scenario was to determine how much
25 movement toward unity would occur for each customer class
26 if the new load study were to show a significant increase
27 in non-coincident peak demand for classes above unity, and
28 a significant decrease for those below unity. As mentioned
29 above, we increased the non-coincident peak demand for
30 classes above unity by 15%, and reduced the demand for
31 classes below unity by 15%.
32 What were the results for Scenario 2?Q.
407
Knox, Di 23
Avista Corporation
.1
2
A.The resul ts of Scenario 2 are shown on Exhibi t
No. 11,Schedule 4, lines 9 through 12.Illustration 3
3 below highlights the rates of return produced by this
4 scenario compared to the base case.
5 Illustration 3 :
Customer Class Base Case Scenario 2
Rate of Return Rate of Return
Residential Service Schedule 1 4.56%0.85 5.19%0.97
General Service Schedule 11 7.89%1.48 7.09%1.33
Large General Service Schedule 21 6.74%1.26 5.89%1. 10
Extra Large General Service Schedule 25 3.15%0.59 3.15%0.59
Ex.Lg.Gen.Service Potlatch Schedule 25P 3.93%0.73 3.93%0.73
Pumping Service Schedule 31 7.64%1. 43 6.85%1.28
Lighting Service Schedules 41 -49 4.89%0.92 5.02%0.94
Total Idaho Electric System 5,34%1. 00 5.34%1.00
6
7.8
9
10
11
12
13
14
15
16
17
18
19.
Costs did shift in this scenario, but not enough to
change the rate spread implications.Schedules 11, 21 and
31 are still above unity, and Schedules 1 and Lighting
service are improved bu t remain less than unity.
Therefore, even if this Scenario were to occur, there would
still be a need for a rate spread proposal to move relative
rates of return for customer classes closer to unity,
similar to what Mr. Hirschkorn has proposed in this case.
Q. Would you expect the new load study to show
higher non-coincident peak demnds for only the customer
classes above unity, and lower non-coincident peak demnds
for only the customer classes below unity, as you tested in
Scenario 2?
408
Knox, Di 24
Avista Corporation
.
5
6
7
8
9
10
11
12.13
14
15
16
17
18
19
20
21
22
23
24
25.
1
2
It is unlikely that. such a scenario wouldA.No.
actually occur.However, for my sensitivity analysis I
3 wanted to test a scenario that is probably beyond what
4 would likely occur.
Scenario 3
Q. Lets moe on to the two sensitivity studies
related to coincident peak.How are the class
contributions to system peak demnd determined in the Base
Case?
A. The coincident peak allocation factor is based on
the electric system hourly peak for each month of the
twelve-month test period (12 hourly coincident peaks). The
total Idaho peak load is known for the twelve peak hours.
wi th regard to each customer class, the peak demand
for each class, for each of the 12 monthly peak hours
(contribution to the system peak), is based on an analysis
of monthly billing data, weather sensitivity statistics,
and hourly load shapes from prior load studies.
Q. Are the twelve hourly coincident peaks for
Schedules 25 and 25P estimated in the same maer?
A.No.As I mentioned earlier, we have actual,
hourly load data for Schedules 25 and 25P, and therefore,
we know what their usage is at the time of the twelve
monthly system peaks. Thus, with regard to the use of peak
demand data in cost of service studies to allocate demand-
409
Knox, Di 25
Avista Corporation
.1
2
related production and transmission costs, the current cost
of service study already includes the actual, metered
3 contribution to the system peak for these schedules.
4 Q.What change did you make to the coincident peak
5 demnd data in Scenario 3, and what were you trying to
6 measure:?
7 A.In Scenario 3, I made one change from the Base
8 Case in the determination of the hourly coincident peak
9 contribution for each schedule.Rather than use hourly
10 load shapes from prior load studies to determine the hourly
11 peak for each customer class on the peak day, I used one-
12 sixteenth, or 6.25%, of the daily energy use on the peak
13 day for each class to represent the hourly peak demand at.14 the time of the system coincident peak.
15 The use of 6.25% of daily energy to represent a peak
16 hour demand for the peak day has been used historically in
17 the natural gas industry to determine the appropriate size
18 of natural gas delivery service equipment.Al though the
19 6.25% may not be perfectly transferrable to the electric
20 industry, it provided a reasonable basis to achieve my
21 objective in this Scenario.
22 My objective in Scenario 3 was to adjust the peak
23 demand data such that the peak hour for each customer class
24 occurred at the time of the system peak, i. e., all customer
.
410
Knox, Di 26
Avista Corporation
.classes peak at the time of the system peak in each of the1
2
3
4
5
twelve months.
Q.What were the results of Scenario 3?
Scenario 3 results are shown on Exhibit 11,A.
Schedule 4, lines 13 through 16.Illustration 4 below
6 highlights the rates of return produced by this Scenario
7 compared to the Base Case.
8 Illustration 4:
Customer Class
.
Residential Service Schedule 1
General Service Schedule 11
Large General Service Schedule 21
Extra Large General Service Schedule 25
Ex. Lg. Gen. Service Potlatch Schedule 25P
Pumping Service Schedule 31
Lighting Service Schedules 41 - 49
Total Idaho Electric System
Base Case
Rate of Return
4.56%
7.89%
6.74%
3.15%
3.93%
7.64%
4.89%
5.34%
0.85
1.48
1.26
0.59
0.73
1.43
0.92
1. 00
Scenario 3
Rate of Return
4.66%
7.96%
6.55%
3.15%
3.93%
6.77%
4.89%
5.34%
0.87
1.49
1.23
0.59
0.73
1.27
0.92
1.00
9
10 The rate of return and return ratios for Schedules 1
11 and 11 rise slightly, while they fall somewhat for
12 Schedules 21 and 31, but the rate spread implications
13 remain unchanged.
14 Scenario 4
Q.What did you test in the fourth scenario?15
16 In Scenario 4 I wanted to test what would happenA.
17 if a new load study were to indicate that some schedules
18 have a higher contribution to the system coincident peak
.
411
Knox, Di 27
Avista Corporation
.
.
.
1
2
than the Base Case, and other schedules have a lower
contribution.
3 For Scenario 4 I made the following adjustments to the
4 Base Case coincident demand data:
5
6
7
8
9
10
11
12
13
14
15
16
1.For customer classes that have a relative rate of
return above uni ty (1.0), I increased the demand for
the class at the time of the system coincident peak by
approximately 10%.6
2.For customer classes that a have a relative rate of
return below uni ty (1.0), I decreased the demand for
the class at the time of the system coincident peak by
approximately 10%.
Q.What were you trying to measure by making these
17 adjustments?
18
19
As I explained earlier related to Scenario 2, inA.
this filing we are proposing a rate spread that is designed
20 to move each customer class closer to unity. If a new load
21 study were to show an increased contribution to the system
22 coincident peak for the customer classes above unity, and a
23 lower contribution to the system coincident peak for the
24 customer classes below unity, it would result in the
25 following changes to the cost of service study:
26
27
28
29
30
1.The increased contribution to the system coincident
peak for customer classes above unity would result in
an increased allocation of demand-related production
and transmission costs to these customer classes,
6 In order to preserve the same level of Idao peak demad as the Base Case, it was necessar to adjust
the percentage ircrease to Schedules 11, 21 and 31 to 11.6%, and reduce the percentage decrease for
Schedules 1 and Lightig service to 9.4%.
412 Knox, Di 28
Avista Corporation
.which would lower the relative rate of return forthese classes (move them closer to unity) .1
2
3
4
5
6
7
8
9
10
The decreased contribution to the system coincident
peak for customer classes below unity would result in
a decreased allocation of demand-related production
and transmission costs to these customer classes,
which would increase the relative rate of return forthese classes (move them closer to unity) .
2.
11 The purpose of this Scenario was to determine how much
12 movement toward unity would occur for each customer class
13 if the new load study were to show a significant increase
14 in contribution to the system coincident peak for classes
15 above unity, and a significant decrease for those below
16 unity.
Q.What were the results of Scenario 4i?.17
18
19 Schedule 4, lines 17 through 20.
A. Scenario 4 resul ts are shown on Exhibi t 11 ,
Illustration 5 below
20 highlights the rates of return produced by this scenario
21 compared to the Base Case.
22 Illustration 5:
Customer Class
Residential Service Schedule 1
General Service Schedule 11
Large General Service Schedule 21
Extra Large General Service Schedule 25
Ex. Lg. Gen. Service Potlatch Schedule 25P
Pumping Service Schedule 31
Lighting Service Schedules 41 - 49
Total idaho Electric System
Base Case
Rate of Return
4.56%
7.89%
6.74%
3.15%
3.93%
7.64%
4.89%
5.34%
0.85
1.48
1.26
0.59
0.73
1.43
0.92
1.00
Scenario 4
Rate of Return
5.06%
7.26%
6.09%
3.15%
3.93%
7.08%
4.95%
5.34%
0.95
1.36
1.14
0.59
0.73
1.32
0.93
1. 00
23.
413
Knox, Di 29
Avista Corporation
.1
2
The rate of return and return ratios for Schedules 1
and Lighting service improve, but are still below unity and
3 the return ratios for Schedules 11, 21 and 31 each drop by
4 about one-tenth but are still well above unity.The rate
5 spread implications remain essentially unchanged.
6 Q.Would you expect the new load study to show a
7 higher contribution to the system coincident peak for only
8 the customer classes above unity, and a lower contribution
9 to the system coincident peak for only the customer classes
10 below unity, as you tested in Scenario 4?
.
11
12
13
14
15
A.No. As with Scenario 2, it is unlikely that such
a scenario would actually occur.However, agaîn, for my
sensitivity analysis I wanted to test a scenario that is
probably beyond what would likely occur.
Q.What conclusions do you draw from these demnd
16 allocation sensitivity studies?
17 A. The following chart illustrates the return ratios
18 for the Base Case and all four sensitivity scenarios:
.
414
Knox, Di 30
Avista Corporation
.
2.3
4
5
6
7
8
9
10
11
12
13
14
15.
1 Illustration 6:
Class Rate of Return Vs. Unit
Base Case Vs. All Other Sensitivity Scenarios
1.6
1.4
¡ 1.2 Unity
a:
E:i
'&
a: 0.8
0.6
0.4
~,,#r$
iç rr
eoO
"ti-."
eoQ'
-.eßti
eoQ'
et
e:Q'
a,-.~~
e:Q'
9.-.t;
~
e:Q'
"
eoQ'
Schedule
-+ Return Ratio-Base Case __ Return Ratio-Scenario 1 -- Return Ratio-Scenano 2
~ Return Ratio-Scenario 3 __ Return Ratio-Scnario 4
As can be seen in Illustration 6 theabove,
sensitivity analyses demonstrate that, while an updated
load study may fine tune the cost relationships among the
customer groups, we can expect only relatively small
changes in results.The schedules that are well above
unity will continue to be above unity, and the schedules
that are well below unity will continue to be below unity.
(There will be little or no change to Schedules 25 and 25P,
which already have actual, hourly demand data and receive
direct assignment of most distribution plant.)Therefore,
the Company believes that the existing cost of service
study, even absent new load study information, provides a
sound foundation for rate spread purposes.
415
Knox, Di 31
Avista Corporation
.1
2
VI. NATt GAS COST OF SBRVJCB
Q.Please describe the natural gas cost of service
3 study and its purpose.
4 A.A natural gas cost of service study is an
5 engineering-economic study which separates the revenue,
6 expenses, and rate base associated with providing natural
7 gas service to designated groups of customers. The groups
8 are made up of customers with similar usage characteristics
9 and facility requirements. Costs are assigned in relation
10 to each groups' characteristics, resulting in an evaluation
11 of the cost of the service provided to each group.The
12 rate of return by customer group indicates whether the
13 revenue provided by the cus tomers in each group recovers.14 the cost to serve those customers.The study results are
15 used as a guide in determining the appropriate rate spread
16 among the groups of customers.Exhibi t No. 11, Schedule 5
17 explains the basic concepts involved in performing a
18 natural gas cost of service study.It also details the
19 specific methodology and assumptions utilized in the
20 Company's Base Case cost of service study.
21 Q.What is the basis for the natural gas cost of
22 service study provided in this case?
23 A.The cost of service study provided by the Company
24 as Exhibit No.11, Schedule 6 is based on the twelve months
25 ended September 2008 test year pro forma results of.
416
Knox, Di 32
Avista Corporation
.operations presented by Ms. Andrews in Exhibit No.10,1
2
3
Schedule 2.
Q.Would you please exlain the cost of service
4 study presented in Bxhibit No. 11, Schedule 6?
5 A.Yes. Exhibit No. 11, Schedule 6 is composed of a
6 series of sumaries of the cost of service study results.
7 page 1 shows the results of the study by FERC account
8 category.The rate of return and the ratio of each
9 schedule's return to the overall return are shown on lines
10 38 and 39. This sumary is provided to Mr. Hirschkorn for
11 his work on rate spread and rate design. The results will
12 be discussed in more detail later in my testimony.The
13 additional sumaries show the costs organized by functional.14 category (page 2) and classification (page 3), including
15 margin and unit cost analysis at current and proposed
16 rates.
17 The Excel model used to calculate the cost of service
18 and supporting schedules have been included in their
19 entirety both electronically and hard copy in the
20 workpapers accompanying this case.
21 Q.Does the Natural Gas Base Case cost of service
22 study utilize the methodology from the company's last
23 natural gas case in Idaho?
.
417
Knox, Di 33
Avista Corporation
.1
2
A.' Yes. The Base Case cost of service study was
prepared using the methodology accepted by the Idaho
3 Commission in Case No. AVU-G-04-0l and AVU-G-08-01.
4 Q.Wht are the key elements that define the cost of
5 service methodology?
6
7
A.Purchased gas costs are derived from the current
purchased gas tracker methodology .underground storage
8 costs are allocated by normalized winter throughput.
9 Natural gas main investment has been segregated into large
10 and small mains. Large usage customers that take service
11 from large mains do not receive an allocation of small
12 mains.Meter installation and services investment is
13 allocated by number of customers weighted by the relative.14 current cost of those items. System facilities that serve
15 all customers are classified by the peak and average ratio
16 that reflects the system load factor, then allocated by
17 coincident peak demand and throughput,respectively.
18 Demand side management costs are treated in the same way as
19 system facilities. General plant is allocated by the sum
20 of all other plant. Administrative & general expenses are
21 segregated into labor related, plant related, revenue
22 related, and "other".The costs are then allocated by
23 factors associated with labor, plant in service, or
24 revenue, respectively.The "other" A&G amounts get a
25 combined allocation that is one-half based on O&M expenses.
418
Knox, Di 34
Avista Corporation
.1 and one-half based on throughput.A detailed description
2 of the methodology is included in Exhibit No.11, Schedule
3 5.
4 Q.Wht are the results of the Comany's natural gas
5 cost of service study?
6 A.I believe the Base Case cost of service study
7 presented in this filing is a fair representation of the
8 costs to serve each customer group.The study indicates
9 that Large Firm general service Schedule 111 is providing
10 slightly less than the overall return (unity), while all
11 other schedules are providing slightly more than unity to
12 varying degrees.The return for all of the Schedules are
13 relatively close to the overall return indicating the.14
15
current rate spread is fair.
The following table shows the rate of return and the
16 relative return ratio at present rates for each rate
17 schedule:
18 Illustration 7:
Residential Service Schedule 101
Small Firm Service Schedule 111
Interruptible Service Schedule 131
Transportation Service Schedule 146
Total Idaho Natural Gas System
Rate of
Return
6.97%
6.24%
7.44%
8.78%
6.87%
Return RatioCustomer Class
1.02
0.91
1.08
1.28~
19
.
419
Knox, Di 35
Avista Corporation
.1
2
The sumary results of this study were provided to Mr.
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.
.
.
420
Knox, Di 36
Avista Corporation
.1
2
I. INTRODUCTION
Q.Please state your name, business address and
3 present position with Avista Corporation?
4 A.My name is Brian J. Hirschkorn and my business
5 address is 1411 East Mission Avenue, Spokane, Washington.
6 I am presently assigned to the State and Federal Regulation
7 Department as Manager of Pricing.
8
9
Q.Would you briefly describe your duties?
A.My primary areas of responsibility include
10 electric and gas rate design, customer usage and revenue
11 analysis, and tariff administration.
12 Q.Would you briefly describe your educational
13 background?.14 A.I am a 1978 graduate of Washington State
15 university with Bachelor degrees in Business Administration
16 and Accounting.
17 Q.Have you previously testified before the
18 Commission?
19 A.Yes.I have testified before this Commission in
20 several prior rate proceedings as a revenue and rate design
21 witness.
22 Q.What is the scope of your testimony in this
23 proceeding?
24 A.My testimony in this proceeding will cover the
25 spread of the proposed annual electric revenue increase of
26 $31,233,000, or 14.2%, among the Company's electric general.27 service schedules.with regard to natural gas service, I
421 Hirschkorn, Di 1
Avista Corporation
.1 will describe the spread of the proposed annual revenue
2 increase of $2,740,000 i or 3.0%, among the Company's
3 natural gas service schedules.My testimony will also
4 describe the changes to the rates within the Company's
5 electric and natural gas service schedules.
6 Q.Are you sponsoring any Exibits that accomany
7 your testimony?
8 A.Yes. I am sponsoring Exhibit No. 12, Schedules 1
9 through 3 related to the proposed electric increase, and
10 Schedules 4 through 6 related to the proposed natural gas
11 increase.
12 Table of Contents
.13
14
15
16
17
18
19
20
21
22
23
24
25
Executive Sury
Proposed Electric Revenue Increase
Estimated PCA SUrcharge ReductionSumry of Rate Schedules and Tariffs
Proposed Rate Spread (Increase by Schedule)
Proposed Rate Design (Rates within Schedules)
Proposed Natural Gas Revenue IncreaseSumry of Rate Schedules and Tariffs
Proposed Rate Spread
Proposed Rate Design
II. BXECUTIVE SUMY
26 Proposed Electric Increase
Page 2
Page 6
Page 8
Page 10
Page 13
Page 23
Pagè 25
Page 27
27 Q.What is the proposed electric revenue increase in
28 this case and how is the Company proposing to spread the
29 total increase by rate schedule?
30 A.The proposed electric increase is $31,233,000, or
31 14.2% over present base tariff revenue/rates in effect.
32 The proposed general increase over present billing rates,.33 including all other rate adjustments (PCA,DSM and
422 Hirschkorn, Di 2
Avista Corporation
.
.
.
1
2
Residential Exchange) , is 12.8%. With the proposed
decrease in the present Power Cost Adjustment (PCA)
3 surcharge of 5.0%, the net increase is 7.8% over present
4 billing rates.
5 The proposed general increase of $31,233,000 has been
6 spread by rate schedule on a basis which: 1) moves the
7 rates for nearly all the schedules closer to the cost of
8 providing service, and 2) resul ts in a reasonable range in
9 the (net)proposed percentage increase theacross
10 schedules. The PCA surcharge is applied on a uniform cents
11 per kwh basis across all schedules and results in a
12 different percentage increase by schedule depending on the
13 level of base tariff rates/revenue.By including the
14 proposed decrease in the current PCA surcharge during 2009,
15 an opportunity is presented to move base tariff rates
16 closer to the cost of providing service.The proposed
17 increase over present billed rates/revenue by schedule is
18 shown below:
19
20
21
22
23
24
25
26
27
28
29
General Est.peA Net
Increase Decrease Increase
Residential Sch.1 13.1%-4.4%8.7%
General Srvc.Sch.11 11.6%-3.8%7.8%
Lg.Gen.Srvc.Sch.21 12.7%-4.9%7.8%
Ex.Lg.Gen.Srvc.Sch.25 14.5%-6.7%7.8%
potlatch-Lewiston Sch.25P 13.0%-7.3%5.7%
pumping Srvc.Sch.31 12.4%-4.6%7.8%
Street & Area Lgt.Schs.10.5%-1. 6%8.9%
Overall 12.8%-5.0%7.8%
423 Hirschkorn,Di 3
Avista Corporation
.1
2
3
This information is shown in detail on page 1,
Schedule 3 of Exhibit No. 12.
Q.In AVl-B-08-01, the Company stated that it is
4 perfor.ing a load research study and that the results will
5 not be available until late 2009/early 2010.Why is the
6 Company proposing to spread the general increase other than
7 on a uniform percentage basis without the results of the
8 new load study?
9 A.As discussed in Witness Knox's testimony, the
10 Company performed a sensitivity analysis assuming varying
11 results of the new load study.As shown on Schedule 4 of
12 Exhibit 11, the potential results of the load study would
13 not significantly change the results of the Company's cost.14 of service study presented in this filing. Given this, and
15 the effect of the proposed PCA decrease, the company did
16 not want to forgo this opportunity to adjust rates by
17 schedule closer to the cost of providing service.
18 Q.What is the proposed increase for a residential
19 electric customer with average consumption?
20 A.The proposed increase for a residential customer
21 using an average of 982 kWhs per month is $6.71 per month,
22 or an 8.6% increase in their electric bill.As part of
23 that increase,the Company is propos ing that the
24 basic/customer charge be increased from $4.60 to $5.00 per
25 month. The present bill for 982 kWhs is $78.47 compared to
26 the proposed level of $85.18,including all rate.27 adjustments.
424 Hirschkorn, Di 4
Avista Corporation
.1 Q. Is the Company proposing any changes to the
2 present rate structures within its electric service
3 schedules?
4 A.No.The Company is not proposing any changes
5 to the present rate structures within its electric
6 schedules.
7 Q. Where do you show the proposed changes in rates
8 within the electric service schedules?
9 A. This information is shown in detail on page 3,
10 Schedule 3 of Exhibit No. 12.
11
12 Proposed Natural Gas Increase
13 Q.How is the Company proposing to spread the.14 overall natural gas increase of $2,740,000, or 3.0%, by
15 service schedule?
16 A.The Company is proposing the following
17 revenue/rate changes by rate schedule:
18
19
20
21
22
23
24
Large General Service Schedule 111
3.1%
2.5%
General Service Schedule 101
Interruptible Sales Service Schedule 131 1. 7%
Transportation Service Schedule 146 10.9%
This information is also shown on page 1, Schedule 6
25 of Exhibit No. 12. The Company utilized the results of the
26 natural gas cost of service study, sponsored by witness.27 Knox, as a guide in spreading the overall revenue increase
425 Hirschkorn, Di 5
Avista Corporation
.1
2
to its natural gas service schedules.
Q. What is the proposed monthly increase for a
3 residential natural gas customer with average usage?
4 A.The increase for a residential customer using an
5 average of 66 therms of gas per month would be $2.56 per
6 month, or 3.2%.A bill for 66 therms per month would
7 increase from the present level of $79.38 to a proposed
8 level of $81.94, including all present rate adjustments.
9 As part of this increase, the Company is proposing an
10 increase in the monthly customer charge of $0.25 per month,
11 from $4.00 to $4.25.
12
13 III. PROPOSED BLBCTRIC RBNt INCRESB.14 Proposed PCA Surcharge Reduction
15 Q.Please explain the Company's proposal to adjust
16 the electric PCA surcharge rate when the general rate
17 increase is implemented.
18 A.The Company proposes that the current PCA
19 surcharge rate of o. 610ç per kWh be reduced at the time the
20 general rate increase is implemented.The Company is
21 proj ecting that the surcharge rate can be reduced from
22 0.610ç to 0.257ç, representing a five (5) percent reduction
23 in rates to customers based on a reduced PCA surcharge.
24 This is based on the Company's power supply forecast (s) and
25 assumes that the rate change would occur on July 1, 2009.
26 The unrecovered PCA deferral balances would be.27 approximately $11.5 million at that time.The new,
426 Hirschkorn, Di 6
Avista Corporation
.1 surcharge rate of o. 257ç per kWh is designed to recover the
2 deferral balance over a 15-month period, July i, 2009
3 through Septemer 30, 2010. At the time the PCA surcharge
4 is reduced, it may be necessary to adjust the 15-month
5 amortization period or the surcharge reduction itself,
6 based on the timing of the general rate adjustment and
7 actual PCA entries as of that time.
8 Q.When would the Company submit a filing to change
9 the surcharge?
10 A.The Company would file the change to the
11 surcharge rate coincident with filing the new rates that
12 implement the general rate increase.The Company files
13 monthly PCA reports that show the actual PCA deferral.14 balances at the end of each month.
15 Q.Would the Company still make its annual filing to
16 review the PCA deferrals?
17 A.Yes.The Company would still make its annual
18 filing on or before August i, 2009, to review PCA deferrals
19 for the period July 2008 through June 2009 as well as the
20 unrecovered balance of deferrals being recovered from the
21 existing surcharge.Staff would conduct its normal review
22 of the annual PCA filing. As a result of Staff i s review, a
23 modification to the PCA surcharge rate, if necessary, could
24 be made by changing the PCA surcharge rate again on October
.
25 i, 2009.
26
27
427 Hirschkorn, Di 7
Avista Corporation
.1
2
Sumary of Electric Rate Schedules and Tariffs
Q. Would you please explain what is contained in
3 Schedule 1 of Exhibi t No. 12?
4 A.Yes.Schedule i is a copy of the Company's
5 present and proposed electric tariffs, showing the changes
6 (strikeout and underline) proposed in this filing.
7 Q.Could you please describe what is contained in
8 Schedule 2 of Exibit No. 12?
9 A.Yes.Schedule 2 contains the proposed (clean)
10 electric tariff sheets incorporating the proposed changes
11 included in this filing.
12 Q.What is contained in Schedule 3 of Exibit NO.
13 12?.14 A.Schedule 3 contains information regarding the
15 proposed spread of the electric revenue increase among the
16 service schedules and the proposed changes to the rates
17 wi thin the schedules.Page i shows the proposed general
18 revenue and percentage increase by rate schedule compared
19 to the present revenue under base tariff and billing rates,
20 as well as the proposed net percentage increase to billed
21 rates/revenue including the estimated decrease in the
22 current PCA surcharge.Page 2 shows the rates of return
23 and the relative rates of return for each of the schedules
24 before and after application of the proposed general
25 increase. Page 3 shows the present rates under each of the
26 rate schedules, the proposed changes to the rates wi thin.27 the schedules (including the estimated PCA surcharge
Hirschkorn, Di 8
Avista Corporation428
.1
2
reduction), and the proposed rates after application of the
changes .,These pages will be referred to later in my
3 testimony.
4 Q.Would you please describe the Company' s present
5 rate schedules and the types of electric service offered
6 under each?
7 A.Yes.The Company presently provides electric
8 service under Residential Service Schedule 1, General
9 Service Schedules 11 and 12,Large General Service
10 Schedules 21 and 22, Extra Large General Service Schedules
11 25 and 25P (Potlatch's Lewiston Plant) and pumping Service
12 Schedules 31 and 32.Addi tionally, the Company provides
13 Street Lighting Service under Schedules 41-46 i and Area.14 Lighting Service under Schedules 47 -49.Schedules 12, 22,
15 32, and 48 exist for residential and farm service customers
16 who qualify for the "Residential Exchange" program operated
17 by the Bonneville Power Administration.The rates for
18 these schedules are identical to the rates for Schedules
19 11,21,31,and 47,respectively,except for the
20 Residential Exchange rate credit.The following table
21 shows the type and numer of customers served in Idaho (as
22 of September 30, 2008) under each of the service schedules:
.
23 Schedule
24 Residential Sch. 1
25 General Sch. 11&12
26 Lge. Gen. Sch. 21&22
27 Ex. Lge. Gen. Sch. 25
28 pumping Sch. 31&32
29
Tye of Customer No. of Customers
Residential
Sm. Caro. /less than 50 kw
Med-Lg. Coro. & Ind. lover 50 kw
Lge. Coro. & Ind./over 3,000 kva
Water & Effluent pumping
99,073
19,005
1,452
13
1,305
429 Hirschkorn, Di 9
Avista Corporation
.
.
.
1
2
Proposed Blectric Rate Spread
Q. How does the Company propose to spread the total
3 general' revenue increase request of $31,233,000 among its
4 various rate schedules?
5 The Company is proposing that the overallA.
6 requested revenue increase be spread on the following basis
7 (also shown is estimated PCA decrease and the resulting net
8 increase):
General Est.peA Net
Increase Decrease Increase
Residential Sch.1 13.1%-4.4%8.7%
General Srvc.Sch.11 11. 6%-3.8%7.8%
Lg.Gen.Srvc.Sch.2l 12.7%-4.9%7.8%
Ex.Lg.Gen.Srvc.Sch.25 14.5%-6.7%7.8%
Potlatch-Lewiston Sch.25P 13.0%-7.3%5.7%
Puping Srvc.Sch.31 12.4%-4.6%7.8%
Street & Area Lgt.Schs.10.5%-1. 6%8.9%
Overall 12.8%-5.0%7.8%
9
10
11
12
13
14
15
16
17
18
19
20
21 This information is shown in detail on Page 1, Schedule 3
22 of Exhibit No. 12.
23 Q. What rationale did the company use in developing
24 the proposed general increase by rate schedule?
25 A. The company used the results of the cost of
26 service study sponsored by company witness Knox, as well as
27 the net increase resulting after application of the
28 estimated 2009 decrease in the current PCA surcharge. The
29 application of the proposed increase generally results in
30 the rates of return for the various service schedules
430 Hirschkorn, Di 10
Avista Corporation
.1
2
moving closer to the overall rate of return (unity). The
table below shows the relative rates of return (schedule
3 rate of return divided by overall rate of return) before
4 and after application of the proposed general increase:
5
6
7
8
9
Residential Sch. 1
Present
Relative ROR0.85
1.48
Proposed
Relative ROR0.86
General Srvc. Sch. 11 1.27
.
10
11
12
13
14
15
Lg.Gen.Srvc.Sch.21 1.26
Ex.Lg.Gen.Srvc.Sch.25 0.59
potlatch-Lewiston Sch.25P 0.73
Pumping Srvc.Sch.31 1. 43
Street & Area Lgt.Schs.0.92
Overall 1. 00
1. 17
0.84
0.99
1.28
0.73
1. 00
16 As shown, for those Schedules where the present rates
17 are substantially above or below the cost of service, the
18 proposed increase results in a considerable movement toward
19 unity (1.00).
20 Q. Why is the Company proposing to spread the general
21 increase other than on a unifor. percentage basis without
22 the results of the new load study?
23 A. While a load study is currently underway, the
24 results of the study will not be available until early
25 2010. The Commission, in Order No. 30647 in Case No. AVU-
26 E-08-01, discussed the use of sensitivity studies in the
27 absence of a load study.Accordingly, the Company has.28 performed a sensitivity analysis of its cost of service
Hirschkorn, Di 11
Avista Corporation431
.1 study results under several different outcomes of the load
2 study. As shown on Schedule 4 of Exhibit 11, and described
3 in Company witness Knox's testimony, the outcome of the
4 load study currently underway should not materially change
5 the results of the Company's present cost of service study,
6 i . e., those schedules whose rate of return is considerably
7 less than the overall rate of return would continue to be
8 less,and those schedules whose rate of return is
9 considerably above the overall rate of return would
10 continue to be above. Given the results of this analysis,
11 and the effect of the estimated PCA rate reduction
12 (different percentage reduction by schedule), the Company
13 did not want to forgo this opportunity to adjust rates by.14 schedule to move closer to the cost of providing service.
15 The Company believes that the proposed rate spread results
16 in a reasonable approach to moving the rates for most
17 schedules toward the cost of providing service.
18 Q. The relative rate of return for street and area
19 lighting schedules moves further away from unity after
20 application of the proposed increase (0.92 to 0.73). Why
21 is the compåny proposing an increase to these schedules
22 that yields this result?
23 A. Whereas the average reduction in the present PCA
24 surcharge across all schedules is 5.0%, the average PCA
25 reduction for street and area schedules is only 1.6%. This
26 is because most of the revenue under these schedules.27 applies to the capital recovery of lights and poles, and
432 Hirschkorn, Di 12
Avista Corporation
.1 the PCA is applied to the "energy" portion of the rate(s).
2 Therefore, in order to achieve a reasonable net increase to
3 those schedules of 8.9%(general increase and PCA
4 decrease), the Company had to apply an average general
5 increase of 10.5% to those schedules, which is considerably
6 less than the overall general increase of 12.8%.
7
8 Proposed Rate Design
9 Q.Where in your Exibit do you show a comparison of
10 the present and proposed rates within each of the Company's
11 electric service schedules?
12 A.Page 3, Schedule 3 of Exhibit No. 12 shows a
13 comparison of the present and proposed rates within each of.14 the schedules, which I will describe below.Colum (a)
15 shows the rate/billing components under each of the
16 schedules, column (b) shows the base tariff rates within
17 each of the schedules, colum (c) shows the present rate
18 adjustments applicable under each schedule, and colum (d)
19 shows the present billing rates.Colum (e) shows the
20 proposed general rate increase to the rate components
21 within each of the schedules, colum (f) shows the proposed
22 billing rates and colum (h) shows the proposed base tariff
23 rates.
24 Q.Is the Company proposing any changes to the
25 existing rate structures within its rate schedules?
.26
27
A.NO, it is not.
Q.Turning to Residential Service Schedule 1, could
433 Hirschkorn, Di 13
Avista Corporation
.1 you please describe the present rate structure under this
2 schedule?
3 A.. Yes.Residential Schedule 1 has a present
4 customer / basic charge of $4.60 per month and two energy
5 rate blocks:0-600 kWhs and over 600 kWhs.The present
6 base tariff rate for the first 600 kWhs per month is 6.552
7 cents per kWh and 7.416 cents for all kWhs over 600.
8 Q.How does the Comany propose to spread the
9 proposed general revenue increase of $12,279,000 to
10 Schedule 1?
11 A.The Company proposes to increase the monthly
.
12 customer charge from $4.60 to $5.00, or 8.7%. The proposed
13 increase to the energy rate for the 0-600 kWh block is
14 0.907 cents/kWh and the proposed increase to the over 600
15 kWh block is 1.135 cents/kWh, or 125% of the increase
16 applied to the first block rate.
17 Q.Why is the Company proposing to increase the
18 monthly customer charge from $4.60 to $5.00 per month?
19 A.A substantial portion of the Company's costs are
20 fixed and do not vary with the amount of energy used by
21 customers.As reflected in this filing, the cost of
22 operating and maintaining our electric system is increasing
23 and the Company has been providing this message to
24 customers. The Company believes it is important that rates
25 at least partially reflect these increasing costs and allow
26 the Company a more reasonable opportuni ty to recover some.27 of these costs. However, the Company also understands the
434 Hirschkorn, Di 14
Avista Corporation
.1 controversial nature of residential "customer charges" and
2 is proposing only a relatively modest increase in the
3 charge.
4 Q.Why is the Company proposing a higher percentage
5 increase to the tail-block rate (over 600 kWhs) than to the
6 first-block rate?
7 A.By applying a higher percentage increase to the
8 tail-block rate, a stronger price-signal is provided to
9 customers regarding the higher incremental cost of
10 producing energy in the future. This price-signal provides
11 additional financial incentive for customers to use energy
12 more efficiently.Application of the proposed increase
13 results in a rate differential of approximately 1.1 cents.14 per kWh between the two block rates compared to the present
15 differential of 0.86 cents per kWh.
16 Q.Did the Company consider proposing the
17 implementation of an additional rate block in this filing
18 to provide an even stronger price signal to customers?
19 A.Yes, it did. However, given the current state of
20 the economy and other concerns, it chose not to propose
21 implementation of an additional inverted rate block in this
22 filing.
23
24
Q.Could you please explain these other concerns?
A.Yes.The first concern is related to the
25 potential affect of further inverting rates on low- and
26 limited-income customers. The Company examined the average.27 annual usage of its Idaho residential all-electric (no
435 Hirschkorn, Di 15
Avista corporation
.1 natural' gas) customers that have received LIHEAP assistance
2 and those that have not received assistance. Over a recent
3 twelve month period, the average annual usage for customers
4 that have received assistance was 1,900 kWhs greater than
5 for those customers that did not.Looking at a smal 1
6 sample of the customers that have received assistance, it
7 is apparent that many of these households utilize
8 electrici ty for home-heating and further inverting
9 residential rates could have a disproportionate effect on
10 these customers' bills.
11 The second concern relates to customer education
12 regarding inverted rates.While the Company has provided
13 customers with on-going information about energy-efficiency.14 programs and steps to conserve energy, more information
15 needs to be provided to customers regarding inverted rates
16 prior to implementing significant rate structure changes.
17 This information can then be used to help customers better
18 understand and manage their usage and monthly bill.
19 Lastly, the Company is concerned with the timely
20 recovery of its fixed costs as it relates to a further
21 inversion of residential rates.The proposed tariff rate
22 for residential usage in excess of 600 kWhs per month is
23 8.55 cents per kWh.This rate is well in excess of the
24 short-run marginal/incremental cost of energy and reflects
25 recovery of a significant level of fixed costs.Further
26 rate inversion would result in additional fixed costs.27 reflected/recovered through an even higher tail-block rate,
436 Hirschkorn, Di 16
Avista Corporation
.1 while usage billed at this rate will vary considerably
2 based on weather.
3 Q.Wht is the average monthly electric usage for a
4 residential customer, and what is the effect of the
5 proposed increase on a customer's bill?
6 A.The average monthly usage for a residential
7 customer is 982 kWhs.Based on the proposed increase,
8 including the estimated reduction in the PCA surcharge, the
9 average monthly increase would be $6.71, or 8.6%. The
10 present monthly bill for 1,000 kWhs of usage is $78.47 and
11 the proposed monthly bill would be $85.18, including all
12 rate adjustments.
13 Q.Turning to General Service Schedule 11, could you.14 please describe the present rate structure and rates under
15 that Schedule?
16 A.Yes.The present rate structure under the
17 schedule includes a monthly customer charge of $6.50, an
18 energy rate of 7.295 cents per kWh for all usage under
19 3,650 kWhs per month, and an energy rate of 6.223 cents per
20 kWh for usage over 3,650 kWhs per month.There is also a
21 demand charge of $4.00 per kW for all demand in excess of
22 20 kW per month. There is no charge for the first 20 kW of
23 demand.
24 Q.How is the Company proposing to apply the
25 proposed general revenue increase of $3,485,000 to the
26 rates under Schedule 11?.27 A.The Company is proposing that the customer charge
437 Hirschkorn, Di 17
Avista Corporation
.1 be increased by $0.25, from $6.50 to $6.75 per month, and
2 that the demand charge (over 20 kW) be increased $0.25 per
3 kW, from $4.00 to $4.25. The remaining revenue increase for
4 the Schedule is proposed to be recovered through a uniform
5 percentage increase applied to the two (block) energy
6 rates. The increase in the first block rate is 1.082 cents
7 per kwh, and is 0.922 cents per kwh in the second block
8 rate.
9 Q.Turning to Large General Service Schedule 21,
10 could you please describe the present rate structure under
11 that Schedule and how the Company is proposing to apply the
12 increase of $6,506,000 to the rates within the schedule?
13 A.Large General Service Schedule 21 consists of a.14 minimum monthly charge of $275.00 for the first 50 kW or
15 less, a demand charge of $3.50 per kW for monthly demand in
16 excess of 50 kW, and a two-block energy rate(s):5.384
17 cents per kWh for the first 250,000 kWhs per month and
18 4.594 cents per kWh for all usage in excess of 250,000
19 kWhs.
20 The Company is proposing that the present minimum
21 demand charge (for the first 50 kW or less) be increased by
22 $25 per month, from $275.00 to $300.00, and the demand
23 charge for kW over 50 per month be increased by $0.50 per
24 kW, from $3.50 to $4.00.The remaining revenue increase
25 for the Schedule is proposed to be recovered through a
.26 uniform percentage increase applied to the two (block)
27 energy rates. The proposed increase for the first 250,000
438 Hirschkorn, Di 18
Avista Corporation
.1 kWhs used per month under the schedule is 0.782 cents per
2 kWh, and an increase of 0.666 cents per kWh for usage over
3 250 i 000 kWhs per month.
4 Q.Turning to Bxtra Large General Service Schedule
5 25, could you please describe the present rate structure
6 under that Schedule and how the Company is proposing to
7 apply the increase of $2,398,000 to the rates within the
8 Schedule?
9 A.Extra Large General Service Schedule 25 consists
10 of a minimum monthly charge of $10,000.00 for the first
11 3,000 kVa or less, a demand charge of $3.25 per kVa for
12 monthly demand in excess of 3,000 kVa, and a two-block
13 energy rate (s): 4.411 cents per kWh for the first 500,000.14 kWhs per month and 3.736 cents per kWh for all usage in
15 excess of 500,000 kWhs.
16 The Company is proposing that the present minimum
17 demand charge under the schedule be increased by $1,000 per
18 month, from $10,000 to $11,000, and the demand charge for
19 kVa over 3,000 per month be increased by $0.50 per kVa,
20 from $3.25 to $3.75.The remaining revenue increase for
21 the Schedule is proposed to be recovered through a uniform
22 percentage increase applied to the two (block) energy
23 rates.The proposed energy rate increase for the first
24 500,000 kWhs used per month is 0.760 cents per kWh and the
25 increase for usage over 500,000 per month is 0.643 cents
26 per kWh..27 Q.Did the Company consider implementing time-of -use
439 Hirschkorn, Di 19
Avista Corporation
.1
2
(TOU) rates for Schedule 25 customers in this Case?
A.Yes,it did.However,given the current
3 recession and its effect on the operations and financial
4 condition of many of these customers, the Company felt that
5 this was not the appropriate time to propose such a change.
6 Six of the twelve Schedule 25 customers manufacture wood
7 products. Because of the current recession, three of those
8 six customers have completely ceased production for an
9 indefinite period, and the other three have substantially
10 reduced production. Two of the remaining customers operate
11 silver mines and the future operation of those mines is
12 uncertain.
13 Q.What steps is the Company taking to assess the.14 possible implementation of TOU rates for these customers in
15 the future?
16 A.The Company has met with these customers to
17 discuss the possibility of implementing TOU rates in the
18 future.Most of these stated that it would be difficult
19 for them to shift a significant portion of their load to
20 off-peak periods because of labor and operational issues.
21 Nevertheless, the Company plans to again meet with and
22 gather additional information from each of these customers
23 during 2009 to assess their future operating plans
and the
24 feasibility of implementing TOU rates in the future.
25 Q.Could you please describe the service the Company
26 provides to potlatch's Lewiston Plant?.27 A.Yes.In Commission Order No. 29418, dated
440 Hirschkorn, Di 20
Avista corporation
.1 January 15, 2004, the Commission approved a ten~year Power
2 Purchase and Sale Agreement (Agreement) between Avista and
3 Potlatch Corporation, applicable to potlatch's Lewiston
4 Plant.The Agreement became effective July 1, 2003 and
5 expires June 30, 2013.The Agreement provides for the
6 purchase by Avista of potlatch's on-site generation of up
7 to 62 average megawatts per year at a price of $42.92 per
8 megawa t t - hour.Power purchased from potlatch under the
9 Agreement is a directly-assigned resource to Idaho (no
10 allocation to Washington). Avista serves potlatch's entire
11 load requirement at the Plant, approximately 100 average
12 megawatts, under Schedule 25P.During the twelve months
13 ended September 30, 2008, potlatch's generation was 49.14 average megawatts and their total load requirement was 104
15 average megawatts.
16 Q.Could you please describe the application of the
17 proposed increase of $ 5, 694, 000 to the rates under Schedule
18 25P?
19 A.Yes.The Company is proposing that the present
20 minimum demand charge under the schedule be increased by
21 $1,000 per month, from $10,000 to $11,000, and the demand
22 charge for kVa over 3,000 per month be increased by $0.50
23 per kVa, from $3.25 to $3.75.The remaining revenue
24 increase for the Schedule is proposed to be recovered
25 through an increase of 0.553 cents per kWh to the energy
26 charge..27 Q.What changes is the Company proposing to the
Hirschkorn, Di 21
Avista Corporation441
.1 rates under pumping Schedule 31 to recover the proposed
2 general revenue increase of $560,000?
3 A.The Company is proposing that the customer charge
4 be increased by $0.25, from $6.50 to $6.75 per month, with
5 the remaining revenue increase spread on a uniform
6 percentage basis to the two energy rate blocks under the
7 Schedule. The proposed increase in the first block rate is
8 1.015 cents per kWh and the increase in the second block
9 rate is 0.866 cents per kwh.
10 Q. How is the Company proposing to spread the
11 proposed revenue increase of $311,000 applicable to Street
12 and Area Light schedules, to the rates contained in those
13 schedules (Schedules 41-49)?.14 A.The Company proposes to increase present street
15 and area light (base) rates between 10.5% and 16.0%
16 depending on the Schedule.When the general percentage
17 increase is combined with the estimated PCA surcharge
18 decrease for each Schedule, the net proposed increase for
19 all lighting rates is 8.9%.The (base tariff) rates are
20 shown in the proposed tariffs for those schedules,
21 contained in Schedule 2 of Exhibi t No. 12.
22 Q.Are you proposing any other changes to the
23 Company's electric service tariffs?
.
24
25
26
27
A.No.
iv. PROPOSED NATU GAS REVENU INCRESB
Q.Could you please explain what is contained in
442 Hirschkorn, Di 22
Avista Corporation
.Schedule 4 of Bxhibi t No. 12?1
2 A.Yes.Schedule 4 of Exhibi t 12 is a copy of the
3 Company's present and proposed natural gas tariffs, showing
4 the changes (strikeout and underline) proposed in this
5 filing.
6 Q.Could you please describe what is contained in
7 Schedule 5 of Exhibit No. 12?
8 A.Schedule 5 of Exhibit No. 12 contains the
9 proposed (clean) natural gas tariff sheets incorporating
10 the proposed changes included in this filing.
11 Q.Could you please explain what is contained in
12 Schedule 6 of Bxhibit No. 12?
13 A.Yes.Schedule 6 of Exhibit No. 12 contains.14 information regarding the proposed spread of the natural
15 gas revenue increase among the service schedules and the
16 proposed changes to the rates within the schedules. Page 1
17 shows the proposed general revenue and percentage increase
18 by rate schedule. Page 2 shows the rates of return and the
19 relative rates of return for each of the schedules before
20 and after the proposed increases. Page 3 shows the present
21 rates under each of the rate schedules, the proposed
22 changes to the rates wi thin the schedules, and the proposed
23 rates after application of the changes.These pages will
24 be referred to later in my testimony.
25
26 Swmary of Natural Gas Rate Schedules and Tariffs.27 Q.Would you please review the Company's present
443 Hirschkorn, Di 23
Avista Corporation
.1 rate schedules and the types of gas service offered under
2 each?
3 A.Yes. The Company's present Schedules 101 and 111
4 offer firm sales service.Schedule 101 generally applies
5 to residential and small commercial customers who use less
6 than 200 therms/month.Schedule 111 is generally for
7 customers who consistently use over 200 therms/month.
8 Schedule 131 provides interruptible sales service to
9 customers whose annual requirements exceed 250,000 therms.
10 Schedule 146 provides transportation/distribution service
11 for customer-owned gas for customers whose annual
12 requirements exceed 250,000 therms.
13 Q.The Company also has rate Schedules 112 and 132.14 on file with the Coimission.Could you please explain
15 which customers are eligible for service under these
16 schedules?
17 A.Schedules 112 and 132 are in place to provide
18 service to customers who at one time were provided service
19 under Transportation Service Schedule 146. The rates under
20 these schedules are the same as those under Schedules 111
21 and 131 respectively, except for the application of
22 Temporary Gas Rate Adjustment Schedule 155.Schedule 155
23 is a temporary rate adjustment used to amortize the
24 deferred gas costs approved by the Commission in the prior
25 PGA.Because of their size,transportation service
26 customers are analyzed individually to determine their.27 appropriate share of deferred gas costs.If those
444 Hirschkorn, Di 24
Avista Corporation
customers switch back to sales service,the Company.1
2
3
continues to analyze those customers individually;
otherwise,those customers would receive gas costs
4 deferrals which are not due them, thus the need for
5 Schedules 112 and 132.There are presently only 3
6 customers served under these schedules.
7 Q.How many customers does the Company serve under
8 each of its natural gas rate schedules?
9 A.As of September 2008,the Company provided
10 service to the following numer of customers under each of
11 its schedules:
Interruptible Service Sch. 131
71,472
846
1.
12
13
14
15
16
General Service Sch. 101
Lg. General Service Sch. 111
Transportation Service Sch. 146 5
17 proposed Rate Spread
18 Q.How does the Company propose to spread the
19 overall revenue increase of $2,740,000, or 3.0%, amng its
20 natural gas general service schedules?
21 A.The Company is proposing the following
22 revenue/rate changes by rate schedule:
Lg. General Service Sch. 111
3.1%
2.5%
.
23
24
25
26
27
General Service sch. 101
interruptible Service Sch. 131 1. 7%
Transportation Service Sch. 146 10.9%
445 Hirschkorn, Di 25
Avista Corporation
.1 Q. Is the proposed increase for Transportation
2 Schedule 146 comparable to the increase for the other
3 service schedules?
4 A.No.The proposed increase for Transportation
5 Schedule 146 is not comparable to the proposed increases
6 for the other (sales) service schedules, as Schedule 146
7 revenue does not include an amount for the cost of gas or
8 pipeline transportation, whereas the other sales schedules
9 include those costs/revenue.(Transportation customers
10 acquire their own gas and pipeline transportation. )
11 Including a conservative level of 50.0 cents per therm for
12 the cost of gas and pipeline transportation, the proposed
13 increase to Schedule 146 rates represents an average.14 increase of 2.0% in those customers' total gas bill, which
15 is then expressed on a relatively comparable basis to the
16 proposed increase (decrease) to the other (sales) service
17 schedules, and the overall proposed increase of 3.0%.
18 Q.What infor.ation did the Company use in
19 developing the proposed spread of the overall increase to
20 the various rate schedules?
21 A.The Company utilized the results of the cost of
22 service study, as sponsored by Witness Knox, as a guide in
23 developing the proposed rate spread. The relative rates of
24 return before and after application of the proposed
25 increases by schedule are as follows:
.26
27
446 Hirschkorn, Di 26
Avista Corporation
.1
2
3
4
5
6
7
Relative Rates of Return by Service Schedule
Before Increase After Increase
Schedule 101 :1. 02 1. 01
Schedule 111 :0.91 0.95
Schedule 131 :1. 08 1. 05
Schedule 146 :1.28 1. 29
8 Page 2 of Schedule 6 shows this information in more detail.
9
10 Proposed Rate Design
11 Q.Could you please explain the present rate design
12 within each of the Comany's present gas service schedules?
13 A.Yes.General Service Schedule 101 generally.14 applies to residential and small commercial customers who
15 use less than 200 therms/month.The Schedule contains a
16 single rate per therm for all gas usage and a monthly
17 customer/basic charge.
18 Large General Service Schedule 111 has a four-tier
19 declining-block rate structure and is generally for
20 customers who consistently use over 200 therms/month. The
21 Schedule consists of a monthly minimum charge plus a usage
22 charge for the first 200 therms or less, and block rates
23 for 201-1,000 therms/month, 1001-10,000 therms/month and
24 usage over 10, 000 therms /mon th.
25 interruptible Sales Service Schedule 131 contains a
26 single rate per therm for all gas usage. The schedule also.27 has an annual minimum (deficiency) charge based on a usage
Hirschkorn, Di 27
Avista Corporation447
.
3 per month customer charge and contains a single rate per
4 therm for all gas usage.The schedule also has an annual
5 minimum '(deficiency) charge based on a usage requirement of
6 250,000 therms per year.
7 Q.Where in your Exhibits do you show the present
8 and proposed rates for the Company's natural gas service
9 schedules?
10 A.Page 3 of Schedule 6 shows the present and
11 proposed rates under each of the rate schedules, including
12 all present rate adjustments (adders). Colum (e) on that
13 page shows the proposed changes to the rates contained in.14 each of the schedules.
15 Q.You stated earlier in your testimony that the
16 Company is proposing an overaii increase of 3.1% to the
17 rates of General Service Schedule 101.Is the Comany
18 proposing an increase to the present basic/customer charge
19 of $4.00/month under the schedule?
20 A.Yes.The Company is proposing to increase the
21 basic/customer charge from $4.00 to $4.25 per month.
22 Q.Why is the Company proposing an increase to the
23 basic charge?
24 A.The Company believes that the customer/basic
25 charge should recover a reasonable portion of the fixed
26 costs of providing service.The total fixed cos ts.27 associated with providing service to Schedule 101 customers
448 Hirschkorn, Di 28
Avista Corporation
.1 is several times the present monthly charge of $4.00. The
2 monthly cost associated with recovery of only the average
3 meter and service line for these customers is $6.03 per
4 month.
5 Q.What is the proposed increase to the rate per
6 therm under Schedule 101 in order to achieve the total
7 proposed revenue increase for the Schedule?
8 A.The proposed increase to the energy rate under
9 the schedule is 3.512 cents per therm, as shown in column
10 (e), page 3, Schedule 6 of Exhibit No. 12.
11 Q.What would be the increase in a residential
12 customer's bill with average usage based on the proposed
13 increase for Schedule 101?.14 A.The increase for a residential customer using an
15 average of 66 therms of gas per month would be $2.56 per
16 month, or 3.2%.A bill for 66 therms per month would
17 increase from the present level of $79.38 to a proposed
18 level of $81.94, including all present rate adjustments.
19 Q.Could you please explain the proposed changes in
20 the rates for Large General Service Schedules 111?
21 A.Yes. The present rates for Schedules 101 and 111
22 provide guidance for customer placement:cus tomers who
23 generally use less than 200 therms/month should be placed
24 on Schedule 101, customers who consistently use over 200
25 therms per month should be placed on Schedule 111.Not
26 only do the rates provide guidance for customer schedule.27 placement, they provide a reasonable classification of
Hirschkorn, Di 29
Avista corporation449
.1 customers for analyzing the costs of providing service.
2 The proposed increase to the minimum charge for
3 Schedule' 111 (for 200 therms or less) of $7.00 per month is
4 the sum of the Schedule 101 customer charge increase of 25
5 cents plus the proposed increase to the Schedule 101 rate
6 per therm of 3.512 cents multiplied by 192 therms.This
7 application maintains the present (breakeven) relationship
8 between the schedules, and will minimize customer shifting
9 between the Schedules.The remaining revenue requirement
10 for the Schedule is proposed to be recovered through a
11 uniform percentage increase of 2.5% to the remaining block
12 rates under the Schedule.
13 Q.How does the Company propose to recover the.14 increase of $7,000 to interruptible Service Schedule 131?
15 A.The Company proposes to increase to the usage
16 charge under the Schedule by 1.598 cents per thermo
17 Q.How does the Company propose to recover the
18 increase of $35,000 to Transportation Schedule 146?
19 A.The Company is proposing to increase the per
20 therm charge under the Schedule by 1.598 cents per thermo
21 Q.Is the Company proposing any other changes to its
22 natural gas service schedules?
23
24
A. No, it is not.
Q.Does that complete your pre-filed direct
25 testimony?
26 A. Yes, it does..
450 Hirschkorn, Di 30
Avista Corporation
.1
2
I. INTRODUCTION
Q.Please state your name, emloyer and business
3 address.;
4 A.My name is Bruce Folsom. I am employed by Avista
5 as the Senior Manager of Demand Side Management (DSM). My
6 business, address is East 1411 Mission Avenue, Spokane,
7 Washington.
8 Q.Would you please describe your education and
9 business experience?
10 A.I graduated from the Uni versi ty of Washington in
11 1979 wi th Bachelor of Arts and Bachelor of Science degrees.
12 i received a Masters in Business Administration degree from
13 Seattle University in 1984..14 I joined the Company in 1993 in the State and
15 Federal Regulation Department.My duties included work
16 associated with tariff revisions and regulatory aspects of
17
18
integrated resource planning,demand side management,
competi ti ve bidding, and emerging issues.In 2002, I was
19 named the Manager of Regulatory Compliance which added
20 responsibilities such as implementing the Federal Energy
21 Regulatory Commission's major changes to its Standards of
Conduct rule.I began my current position in Septemer of22
23
24
2006.Prior to joining Avista, I was employed by the
Washington Utilities and Transportation Commission
25 beginning in 1984, and then served as the Electric Program
.
451 Folsom, Di 1
Avista Corporation
.1
2
Manager from 1990 to February, 1993. From 1979 to 1983 i i
was the Pacific Northwest Regional Director of the
3 Environmental Careers Organization, a national, private,
4 not-for-profit organization.
5 Q.What is the scope of your testimony in this
6 proceeding?
7
8
A.I provide an overview of the Company's DSM
programs and recent results.I also provide documentation
9 showing that Avista' s expenditures for electric and natural
10 gas energy efficiency programs have been prudently
11 incurred.
12 Q.Are you sponsoring any exhibits to be introduced
13 in thi s proceeding?.14 A.Yes.I am sponsoring Exhibit No. 13 prepared
15 under direction. Exhibit No. 13 documents the results and
16 cost-effectiveness of Avista' s DSM programs.
17
18
19
II. DSM PROGRAS AN CUR PBRIOD RESULTS
Q.Would you please provide a brief overview of
20 Avista's DSM programs?
21
22
A.Yes. Avista has historically had a significant
and consistent commitment to energy efficiency.In the
23 mid-1990s, while the electric industry was pulling back
24 from offering energy efficiency services, Avista pioneered
25 the Energy Efficiency Tariff Rider. Now in its fourteenth
.
452 Folsom, Di 2
Avista Corporation
.
.
.
1
2
year, the tariff rider was the country's first distribution
charge to fund DSM and is now replicated in many other
3 Schedule 91 currently has a commodity rate ofstates.
4 1.58% for electric service and the Schedule 191 rate is
5 1.46% for natural gas.
6 The Company's approach to energy efficiency is based
7 on two key principles.The first is to pursue all cost-
8 effective kilowatt hours and therms by offering financial
9 incentives for energy saving measures with a simple
10 The second keyfinancial payback of over one year.
11 principle is to use the most effective "mechanism" to
12 deliver energy efficiency services to customers.These
13 mechanisms are varied and include 1 ) prescriptive programs
14 (or "standard offers" such as high efficiency appliance
15 rebates), 2) site-specific or "customized" analyses at
16 customer premises,"market transformational" ,or3 )
17 regional, efforts with other utilities, 4) low-income
18 weatherization services through local Community Action
19 Agencies, and 5) low-cost/no-cost advice through a mul ti-
20 channel communication effort.These will be described
21 later in my testimony.
22 The Company's offerings include over 300 measures that
23 into 30 for customerpackagedoverprogramsare
24 convenience. As part of Avista' s planning efforts, over
25 3000 measures are considered and then examined for cost-
453 Folsom, Di 3
Avista Corporation
.1
2
3
4
5
6
7
8
9
10
11
12
13.
.
effectiveness.comprehens i ve energyTheCompany's
efficiency outreach, the "Every Little Bit" communications
campaign, received several national honors in 2008.This
comprehens i ve communication approach helps customers
reorient their thinking about energy efficiency.
The Company's programs are delivered across a full
customer spectrum.Virtually all customers have had the
opportuni ty to participate and a great many have directly
benefited from the program offerings. As will be described
later in my testimony, all customers have indirectly
benefited through enhanced cost-efficiencies as a result of
this portfolio approach.
Avista offers the following residential programs:
454 Folsom, Di 4
Avista Corporation
.2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
.
1 Illustration No.1:
RESIDENTIAL
High Efficiency Furnace/Boiler
High Efficiency Heat Pump
High Efficiency variable Speed Motor
High Efficiency Tank Water Heater
High Efficiency Tankless Water Heater
High Efficiency Ground Source Heat Pump
High Efficiency Replacement Air Conditioning
Space Heat Conversion (Direct Use of Natural Gas)
Water Heat Conversion (Direct Use of Natural Gas)
Heat Pump Conversion (Direct Use of Natural Gas)
Ceiling, Attic, Floor, Wall Insulation
High Efficiency windows
Fireplace Damper
Multifamily (UCONS)
BuiltGreen~ (New Construction Energy Star~)
Something for Everyone
Energy Star~ Appliances
CFL (and CFL Recycling) Promotions
Warm Homes, Warm Hearts
"Second" Refrigerator Recycling Program
"Geographic Saturation"
Communi ty Events and Workshops
Low-cost/no-cost information
Direct Use of Nat Gas: Multi-Family Housing Conversion
Regional Market Transformation (NEEA)
On-line Home Audits
LIMITBD INCOME RESIDBNTIAL
Limited Income Weatherization with Community Action
Programs
(Note: All residential programs above are alsoavailable)
37 The residential programs shown above are standard
38
39 invol ve a menu of rebates on selected measures (e. g. ,
offerings or what we call "prescriptive programs."These
40 lighting, weatherization, appliances, etc.).
.
455 Folsom, Di 5
Avista Corporation
.1
2
3
4
For commercial cus tomers , in addi tion to prescriptive
programs, Avista offers "site-specific" programs. Site.:
specific programs are customized to the cus tomer's
premises.The site-specific offering provides incentives
5 on any, cost-effective commercial and industrial energy
6 efficiency measure. This is implemented through site
7 analyses, customized diagnoses, and incentives determined
8 for savings generated specific to the customer's premises
9 or process. The following illustration shows the programs
10 available to Avista' s commercial and industrial customers.
11 Illustration 2:
.
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
NON-RESIDENTIAL (COMMRCIAL &: INDUSTRIAL)
Si te-Specific
(Note: Incentives offered for any measure wi th ~ 1
year payback)
Air Care Plus (Rooftop HVAC Maintenance)
EnergySmart Commercial Refrigeration
LEED Certification Incentives
Power Management for PC Networks
Premium Efficiency Motors
Food Service
LED Traffic Signals
Refrigerated Warehouse
Commercial HVAC variable Frequency Drives
Retro-Commissioning
Clothes Washers
Side Steam and Demand Filtration
Vending Machine Controllers
Lighting and Controls
32 These programs are supported by twenty-one full-time
33
34 include Company support from the Contact Center, Corporate
equivalents (FTE) spread over 34 staff.(This does not
.
456 Folsom, Di 6
Avista Corporation
.1
2
Communications, Accounting and other direct and indirect
support. )The 2008 DSM budget (system) was over $18
3 million; representing an increase of $6 million over 2007.
4 Of the Company's revenues collected under Schedules 91
5 (electric tariff rider) and 191 (natural gas tariff rider)
6 in 200&, 70.9% was paid out to customers in direct
7 incentives pursuant to the cost-effecti veness tests
8 described below. This does not include additional benefits
9 such as technical analyses provided to customers by the
10 Company's DSM engineering staff.
11 Q.What were the Company's energy efficiency targets
12 and results for 2008?
.13
14
A.The Company's energy efficiency targets are
established in the process of developing the Electric and
15 Natural Gas Integrated Resource Plans (IRPs).These
16 targets are revisited and adjusted to take into account new
17 programs as part of our ongoing business planning process.
18 The results of Avista's energy efficiency programs
19 continue to exceed the targets established as part of the
20 IRP process.The current estimate of local energy
21 efficiency savings for January through November 2008 is
22 62.1 million kWhs (approximately 7 amW) or 117% of the
23 Company's annual target. These preliminary results will be
24 revised based upon ongoing verification of the data by the
25 Company.
.
457 Folsom, Di 7
Avista Corporation
.1 These are preliminary, unaudited results that will
2 be updated. Over 137 aM of cumulative savings have been
3 achieved through Avista' s energy efficiency efforts in the
4 past thirty years; over 110 aM of DSM is currently in
5 place on the Company's system. By comparison Avista's 2008
6 total electric retail load was 1098 aM. The 2008 natural
7 gas savings targets for Washington and Idaho is 1.425
8 million therms.Over 1.75 million therms have been saved
9 through Novemer of 2008, which is 123% of the 2008 annual
10 target.
11 Q.Do the 2008 results reflect Avista's
12 participation in regional energy efficiency efforts?
13 A.No.In addition to Avista' s prescriptive and.14 site-specific programs, the Company funds and participates
15 in the activities of the Northwest Energy Efficiency
16 Alliance (NEEA). NEEA focuses on using a regional approach
17 to obtain electric efficiency through the transformation of
18 markets for efficiency measures and services.An example
19 of NEEA-sponsored programs that benefit Avista customers
20 are efforts to decrease the cost of compact fluorescent
21 light bulbs (CFLs) and high-efficiency appliances by
22 working through manufacturers. For some measures, a large-
23 scale, cross-utility approach is the most cost-effective
24 means to achieve energy efficiency savings. This approach
25 seems particularly effective for markets composed of large
.
458 Folsom, Di 8
Avista Corporation
.1 numers of smaller usage consumers, such as the residential
2 and small commercial markets.
3 The results from NEEA programs for 2008 have not been
4 reported as of the date of the submittal of this testimony.
5 Historically, however, Avista has received approximately
6 1.5 aM of savings in its service terri tory from NEEA
7 programs.
8 Q.Please explain Avista i s relationship to the
9 Northwest Energy Bfficiency Alliance (NBEA).
10 A.Avista has been a member of the NEEA since the
11 creation of that organization in 1996. As stated above, the
12 mission of NEEA is to acquire cost-effective electric.13
14
efficiency resources through regional market
transformation. Avista is supportive of the use of a
15 coordinated regional market transformation effort to the
16 extent that the effort is a cost-effective enhancement of,
17 or alternative to, local utility efforts at acquiring those
18 resources for our customers.
19 In 2007, the last year for which data is available,
20 NEEA acquired 2.0 aM applicable to Avista' s service area
21 at a cost of 0.07 cents/kWh. Avista' s Total Resource Cost
22 avoided cost for a comparable time period is 0.4 cents /kWh
23 (using Avista' s weighted average measure life and discount
24 rate). Historically, NEEA's TRC acquisition cost has always
.
459 Folsom, Di 9
Avista Corporation
.1 been well below Avista' s comparable electric avoided cost.
2 The value of the NEEA portfolio has been realized by
3 Avista i s customers both directly as participants in markets
4 that have been cost-effectively transformed by NEEA
5 ventures, as well as indirectly as a result of reduced
6 demand and consequently lower energy cos ts through
7 wholesale markets.
8 Avista has been actively involved in the governance of
9 NEEA since the creation of the organization. The governance
10 contains numerous safeguards to promote broad regional
11 representation (including representation of the interests
12 of customers east of the Cascades and investor-owned
13 utility customers), prudent oversight of organizational.14 expenditures by the board of directors and appropriate
15 opportunities for the cessation of Avista funding in the
16 event of changes in organizational mission or
17 effectiveness.
18 Q.How do you increase customer participation in
19 your DSM programs?
20 A.Our focus on the residential side is to increase
21 customer understanding of our programs and how our programs
22 can help customers reduce their bills. We do this through
23 bill inserts and communications to drive customers to our
24 website with a "call-to-action" to use our financial
25 rebates. The following depicts a recent enhancement to our.
460 Folsom, Di 10
Avista Corporation
.
.
.
1
2
webs i te, ww.EveryLitteBit.com .This is an interactive
tool to engage customers and allows customers to quickly
3 view programs that they can use,by "clicking on"
4 particular features of the dwelling:
5 Illustration No.3:6 ~-~
7
8
9
10
11
12
13
14
15
16
17
18
19
liHle;'
fO ENfY STAA'NECONSmlJCTON RETE..........."..--.". ..... - ......,.~."._.. .
Q.Have you reviewed the Staff's coments on Bnergy
Avista's response theirisAffordability and what
20 recommendations?
21 No.GNR-U-08-01,"EnergyA.Yes.In Case
22 Affordability Issues and Workshops, "the Commission
23 initiated workshops to provide a forum for the exploration
24 of issues related to the affordability of energy in Idaho.
25 Staff provided their comments November 26, 2008.In the
461 Folsom, Di 11
Avista Corporation
.1
2
.
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
Company's reply comments filed December 19, 2008, we agreed
with Staff's recommendations concerning DSM and noted that:
.The Company historically has addressed
weatherization funding levels in our rate cases;
Avista has been an advocate for energy conservationeducation;
Avista continues to review our incentive programs
and the level of incentive amounts on an ongoingbasis;Regarding low- or no-interest loans,
examining expansion of current customer
preferring to work with the existinginstitution infrastructure that has this
as their primary service;Avista strongly supports initiative (s), including
those by the Northwest Energy Efficiency Alliance,
to include multi~family and manufactured homes in
the Energy Star~ Home Program; and
Avista supports improved appliance and buildingstandards and codes as the most cost-effective
means for energy efficiency delivery.
.
.
.we areoptions,financialfunction
.
.
Q.What is the status of the tariff rider balance?
A.The tariff rider balanCè both Idaho and
Washington, electric and natural gas is a negative
26 $9,982,000 (i. e. dollars expended exceed dollars collected
27
28
By jurisdiction and fuel, thethrough the Tariff Rider).
as of November 2008:negative rider balances are,
29 ($1,149,000) - Idaho electric; ($858,000) - Idaho natural
30 gas; ($5,499,000) - Washington electric; and ($2,476,000) -
31 Washington natural gas.
32 Q. What are the causes of these increasing negative
33 balances?
.
462 Folsom, Di 12
Avista Corporation
.1 A. The Company has leveraged the high level of
2 public interest in \ green' technologies to enhance the
3 acquisition of cost-effective energy-efficiency measures.
4 These leveraging opportuni ties and the cus tomer response to
5 the Company's efficiency programs have exceeded our
6 expectations.
7 Q.What is the Company's plan to address these
8 balances?
9 A.The largest negative balances, or over 78%, are
10 in Washington. On Decemer 31, 2008, we filed tariff rider
11 revisions in Washington to reduce the washington tariff
12 rider balances to zero. By means of a separate filing, to
13 follow soon after the filing of this case, we will submit.14 revised tariff riders in Idaho to do the same.We are
15 filing the tariff rider revisions separate from this
16 general rate case so that the revisions can go into effect
17 early in 2009, if approved, and thereby, prevent an
18 increasing negative balance.
19 Q.What plans does the Company have in the future to
20 address these tariff rider balances?
21 A.Schedules 91 and 191 should be the equivalent of
22 a" true-up mechanism" that is revised annually to reflect
23 expenditures to fund energy efficiency programs.In the
24 past few years, customer demand for energy efficiency
25 programs has been greater than available funding, which has
.
463 Folsom, Di 13
Avista Corporation
.
.
.
1
2
resul ted in the need for increased energy efficiency
funding. Avista remains committed to expeditiously
3 responding to customer requests for funding where the cost-
4 effectiveness tests are satisfied.
5 What kind of external oversight does the CompanyQ.
6 have regarding DSM?
7 The Company established. a non-binding oversightA.
8 group, the External Energy-Efficiency (Triple-E) board in
9 provide improved opportuni ties for1999tofor
10 communication,input and oversight of Avista' s DSM
11 portfolios.Avista currently facilitates meetings of the
12 board twice per year, provides a full analysis of the
13 results of DSM operations on an annual or more frequent
14 basis, discloses (with appropriate concern for customer
15 confidentiality) large projects and projects benefiting
16 Avista facilities, and provides the Triple-E with a
17 quarterly update of DSM activities.Additionally, the
18 Triple-E board can initiate additional meetings of the
19 board at their own request. Board membership has included
20 representatives from regulatory, governmental,
21 environmental, nationally recognized energy-efficiency
22 customer advocates for limited income andexperts,
23 industrial well end-use customersegmentsasas
24 participants.
464 Folsom, Di 14
Avista Corporation
.1 Q. Does the Company propose to increase its low-
2 income weatherization funding as part of this filing?
3 A.Yes.The Company proposes to increase its low-
4 income weatherization funding for electric and natural gas
5 service by a percentage amount equal to the percentage rate
6 increase granted in this case for residential customers
7 (net of the PCA surcharge reduction for electric service).
8 The additional funding would be provided through the DSM
9 tariff riders, Schedules 91 and 191.
.
10
11
12
13
14
III. PRUDBNCE OF INCtJD DSM COSTS
Q.Would you please explain the Company's request
for a finding of prudence in this case?
A. Yes. When the Commission approved the Company's
15 energy efficiency programs in 1995 (in Case Nos. WWP-E-94-
16 12 and WWP-G-94-6), Avista committed to demonstrating the
17 prudence of program expenditures in future general rate
18 cases.In the Company's last general electric and natural
19 gas rate cases (Case Nos. AVU-E-08-01 and AVU-G-08-01), the
20 Commission issued a finding in Order No. 30647 that
21 electric and natural gas expenditures through December 31,
22 2007 were prudently incurred.At this time, the Company
23 requests that the Commission issue a finding that electric
24 and natural gas energy efficiency expenditures from January
25 1, 2008 through November 30, 2008 were prudently incurred..
465 Folsom, Di 15
Avista Corporation
.
.
.
1
2
3
Q. Would you please sumrize the Company's energy
efficiency-related savings for this time period?
A.Yes. The Company's tariff riders under Schedules
4 91 (electric) and 191 (natural gas) are system benefit
5 charges to fund energy efficiency.
6 As shown in Exhibit No. 13, from January 1, 2008
7 through November 30, 2008, 62.1 million kWh and 1.75
8 million therms of energy savings were obtained.Page 1 of
9 Exhibit No. 13 details the energy savings by regular and
10 low-income portfolios for both electric and natural gas DSM
11 programs.
12 Has there been ongoing review of the Company'sQ.
13 programs?
14 Yes, as previously discussed, the Company hasA.
15 regularly convened a stakeholders forum known as the
16 External Energy Efficiency Board.These meetings have
17
18
19
repres en ta t i ves ,Commission staffincludedcustomer
members,and individuals from the environmen tal
communities.These stakeholder meetings review the
20 Company's program offerings as well as the underlying cost-
21
22
23
24
25
effecti veness tests and resul ts .
Q.Have the Company's DSM programs been cost-
effective?
A.Yes.The electric programs have been cost-
effective from both a Total Resource Cos t (TRC)and Utility
466 Folsom, Di 16
Avista Corporation
.1
2
Cost Test (UCT) perspective.Page 2 of Exhibit No. 13
shows that the TRC benefit-to-cost ratio of 1.94 for the
3 overall electric DSM program portfolio is cost-effective,
4 with a net TRC benefit to customers of over $23 million.
5 The UCT benefit-to-cost ratio is cost-effective with a net
6 UCT benefit of over $32 million. The levelized TRC and UCT
7 cost is 4.8 cents and 2.3 cents per kWh, respectively. The
8 overall portfolio of measures has a weighted average
9 measure life of 13 years. The comparable levelized electric
10 avoided cost for a measure of this life is 8.7 cents per
11 kWh.The electric DSM programs were also cost-effective
12 under the Participant Test.
13 Page 3 of Exhibit No. 13 illustrates the natural gas.14
15
DSM program portfolio cost-effectiveness under both the TRC
and UCT tests.But for one customer, the Company's TRC
16 would be 1.16, with any numer above 1.00 being cost
17 effective. This customer, based on their own initiatives,
18 spent $4.2 million on energy efficiency projects of which
19 Avista contributed $247,000.Avista's contribution of
20 $247,000 divided by the 104,000 therms of savings from
21 these projects results in a $2.36 per first year therm
22 utility incentive investment, in comparison to an avoided
23 cost value of approximately $10 for a therm of the measure
24 life associated with those proj ects.Apart from this
25 customer, the TRC and UCT benefit cost ratios are 1.16 and.
467 Folsom, Di 17
Avista Corporation
.i
2
2.64 respectively. Therefore, except for the one customer,
the natural gas DSM portfolio passes both the TRC and UCT
3 tests.
4 Q.Please sumrize the Company's conclusions.
5
6
A.The Company's expenditure of tariff rider revenue
has been reasonable and prudent.A portfolio of programs
7 covering all customer classes has been offered with a total
8 savings of over 62.1 million annual kWhs and 1.7 million
9 therms during January 1, 2008 through November 30, 2008. A
10 13-year levelized utility cost per saved kilowatt hour of
11 2.3 cents per kWh has been achieved. The levelized avoided
12 costs during this similar period has been 8.7 cents per
kWh.The 15 year levelized utility cost per saved therm.13
14
15
has averaged 37.1 cents per thermo
The Tariff Rider and programs have been very
16 successful. Participating customers have benefited through
17 lower bills. Non-participating customers have benefited
18 from the Company having acquired lower cost resources as
19 well as maintaining the energy efficiency message and
20 infrastructure for the benefit of our service territory.
21 In closing, Avista respectfully requests that the
22 Commission issue a finding of prudence for energy
23 efficiency expenditures from January 1,2008 through
24 November 30, 2008.
.
468 Folsom, Di 18
Avista Corporation
.
.
.
1
2
Q. Does
testimony?
3 A.
that
Yes, it does.
complete
469
your pre-filed direct
Folsom, Di 19
Avista Corporation
e
e
e
1 Q.Please state your name and business address for
2 the record.
3 A.My name is Randy Lobb and my business address is
4 472 West Washington Street, Boise, Idaho.
5 Q.By whom are you employed?
6 A.I am employed by the Idaho Public Utilities
7 Commission as Utilities Division Administrator.
8 Q.What is your educational and professional
9 background?4
10 A.I received a Bachelor of Science Degree in
11 Agricultural Engineering from the University of Idaho in
12 1980 and worked for the Idaho Department of Water Resources
13 from June of 1980 to November of 1987. I received my Idaho
14 license as a registered professional Civil Engineer in 1985
15 and began work at the Idaho Public Utilities Commission in
16 December of 1987. My duties at the Commission currently
17 include case management and oversight of all technical
18 Staff assigned to Commission filings. I have conducted
19 analysis of utility rate applications, rate design, tariff
20 analysis and customer petitions. I have testified in
21 numerous proceedings before the Commission including cases
22 dealing with rate structure, cost of service, power supply,.
23 line extensions, regulatory policy and facility
24 acquisitions.
25 Q.What is the purpose of your testimony in this
470CASE NOS. AVU-E-09-1/AVU-G-09-1
OS/29/09
LOBB, R. (Di). 1
STAFF
e
e
e
1
2
case?
A.The purpose of my testimony is to introduce Staff
3 witnesses and the issues they address and describe Staff's
4 approach in evaluating the Company's request. i will also
5 discuss the various policy issues associated with this case
6 including establishing a test year, incorporating the
7 Lancaster Tolling Agreement and making changes to the
8 sharing percentages in the Company's Power Cost Adjustment
9
10
11
12
13
14
(PCA) .,
Q.How is your testimony arranged?
A.My testimony is arranged as follows:
I. Recommendation Summary
II. Introduction of. Staff witnesses
III. Case Evaluation
15 iv. Lancaster
16 v. The PCA
17 Recommenda tion Sumary
18 Q.Could you please summarize Staff's
19 recommendation?
20 A.Yes. Staff recommends an Idaho electric base
21 revenue requirement increase of $8.622 million or 3.91% and
22 a natural gas base revenue requirement increase of $1.894
23 million or 2.06%. Staff recommends an overall rate of
24 return of 8.55% and a return on equity of 10.5%.
25 Staff accepts the Company proposed historic test
471CASE NOS. AVU-E-09-1/AVU-G-09-1
OS/29/09 LOBB, R.(Di) 2
STAFF
e
e
e
1 year of October 31, 2007 through November 1, 2008 but
2 limi ts the proforma period for adj ustments to 14 months
3 through December 31, 2009.
4 The primary rate base and revenue adj ustments
5 proposed by Staff include a reduction in normalized power
6 supply costs of approximately $40.6 million (on a total
7 Company or system basis) from that proposed by the Company
8 and a reduction in the requested return on equity from 11%
9 to 10.5%. Other adjustments include elimination of rate ,
10 base additions and non power expense adjustments after
11 December 31, 2009 including the 2010 salary increase, cost
12 amortization of Montana Riverbed Agreement and removal of
13 costs associated with the Company's relicensing of its
14 Spokane River hydro facilities.
15 Staff proposes a uniform revenue spread to all
16 customer classes on the electric side with an across the
17 board increase in all energy rate components. Staff
18 further recommends that the Commission accept the Company's
19 proposed customer class revenue spread on the gas side as
20 adjusted for Staff's proposed revenue requirement and
21 approve an across the board increase in customer rate
22 components except the monthly customer charge. In an
23 effort to mitigate the impact of higher base rates, Staff
24 recommends that Purchase Gas Adjustment (PGA) and Power
25 Cost Adjustment (PCA) rates be reduced to offset the base
CASE NOS. AVU-E-09-1/AVU-G-09-î72
OS/29/09 LOBB, R. (Di) 3
STAFF
e
e
e
1 rate increases approved for gas and electric service in
2 this case.
3 Finally, Staff recommends that the Commission
4 approve the Company's request to include the cost of the
5 Lancaster Tolling Agreement in the PCA as proposed.
6 However, Staff recommends that the Commission deny the
7 Company's request in this case to change the sharing
8 percentage from 90%/10% to 95%/5% in the PCA mechanism.
9 Introduction of Staff Witnesses I
10 Q.Could you please describe Staff's filing in this
11 case?
12 A.Yes. Senior Staff Engineer Rick Sterling is
13 responsible for review of profroma test year adjustments
14 proposed by Company witness Johnson and review of the
15 Company's Aurora power supply model used to calculate
16 annual net power supply costs. As a result of his review,
17 Mr. Sterling proposes two modifications to the modeled
18 power supply costs addressed by Company witness Kalich.
19 The first adjustment is a reduction in forecasted natural
20 gas prices to reflect more current forward market prices.
21 This adjustment reduces the Company's requested annual net
22 power supply costs by $36.33 million on a system basis.
23 The second adjustment removes short-term fixed
24 and financial hedge transactions made under the Company's
25 risk management plan. The volume and price of these
473CASE NOS. AVU-E-09-1/AVU-G-09-1
OS/29/09 LOBB, R. (Di) 4
STAFF
e
e
e
1 transactions are a function of below normal weather and
2 market conditions and are not appropriate for normalized
3 power supply costs included in base rates. This adjustment
4 reduces Company requested annual net power supply costs by
5 approximately $4.3 million on a system basis.
6 Senior Staff Auditor Joe Leckie develops Staff
7 recommended test year electric rate base with proforma
8 adjustments. Mr. Leckie accepts the Company's calculation
9 of rate base using the 13-month average as adjusted for -
10 Staff's proposed proforma period. Staff recommends Company
11 proposed plant additions through December 31, 2009, to
12 arrive at a recommended Idaho jurisdictional rate base
13 level of approximately $564.144 million.
14 Mr. Leckie also addresses the cost of the Coeur
15 d' Alene Tribe Settlement, the Montana Riverbed Agreement
16 and Spokane River Relicensing. Mr. Leckie recommends that
17 the Commission accept the Company's proposed treatment of
18 costs associated with the Tribal Settlement with adjustment
19 limited to rate base averaging consistent with Staff's
20 proposed test year. He then recommends an adj ustment to
21 remove the costs of Spokane River relicensing because no
22 FERC license has yet been issued and costs are therefore
23 not used and useful. He also recommends that the deferred
24 costs associated with the Montana Riverbed Agreement be
25 amortized over the 8-year agreement without carrying
474CASE NOS. AVU-E-09-1/AVU-G-09-1
OS/29/09 LOBB, R. (Di). 5
STAFF
e
e
e
1 charges. This allows the Company to fully recover its
2 investment but not earn a return on the deferred expenses.
3 Staff Auditor Donn English provides the Staff
4 recommendation for rate base, expenses and revenue
5 requirement for natural gas service in Idaho.- He proposes
6 several adjustments on a total Company basis that reduce
7 revenue requirement for both gas and electric service. His
8 adjustments include elimination of 2010 salary increases
9 and acceptance of actual 2009 salary increases with various ,
10 other adjustments in salary expense. He recommends an
11 adjustment based on reduced regulatory fees, a reduction in
12 Board of Director expenses and adj ustments in a variety of
13 other expense categories. Mr. English also addresses
Employee Pension expense liability. Adjustments on the14
15 electric side are provided to Staff witness Vaughn for
16 derivation of the electric revenue requirement. For Idaho
17 natural gas service, Mr. English recommends a rate base of
18 $90.03 million and an Idaho revenue requirement increase of
19 2.06% or $1.894 million.
20 Staff Auditor Cecily Vaughn begins with actual
21 audited, total Company cost data for the historical 12-
22 month test year base period of October 1, 2007 through
23 September 30, 2008. She then applies the Company proposed
24 jurisdictional allocation methodology and Staff proposed
25 expense and rate base adjustments to develop an Idaho
475CASE NOS. AVU-E-09-1lAVU-G-09-1
OS/29/09 LOBB, R. (Di) 6
STAFF
e
e
e
1 jurisdictional electric revenue requirement through
2 December 31, 2009. The resulting annual base revenue
3 requirement increase proposed by Staff is approximately
4 $8.622 million for an overall increase of 3.91%.
5 Dr. Vaughn's revenue requirement proposal is
6 based on the expense adjustments of Staff witnesses
7 English, the rate base and expense adjustments of Staff
8 witness Leckie, the power supply expense adjustment of
9 senior Staff witness Sterling and the cost of capital 4
10 recommendations of Staff Accounting witness Carlock.
11 Deputy Administrator and Audit Section Supervisor
12 Terri Carlock addresses cost of capital and return on
13 equity. Ms. Carlock recommends a return on equity of
14 10.50% and a capital structure of approximately 50% debt
15 and 50% equity for an overall recommended rate of return of
16 8.55%.
17 Senior Staff Engineer Keith Hessing addresses the
18 electric class cost of service (COS) methodology, class
19 revenue spread and several Company proposed modifications
20 to the power cost adjustment (PCA) mechanism including
21 tracking transmlssion expense, modifying the retail revenue
22 credit and inclusion of the production tax credit (PTC).
23 Based on his review, Mr. Hessing recommends that the
24 Commission accept the Peak Credit Cost of Service
25 methodology proposed by the Company but spreads revenue
476CASE NOS. AVU-E-09-1/AVU-G-09-1
OS/29/09 LOBB, R. (Di) 7
STAFF
e
e
e
1 uniformly ~in this case to all customer classes until
2 current class COS load studies are completed. Using the
3 Staff proposed jurisdictionally allocated Idaho revenue
4 requirement, Mr. Hessing recommends a uniform base rate
5 increase for all electric customer classes of 3.91%. Mr.
6 Hessing recommends that the Commission approve the
7 Company's proposed changes to the PCA to track variations
8 in the Production Tax Credit and third party transmission
9 costs/revenues included in base rates. Mr. Hessing further ,
10 recommends that the Commission approve the Company's
11 proposal to establish the retail revenue adjustment in the
12 PCA using the Commission approved average cost of
13 production and transmission subsequently established in
14 this case. Finally, Mr. Hessing evaluates the expected
15 level of PCA deferral balances over the next 18 months and
16 recommends a PCA rate reduction of 0.361 cents per kWh that
17 will offset the impact of the Staff's proposed base rate
18 increase without unduly increasing the risk of higher PCA
19 deferral balances in the future.
20 Staff Economist Matt Elam recommends that the
21 Commission accept the Company's gas cost of service based
22 revenue spread to the various customer classes. Using the
23 Staff proposed revenue requirement, the increases range
24 from a 2.0% increase for Schedule 131 to a 3.0% increase
25 for Schedule 111. Schedule 101, which is mostly
477
CASE NOS. AVU-E-09-1/AVU-G-09-1
OS/29/09
LOBB, R. (Di) 8
STAFF
e
e
e
1 residential, will receive an increase of 2.9%. Mr. Elam
2 further recommends that only the commodity charge be
3 increased in each class to recover the proposed base
4 revenue increase. Finally, Mr. Elam recommends that the
5 PGA rate per therm be decreased by 0.02599 cents to offset
6 impact of the base rate increase and reflect the lower
7 forecasted cost of natural gas.
8 Staff Economist Bryan Lanspery recommends that
9 the revenue assigned to the various electric customer ,
10 classes as proposed by Staff witness Hessing be recovered
11 solely from the energy component. In addition Mr. Lanspery
12 utilizes the PCA rate reduction provided by Mr. Hessing to
13 offset the base energy rate increase for a net change in
14 rates ranging from an increase of 1.2% for General Service
15 Schedule 11 to a decrease of 2.01% for Potlatch (now known
16 as Clearwater Paper) Schedule 25. Residential customers
17 will see a net change of 0.61% under Mr. Lanspery's
18 recommendation.
19 Staff Economist Lynn Anderson addresses the
20 prudency of demand side management (DSM) expenditures made
21 by Avista from January 2008 through November 2008. Mr.
22 Anderson recommends that the Commission defer consideration
23 of the Company's DSM program expenditures until sufficient
24 information is provided to evaluate prudency. Mr. Anderson
25 points to a lack of post implementation program evaluation
478CAE NOS. AVU-E-09-1/AVU-G-09-1
OS/29/09 LOBB, R. (Di) 9
STAFF
e
e
e
1 and plans of the Company to improve its evaluation programs
2 as justification for deferring a finding of prudency in
3 this case.
4 Finally, Consumer Investigators Marilyn Parker
5 and Curtis Thaden address a broad range of consumer issues.
6 Ms. Parker discusses the number and tenor of customer
7 comments received by the commission in this case. She also
8 addresses the monthly residential customer charge, and
9 opposes any increase. She concludes by addressing reduced ,
10 telephone service level standards, increasing customer
11 complaints and the various improvements that the Company
12 has made in service quality technology.
13
14
Mr. Thaden provides information on customer
demographics, low income financial assistance programs,
15 payment programs and low income energy efficiency programs.
16 Case Evaluation
17
18
Q.What has been your role in this case?
A.My role as Staff Administrator has been to
19 oversee the preparation of the Staff case with respect to
20 identification of issues, coordination of positions on
21 those issues and development of Staff policy.
22 Q.What are the important policy issues in this
23 case?
24 A. In my opinion, the most important policy issues
25 include: establishing the rate case test year ¡identifying
479CASE NOS. AVU-E-09-1/AVU-G-09-1
OS/29/09 LOBB, R. (Di) 10
STAFF
e
e
e
1 revenue requirement adjustments; assigning cost of service
2 responsibility, and applying appropriate rate designs
3 including mitigation using the PGA and PCA. Additionally,
4 modification of PCA sharing percentages is an important
5 policy issue in this case.
6 Q.Please describe Staff's approach in evaluating
7 the Company's rate increase request.
8 A.Staff's approach in evaluating the Company's rate
9 request in this case was consistent with methods used many .
10 times in general rate cases over the last few years. Staff
11 audited the actual costs booked in the test year, evaluated
12 the Company's proposed proforma adjustments to historic
13 costs and identified costs that were believed to be
14 inappropriate. Because Avista is an electric and natural
15 gas company operating in several state jurisdictions,
16 actual costs and proforma adjustments were evaluated on a
17 total Company basis. Any cost adjustments in the Company's
18 case identified by Staff were then allocated to gas and/or
19 electric service on an Idaho jurisdictional basis.
20 Q.Did Staff focus on any specific issues in its
21 review?
22 A.Yes. As in all cases, Staff focused on cost of
23 capi tal and the level of test year operation and
24 maintenance expense including employee compensation. Staff
25 also focused on the big ticket expense changes and capital
480
CASE NOS . AVU-E-09-1/AVU-G-09-1
OS/29/09 LOBB, R. (Di) 11
STAFF
e,
e
e
1 addi tions since the last rate case. Finally, Staff focused
2 on the "known and measurable" and "used and useful"
3 proforma adj ustments to historic test year costs and the
4 period beyond the historic test year that adjustments
5 should be allowed.
6 Q.What proforma period does the Staff recommend be
7 allowed to adjust actual test year results of operations?
8 A.The Company uses an actual historic test period
9 of October 1, 2007 through September 30, 2008. Staff I
10 recommends that known and measureable proforma adjustments
11 be allowed through December 31, 2009. Staff believes that
12 the 15-month proforma period beyond the end of the 12-month
13 test year assures that expenses and plant additions are
14 both known and measurable and used and useful. The
15 exception is in the calculation of net power supply costs
16 because these costs are already normalized using a
17 forecasting model. Staff does not oppose allowing a
18 forecast of power supply costs through June 30, 2010 and
19 inclusion of any production plant used in the calculation.
20 Q.How does this compare to the most recent Order
21 issued by the Commission regarding historic test year and
22 proforma period?
23 A.The most recent Commission decision on
24 appropriate test year came in Order No. 30722 in Case No.
25 IPC-E-08-10. In that Order the Commission approved
481CASE NOS. AVU-E-09-1/AVU-G-09-1
OS/29/09 LOBB1 R. (Di) 12
STAFF
peL XL erroreSubsys em: KERNEL
, moñification of Idaho Power's historic 12-month test periodErtor: niegalTag
O~ra r: wi~blimited adjustment into the future for anticipatedn: 79á 1 dd" dcapi ta a i tions an expense changes.The proformaPosit.
3
adjustment' period was limited to 12 months beyond the end
of the historic test period. The Commission did allow a
forecast of normalized power supply costs beyond the 12
month proforma period. Staff believes its recommended test
year and proforma period is consistent with the
Commission's Order in the Idaho Power case..
Q. Is Staff's recommendation to reduce the Company's
electric revenue increase request from $31.23 million to
$8.622 million and gas revenue requirement increase from
$2.74 million to $1.894 million in response to the weakened
economy and the level of opposition expressed by the
Company's customers?
A. Not necessarily. The impact of Company rate
increases on customers is always a concern of the
Commission Staff . In a weakened economy as described by
Staff witness Thaden, I believe customers expect Staff to
more aggressively evaluate the Company's request. However,
Staff believes it is always thorough in its audit review,
and this case is no exception. Staff believes its
recommendation to use PGA and PCA rate reductions to
mitigate base rate increases is a reasonable response to
current economic conditions.
482CASE NOS. AVU-E-09-1/AVU-G-09-1
OS/29/09 LOBE, R. (Di) 13
STAFF
e
e
e
1 Staff also believes it has continued to recommend
2 adjustments in those areas that are fair to the Company but
3 pass through only those costs that are necessary at this
4 time. For example, the lion share of the revenue
5 requirement adjustments come from three areas: 1) limiting
6 the test year proforma period; 2) granting a reasonable
7 return on equity to shareholders, and 3) reducing the
8 requested electric power supply costs to reflect more
9 accurate prices available in the market place. The .,
10 justification for adjustments in these areas is fully
11 described in the testimony of the appropriate Staff
12 wi tnesses .
13 Q. Shouldn' t even greater reductions in revenue
14 requirement have been proposed by Staff given the current
15 economic conditions?
16 A.Staff does not believe it is fair or reasonable
17 to the Company or its customers to propose a reduced
18 revenue requirement beyond that recommended by Staff in
19 this case. Based on its review of Company O&M expenditures
20 and capital additions, Staff concludes that its recommended
21 revenue requirement is appropriate and necessary to provide
22 adequate service.
23 Staff. believes that a further reduction in O&M
24 expenses could reduce service quality and reliability
25 beyond the point acceptable to most Avista customers.
483CASE NOS. AVU-E-09-1/AVU-G-09-1
OS/29/09 LOBB, R. (Di) 14
STAFF
e
e
e
1 Additionally, Staff believes that disallowing capital
2 investment for plant replacement actually completed could
3 impact Avista's earnings, financial ratings and ability to
4 borrow money at reasonable interest rates. Finally,
5 failure to allow the Company to include costs of
6 replacing/protecting aging or existing infrastructure could
7 reduce such investment in the future, again diminishing
8 reliability and service quality. Staff does not believe it
9 is appropriate at this time to sacrifice service quality to I
10 assure marginally lower rates.
11 Q.Company witness Andrews states in her testimony
12 (page 9, lines 9-21) that costs associated with the
13 Coeur d' Alene Tribal Settlement and Spokane River
14 Relicensing were reviewed and approved for recovery in Case
15 No. AVU-E-08-01. Do you agree?
16 A.No. In the last case, the agreement between the
17 Coeur d' Alene Tribes and the Company had not been completed
18 and its costs were not finally known and measurable. Staff
19 agreed as part of the Settlement and the Commission
20 approved to defer all costs with a carrying charge until
21 the next rate case. Staff did not complete its review of
22 these issues in Case No. AVU-E-08-01 because final costs
23 were not known. The same is true for the Spokane River
24 relicensing¡ these costs were not known and measurable
25 because FERC had yet to approve the new license. Likewise,
484CASE NOS. AVU-E-09-1/AVU-G-09-1
OS/29/09
LOBB, R. (Di) 15
STAFF
e
e
e
1 these costs could not and were not approved in that case
2 for automatic recovery in this case.
3 Q.'Were there indications in the last rate case that
4 costs associated with these two issues were incomplete?
5 A.Yes. Company witness Norwood states, on page 8
6 of his testimony filed in Support of the Settlement in Case
7 No. AVU-E-08-01, that a final license for Spokane River has
8 yet to occur. On page 9 he states that confidential
9 litigation (the Coeur d' Alene Tribe Settlement) is still ,
10 pending and has yet to be finally resolved. Moreover, the
11 Stipulation at page 5 states that issuance of the FERC
12 license "has yet to occur." And on page 6, the parties
13
14
acknowledge that settlement of the Coeur d' Alene Tribal
litigation "is still pending and has yet to be finally
15 resol ved..."
16 Q.Is the Staff prohibited from making cost recovery
17 adjustments on these issues in this case?
18 A.No, not in my opinion. Neither Staff nor the
19 Commission in the last case evaluated the prudency of the
20 Coeur d' Alene Tribal Agreement or the Spokane River
21 Relicense. The Commission simply approved the Settlement
22 deferring the costs for accounting purposes. The
23 Settlement in no way authorized automatic, undisputed cost
24 recovery in this case based on the proposal of the Company
25 in Case No. AVU-E-08-01.
485CASE NOS. AVU-E-09-1/AVU-G-09-1
OS/29/09 LOBB, R. (Di) 16
STAFF
e
e
e
1 Q.Why does the Staff recommend a reduction in the
2 PGA and PÇA rates to mitigate proposed base rate increases?
3 A.Staff believes that the PGA rate reduction is
4 justified because the current weighted average cost of gas
5 (WACOG) embedded in rates is much higher than the forward
6 cost of gas in the market place. Even with the reduction,
7 the WACOG will likely decrease again this year as part of
8 the Company's annual PGA filing.
9 Staff's proposed PCA rate reduction is reasonable .
10 but relies on future water conditions that are unknown and
11 might impact future PCA deferral balances. Staff witness
12 Hessing provides more information on future PCA deferral
13 balances with the proposed PCA rate reduction in this case.
14 Nevertheless, Staff believes that the risk of higher PCA
15 rates in the future is justified to moderated rate
16 increases for customers today.
1 7 Lancaster
18 Q.What is your understanding of the Lancaster
19 Tolling Agreement?
20 A.The Lancaster power plant is a 275 Mw gas fired,
21 Combined Cycle Combustion Turbine (CCCT) located in
22 Rathdrum, Idaho. The Lancaster Tolling Agreement between
23 Avista Utilities and Rathdrum Energy LLC came about as part
24 of Avista Corporations sale to Coral Energy of Avista ,
25 Energy (an Avista Utilities affiliate). Avista Energy
LOBB, R. (Di) 17
STAFF
e
e
e
13
14
1 owned the output, under long term agreement (through 2027)
2 of the Rathdrum plant that came online in 2001. Avista
3 Utilities simply assumed the Avista Energy tolling
4 agreement originally signed with Rathdrum Energy LLC in
5 1998.
6 Beginning on January 1, 2010, Avista Utilities
7 has agreed to purchase all of the plant output through
8 2027. The generating plant will be owned and operated by
9 Rathdrum Energy LLC but dispatched as specified by Avista .
10 Utilities. In return for the right to dispatch and utilize
11 plant output, Avista will pay a capacity charge, a fixed
12 O&M charge, a variable O&M charge and will purchase and
deliver all natural gas to fuel the plant. Avista will
15 transmission rights to Avista' s system over BPA lines.
also incur fixed costs for gas pipeline capacity and
16 Capacity and O&M charges will escalate at specified fixed
17 and variable rates over the remaining life of the contract.
18
19
Q.Is the Lancaster Tolling Agreement reasonable?
A.Yes, based on my review of the information
20 available at the time Avista utilities signed the Agreement
21 (April 2007), I believe purchase of the output from the
22 Lancaster CCCT was reasonable.
23
24
Q.How did you come to that conclusion?
A.I came to that conclusion by reviewing Avista' s
25 2007 Integrated Resource Plan (IRP) and comparing the cost
487CASE NOS. AVU-E-09-1/AVU-G-09-1
OS/29/09 LOBB, R. (Oi) 18
STAFF
e
e
-
1 of the La~caster Agreement to the cost of generation
2 alternatives available to meet anticipated loads. At first
3 glance, the tolling agreement looks somewhat self serving
4 when viewed as part of the sale of Avista Energy.
5 For example, although the preferred portfolio
6 identified in Avista's 2007 IRP called for up to 350 Mw of
7 new combined cycle generating capacity by 2012, the Company
8 did not issue a request for proposals (RFP) or obtain any
9 competitive bids to acquire a CCCT resource. In addition,4
10 assumption of the tolling Agreement by Avista Utilities
11 seemed to be a concession by Avista Corporation in order to
12 sell its affiliate, Avista Energy. Finally, Avista
13 Utilities did not hire an independent third party
14 consultant to evaluate the economic benefit of acquiring
15 the Lancaster output until after the transaction had
16 already occurred.
17 Regardless of appearance, the real question is
18 whether the transaction meets the reasonably anticipated
19 needs of customers at reasonable price. While the tolling
20 agreement was associated with an affiliate transaction and
21 outside the usual RFP competitive bidding process, Avista
22 had a demonstrated need and the Company's internal
23 evaluation and that of an independent third party
24 consul tant provided extensive economic analysis of the
25 transaction as compared to other alternatives.
488CASE NOS. AVU-E-09-1/AVU-G-09-1
OS/29/09 LOBB, R. (Di) 19
STAFF
e
e
e
1 As part of its evaluation, Staff reviewed the
2 underlying tolling agreement, the internal net present
3 value (NPV) comparison of alternatives performed by Avista,
4 the discounted cash flow (DCF) comparative analysis of
5 alternatives performed by Thorndike Landing LLC, the
6 Northwest Power and Conservation Council forecasts of CCCT
7 development costs and past and present CCCT surrogate cost
8 estimates used to set Idaho published avoided cost rates.
9 In each case, the price paid for Lancaster over ,
10 the life of the Agreement was lower than available CCCT
11 alternatives. Moreover, when the price is compared to
12 other more recent combined cycle resource acquisitions in
13
14
15
the region, the purchase agreement appears even more
valuable and beneficial to ratepayers.
Q.Oid Avista show a need in 2007 for a resource of
16 this size by 2010?
17 A.Pages 2-19 and 2-20 of Avista's 2007 IRP, shows
18 projected capacity and energy short falls beginning in
19 2011. These pages also show the effect of Lancaster output
20 on the Company's net positions through 2027.
21 What does the tolling agreement cost Avista andQ.
22 its customers and how does that compare to other CCCT
23 alternatives?
24 A.The net present value and OCF analysis performed
25 by Avista and Thorndike, respectively, compared the
CASE NOS. AVU-E-09-1/AVU-G-09-l89
OS/29/09 LOBB, R. (Oi) 20
STAFF
e
e
e
1 Lancaster tolling agreement to other theoretical tolling
2 agreement~ based on capital construction costs of existing
3 regional CCCT resources. The analysis also compared the
4 agreement to expected costs to construct a new CCCT in the
5 region.
6 The analyses show that the tolling agreement is
7 essentially equivalent to a Company owned Greenfield plant
8 with a capital cost of about $530/kW. Further analysis
9 shows that the value of the tolling agreement is equivalent -
10 to paying up to $677 /kW. The cost of the Tolling Agreement
11 compares favorably to all estimates of new construction
12 costs that likely would be incurred for a similar sized
13 plant. For example, Avista's 2007 IRP shows new CCCT
14 capital costs of $786/kW, PacifiCorp's 2007 IRP shows new
15 cost ranging from $758 to $870/kW ànd Idaho Power's 2006
16 IRP estimates CCCT capital costs at $732/kW.
1 7 More recent examples of comparable CCCT
18 transactions include the purchase by PacifiCorp of the
19 existing 500 Mw Chehalis CCCT at a cost of approximately
20 $610/kW. Recent RFPs issued by PacifiCorp and Idaho Power
21 returned CCCT capital costs in the range of $1000 to
22 $1300/kW. Current surrogate CCCT costs (which are based on
23 current costs as reported by the Northwest Power and
24 Conservation Council) used to establish the Idaho published
25 avoided cost rate is $1100/kW.
490CASE NOS. AVU-E-09-1/AVU-G-09-1
OS/29/09 LOBB, R. (Di) 21
STAFF
e
e
e
1 According to the Company, 2010 fixed costs are
2 expected to be $20.87 per Mwh at a 69% capacity factor. At
3 gas prices ranging from $5 to $7/MMbtu, a heat rate of
4 about 7000 kWh/MMtu and variable O&M charges, 2010
5 generation cost could range from $58 to $72/Mwh.
6 Q.Has the Company included Lancaster Tolling costs
7 in base rates?
8 A.No. Avista has requested that costs associates
9 wi th the tolling agreement be passed through the PCA when .
10 the Company begins purchasing the output on January 1,
11 2010. Staff witness Hessing will address treatment of
12 these costs through the PCA.
13 The PCA
14 Q.Has the Company proposed any changes to the PCA?
15 A.Yes, Company witness Johnson has proposed four
16 changes to the PCA in this case. The first three changes
17 dealing with tracking variations in third party
18 transmission expense/revenues, tracking variations in PTC
19 and the method of calculating the retail revenue credit
20 will be address in the testimony of Staff witness Hessing.
21 I will address the Company's proposal to change
22 PCA sharing from the current 90%/10% split to a 95%/5%
23 split.
24 Q.What justification does the Company provide to
25 support such a change in the sharing percentage?
491CAE NOS. AVU-E-09-1/AVU-G-09-1
OS/29/09 LOBB, R. (Di) 22
STAFF
e
-
e
1 A.Company witness Johnson was the only Company
2 witness to address this issue. His one page justification
3 was a description of how energy prices went from $88/Mwh in
4 April of 2008 to $25/Mwh in June and how volatility in gas
5 prices wiii become more significant for Avista with the
6 addi tion of the Lancaster plant.
7 Q.Is the justification provided by the Company in
8 this case sufficient to warrant:å change in the PCA sharing
9 percentage?4
10 A.No, not in my view. While the Company has
11 pointed to the volatility in gaš ànd electric prices in
12 2008, it has not provided any införmat~on on how PCA
13 sharing percentages have affected the Company over the life
14 of the deferral mechanism. There is no demonstration of
15 negative financial impact or how that might change if
16 sharing percentages are modified. Idaho currently
17 represents only about 36 percent of Avista' selectric
18 service with 64 percent of its services provided in
19 Washington. Any financial benefit to the Company or its
20 customers from changes in the Idaho PCA could be completely
21 offset by actions in its Washington jurisdiction. Finally,
22 the Company has not provided any rationale or supporting
23 justification showing why current PCA sharing unduly
24 penalizes the Company or why reducing its share of
25 extraordinary power supply costs is appropriate at this
CASE NOS. AVU-E-09-1/AVU-G-09-~92
OS/29/09 LOBB, R. (Di) 23
STAFF
e
e
-
1 time.
3 proceeding?
Does this conclude your direct testimony in this
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
2 Q.
A.Yes, it does.
~
493CASE NOS. AVU-E-09-1/AVU-G-09-1
OS/29/09 LOBB, R. (Di) 24
STAFF
e
-
e
1 Q.Please state your name and business address for the
3
2 record.
A.'My name is Lynn Anderson and my business address is
4 472 West Washington Street, Boise, Idaho.
5
6
Q.By whom are you employed and in what capaci ty?
A.I am employed by the Idaho Public Utilities
7 Commission as a Staff economist.
8
9
Q.What are your duties with the Commission?
A.Currently, my primary duties are evaluating energy
10 efficiency policy, opportunities, barriers, efforts and cost-
11 effectiveness, the results of which are used to make
12 recommendations to the Commission and other entities.
13
14
15
Additional duties include investigating utility applications,
customer petitions and conducting general research.
Q.Would you please outline your academic and
16 professional background?
17 A.I have a Bachelor of Science degree in government
18 and a Bachelor of Arts degree ìnsociology, both from Idaho
19 State University where I also studied economics and
20 architecture. I studied engineering at graduate and
21 undergraduate levels at Northwestern University and Brigham
22 Young University, respectively, and graduate-level public
23 administration and quantitative analysis at Boise State
24 University.
25 I have attended many training seminars and
494
CASE NOS. AVU-E-09-01/AVU-G-09-015/29/09 ANERSON, L. (Di) 1
STAFF
e
e
e
1 conferences regarding utility regulation, operations,
2 forecasting, marketing and program evaluation, including
3 Lawrence Berkeley Laboratory's Advanced Integrated Resource
4 Planning seminar in 1994, the Northwest Public Power
5 Association's Troubleshooting Residential Energy Use course
6 in 2001, and the International Energy Program Evaluation
7 conferences in 2003, 2005 and 2007.
8 I began my employment with the Commission in 1980
9 as a utility rate analyst. In 1983 I was appointed to the
10 telecommunications section supervisor position and in 1992 I
11 was appointed to my present position as an economist. In
12 that capacity I have been a Staff representative to the
13 Northwest Energy Efficiency Alliance's Board and Cost-
14 Effectiveness Committee, Avista Utilities' External Energy
15 Efficiency Board, Idaho Power's Energy Efficiency Advisory
16 Group, the Northwest Power and Conservation Council's Demand
17 Response Initiative, the Energy Efficiency and Conservation
18 Task Force of the Idaho Strategic Energy Alliance, and work
19 groups under the National Action Plan for Energy Efficiency,
20 including Evaluation, Measurement and Verification (EM&V).
21 Since 1999 I have served the Commission as a. policy
22 strategist for electricity and telecommunications issues on
23 an as-needed basis.
24 From 1975 to 1980 I was employed by the Idaho
25 Transportation Department where I performed benefit/cost
p n h.~~J
CASE NOS. AVU-E-09-01/AVU-G-09-015/29/09 ANERSON, L. (Di) 2
STAFF
e 1
2
3
4
5
6
7
8
9
10
11
12
e 13
14
15
16
17
18
19
20
21
22
23
24
25
e
analyses of highway safety improvements and other statistical
analyses.
Q. What is the purpose of your testimony?
A. .The purpose of my testimony is to provide
information regarding Avista Utili ties' efforts to promote
energy efficiency (aka demand-side management or DSM) and to
recommend that the Commission defer a prudency finding for
Avista Utilities' 2008 DSM expenses until such time that the
Company is able to provide more comprehensive evaluations of
its DSM programs and efforts.
Prudency of Efficiency/DSM Expenses
Q. Does Avista's Application or the pre-filed
testimony of any witness in this case ask the Commission to
determine the prudency of the Company's past energy
efficiency or demand-side management (DSM) expenses?
A. Yes, both the Application and Company witness Bruce
Folsom request a prudency finding for Avista' S DSM programs
from January through November of 2008. However, Mr. Folsom's
testimony and exhibit in support of the request provide DSM
information that is combined for both its Washington and
Idaho service areas. Only through discovery requests was
Staff able to obtain Idaho-specific DSM program costs and
estimated savings for this 11-month period. For example,
Avista's total DSM costs for the first 11 months of 2008 are
purportedly shown on page 1 of Mr. Folsom's Exhibit No. 13 as
496
CASE NOS. AVU-E-09-01/AVU-G-09-015/29/09 ANERSON, L. (Di) 3
STAFF
Utility Cost Test (UCT) costs of $12.1 million for
electricity programs and $5.9 million for natural gas
programs. Avista's response to Staff Production Request No.
B indicatèd that Idaho's share of the above costs were $3.7
million for electricity programs and $2.4 million for natural
gas programs.
Q. Beyond providing aggregated DSM data for multiple
states, do you question parts of Mr. Folsom's testimony?
A. Yes, I do. On page 9 of Mr. Folsom's pre-filed
testimony is a discussion of Avista' s cost per kilowatt-hour
of savings obtained through its participation in the
Northwest Energy Efficiency Alliance (NEEA). Mr. Folsom
states "In 2007, the last year for which data is available,
NEEA acquired 2.0 aMW applicable, to Avista' s service area at
a cost of 0.07 cents/kWh" and that Avista' s "... avoided cost
for a comparable time period is 0.4 cents/kWh." 1 I believe
these costs should have read "0.7 cents/kWh" savings and "4.0
cents/kWh" avoided costs. In addition to the misplaced
decimals, it should be noted that NEEA, for the most part,
has not tracked savings by utility service area. Instead,
NEEA has allocated its total regional savings proportionally
to individual utili ties based only on utility funding
percentages. Thus, there is little or no data to support the
declarations of 2.0 aMW of NEEA direct savings in 2007 in
1 The hypothetically allocated 2.0 aMW in 2007 actually represents
cumulative savings from prior years through 2007.
tj 97
CASE NOS. AVU-E-09-01/AVU-G-09-015/29/09 ANERSON, L. (Di) 4
STAFF
Avista'.s s'ervice area or the cost-effectiveness of whatever
actual sav.ings there were in Avista's service area in 2007 or
any other year. This does not mean' that NEEA has not been a
valuable resource for Avista' s customers, but only that a
verifiabl~ measure of that value is not available. It is
noteworthy that NEEA's recently adopted 2010-2014 Business
Plan states that NEEA will report future savings at the
service terri tory level.
Q. Were you able to evaluate prudency of Avista
Utilities' DSM expenditures based on the Company's filing?
A. No, there was not sufficient information in the
filing to fully assess DSM prudency. Consequently, many
production requests and follow-up questions needed to be
asked and although the Company provided much information
about its DSM program planning and implementation, it did not
provide sufficient post-implementation evaluations of its DSM
programs to fully justify a prudency determination by the
Commission. For example, in Avista's response to Staff
Production Request NO.5, which asked for comparisons of pre-
implementation estimated evaluation budgets to actual
evaluation costs, the Company did not provide such data and,
instead, provided an explanation of why Avista has not
tracked evaluation costs in the past, e. g. the less-than-
formal nature of its in-house evaluations and its reliance
upon indirect evaluations performed by outside entities such
498
CASE NOS. A VU - E - 09- 01/ A VU - G - 09- 015/29/09 ANERSON, L. (Di) 5
STAFF
as "... the Northwest Power and Conservation Council's
Regional Technical Forum, Energy Star, Consortium for Energy
Efficiency, Electric Power Research Institute, and others."
,Importantly, this response also states that "Avista
is presently in the process of changing our EEM (energy
efficiency measure) verification system to allow for better
documentation of EEM's and scheduled revisiting to adjust for
changes in savings as well as measure costs."
Additional evidence of Avista's lack of sufficient
program evaluation was obtained in its response to Staff
Production Request No.6, in which the Company was asked to
list and provide copies of all program evaluations from 2004
through 2009 - the Company provided only four such "studies,"
all but one of which consisted of just one or two pages of
data with little or no verbal analyses. Avista's response
further elaborated that while it had other examples of such
"studies," ".. .it would take a great deal of time and effort
to go through all of our proj ects from the last 5 years and
pull them out. For this reason, Avista planned the new
approach to EEM verification which we have already started to
implement. "
The Company's response to Staff Production Request
No. 6 ended with the following statement: "In order to
control costs, the least data necessary and the combined
understanding of the analysts, program managers, and
499
CASE NOS. AVU-E-09-0i/AVU-G-09-0i5/29/09 ANERSON, L. (Di) 6
STAFF
e
e
e
1 engineers is gathered to mi tigaté the risk of inaccurate data
2 and improper reporting of energy savings."
3 In consideration of the Avista' s responses to
4 production requests, it became clear that formal and
5 transparent post-implementation evaluation of DSM programs
6 has not been a high priority of the Company.
7 How important are post-implementation evaluationsQ.
8 of DSM programs?
9 A.Such evaluations are essential to both verify cost-
10 effectiveness of programs and to further improve them, or to
11 provide evidence that they should be discontinued. It is a
12 common and accepted best-practice that DSM programs require
13 transparent, post-implementation evaluations.
14 Because Avista's evaluation of its service area-
15 specific DSM programs has been largely an informal process,
16 most evaluation results apparently exist only in the memories
17 of a few employees and their computers. Thus, Avista's DSM
18 implementers and managers are hampered to the extent the
19 informal evaluation results are not readily available to
20 them; the Commission is hampered in its prudency
21 determination; and Avista' s customers are hampered in their
22 understanding of the DSM programs and acceptance of the
23 charges on their bills to support those programs.
24 Q.Is Avista' s concern about controlling evaluation
25 costs a valid reason to skimp on DSM program evaluations?
500
CASE NOS. AVU-E-09-01/AVU-G-09-óì
5/29/09 ANERSON, L. (Di) 7
STAFF
A. While cost-consciousness is important, formal,
credible and transparent evalu~tions remain essential to
prudent DSM program management. By "formal" I do not mean to
suggest that all evaluations need to be lengthy, costly
reports completed by outside consulting firms, although it is
sometimes useful and efficient to hire such consultants for
their specific expertise and to gain additional perspective.
Q. Was the Company aware of its responsibility to
thoroughly evaluate its DSM programs?
A. Clearly, Avista should have been aware of the
Staff's and the Commission's concerns about proper program
evaluation based upon the Staff's comments and the Commission
Order issued in Case No. AVE-E-99-04. In that case, Avista
sought much greater flexibility in planning and implementing
its DSM programs. The Staff recommended approval of the
request and the Commission granted the requested increased
flexibility. But the Staff câutioned in its filed comments
that "... the importance of program evaluation will
significantly increase with the increased flexibility
provided under the new tariffs." (p.- 4). And the Commission
Findings in Order No. 28138 included the following caution:
"We share Staff's concerns regarding the sweeping nature of
the proposed changes as they might affect the Company's
abili ty to determine energy savings' and appropriate funding
levels. We are encouraged by the Company's proposal to
50:1
CASE NOS. AVU-E-09-01/AVU-G-09-(Ù5/29/09 ANERSON, L. (Di) 8
STAFF
e
e
e
i closely monitor its DSM programs. The Company remains
2 responsible for demonstrating that its Schedule 90 DSM
3 programs àre a cost effective use of its Schedule 91 DSM
4 surcharge revenues." Order No. 28138 at 4 (emphasis added) .
5 Q.,Is there additional evidence of Avista's general
6 awareness of the necessity of transparent program
7 evaluations?
8 Yes. In response to Staff Production RequestA.
9 No.5, Avista stated, "The Engìheering group uses the IPMVP
10 (International Performance Measurement and Verification
11 Protocol) guidelines for their EÈM verification work."
12 Beginning on page 6 of the IPMVP is a good, multi-part
13 explanation for why formal, transparent measurement and
14 verification of energy efficiency measures and programs is
15 important, including the need for increasing energy savìngs,
16 reducing program costs, improving program management, and
17 increasing public understanding and acceptance of the costs.
18 Based on the Company's responses to production
19 requests, Avista employees do evaluate at least some DSM
20 projects and other employees dilìgently track the actual
21 program by program costs and assumed savìngsi but very few
22 evaluations are avaìlable for inspection by the Staff, let
23 alone by the public. In fact, the four proj ect "evaluations"
24 provided to Staff were labeled as '"confidential" .
25 Q.Has Staff recommended a prudency finding for
50Z
CASE NOS. AVU-E-09-01/AVU-G-09-015/29/09 ANERSON, L. (Di) 9
STAFF
e
e
e
1 Avista's DSM programs since Order No. 28138 was issued in
2 1999?
3 Yes, in Case Nos. AVU-E-04-01/AVU-G-04-01, I statedA.
4 a belief that Avista reasonably and prudently managed its DSM
5 resources from 1999 through October 2003. And in its last
6 rate case (AVU-E-08-01/AVU-G-08-01), the Company, Staff and
7 Parties negotiated Stipulation Paragraph No. 11 that said
8 ~The Parties agree that Avista's expenditures for electric
9 and natural gas energy efficiency programs from November 1,
10 2003 through December 31, 2007 ~ have been prudently
11 incurred." In the former case the Commission found that
12 Avista's DSM efforts were prudent and in the latter case it
13 accepted the negotiated Settlement Stipulation.
Q. In either the 2004 or l.he 2008 cases cited above,14
15 did the Company provide post-implementation DSM program
16 evaluations?
17 No, the Company did not volunteer such evaluationsA.
18 and the Staff did not specifically request them. However,
19 the fact that Staff did not request copies of evaluations in
20 the past shoula not have suggested to Avista that it was no
21 longer expected to evaluate its DSM programs, given that good
22 program management requires such evaluations and that Staff
23 and the Commission clearly stated in 1999 that evaluations
24 would become even more important as a result of the Company's
25 increased flexibility to plan and manage its DSM programs.
503
CASE NOS. AVU-E-09-01/AVU-G-09-015/29/09 ANERSON, L. (Di) 10
STAFF
e
e
e
1 Q.Do you have other concerns about the prudency of
2 Avista' s DSM efforts?
3 A.In general, I believe that Avista' s employees try
4 to perform: their DSM planning and implementation duties in a
5 conscientious and cost-effective manner, notwithstanding the
6 Company's need for, and already planned, evaluation process
7 improvements. However, there are a few issues that cause at
8 least some concern. These are: 1) a probable over-statement
9 of savings due to lack of net-to-gross energy savings
10 adjustments; 2) probable over-emphasis of portfolio-level
11 cost-effectiveness; and 3) probable over-emphasis of total
12 resource cost test (TRC) cost-effectiveness.
13 Q.Please explain net-to-gross adjustments of energy
14 savings.
15 A.Various DSM standard practice manuais2 state that
16 gross energy savings observed subsequent to implementation of
17 a DSM program should be adjusted to reflect both estimated
18 savings that would have occurred absent the program and
19 savings that occur due to the program but that fall outside
20 the program's measurement metrics. To the extent that the
21
22
23
24
25
former outweighs the latter, as it does for many programs,
analysts who ignore net-to-gross adjustments overstate the
cost-effectiveness of DSM programs.
2 National Action Plan for Energy Efficiency's Model Energy Efficiency
Program Impact Evaluation Guide, the California Standard Practice Manual:
Economic Analysis of Demand-Side Programs and Projects, and the Electric
Power Research Institute's End-Use Technical Assessment Guide (TAG).
504
CASE NOS. AVU-E-09-01/AVU-G-09-01
5/29/09 ANDERSON, L. (Di) 11
STAFF
e
e
-
1 Q.Please explain your concerns regarding possible
2 over-emphasis of "portfolio-level" and "TRC" cost-
3 effectiveness.
4 Avista's policy and tariff says that TRC (totalA.
5 resource èost) cost-effectiveness will be determined for its
6 overall portfolio of DSM programs. Company DSM managers have
7 said that it is not necessary for each measure or program to
8 be cost-effective. But, Commission Order No. 22299 issued in
9 1989 says that utilities' DSM costs should be no higher than
10 necessary and absolutely no higher than the avoided cost.
11 The Order expected that some resources would be priced at
12 full avoided cost, some at "no losers" cost, and some below
13 "no losers" cost." Clearly, the Commission did not intend
14 for utilities to evaluate cost-effectiveness for entire
15 portfolios without consideration of each measure's cost-
16 effectiveness.
17 Conceivably, there are some non-cost-effective
18 measures for which it may be prudent for utilities to provide
19 incentives if such measures can be shown to help sell cost-
20 effective measures to customers. But the burden of proof is
21 on the utility to show how the utility's overall cost-
22 effectiveness is increased, rather than decreased, by
23 inclusion of non-cost-effective measures in its portfolio.
24 Failure to do so would be an indication of imprudent DSM
25 management.
5D5
CASE NOS. AVU-E-09-01/AVU-G-09-015/29/09 ANERSON, L. (Di) 12
STAFF
e
e
e
1 It is important to note that while the TRC cost-
2 effectiveness test is a useful tool to screen possible DSM
3 measures and programs, it is not a sufficient cost-
4 effecti veness evaluation perspective. One of the reasons for
5 TRC insufficiency is that this cost-effectiveness test does
6 not count utility incentives as á cost and therefore it
7 places absolutely no limits on incentives, in other words
8 higher incentives always produce higher TRC results, even if
9 the incentive paid exceeds the actual measure cost or even
10 the avoided supply cost. Clearly , cost-effectiveness from
11 the utility cost test (UCT) perspective must also be
13
12 evaluated.
14
It should be noted that in spite of Avista's tariff
stating its reliance upon TRC cost-effectiveness, the Company
15 also consistently calculates and says it considers cost-
16 effectiveness perspectives from the UCT, participant test,
17 and non-participant test (ratepayer impact) .3 Still, this
18 tariff language seems to not conform to Order No. 22299.
19
20
21
22
23
24
25
3 The TRC perspective compares the value of avoided supply costs to
the total of the utilities' DSM program administrative costs and the
direct cost of the measure's labor and materials, including any costs
incurred by customers. In the TRC, utility incentive payments are viewed
as transfer payments and are ignored.
The UCT perspective compares the value of avoided supply costs to
only the utility's DSM costs, including administration and incentive
payments to participants. Non-rebated customer costs are ignored. The
UCT is a misnomer in that customers, not utilities, are the ultimate
beneficiaries of programs that pass this cost-effectiveness test.The participant test compares the net costs (i. e. costs after
rebates and tax incentives) incurred by program participants to their
personal benefits, e. g. lower bills and increased comfort or production.
The non-participant test considers whether energy rates are changed
as a result of the program.
506CASE NOS. AVU-E-09-01/AVU-G-09-015/29/09 ANERSON, L. (Di) 13
STAFF
e
e
-
1 Reoommenda tions
2 Q.What are your recommendations regarding Avista' s
3 request for the Commission to find that its DSM expenses from
4 January through November 2008 were prudently incurred?
5 I recommend that the Commission defer prudencyA.
6 determination of Avista's January through November 2008 DSM
7 costs until the Company provides appropriate DSM program
8 evaluations. I anticipate that when the Company is able to
9 provide these evaluations it will be able to request a
10 prudency finding for more than the first 11 months of 2008.
11 Historically, due to agreements reached when the
12 Company's DSM tariff rider was initiated, Avista has only
13 requested DSM prudency findings in conjunction with general
rate case filings. I suggest that the Commission state that14
15 it will accept future applications for DSM prudency
16 determinations at any time chosen by the Company, thus
17 potentially severing this non-rate case issue from future
18 rate cases.
19 Finally, I recommend that Avista' s tariff Sheets 90
20 and 190 be modified by removal of the following sentence:
21 "The acquisition of resources is cost-effective as defined by
22 a Total Resource Cost test (TR) as a portfolio."
23 Q.Does this conclude your direct testimony in this
24 proceeding?
25 A.Yes, it does.
507
CASE NOS . AVU-E-09-01/AVU-G-09-01
5/29/09 ANERSON, L. (Di) 14
STAFF
e
e
e
1 Q.Please state your name and business address for
2 the record.
3 A.My name is Keith D. Hessing and my business
4 address i~ 472 West Washington Street, Boise, Idaho.
5
6
Q.By whom are you employed and in what capacity?
I am employed by the Idaho Public UtilitiesA.
7 Commission as a Public Utilities Engineer.
8
9
10
Q.What is your education and experience
background ¿l
A.I am a Registered Professional Engineer in the
11 State of Idaho. I received a Bachelor of Science Degree
12 in Civil Engineering from the University of Idaho in 1974.
13
14
Since then, I worked six years for the Idaho Department of
15 have been continuously employed at the Commission since
Water Resources, and two years for Morrison-Knudsen. I
16 August 1983.
17 As a member of the Commission Staff, my primary
18 areas of responsibility have been electric utility power
19 supply, revenue allocation and rate design.
20 Q.What is the purpose of your testimony in this
21 proceeding?
22 A.I will discuss electric issues including
23 Jurisdictional Separations, Class Cost of Service, Revenue
24 allocation to the various customer classes and the
25 Company's Power Cost Adjustment (PCA) mechanism.
508CASE NOS. AVU-E-09-1/AVU-G-09-l'OS/29/09 HESSING, K (Di) 1
STAFF
e
e
e
1 Q.Please summarize your testimony.
I propose the following:2 A.
3 1) That Jurisdictional Separations methodology
4 not be changed.
5 2) That the Company's Class Cost of Service
6 study not be used to allocate revenue to customer classes.
7 3) That the increased revenue requirement be
8 allocated to customer classes on a uniform percentage
9 basis.l
10 4) That PCA methodology be modified to include
11 third party transmission revenue and expense, the
12 Production Tax Credit, changes in Retail Revenue Credit
13 methodology and that Lancaster costs and benefits be
14 included in the PCA.
15 5) That the current PCA rate of 0.610 ç/kWh be
16 reduced to 0.361 Ç/kWh to offset the average increase in
17 base rates proposed by Staff.
18 6) That the Productión Property Adjustment
19 accepted by the Commission in the Company's last general
20 rate case be continued.
21 Jurisdictional Separations
22 Q.Have you reviewed the electric Jurisdictional
23 Separations methodology and allocation factors employed by
24 Avista in this filing?
25 A.Yes.
509CASE NOS. AVU-E-09-1/AVU-G-09-1
OS/29/09 HESSING, K (Di) 2
STAFF
e
e
e
1 Q.Does the Company's filing propose to change
2 Jurisdictional Separation methodology?
3 A.No. The Company proposes to use the same
4 methodology that it has used and that the Commission has
6
5 accepted for many years.
Q."Is it important that the methodology has not
7 changed?
8
9
A.Yes. Changes in methodology shift costs among
jurisdictions. Methodology changes should not be made 4
10 without compelling evidence and need for the change. When
11 the methodology does not change, jurisdictional cost
12 differences from the preceding case are driven by
13
14
jurisdictional characteristics (energy, demand, customer,
etc.) and accounting data. Consistent Separations
16
15 methodology leads to more stable customer rates.
Q.What Jurisdictional Separations methodology and
17 Jurisdictional Allocators does the Staff propose?
18 A.Staff proposes that the Commission accept the
19 electric methodology and allocation factors presented by
20 the Company.
22
21 Class Cost of Service
Q.Have you reviewed the Company's electric Class
24
23 Cost of Service (COS) Study?
25
A.Yes.
Q.Is the Company proposing to change the
CASE NOS. AVU-E-09-1/AVU-G-09-f10
OS/29/09 HESSING, K (Di) 3
STAFF
e
e
e
1 methodology from that accepted by the Commission in recent
3
2 years?
A.No. For a great many years the Company has
4 proposed that the Peak Credit method be used to calculate
5 class cost of service and the Commission has accepted it.
6 In the Company's last general rate case, Case No.
7 AVU-E-08-01 a settled case, the rate increase was spread
8 on a uniform percentage basis to all customer classes.
9 The uniform percentage spread was used because load ~
10 research data was stale not because the Peak Credit COS
11 methodology was unacceptable. Stale load research data
12 impacts all COS methods.
13
14
15
Q. Did the Company update its load research data
for this filing?
A.No. The Company reports that load research data
16 is being updated during calendar year 2009 and that the
17 new data will not be available until after the end of the
19
18 year.
Q.Does the Company propose that the Commission use
20 COS results to guide its allocation of revenue to customer
21 classes in this case?
22 A.Yes. The Company has filed a COS study using
23 the Peak Credit method. The Company proposes movement
24 toward COS based on its study results.
25 Q.Has the Company addressed the stale Load
CASE NOS. AVU-E-09-1/AVU-G-09-ï~æ
OS/29/09 HESSING, K (Di) 4
STAFF
e
e
e
1
2
Research data question in its filing?
Yes. The Company has filed four other PeakA.
3 Credit COS' studies that attempt to address the sensitivity
4 of the study to changes in load research results.
5
6 data should be used to determine class cost of service and
Q.,Are you convinced that the stale load research
7 to guide the allocation of revenue to the various customer
8 classes?
9 A.No, I remain concerned because the sensitivity l
10 analysis did not cover the scenario that I believe is most
11 likely. That scenario would have Residential Class peak
12 characteristics changing without offsetting changes in
13 other classes. I propose an alternative to COS based
14 revenue allocation below.
15 Revenue Allocation to Customer Classes
f 16
17
Q.What is your revenue allocation proposal?
A.I propose that revenue requirement be allocated
18 to customer classes on a uniform percentage basis. This
19 is the same allocation methodology that the Commission
20 approved in the Company's last case to deal with stale
21 Load Research data. It is an interim solution.
22
23
Q.What increase do you propose?
Staff witness Cecily Vaughn proposes an increaseA.
24 in base electric revenues of $8,622,000 which is a 3.91%
25 increase in base rates. I propose that rates be adjusted
5'1:2.CASE NOS. AVU-E-09-1/AVU-G-09-1
OS/29/09
HESSING, K (Di) 5
STAFF
e
e
e
1 in each class to obtain a 3.91% increase in base revenue.
3
2 The Power 'Cost Adjustment (PCA) Mechanism
Q..Is the Company proposing changes to its PCA
4 mechanism?
5 A.'Yes. In its filing Company witness Johnson
6 proposes several changes to its PCA mechanism. One change
7 is to increase Customer/Shareholder sharing percentages of
9
8 abnormal power supply costs from 90/10 to 95/5. Staff
wi tness Lobb addresses this proposal in his testimony. He ;
10 recommends that sharing remain at the current level of
11 90/10.
12
13
14
15
16
Q.Does the Company also propose a change to
include abnormal third party transmission revenues and
costs in the PCA?
A.Yes.
Q.Do you recommend that these costs and revenues
17 be included?
18 A.Yes, I do. Avista incurs third party
19 transmission costs when it purchases power and has it
20 wheeled or delivered to its service area by a third party.
21 Avista also incurs third party transmission costs when it
22 sells power and pays a third party to deliver it. Third
23 party transmission revenues occur when Avista is the third
25
24 party and is delivering power for others.
Q.Does the Company propose to change the way its
513CASE NOS. AVU-E-09-1/AVU-G-09-1
OS/29/09 HESSING, K (Di) 6
STAFF
e
e
e
1 Retail Revenue Credit is calculated?
2 A.Yes, it does.
3 Q.What is the proposed change?
4 The Company's Retail Revenue Credit rate, calledA.
5 a Load Growth Adjustment rate in Idaho Power Company's
6 PCA, is currently based on the marginal cost of obtaining
7 power. In a load growth situation, application of the
8 Retail Revenue Credit rate removes the cost of load growth
9 on the margin from abnormal power supply costs before the l
10 PCA rate is calculated and, therefore, denies recovery of
11 load growth related power supply costs incurred at the
12 margin. The theory is that the growth in load causes the
13 Company to incur power supply costs at the marginal rate
14 and that those costs should be recovered as a result of a
15 general rate case - not a PCA case.
16 In this filing Avista proposes to base the
17 Retail Revenue Credit rate on the embedded cost of power
18 supply already included in rates. The Company's
19 calculations include the embedded fixed cost of production
20 and transmission included in rates and the variable cost
21 of production included in rates. The theory behind these
22 calculations is that the Company receives these revenues
23 that are embedded in rates when it sells an additional
24 load growth kWh and, therefore, should not be allowed to
25 recover them a second time in the PCA. The Company
514CASE NOS. AVU-E-09-1/AVU-G-09-1
OS/29/09 HESSING, K (Di) 7
STAFF
e
e
e
1 proposes that these embedded costs, already being
2 recovered "through retail rates, be removed from power
3 supply costs that are granted PCA treatment. This
4 treatment avoids a double recovery of embedded costs and
5 allows the Company full recovery of the marginal cost of
6 load growth.
7 Q.Do you support the Company's proposal to change
9
8 the calculation of the Retail Revenue Credit rate?
A.
10 in the Settlement Stipulation accepted by the Commission
Yes for the reasons cited above. In addition,ì
11 in Avista's last general rate case, Case No. AVU-E-08-01,
12 this method was employed although a long-term change in
13
14
the methodology was not discussed or ordered.
15 existing PCA mechanism?
Q. Does Avista propose another change to its
16 A.Yes. Avista proposes to include in the PCA
17 amounts that differ from the amount included in base rates
18 for the Production Tax Credit (PTC). Avista receives a
19 production tax credit for energy generated at Kettle Falls
20 and for the Cabinet Gorge upgrâde. The normal Production
21 Tax Credit reduces the revenue requirement in base rates.
22 The credit is directly related to Company power supply
24
23 costs and varies with energy production.
Q.Do you believe that the Production Tax Credit
25 should be included in the PCA?
5i5CASE NOS. AVU-E-09-1/AVU-G-09-1
OS/29/09 HESSING, K (Di) 8
STAFF
e
e
e
9
10
1 A.Yes I do, for the reasons cited above. Allowing
2 the credits to be ìncluded in the PCA will assure all the
3 benefits received in 2009 related to Kettle Falls are
4 passed on to customers without harming the Company when
5 the Kettle Falls PTC expires. Any new tax credits similar
6 to the PTC or extensions to existing credì ts that are
7 authorized in the future, should also be credits in the
8 PCA. This will allow customers to receive the benefits in
a fair manner.l,
Q.Does the Company make one more proposal that
11 would modify the PCA on a short-term interim basis?
12
13
14
A.Yes it does. The Company proposes that the
impacts of the Lancaster combined cycle combustion turbine
(CCCT) Tolling Agreement be included in the peA. The
15 Company proposes to include 100% of the fixed costs for
16 PCA recovery and to apply the PCA sharing percentage to
17 variable costs. The Combustion Turbine becomes a Company
18 contract resource on January 1, 2010. Because this date
19 is well after the date that rates will become effective in
20 this rate case, ìt is not reasonable to include the cost
22
21 of Lancaster in base rates ìn this case.
Q.How does this treatment of Lancaster costs
23 differ from the normal circumstance?
24 A.Normally fixed costs would be included in base
25 rates and would receive no PCA treatment. There is
516CASE NOS. AVU-E-09-1/AVU-G-09-1
OS/29/09 HESSING, K (Di) 9
STAFF
e
e
e
14
1 usually iittle or no variability in fixed costs. The
2 normal level of variable natural gas costs would also be
3 included in base rates. The PCA would capture only
4 variations from normal gas costs.
5 The Lancaster treatment proposed by the Company
6 in this case places unusual and substantial upward
7 pressure on PCA deferral balances that will remain until
8 fixed costs and normal levels of variable costs are moved
9 to base rates in the Company's next general rate case.~
10 Q.Why not wait until the Company's next general
11 rate case to include Lancaster in base and PCA rates?
12 A.Beg inning January 1, 2010, the PCA wi 1 1
13 automatically begin to capture the benefits of the
resource. The shared benefits flow to Avista customers
15 through the PCA. The benefits are a reduced cost of
16 supplying load and profits from off system sales. It is
17 not fair to shareholders to require them to absorb the
18 costs of the resource while the PCA passes the benefits on
20
19 to customers.
Q.Does a new power supply resource always reduce
22
21 the Company's power supply costs?
A.The answer is yes if we are talking about the
23 variable power supply costs of the Company. This is true
24 because the resource is only run to meet load requirements
25 when it is the lowest cost alternative or to make off
CASE NOS. AVU-E- 09-1/AVU-G- 09- 11:7
OS/29/09 HESSING, K (Di) 10
STAFF
e
e
e
1 system sales when sales revenues are higher than gas
3
2 costs.
4 associated with a resource?
Q.~hat about the fixed power supply costs
5 A.Fixed power supply costs are normally included
6 in base rates for full recovery in a general rate case
7 once those costs have been found to- have been prudently
8 incurred. This circumstance differs in that full recovery
9 of fixed costs has been requested through the PCA 4
10 beginning January 1, 2010 when the resource becomes
11 available to the Company.
12
13
14
15
Q.What about the question of whether or not the
fixed costs associated with the resource were prudently
incurred?
A.Staff witness Randy Lobb addresses that question
16 is his testimony. He concludes that the fixed costs of
17 the resource have been prudently incurred.
18
19 treatment have on the PCA deferral balance?
Q.What impact would the Company's proposed PCA
20 A.If the Company's proposed treatment is adjusted
21 for 90/10 sharing as proposed by Staff, the inclusion of
22 Lancaster in the PCA would increase the annual deferral
23 balance by approximately $6.5 million in calendar year
25
24 2010.
Q.Do you support the Company's proposal to include
518CAE NOS. AVU-E-09-1/AVU-G-09-1
OS/29/09
HESSING, K (Di) 11
STAFF
-
-
e
1 Lancaster fixed and variable costs in the PCA beginning
3
2 January 1, 2010?
A.I do. I believe it provides an equitable
4 balance between shareholders and ratepayers of Lancaster's
5 benefits and costs until the fixed costs and normal
6 variable costs can be placed in base rates in the
7 Company's next general rate case.
8 The Power Cost Adjustment Rate
9 Q.
10 that is currently in place?
Does the Company propose to change the PCA rate
11
I
A.Yes, it does. The Company proposes a reduction.
12 in the current PCA rate from 0.610 ç/kWh to 0.257 ç/kWh as
13
14
a temporary offset to the 12.8% increase in current rates
15 would reduce the overall increase that customers would
(14.2% increase in base rates) that it is proposing. This
16 experience on implementation of new rates by 5.0% to 7.8%.
17 The Company further proposes that the new PCA rate be
18 continued a year past its normal expiration date to
19 October 1, 2010 if deferral balances do not become too
20 large.
21
22
Q.What is your proposal for the existing PCA rate?
Staff proposes a much smaller general or baseA.
23 rate increase than that proposed by the Company. The
24 Staff proposes a 3.91% base rate increase. Therefore, I
25 propose that the Commission offset the entire base rate
5.19
CASE NOS. AVU-E-09-1/AVU-G-09-1
OS/29/09 HESSING, K (Di) 12
STAFF
e
e
e
1 increase with an equivalent reduction in the PCA rate. A
2 reduction in the PCA rate from 0.610 t/kWh to O. 361t/kWh
3 offsets Staff's proposed $8.622 million increase in base
4 rates.
5 Q.Would the net revenue requirement of all
6 customer classes be zero under your proposal?
7 A.No, because PCA rates affect class revenues on a
8 t/kWh basis and not an equal percentage basis. Some
9 classes will experience net increases and others will l
10 experience net decreases. The increases and decreases
11 will average z~ro. Staff witness Bryan Lanspery shows
12 these results on Staff Exhibit No. 124. His exhibit shows
13 a PCA rate reduction of 0.2489 t/kWh across all customer
14 classes.
15 How long will your proposal to offset the baseQ.
16 rate increase with a PCA rate decrease last?
17 A. It will last until one rate or the other
18 changes. The PCA rate is normally adjusted annually in
19 October. The Staff will review the PCA deferral balance
20 prior to October this year and make a recommendation to
21 the Commission. One of the alternatives that will be
22 addressed at that time is whether or not it is reasonable
23 to continue the PCA rate established in this case until
25
24 October 1, 2010.
Q.What is the effect of changing the PCA rate now
520CASE NOS. AVU-E-09-1/AVU-G-09-1- .
OS/29/09 HESSING, K (Di) 13
STAFF
e
e
e
10
1 and possibly continuing the rate to October 1, 2010?
2 Reducing the rate reduces future revenue toA.
3 offset deferral balances. If the rate is reduced too much
4 it may have to be increased to amortize deferral balances
5 that are building faster than offsetting revenue. Of
6 course, if the opposite situation occurs, the rate would
7 have to be further reduced.
8 Q.What is the current and expected future status
9 of PCA deferrals?I
A.The current PCA rate recovers approximately
11 $21.1 million per year. The rate was designed to recover
12 $9.6 million of last year's deferral balance during the
13
14 reduced beginning July 2009, when I anticipate base rates
May through September period this year. If the rate is
15 will change, I estimate that $2.5 million of the $9.6
16 million will be unrecovered on October 1.
17 In addition there is a balance of $7.2 million
18 in the deferral account for the first 10 months of the
19 current deferral year, through April of 2009. Assuming
20 PCA treatment of Lancaster costs as previously discussed,
21 six months (January through June) of those costs would
22 accumulate in the next deferral period. This is estimated
23 to be $5.0 million. The net effect of these deferrals
24 through June of 2010 would cause new PCA rates on October
25 1, 2010 to have to be increased $2.2 million. This
521CASE NOS. AVU-E-09-1/AVU-G-09-1
OS/29/09 HESSING, K (Di) 14
STAFF
e
e
e
1 calculation assumes that the unknown non-Lancaster
2 deferrals from May 2009 through June 2010 net to zero.
3 The calculation follows:
5
4 Million $
PCA Revenue ~O. 361 t/kWh 12.5
6
7
8
9
10
Unrecovered balance (Jul-Sep 09)
This years deferral (First 10 Months)
Lancaster Deferrals (Jan-Jun 2010)
-2.5
-7.2
-5.0
Unknown Deferrals (May 2009-June 2010)
Net Deferral
0.0 ~
-2.2
11 The unknown Deferrals category could increase by $8.6
12 million before the rate would return to the current rate
13
14
of 0.610 t/kWh.
The Staff proposal is more conservative than the
15 Company's proposal in terms of the PCA rate. The Company
16 proposes that the rate be reduced to o. 257t/kWh which will
17 produce approximately $8.9 million in annual revenue. By
18 my calculation the Company's proposal will leave a
19 deferral shortfall in 2010 of approximately $5.8 million
20 if all other assumptions are the same.
21
22 rate the greater the risk that the PCA rate will have to
Of course, the larger the reductions in the PCA
23 be increased the next time it is adjusted.
24 In spite of the risk of having to increase the
25 PCA rate in October 2010, I continue to propose that the
522CASE NOS. AVU-E-09-1/AVU-G-09-1
OS/29/09 HESSING, K (Di) 15
STAFF
e
e
e
14
1 current PCA rate be reduced to offset the base rate
2 increase supported by Staff in this case. I believe the
3 risk is jústified based on good water conditions in
4 northern Idaho and the current adverse economic climate as
5 evidenced by customer comments in this case.
6 Q.In the event that the Commission approves a
7 larger base rate increase than that proposed by Staff, do
8 you propose that the Commission offset the entire increase
9 with a PCA rate decrease?l
10 A.I believe that offsetting the base rate increase
11 with a PCA rate decrease is a good idea. However, I
12 believe that it is appropriate to establish a limit to the
13 size of the PCA rate reduction. I recommend the PCA rate
15 The Company's proposal is 0.257 ç/kWh. This limit would
not be reduced beyond the rate proposed by the Company.
16 allow the Commission to offset any base rate increase up
17 to 5%.
19
18 The Production Property Adjustment
Q.Has the Company included a Production Property
20 adjustment in its case?
21 A.Yes. The Company first proposed a Production
22 Property adjustment in its last general rate case. In the
23 settlement of that case the adjustment was accepted by the
25
24 Commission.
Q.What is the purpose of the Production Property
523CASE NOS. AVU-E-09-1/AVU-G-09-1
OS/29/09 HESSING, K (Di) 16
STAFF
e
e
e
1 adjustment?
2 The Production Property adjustment reduces theA.
3 revenue requirement calculation to offset increased
4 revenue requirement included in a case because the Company
5 reached out beyond the test year to include costs that it
6 expects to incur just before or during the first year the
7 new rates are expected to be in place. The revenue
8 requirement reduction compensates customers for a mismatch
10 to support a higher future load. The adjustment is made
9 between rate design load and costs that would be required
11 by removing a percentage of the proj ected costs equivalent
12 to the percentage amount of the proj ected load growth.
13
14 Credi t calculated in the PCA because the base energy
The methodology also affects the Retail Revenue
15 amount included in the PCA is the proj ected amount
16 expected in the first year that new rates from this case
17 will be in place. If the load proj ection is exactly
18 correct, no Retail Revenue adjustment will be made in the
19 PCA because there will be no load difference between
20 actual and base.
21 A review of the results of this methodology
22 following the Company's last general rate increase
23 indicates that it is working as anticipated.
24 Q.Does this conclude your direct testimony in this
25 proceeding?
524CASE NOS. AVU-E-09-1/AVU-G-09-1
OS/29/09
HESSING, K (Di) 17
STAFF
c
e
e
e
2 the record.
1 Q.Please state your name and business address for
3 A.My name is Rick Sterling. My business address
4 is 472 West Washington Street, Boise, Idaho.
5
6
Q.By whom are you employed and in what capacity?
A.I am employed by the Idaho Public Utilities
7 Commission as a Staff engineer.
8
9
10
What is your educational and professionalQ.
background?J
A.I received a Bachelor of Science degree in Civil
11 Engineering from the university of Idaho in 1981 and a
12 Master of Science degree in Civil Engineering from the
13
14
University of Idaho in 1983. I worked for the Idaho
Department of Water Resources Energy Division from 1983 to
15 1994. In 1988, I became licensed in Idaho as a registered
16 professional Civil Engineer. I began working at the Idaho
17 Public Utilities Commission in 1994. My duties at the
18 Commission include analysis of a wide variety of electric
19 and large water utility applications.
20 Q.What is the purpose of your testimony in this
21 proceeding?
22 A.The purpose of my testimony is to review the
23 power supply modeling computations of Avista witness
24 Kalich and the power supply pro forma adjustment
25 calculations of Company witness Johnson. I propose
526CASE NOS. AVU-E-09-1/AVU-G-09-1
OS/29/09 STERLING, R. (Di) 1
STAFF
f
e
e
e
1 changes to the gas price assumptions used for power supply
2 modeling, and I propose removing all term (less than 18
3 months) 'gas and electric transactions from the analysis
4 used to compute power supply costs for inclusion in base
5 rates.
6 Q.What model did the Company use to dispatch its
7 portfolio of resources and obligations?
8 A.Avista uses the AURORA model for determining
9 power supply costs. Staff has a license to use the AURORA
10 model (courtesy of Avista), and possesses the ability to
11 run the model and interpret its results. The model
12 optimizes dispatch of Company-owned resources and
13 contracts in each hour of the pro forma year. The pro
14 forma period is July 1, 2009 through June 30, 2010. The
15 model simulates true system operations by evaluating
16 future resource decisions on an hourly basis. Company
17 witness Kalich provides detailed testimony on the AURORA
18 model used by the Company to develop short-term power
19 purchase expense, fuel expense and short-term power sales
20 revenue. His testimony includes a good description of the
21 calculations performed by AURORA.
22 Q.Did Staff use the same AURORA version and
23 database as Avista for reviewing the Company's proposed
24 power supply costs and for determining Staff i s proposed
25 adjustments?
527
CASE NOS. AVU-E-09-1/AVU-G-09-1
OS/29/09
STERLING, R. (Di) 2
STAFF
e
-
e
1 A.Yes, Staff used exactly the same version of
2 AURORA (version 9.3.1001), including the same database
3 used by the Company (North_American_DB_2008-03).1
4 Q.What modifications did Avista make to the
5 database for this case?
6 A.'Avista modified its portfolio of resources to
7 reflect actual operating characteristics, modified natural
8 gas prices to match proj ected forward prices over the pro
9 forma period, modified regional resource characteristics
10 where better information is known, and replaced Northwest
11 hydro data with Northwest Power Pool data.
12
13
14
Q.Do you accept the modifications made by Avista
for this case?
A.I accept the Company's modifications to its own
15 and to other regional resources to better reflect actual
16 operating characteristics. I also accept replacement of
17 Northwest hydro data with Northwest Power Pool data.
18 However, I do not accept the natural gas prices used by
19 Avista for the pro forma period.
20 Q.What natural gas prices did Avista use for the
21 pro forma period for its AURORA analysis?
22 A.The natural gas prices used by the Company for
23 this filing are based on a three-month average from
24
25
lIn the testimony of Avista witness Kalich, he erroneously stated
that Avista used AURORA version 9.1.1003. The Company actually used
version 9.3.1001.
528CASE NOS. AVU-E-09-1/AVU-G-09-1
OS/29/09 STERLING, R. (Di) 3
STAFF
e
-
e
1 September 1, 2008 to November 30, 2008, of monthly forward
2 prices for the pro forma period.
3 Q.What gas prices did you use for your analysis?
4 A.I used a one-month average from March 27, 2009
5 to April 27, 2009, of monthly natural gas forward prices
6 for the pro forma period. In other words, I averaged 30
7 forward prices (one each day) for each month for a 12-
8 month period. I chose to use a one-month average of
9 prices because they were the most recent available at the
10 time I performed the AURORA analysis.
11 Q.Why do you believe that the natural gas prices
12 you used are better than those used by Avista?
13 A.The prices used by Avista were reasonable at the
14 time the Company conducted its analysis and prepared its
15 case. However, forward gas prices have dropped
16 dramatically since that time. Exhibit No. 101 shows a
17 history of natural gas forward prices since January 2007.
18 Each separate line in the chart represents one month of
19 the pro forma period. In addition to gas forwards, I have
20 also shown forecasted prices from the U. S. Department of
21 Energy i s Energy Information Administration (EIA), prepared
22 since January 2008 in its monthly Short Term Energy
23 Outlook reports. Note that EIA i S forecasted prices
24 closely track gas forward prices. As indicated by the
25 chart, prices peaked last summer, but have dropped
529CASE NOS. AVU-E-09-1/AVU-G-09-1
OS/29/09 STERLING, R. (Di) 4
STAFF
steadily since then. In preparing its case, Avista used
an average of prices bounded by the wide pair of bold
vertical lines (Sept 08 - Nov 08) shown on the graph in
Exhibit No. 101. I used an average of prices bounded by
the narrow, pair of vertical lines on the right side of the
graph. A numerical comparison between Avista' s prices and
those that I used is shown in Exhibit No. 102 for various
trading hubs included in the AURORA modeling. Exhibit
No. 103 shows a comparison of monthly prices for the pro
forma period for specific gas-fired plants owned by
j
Avista.
I believe the prices I used for my analysis are
a much better indication of natural gas prices likely to
occur during the pro forma period. The pro forma period
begins in July 2009, just two months from the time this
testimony is being prepared. Prices obtained two months
before the start of the pro forma period are much more
likely to be representative than prices obtained 7-10
months before the pro forma period, especially if the
change in prices has been continuous and steady over the
past 10 months as shown in Exhibit No. 101.
Q. Please explain what a forward price is.
A. A forward price is a price quote to deliver gas
at some future date at a price àgreed upon today. They
are not a forecast of what prices are expected to be at
530
CASE NOS. AVU-E-09-1/AVU-G-09-1
OS/29/09
STERLING, R. (Di) 5
STAFF
e
e
e
1 some future time, instead, they are the actual prices at
2 which gas can be purchased now for delivery in the future.
3 Q.Current natural gas prices are extremely low
4 compared to prices seen over the past several years. Why
5 are you prpposing to use lower prices for computing
6 Avista' s power supply costs rather than the higher prices
7 of the past?
8 A.For most ratemaking purposes, adjustments are
9 made to a specific test period to .normalizepower supply
10 expenses for normal weather and hydroelectric generation
11 and to reflect known and measurable changes for the pro
12 forma period that rates will be in effect. Adjustments
13 are also made to reflect contract changes from the test
14 period to the pro forma period. In the case of natural
15 gas fuel, however, historic averages or test period actual
16 costs are not necessarily a good approximation of costs
17 that will likely be incurred in the future pro forma
18 period. Consequently, natural gas fuel costs are now
19 usually based on forecasts of what those costs are
20 expected to be during the time when new rates will be in
21 effect. They are not historic, nor are they known and
22 measurable in the traditional sense. The gas prices I
23 have used for my AURORA analysis are the prices I expect
24 to occur during the period in which the rates set in this
25 case will be in effect.
531
CASE NOS. AVU-E-09-1/AVU-G-09-1
OS/29/09 STERLING, R. (Di) 6
STAFF
e
e
e
1 While it is true that natural gas prices are
2 currently at six-year lows, it is also true that the
3 prices I used in my analysis are the actual prices at
4 which gas tan be purchased now for delivery in the pro
5 forma period. Obviously, Avista will not purchase now all
6 of the gas it expects to need during the pro forma period,
7 but I believe forward prices over the .course of the past
8 month are the best information currently available to
9 predict prices that Avista will pay for gas to be used
10 during the pro forma period.
11 Q.Besides natural gas prices, have you made any
12 additional changes to the AURORA input data used by
13 Avista?
14 A.Yes, I have. Since its last general rate case
15 in 2008, Avista has included the actual term power and
16 natural gas transactions already entered into for delivery
17 in the pro forma period. Term transactions are monthly
18 and quarterly transactions made less than 18 months prior
19 to delivery. Avista contends that term transactions
20 should be included to more accurately reflect the actual
21 power supply expense the Company will incur during the pro
22 forma period. As of November 30, 2008, Avista had entered
23 into 33 forward electric contracts and forward natural gas
24 contracts for delivery in the pro forma period. The
25 electric contracts include 15 physical purchases and 4
532
CASE NOS. AVU-E-09-1/AVU-G-09-1
OS/29/09
STERLING, R. (Di) 7
STAFF
e 1
2
3
4
5
6
7
8
9
10
11
12
e 13
14
15
16
17
18
19
20
21
22
23
24
25
e
physical sales and 14 financial (fixed-for-floating swaps)
purchases. The natural gas transactions include 4
purchases and 4 sales. As Mr. Johnson explained in his
testimony, Avista added the physical electric transactions
as resources and obligations in the AURORA model and
included a mark-to-model adjustment in the pro forma for
the financial electric and natural gas transactions. If
the actual transactions lower power supply expense (lower
purchase costs or higher sales revenue) as compared to the
cost produced by the AURORA model, then the lower cost is
l
included in the pro forma expense. If the actual
transactions increase power supply expense (higher
purchase costs or lower sales revenue) as compared to the
cost produced by the AURORA model, then the higher cost is
included in the pro forma expense.
Q. What was the effect of Avista including term
transactions in calculating its pro forma power supply
expense?
A. Because many of the actual transactions included
by Avista as pro forma expenses were entered into during
the period of high forward prices during the middle of
2008, and because prices have declined substantially since
July 2008, the overall impact of the actual transactions
is an increase in the pro forma expense. Overall, the
actual transactions increase pro forma expense by
533
CASE NOS. AVU-E-09-1/AVU-G-09-1
OS/29/09
STERLING, R. (Di) 8
STAFF
e 1
2
3
4
5
6
7
8
9
10
11
12
e 13
14
15
16
17
18
19
20
21
22
23
24
25e
$4,314,400 on a system basis, ($1,527,729 Idaho
allocation) compared to what expenses would be based
solely on the AURORA model output.
Q. Why did you exclude term transactions from your
analysis?
A. I excluded all term transactions because I do
not believe that they represent normal conditions upon
which rates should be based. They are generally made to
balance loads and resources in the short-term, usually in ¡
response to expectations about short-term conditions like
water and weather conditions. Term transactions can be
either purchases or sales, and either physical or
financial trades. They are the primary element of the
utility's hedging strategy. Term transactions made during
one certain time period are highly unlikely to be repeated
again exactly, both in terms of price, quantity, and
proportion of purchases versus sales. In my opinion they
in no way represent normal conditions and are not
appropriate to include as a basis for setting base rates
in a general rate case.
Q. If you remove all term transaction from the
power supply cost analysis in this rate case, where do you
propose they be considered instead?
A. The proper place to account for actual term
transaction is in the Company's Power Cost Adjustment
532l
CASE NOS. AVU-E-09-1/AVU-G-09-1
OS/29/09
STERLING, R. (Di) 9
STAFF
e
e
e
1 (PCA) mechanism. Term transactions create real costs that
2 the Company is obligated to payor real revenues that the
3 Company is entitled to receive. The PCA allows them to do
4 so on an annual basis (as opposed to a long-term basis) ,
5 subject to, the 90/10 sharing percentage now in place.2
6 Q.Have term transactions ever been included in the
7 analysis to compute power supply costs for inclusion in
8 base rates?
9 A.No, they have not, not for Avista or for any
10 other electric utility within the Commission IS
11 jurisdiction. Avista' s proposal to include them now would
12 be a significant departure from past practice.
13
14
Q. Please summarize the results of your AURORA
15 removing all term transactions.
analysis using your adjusted natural gas prices and after
16 A.The results of my AURORA analysis are shown in
17 Exhibit No. 104. This compares to the Company's AURORA
18 resul ts as presented in Exhibit No. 5 of Mr. Kalich. My
19 results show an annual cost that is $20.6 million less
20 than the Company iS result. To these results, resource and
21 contract revenues and expenses not accounted for in AURORA
22 (e. g., fixed costs) must be added to determine net power
23 supply expense.
24
25 2Avista has requested to change the PCA sharing percentage to 95/5 in
this general rate case.
535CASE NOS. AVU-E-09-1/AVU-G-09-1
OS/29/09 STERLING, R. (Di) 10
STAFF
e
e
e
1 Q.Please explain how your AURORA results are used
2 to make a pro forma adj ustment to power supply expense.
3 A.As explained by Avista witness Johnson, "The pro
4 forma adjustment to power supply expense involves the
5 determination of revenues and expenses based on the
6 generation and dispatch of Company resources and expected
7 wholesale market power prices as determined by the AURORA
8 model simulation for the pro forma period under normal
9 weather and hydro generation conditions. In addition,.#
10 adjustments are made to reflect contract changes between
11 the test period and the pro forma period." My Exhibit No.
12 ios shows total net power supply expense during the test
13 period and the pro forma period under both Avista i sand
14 Staff i s proposals. For information purposes only, the
15 power supply expense currently in rates, which is based on
16 a 2009 calendar year pro forma period, is also shown.
17 As shown on Exhibit No. ios, current rates are
18 based on a system power supply cost of $174,849,000.
19 Avista i S test year power supply expenses were
20 $180,395,000. Avista proposes to adjust test year power
21 supply expenses upward by $27,645,000 to arrive at a pro
22 forma period power supply expense of $208,040,000 on a
23 system basis ($180,395,000 + $27,645,000 = $208,040,000).
24 This represents an increase of $33,191,000 on a system
25 basis over the amount currently built into rates.
536
CASE NOS. AVU-E-09-1/AVU-G-09-1
OS/29/09
STERLING, R. (Di) 11
STAFF
e
e
e
1 $taff, on the other hand, proposes to decrease
2 test year power supply expenses by $13,000,000 to arrive
3 at a pro forma period power supply expense of $167,395,000
4 on a system basis ($180,395,000 - $13,000,000 =
5 $167,395,000). This represents a decrease of $7,454,000
6 on a system basis from the amount currently built into
7 rates.
8 The Idaho allocation of Avista i s proposed
9 adjustment to test period expenses is an increase of ?
10 $9,789,095. Under Staff's proposal, the Idaho allocation
11 of its proposed adjustment to test period expenses is a
12 decrease of $4,603,300. The overall difference between
13
14
15
the Company's proposed power supply cost and Staff's is
$40,645,000 on a total system basis.
Q.Is it unusual in a rate case to have a
16 difference of over $40 million between the utility's and
17 Staff's recommended power supply costs?
18 A.Yes, it is an unusually large difference.
19 However, as I explained previously, the change in natural
20 gas price that occurred between when the Company prepared
21 its case and when Staff prepared its case is highly
22 unusual. In addition, Avista included term transactions
23 in its case, which neither Avista nor any other Idaho
24 utility has ever done before. These two differences
25 between Avista i s and Staff's case account for the entire
537CASE NOS. AVU-E-09-1/AVU-G-09-1
OS/29/09 STERLING, R. (Di) 12
STAFF
$40 million difference in recommended power supply costs.
Q. Please summarize your recommended changes in
power supply cost.
A. My recommended changes to power supply costs are
shown in Exhibit No. 106. I have compared my recommended
costs with those recommended by Avista witness Johnson. I
have highlighted those cost i terns in which my
recommendation differs from the Company iS. With only
three exceptions, all of my proposed adjustments are based
directly on AURORA results. The three exceptions are for
the Priest River Proj ect, the Black Creek Index purchase,
and the Nichols Pumping sale. Each of these three
contracts has a pricing structure that is tied to electric:
market prices. Because electric market prices are
projected in AURORA, I have adjusted these contract costs
and revenues to be consistent with prices in AURORA.
Exhibit No. 107 shows the computations of these
adjustments using my AURORA results along with the
adj us ted workpapers of Avista witness Johnson.
Q. wi th the exception of the changes you previously
discussed related to gas prices and the removal of all
term transactions, do you accept all of the other
normalizing and pro forma adjustments to the October 2007
through September 2008 test period power supply revenues
and expenses proposed by Avista in this case?
538
CASE NOS. AVU-E-09-1/AVU-G-09-1OS/29/09 STERLING, R. (Di) 13
STAFF
e
e
e
1 A.Yes, I do. All of the other adjustments
2 proposed by Avista are reasonable and in accordance with
3 adj ustments accepted by this Commission in the Company IS
4 prior general rate case.
5 Q.Does this conclude your direct testimony in this
6 proceeding?
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
Yes, it does.A.
iI
sJ9
CASE NOS. AVU-E-09-1/AVU-G-09-1
OS/29/09
STERLING, R. (Di) 14
STAFF
e
e
e
1 Q.Please state your name and business address for
2 the record.
3 A.My name is Joe Leckie. My business address is
4 472 West Washington Street, Boise, Idaho.
5 Q.By whom are you employed and in what
6 capacity?
7 A.I am employed by the Idaho Public Utilities
8 Commission (Commission) as a senior auditor in the
9 Utilities Division.
10 Q.What is your educational and experience
11 background?
12 A.I graduated from Brigham Young University
13 with a Bachelors of Science degree in Accounting. I
14 worked for the accounting firm Touche Ross in its Los
15 Angeles office for approximately one year. I then
16 attended law school and graduated from the J. Rueben
17 Clark School of Law at Brigham Young University with a
18 Juris Doctorate degree.
19 I am licensed to practice law in the State
20 of Montana. I practiced law in the State of Montana for
21 approximately 25 years.
22 I have been employed at the Commission as an
23 auditor since March 2001. I havè attended the annual
24 regulatory studies program sponsored by the National
25 Association of Regulatory Utilities Commissioners (NARUC)
540CASE NOS. AVU-E-09-1/AVU-G-09-1
OS/29/09 LECKIE, J (Di)
STAFF
1
e
e
e
1 at Michigan State University in August of 2001. I have
2 also attended several other training courses sponsored by
3 NARUC on regulatory accounting and auditing.
4 Q.What is the purpose of your testimony?
5 Ä.The purpose of my testimony is to review the
6 Company's capital additions to electric rate base in
7 October, November and December (last quarter) of 2008 and
8 the twelve (12) months of 2009. I will testify about the
9 annual additions generally and will testify about three
10 (3) specific additions. I recommend that Company witness
11 Andrews' proposal to include the costs for the Spokane
12 River relicensing be excluded from rate base at this
13 time. These costs are currently being deferred and I
14 recommend that they continue to be deferred. I also
15 recommend adjustments to the accounting treatment for the
16 Coeur d' Alene Tribe settlement; and finally, i will
17 recommend that the unamortized balance of the deferred
18 costs for the Montana settlement not be included in rate
19 base.
20 All of the numbers that are presented in my
21 testimony refer to the Idaho allocation of the total
22 system numbers. If system numbers are referenced, they
23 will be specifically identified as system numbers.
24 Q.What are your recommendations for the last
25 quarter of 2008 capital additions to electric rate base?
54~CASE NOS. AVU-E-09-1/AVU-G-09-1
OS/29/09 LECKIE, J (Di)
STAFF
2
-
e
e
1 A.Company witness Andrews included the net
2 amount of $3,658,000 as an addition to rate base for
3 capital e~penditures in thè last quarter of 2008. (See
4 Company witness Andrews Exhibit No. 10, page 8). After
5 reviewing .these additions to rate base, it appears that
6 these capital investments are reasonable. The 2008 rate
7 case increased rate base through the end of 2008. (See
8 the Stipulation adopted and approved by the Commission in
9 Order No. 30647).
10 Q.What are your recommendations for Company
11 witness Defelice's additions to rate base for the 2009
12 capital expenditures?
13 A.I have tested and reviewed part of the
14 actual expenditures for those additions through March 31,
15 2009, and I have reviewed the budgeted amounts the
16 Company has projected through the end of 2009. Company
17 wi tness Defelice is requesting a net addition to rate
18 base in the amount of $16.9 million. Although the last
19 nine (9) months of these expenditures are projected, I
20 have not recommended any adjustment to the Company's
21 request. The Company's projections of capital
22 expenditures have been very close to the end of the year
23 actual expenditures. Also, in reviewing the projected
24 expendi tures, there were not any proj ections that
25 appeared to be excessive or unreasonable.
542CASE NOS. AVU-E-09-1/AVU-G-09-1
OS/29/09 LECKIE, J (Di)
STAFF
3
e
e
e
1 Q.You also. reviewed three other specific
2 proj ects of a capital nature: the Spokane River
3 Relicensing Costs, the Coeur d' Alene Tribe Settlement and
4 the Montana Riverbed Lease. Are these costs included in
5 your acceptance of the Company's rate base additions
6 discussed above?
7 Q.No, I discuss my recommendations for each of
8 these expenditures below, and separate from the rate base
9 additions discussed above.
10 Spokane River Relicensing
11 Q.What are your recommendations for the costs
12 expended to date on the Spokane River Relicensing?
13 A.I recommend that all costs expended by the
14 Company for Spokane River hydro relicensing continue to
15 be deferred as they were in the last rate case. The
16 Company has still not obtained a FERC license for the
17 project and therefore, final costs are not known and
18 measureable nor is the new license used and useful.
19 Staff witness Lobb also discusses this in his testimony.
20 Once the license is obtained, Staff will be able to
21 conduct a thorough review of all costs for prudency and
22 include the prudent costs in rate base at that time.
23 The FERC license for the Spokane River
24 hydro-electric facilities has not yet been issued, and
25 there is no indication from FERC when that license might
543CASE NOS. AVU-E-09-1/AVU-G-09-1
OS/29/09 LECKIE, J (Di)
STAFF
4
-
e
e
1 be issued. Currently, the Company is operating the_
2 facili ties. on a temporary license. Past practice would
3 indicate that the Company will be able to continue its
4 operation under a temporary license for the future.
5 Company witness Storro testified that the license should
6 be issued by July 2009.(See Storro testimony, page 29) .
7 However, there is no evidence that the license will be
9
8 issued at that time.
Q.Is deferral of these relicensing costs
10 consistent with the Commission's Order in last year's
12
11 rate case?
13
A.Yes. In the Company's last rate case
(AVU-E-08-01), all the costs for the relicensing were
14 deferred. In Order No. 30647, the Commission accepted
15 the Stipulation of the parties to the case. The
16
17
18
19
20
21
22
23
24
25
Stipulation stated:
9. Accounting Treatment for Certain Costs.
(a.) Spokane River Relicensing - The Company
included the processing costs associated with
its Spokane River relicensing efforts, which
expenditures included actual life-to-date costs
from April 2001 through December 31, 2007, and
2008 pro forma expenditures though December 31,
2008. (See Andrews' Direct Testimony at page
32) Aithough the Company anticipates receiving
a final license from the Federal Energy
Regulatory Commission ("FBRC") in the near
future, that has yet to occur. The relicensing
costs will remain in CWIP (Construction Work in
Progress) and the Company will continue to
accrue AFUDC until issuance of the license, at
which time the relicensing costs will be
transferred to plant in service and
544
CASE NOS. AVU-E-09-1/AVU-G-09-1
OS/29/09
LECKIE, J (Di)
STAFF
5
e
e
e
1
2
3
4
5
6
7
8
9
10
depreciation will begin to be recorded. The
Parties have agreed to defer as a regulatory
-expense item (in Account 186 - Miscellaneous
Deferred Debits) on the Company's balance sheet
,depreciation associated with Idaho's share of
the aforementioned relicensing costs and
related protection, mitigation, or enhancement
expenditures, until the earlier of twelve (12)
months from the date of the issuance of the
license or the conclusion of Avista' s next
general rate case ("GRC"), together with a
charge on the deferral, as well as a carrying
charge on the amount of relicensing costs not
yet included in rate base. The carrying charge
for deferrals and rate base not yet included in
establishing rates would be the customer
deposit rate at that time (presently 5%) .
(Emphasis added).
11 The situation has not substantially changed between that
13
12 case and this one. No evidence indicates the license is
any nearer to issuance now than it was then.
14 Consequently, it is reasonable to continue the provisions
15 for deferral of the depreciation and the carrying charge
16 as set out in the stipulation.
18
17 Coeur d' Aiene Tribe Settlement
Q.Please explain the background surrounding
20
19 the Coeur d' Alene Tribal Settlement.
A.This litigation extends back to 1973 but I
21 will outline the recent history. Briefly, the Tribe
22 asserted that it possessed an ownership interest in Coeur
23 d'Alene Lake and its banks. In 1992, the federal
24 government brought suit against the State of Idaho on
25 behalf of the Tribe to quiet title to that lower portion
545CASE NOS. AVU-E-09-1/AVU-G-09-1
OS/29/09 LECKIE, J (Di)
STAFF
6
e
e
e
1 of the Lake located within the Reservation boundaries.
2 On appeal to the U. S. Supreme Court, the Court ruled that
3 the United States held in trust for the Tribe, that
4 portion of the Lake within the Reservation. Idaho v.
5 United Sta.tes, 533 U.S. 262, 121 S. Ct. 2135 (2001).
6 The Court's decision that the Tribe owned
7 the lower part of the Lake opened the door to other
8 claims against Avista. These claims included: Avista' s
9 "storage" of lake water for its hydro-electric facilities
10 without authorization of the Tribe constituted a
11 "trespass" on Tribal lands for the period from 1907 to
13
12 1981; this trespass would entitle the Tribe to
14
15
16
17
18
19
20
21
22
23
24
25
compensation under § 10 (e) of the Federal Power Act for
the past use of its lands to store water; § 10 (e)
(storage) compensation for the period from 1981 to the
present; and prejudgment interest. Based upon the
Court's decision, Avista and the Tribe entered into
settlement negotiations with a mediator. After years of
negotiations, the parties reached a settlement last year
but the terms of the settlement had not been approved
prior to the Commission's Order in the prior rate cases.
Q. Why is the Company attempting to recover
costs it expended in litigating and settling a legal
action with the Coeur d' Alene Tribe?
546CASE NOS. AVU-E-09-1/AVU-G-09-1
OS/29/09
LECKIE, J (Di)
STAFF
7
e
e
e
1 A.In December 2008 the Company reached an
2 agreement with the Tribe over its property right claims.
3 The settlement provides for an annual payment to the
4 Tribe for .the present right to store water on the Tribe's
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
land (§ 10 (e) of the FPA) ($400, OOO/year for first 20
years and $700, OOO/year for the next 30 years); an annual
payment of $32,000 for a transmission line easement
across the lake; and a series of payments totaling $39
million for the past storage and the "trespass." As
explained above, these claims relate to the Spokane River
facilities and are the subject of a relicensing process
with FERC. The resolution of this legal action clears
one of the Company's hurdles to receive that new license.
Recovery of these costs was in the Company's
last rate case (AVU-E-08-01) were not included in the
agreed upon revenue requirement in that case because the
settlement agreement had not been completed, but the
Company was allowed to defer any annual payments made,
that portion of the $39 million paid (for the past
storage and trespass) and the costs of litigation plus a
carrying charge of five percent (5%) until this rate case
(deferred balance). The Company requested recovery of
its deferred costs by amortizing those costs over a 45-
year period. This time period was chosen to match the
remaining life for any new Spokane River license. Any
~7
CASE NOS. AVU-E-09-1/AVU-G-09-1
OS/29/09 LECKIE, J (Di)
STAFF
8
e
e
e
15
1 unamortized balance would be included in rate base and
2 earn the overall rate of return.
3 Q.How is the Company requesting recovery of
4 these costs in this case?
5 A. -Company witness Andrews has included the
6 annual payments and an amortization of the deferred
7 balance of costs as an addition to the requested revenue
a requirement. This is a gross increase in annual expense
9 of $401,000 and net increase in the revenue requirement
10 of $257,000. See Company witness Andrews' Testimony,
11 Exhibi t No. 10, Schedule 1, page 9.
12 Q.Did Staff review various options for
13 allowing the Company recovery of these costs other than
14 including the unamortized balance in rate base?
A.Staff considered the following options for
16 allowing the Company recovery of these costs: First,
17 Staff considered allowing recovery of the costs but not
1a allowing rate base treatment or allowing any return on
19 the unamortized balance. This would have resulted in a
20 reduction to the Staff's revenue requirement of
21 $1, ioa, 000.
22 Second, Staff then considered the
23 reasonableness of allowing recovery but including a
24 return on the unamortized balance at the average cost of
25 debt. This would have been a reduction of $429,000 to
548CASE NOS. AVU-E-09-1/AVU-G-09-1
OS/29/09 LECKIE, J (Di)
STAFF
9
e
e
e
1 the Staff 's revenue requirement. Staff determined that
2 these options were not reasonable under the circumstances
3 because these costs are similar to other relicensing
4 costs or Expenses previously considered and accepted by
5 the Commission for rate recovery.
6 Third, Staff also considered amortizing
7 these costs over a life other than 45 years. I believe
8 it is appropriate to link the amortization of these costs
9 to approximately the same life as a new license for the
10 Spokane River hydroelectric facilities. While the
11 agreement and associated costs stand alone from the new
12 hydropower license, the agreement is required before a
13 new license can be obtained. Therefore, it seems
14 reasonable to amortize the agreement costs over the
15 expected useful life of the new hydropower license.
16 Q.Is Staff in agreement that the Company
17 should be allowed to recover these costs?
18 A.Yes. Staff also reviewed the possibility of
19 challenging the $39 million in payments and a related
20 portion of the litigation costs under the theory of
21 retroactive ratemaking. Some might argue that if these
22 costs are attributable to a past period and, therefore,
23 it would be inappropriate to have current ratepayers bear
24 the burden of such costs. An al ternati ve theory is that
25 because the past actions where claimed to be for past
54~CASE NOS. AVU-E-09-1/AVU-G-09-1
OS/29/09 LECKIE, J (Di) 10
STAFF
e 1
2
3
4
5
6
7
8
9
10
11
12
e 13
14
15
16
17
18
19
20
21
22
23
24
25
e
trespass to property, an unlawful act, these costs should
not be recoverable.
Staff determined that it would not challenge
recovery of the costs on these theories. Staff places
great weight on the fact that the legal. obligation did
not become known and measurable until the Supreme Court' s
2001 decision and until the subsequent settlement was
legally accepted by the appropriate authorities in 2008
makes this an argument of retroactive ratemaking tenuous
at best. The legal obligations and monetary costs of
these issues were not fully settled until the settlement
approved in December 2008.
Q. Should the Company be allowed to recover the
deferred balance of the payments and expenses?
A. It is clear that the annual payments for the
ongoing use of the Tribe's property and the right to use
the Tribe's property for water storage, as well as the
transmission easement are reasonable and reoccurring
costs of doing business. Therefore, the annual payments
to the Tribe for the use of the property and the
transmission easement should be recoverable by the
Company in its revenue requirement.
Q. What about the recovery of that portion of
the $39 million payments made through the test period
plus the litigation costs amortized over 45 years with
550
CASE NOS. AVU-E-09-1/AVU-G-09-1
OS/29/09 LECKIE, J (Di) 11
STAFF
e 1 the unamo~tized deferred balance included in rate base as
2 requested by the Company?
3 A.I have reviewed the Company's treatment of
4 these costs and support the amortization of these costs
5 over the 45-year period. I also support including the
6 unamortized balance in rate base to earn the overall rate
7 of return. If the deferred balance is amortized over a
8 45-year life, the Company should be entitled to receive
9 some return on the unamortized balance. Allowing the
10 unamortized balance to accrue a return at the average
11 cost of debt does not recognize the full financing costs
12 to the Company for these expenditures.
e 13 The history of this action is long and
14 complicated. Ultimately, the matter found a forum in the
15 U. S. District Court where the legal issues were presented
16 by the interested parties. It was under the supervision
17 of the federal district court that the settlement was
18 finally achieved. During this entire process, the
19 Company diligently pursued a clear definition of its
20 legal rights, thereby clarifying its legal obligation.
21 It appears the Company actively pressed its legal
22 defenses to the claims by the Tribe. Ul timately, the
23 Company agreed to pay the Tribe $39 million as
24 compensation for 100 years of use of tribal property.
25 Also the Company has expended litigation costs of $2.15
e
551
CASE NOS. AVU-E-09-1/AVU-G-09-1
OS/29/09 LECKIE, J (Di) 12
STAFF
million to determine what its legal rights and
obligations are respecting the Tribe and its property.
Since the settlement was agreed to by all the interested
parties, including review by the U. S. Department of
Interior, i t can be argued that the Company reached a
fair and reasonable settlement for its costs in this
matter.
Prior to 1973, the Tribe asserted no
ownership interest of the property used by the Company
for water storage that would have caused the Company to
be put on notice that their use of the property was
improper. Prior to the settlement, the specific amount
of an obligation, if any, owed by the Company was not
known or measurable. Therefore, any speculation on these
costs by the Company could not be included in any request
for recovery from the Commission.
Q. Do you agree with Company witness Andrews'
determination of the annual amount of amortization and
the amount of the deferred balance that will be amortized
in the test period?
A. No. I am in disagreement with the
accounting methodology used by Company witness Andrews to
determine the amount of the annual amortization and the
amount of the unamortized balance to include in rate
base. As I discuss the deferred balance amounts, I will
552
CASE NOS. AVU-E-09-1/AVU-G-09-1
OS/29/09
LECKIE, J (Di) 13
STAFF
e 1 only use Idaho's allocation of the total system costs.
2 (The total system costs are included in Company witness
3 Andrews' Exhibits and Workpapers, as well as the
4 allocation to Idaho.)
5 The basic difference between Company witness
6 Andrews' calculation and my calculation is the 12 -month
7 period of time used to determine the average of monthly
8 balances. Company witness Andrews used the monthly
9 balances for the months of July 2009 through June 2010;
10 and I used the monthly balances for the months of January
11 2009 through December 2009. Exhibit No. 108, page 2
12 compares the Company's calculation of a $7,861,266 rate
e 13 base addition to the Staff calculation of $6,796,290 for
14 a net rate base difference of $1,064,976.
15 While I agree with the Company's
16 determination of the beginning deferred balance of the
17 CDA Tribe settlement costs, an adjustment must be made to
18 the calculation of the unamortized deferred balance to be
19 added to rate base in order to be consistent with Staff's
20 recommended proforma period ending December 31, 2009.
21 The period used by the Company to determine average
22 monthly rate base balances ended June 30, 2010. Under
23 the terms of the settlement with the CDA Tribe, a payment
24 of $3,541,000 ($10,000,000 total system) must be made in
25 December of 2009. This payment has been included by the
e
553
CASE NOS. AVU-E-09-1/AVU-G-09-1
OS/29/09 LECKIE, J (Dil 14
STAFF
e
e
e
1 Company in the unamortized monthly deferred balance as
2 part of the average through June 2010. Because Staff's
3 proforma period ends in December 2009, this payment
4 should only be included in the December 2009 deferred
5 balance as the average of monthly deferred balances is
6 calculated. See Staff Exhibit No. ioa, page 2.
7 With the difference in monthly balances used
a by the Company and Staff, the annual amortization of the
9 deferred balance as determined by Staff is $26,000 less
10 than the determination by the Compány and reduces the
11 Company's revenue requirement by this $26,000. See
12 Staff's Exhibit No. ioa, page 1.
13 Montana Lease
14 Q.What recommendations do you have for Company
15 witness Andrews' treatment of the Montana Lease Expense?
16 A.I recommend acceptance of the accounting
17 treatment for the Montana Lease annual expense as
1a appropriate for inclusion in the revenue requirement
19 calculation.
20 The Company sought and obtained the right to
21 defer the costs associated with lease payments to Montana
22 under the terms of its settlement with the State of
23 Montana on the issue of rental of state property in the
24 stream beds of hydro-electric facilities owned by the
25 Company in Montana.(See Order No. 30492). Company
554
CASE NOS. AVU-E-09-1/AVU-G-09-1
OS/29/09 LECKIE, J (Di) 15
STAFF
e
e
-
1 witness Andrews is asking to defer the Idaho costs to
2 date of $2,885,489'over eight (8) years, or $360,686 per
3 year. Idaho's share of the annual expense for the 2009
4 test year is $1,556,781. Total expense for the test year
5 is $1,917,465, and a net increase to the revenue
6 requirement of $1,231,000. (See Company witness Andrews
7 Exhibi t No. 10 i Workpaper PF12 - 3 )
8 Company witness Andrews' amortization of the
9 deferral amount is the annual amount necessary to
10 amortize the deferred balance over the 8-year period.
11 The annual deferral expense remains constant over the 8-
12 year period. The 8 -year period is an appropriate period
13 of time for the deferral because the agreement/settlement
14 with the State of Montana has a provision for
15 renegotiating the annual lease price beginning in 2016 or
16 eight (8) years from the date of the agreement.
17 The annual lease payment is increased
18 annually by a CPI index. I have reviewed the CPI index
19 increases to determine the annual lease obligation for
20 2009, and the Company used the appropriate increases to
21 determine the 2009 Idaho share of the annual payment of
22 $1,556,781.
23 Q.What is the Company's proposal for the
24 unamortized balance of the total costs?
25 A.The Company is asking that the unamortized
555CASE NOS. AVU-E-09-1/AVU-G-09-1
OS/29/09 LECKIE, J (Di) 16
STAFF
e
e
e
1
2 included in rate base. I recommend that this balance not
balance of the lease settlement cost ($2,434,617) be
3 be included in rate base, but be amortized over the
4 remaining seven years of the proposed 8 -year amortization
6
5 period. This adjustment would reduce net rate base by
$1,582,501.(See Company witness Andrews' Workpaper
7 PF12-4 and Staff witness Vaughn Exhibit No. 118, page 3,
8 Column S) .
9 Staff recommends the Company be allowed to
10 recover its out of pocket costs. However, Staff
11 recommends the unamortized balance not be included in
13
12 rate base. The 8 -year recovery period allows full
15
14 period to not require a return.
recovery of the lease payments and is a short enough time
Q.Does this conclude your direct testimony in
17
16 this proceeding?
18
19
20
21
22
23
24
25
A.Yes, it does.
556
CASE NOS. AVU-E-09-1/AVU-G-09-1
OS/29/09 LECKIE, J (Di) 17
STAFF
e
e
e
1 Q.Please state your name and business address for
2 the record.
3 A.My name is Donn English. My business address is
4 472 W. Washington, Boise, Idaho 83702.
5 Q.By whom are you employed and in what capacity?
6 A.I am employed by the Idaho Public Utili ties
7 Commission as a senior auditor in the utilities Division.
8 Q.What is your educational and experience
9 background?
10 A.I graduated 'from Boise State University in 1998
11 with a BBA degree in Accounting. Following my graduation,
12 I accepted a position as a Trust Accountant with a pension
13 administration, actuarial and consulting firm in Boise. As
14 a Trust Accountant, my primary duties were to audit the
15 day-to-day financial transactions of numerous qualified
16 retirement plans. In 1999, I was promoted to Pension
17 Administrator. As a Pension Administrator, my
18 responsibilities included calculating pension and profit
19 sharing contributions, performing required non-
20 discrimination testing and filing the annual returns (Form
21 5500 and attachments). In May of 2001, I became a
22 designated member of the American Society of Pension
23 Professionals and Actuaries (ASPPA). I was the first
24 . person in Idaho to receive the Qualified 401 (k)
25 Administrator certification and I am one of approximately
CASE NOS. AVU-E-09-1/AVU-G-09-i57
OS/29/09 ENGLISH, D. (Di)
STAFF
1
-
e
e
1 ten people in Idaho who have earned the Qualified Pension
2 Administrator certification. In 2001, I was promoted to a
3 Pension Consultant, a position I held until 2003 when I
4 joined the Commission Staff.
5 Wi th the American Society of Pension
6 Professionals and Actuaries, I served on the Education and
7 Examination Committee for two years. On this committee I
8 was responsible for writing and reviewing exam questions
9 and study materials for the PA-1 and PA-2 exams
10 (Introduction to Pension Administration Courses), DC-1,
11 DC-2 and DC-3 exams (Administrative Issues of Defineq
12 Contribution Plans - Basic Concepts, Compliance Concepts
13 and Advanced Concepts) and the DB exam (Administrative
14 Issues of Defined Benefit Plans). I have also regularly
15 attended conferences and training seminars throughout the
16 country on numerous pension issues.
1 7 While with the Commission, I have audited a
18 number of utilities including electric, water and gas
19 companies and provided comments and testimony in several
20 cases that dealt with general rates, accounting issues,
21 pension issues and othèr regulatory issues. In 2004 I
22 attended the 46th Annual Regulatory Studies Program at the
23 Institute of Public utilities at Michigan State University
24 sponsored by the National Association of Regulatory Utility
25 Commissioners (NARUC). Since then I have regularly
CASE NOS. AVU-E-09-1/AVU-G-09-r58
OS/29/09
ENGLISH, D. (Di)
STAFF
2
e
e
e
1 attended NARUC conferences and meetings, primarily the
2 meetings of the Subcommittee of Accounting and Finance.
3 Q.What is the purpose of your testimony in this
4 proceeding?
5 A.The purpose of my testimony in this case is to
6 address system operating costs that are allocated to
7 Idaho's gas and electric jurisdictions. I will also
8 present the Staff recommended revenue increase in base
9 rates for Avista Utilities' Idaho Gas jurisdiction. This
10 increase in base rates will ultimately be offset by a
11 proposed decrease in the weighted average cost of gas
12 (WACOG) in Staff witness E1am's testimony, for no change in
13 the net billing rate for the residential class. First, I
will propose adjustments that decrease both gas operating14
15 expenses and electric operating expenses included in the
16 Company's filing. Secondly, I will address the Company's
17 proposed gas rate base, and additionally, I will propose
18 adjustments that are related specifically to the Company's
19 proposed Idaho Electric revenue requirement. Finally, I
20 will address the Company's proposed accounting treatment
21 for deferring a carrying charge on the difference between
22 pension expense accrual, as calculated under Statement of
23 Financial Accounting Standards No. 87 (FAS 87), and the
24 actual cash contribution made to the plan by Avista
25 Utilities.
CASE NOS. AVU-E-09-1/AVU-G-09-r59
OS/29/09
ENGLISH, D. (Di)
STAFF
3
e
e
e
1 Q.What is the Staff's recommended revenue
2 requirement for Avista's Idaho Gas jurisdiction?
3 A.Staff recommends an increase in .base rates of
4 $1,894,000, or 2.06% on annual revenues of $91,767,000.
5 This revenue increase is calculated with a Return on Equity
6 of 10.5% and an overall rate of return of 8.55% as
7 discussed in further detail in Staff witness Carlock's
.8 testimony. Staff's proposed rate base of $90 1028,000 is
9 slightly less than the rate base proposed by Avistaof
10 $90,491,000. Staff Exhibit No. 109, Schedule 1 compares
11 the re.sults of Staff's recommendations to those proposed by
12 the Company. The adjustments made by Staff to the
13 Company's case will be discussed in greater detail later in
14 my testimony.
15 Q.Please discuss the difference in the Conversion
16 Factor proposed by the Company and that recommended by
17 Staff as shown on Staff Exhibit No. 109, Schedule 1,
18 line 6.
19 A.The conversion factor is an additional adjustment
20 needed to account for the increase in revenue that triggers
21 additional increases in the Company's tax liability, and
22 other revenue contingent items like the Commission
23 regulatory fees and the Company's uncollectible expenses.
24 The calculation of the conversion factor is shown on Staff
25 . Exhibi t No. 109, Schedule 2. The difference in the
CASE NOS. AVU-E-09-1/AVU-G-09-f60
OS/29/09
ENGLISH, D. (Di)
STAFF
4
e
e
e
1 conversion factors arises from different IPUC assessment
2 rates used to determine the Commission's regulatory fees.
3 At the time of its filing, the Company used the 2008
4 assessment rate of 0.2507%. However, on May 7, 2009 the
5 Commission issued Order No. 30780 which established an
6 assessment rate of 0.1662% of gross Idaho operating revenue
7 derived from intrastate utility business. Staff updated
8 the new assessment rate on line 4, producing a new
9 conversion factor of 0.639336. Because the conversion
10 factor is the same for both gas and electric operations,
11 this adjustment effects both gas and electric revenue
12 requirements.
13 Q. Are yo~ sponsoring any other exhibits with your
14 testimony?
15 A.Yes, I will also be sponsoring Staff Exhibit Nos .
16 110-115 which will illustrate the adjustments Staff has
17 made to the Company's pro forma case to develop the pro
18 forma net operating income recommended by Staff. Staff
19 Exhibit No .110 shows ten adjustments that impact both gas
20 and electric operating results. The Idaho Gas Adjustments
21 on Staff Exhibit No. 110 are then displayed in a columnar
22 fashion on Staff Exhibit No. 111. Column B of Staff
23 Exhibit No. 111 is identical to the Pro Forma Total column
24 in Company witness Andrews' Exhibit No. 10, Schedule 2,
25 page 8, which illustrates the Company's request and becomes
CASE NOS. AVU-E-09-1/AVU-G-09-161
OS/29/09 ENGLISH, D. (Di)
STAFF
5
e
e
e
1 the starting point for all of Staff's adjustments.
2 System Adjustments Allocated to Idaho Gas and Electric
3 Jurisdictions
4 Non-Executi ve Labor Expense
5 Q.Please describe the first adjustment on Staff
6 Exhibit No. 110.
7 A.Line 1 reflects Staff's adjustment to non-
8 executive labor expenses . Executive Labor has been removed
9 and is discussed in a separate adjustment reflected on line
10 2. In Andrews' adjustment PF-1, the increases paid to
11 employees in March of 2008 are first annualized, and then
12 an adjustment is made to reflect the increase paid in March
13 of 2009. An additional adjustment is made to reflect an
14 increase in wages to be paid in March of 2010, and the
15 Company proposes to recover 8 months of the increased 2009
16 expense and an additional 4 months of the 2010 increase to
17 reflect what it believes to be the estimated labor expense
18 for the proposed rate year ending June 30, 2010. The
19 Company calculated estimated labor expense increases of
20 3.8% in 2009 and 2010 for its administrative staff, and
21 used the contractually obligated 4% wage increase for its
22 collective-bargaining union employees . Consistent with
23 Staff's treatment of the proposed test year in this case, I
24 have removed all increases associated with 2010 to reflect
25 the annual labor expenses for the year ending December 31,
CASE NOS. AVU-E-09-1/AVU-G-09~162
OS/29/09
ENGLISH, D. (Di)
STAFF
6
e
e
e
1 2009. Additionally, at the time of its filing, the Board
2 of Directors had not formally approved a wage increase for
3 2009, so the Company's 3. S% was an estimate of what was
4 believed to be the appropriate increase for 2009. The
5 Board of Directors subsequently approved a wage increase of
6 2.5% for 2009 for administrative staff, while the union
7 employees received their 4% increase as mandated by
Scontract.
9 In addition to removing the 2010 increases, I
10 have also reduced the 2009 increases to the amount actually
11 paid in March of 2009, and annualized those increases as if
12 they were in effect for the whole year. The effect of this
13 adjustment reduces Non-Executive Labor expense for the
14 Idaho Gas operation by $75,573 and increases Net Operating
15 Income by $49,000 as shown in Column. s-l of Staff Exhibit
16 No. 111. The effect on Net Operating Income for Idaho
17 Electric Jurisdiction is shown on Staff witness Vaughn's
lS Exhibit No. 11S.
19 Executi ve Labor Expense
20 Q.will you please describe the adjustment on line 2
21 of Exhibit No. 110 for Executive compensation?
22 A.Yes. Line 2 represents Staff's adjustment
23 removing all increases for executive compensation proposed
24 by the Company over the test year amounts. Similar to the
25 Company's approach with non-executive labor, ,the Company
CASE NOS. AVU-E-09-1/AVU-G-09-~63
OS/29/09 ENGLISH, D. (Di)
STAFF
7
e
e.
e
1 included in its request an increase for 2009 and 2010 for
2 its executives. Subsequent to its filing, the executives
3 of Avista decided to forego any increases in base salary
4 for 2009. I have removed all of the proposed salary
5 íncreases for executive labor to reflect this decision to
6 forego increases in 2009, and to remove the estimated
7 increase for 2010 to be consistent with Staff's use of the
8 year ending December 31, 2009. Additionally, I annualized
9 the current base salaries of all executives as of March 31,
10 2009 to reflect a full 12 months of their current pay. The
11 effect of these cumulative adjustments reduces Idaho Gas
12 expenses by $31,051 and increases Net Operating Income for
13 Avista's Idaho Gas jurisdiction by $21, 000 as shown in
14 Column s-2 of Staff Exhibit No. 111. Again, the effect of
15 this adj ustment . on the Idaho Electriç Jurisdiction's Net
16 Operating Income is reflected on Staff witness Vaughn's
17 Exhibit No. 118.
18 Q.Given the number of negative comments from
19 customers regarding executive compensation, is there
20 anything else you would like to add on the topic?
21 A.Because of the current economiccondi tions and
22 the multitude of customers expressing their displeasure
23 with the salaries paid to Avista executives, I will explain
24 Staff's critical approach in analyzing the reasonableness
25 of the executive compensation package, and its impact on
CASE NOS. AVU-E-09-1/AVU-G-09-X64
OS/29/09
ENGLISH, D. (Di)
STAFF
8
e 1 residential customer rates. The amount of executive labor
2 requested to be included in Idaho Gas rates by the Company
3 is 0.20% of annual revenues. On the average Idaho
4 residential monthly gas bill, this means that 10.78 cents
5 goes toward executive labor under the Company's proposal.
6 For Idaho electric customers, the amount requested to be
7 included in rates by the Company is 0.34% of annual
8 revenues, or 15.84 cents per month on the average
9 . residential bill. With Staff's proposed adjustments, Idaho
10 customers using both gas and electricity from Avista will
11 be paying less than 27 cents per month toward executive
12 salaries. Removing all executive salaries from customer
e 13 rates for gas and electric service would save customers
14 approximately $3.00 per year.
15 Furthermore, Staff's proposal for executive labor
16 expense, in this case, is 0.76% increase over the executive
17 labor currently embedded in rates based on 2007 expense.
18 This is a relatively small increase considering that an
19 additional executive position was added during 2008. On
20 average, executive compensation actually decreased by over
21 $22,000 per executive since the last general rate case.
22 Q.Why do you believe customers have a general
23 misunderstanding of the impact executive labor has on their
24 utility rates.
25 A.On March 24, 2009, Avista issued its annual proxy
e
CASE NOS. AVU-E-09-1/AVU-G-09-165
OS/29/09 ENGLISH, D. (Di)
STAFF
9
e 1 statement. Within this proxy statement, Avista is required
2 to list the compensation components of its top 5 officers.
3 Many news outlets in northern Idaho and eastern Washington
4 have reported the total compensation of these officers
5 without regard to how that compensation is paid. Total
6 compensation in the proxy statement consists of base
7 salary, stock awards, option awards , incentive plans, death
8 and disability~plans, and gains on pension and non-
9 qualified deferred compensation earnings, and a multitude
10 of other benefits. For example, it was reported that
11 Avista President and CEO Scott Morris received total
12 compensation of $2,221,905 in 2008. However, as shown on
e 13 Staff Exhibit No. 112, Idaho customers only paid
14 approximately 8.3% of that total, while other jurisdictions
15 contributed as well. It should also be noted that
16 approximately three-fourths of the total compensation
17 reported for Mr. Morris in the proxy statement was charged
18 to non-utility operations of Avista.
19 Adding to the customers' frustration is the
20 current economic conditions of northern Idaho as described
21 in the testimony of Staff witness Thaden. At a time when
22 many customers are experiencing declining incomes, Avista
23 executives are reporting compensation packages that could
24 make people envious. However, when compared to other
25 utility providers of comparable size, Avista executives are-
CASE NOS. AVU-E-09-1/AVU~G-09-166
OS/29/09
ENGLISH, D. (Di) 10
STAFF
e 1 paid below average for the management of a business with
2 $1.5 billion annual revenue.
3 Non-Executi~e Incentive Expense
4 Q.Will you please describe the adjustment labeled
5 Non-Executive Incentive Expense on line 3 of Exhibit No.
6 110?
7 A.Yes. Line 3 reflects Staff's adjustment to the
8 Company's proposed level of employee bonuses, ultimately
9 reducing employee bonuses for non-executive employees to
10 the level accrued during the historical test period.
11 Q.Please briefly describe the Company's Employee
12 Incentive Plan.
13 A. The Company's main employee incentive plan.e 14 consists of two steps. The initial step in the issuance of
15 bonuses is determined when Standard Performance
16 Expectations are met. These Standard Performance
17 Expectations are based on customer satisfaction ratings,
18 average restoration time and average outage per customer.
19 Once the Standard Performance Expectations have been
20 achieved, the actual payouts are dictated by O&M cost
21 savings.
22 Q.How did the Company develop its proposed level of
23 incentive payments to be included in rates?
24 A.Actual incentives paid and the associated payroll
25 taxes for years 2003 through 2007 were adjusted by the
e
CASE NOS. AVU-E-09-1/AVU-G-09-\67
OS/29/09 -
ENGLISH, D. (Di) 11
STAFF
e
e
e
1 Consumer Price Index (CPI) for the year the incentives were
2 paid to restate those costs in 2008 dollars. The Company
3 then computes a six-year average of incentive payments and
4 compares that to the incentive expense included in the test
5 year to determine its pro forma adjustment. The Company's
6 proposed adjustment increases the incentive expense by
7 $1,175,087 for the total system, or $73,238 for the Idaho
8 Gas jurisdiction and $295,137 for the Idaho Electric
9 jurisdiction.
10 Q.Why do you object to the Company' s proposal for
11 its employee incentive plan?
12 A.My first obj ection relates to the use of a six-
13 year average to determine the annual level of incentive
14 expense in this case. As you can see on Staff Exhibit No.
15 113, the annual incentive payments have continually trended
16 downward over the past four years, and the test-year level
17 of incentive expense represents the lowest amount of any of
18 the previous six years. The use of the six-year average in
19 this case would effectively require customers who are. in
20 the midst of a recession to pay for employee bonuses at a
21 level that was incurred during a time when economic
22 conditions were far superior than we are currently
23 experiencing. Furthermore, the Company has not provided
24 any evidence that incènti ve payments will be increasing in
25 the near future to justify the 30% increase over test-year
CASE NOS. AVU-E-09-1/AVU-G-09-~68
OS/29/09
ENGLISH, D. (Di) 12
STAFF
e 1 accruals.,
2 Secondly, because actual payouts are dictated by
3 utility O&M cost savings, bonuses will not be paid unless
4 . shareholder earnings are achieved. The Company's Employee
5 Incentive Plan states that this O&M component focuses on
6 the context of cost management. Though not directly stated
7 as such in the Company's Incentive Plan, O&M cost
8 reductions at a time of increasing revenues has a direct
9 positive correlation to shareholder value. Additionally,
10 any incentive payments made due to any type of O&M
11 benchmark should be self-funding to the extent that any O&M
12 savings achieved should be sufficient to fund the incentive
e 13 payout.
14 Q.How has the Commission typically dealt with these
15 types of incentive plans?
16 A.I believe that both Staff and the Commission
17 acknowledge that incentive payments are an appropriate part
18 of a utility company's overall compensation package,
19 provided that the incentive payouts are not based on
20 increasing shareholder value. In Case No. IPC-E-OS-28, the
21 parties agreed to a stipulation that stated Uft is
22 reasonable to include an employee pay-at-risk or employee
23 incentive component in test-year revenue requirements so
24 long as such incentive component is based on goals that
25 benefit customers." The Stipulation further stated that-
CASE NOS. AVU-E-09-1/AVU-G-09-1.69
OS/29/09 ENGLISH, D. (Di) 13
STAFF
e
e
e
1 "senior management pay-at-risk is appropriately excluded
2 from test~year revenue requirement."
3 Though this stipulation was filed as an agreement
4 between Commission Staff and Idaho Power Company, by
5 accepting' the stipulation, the Commission has expressed its
6 intentions with respect to the treatment of employee
7 incentive plans. The Commission also affirmed in Order No.
8 30722 that "incentive pay is properly included in annual
9 revenue requirement if it is related to identifiable
10 customer benefits." The Commission further stated in that
11 Order that the customer benefits of "O&Mmanagement that ~s
12 reflected in rates set in annual rate cases does not create
13 the necessary nexus between incentive pay and customer
14 benefit. "
15 Finally, I believe that the Commission is
16 cognizant of the public perception of Avista awarding
17 employee bonuses at a time when it is asking to increase
18 the rates it charges for gas and electricity, and
19 especially when many of its customers are struggling
20 financially. If Avista believes that today's financial
21 environment mandates the need for rate increases, those
22 rate increases should be mitigated by a concerted attempt
23 to lower costs and salary. The incentive plan creates the
24 perfect opportunity for Avista to generate funds internally
25 because the Company will undoubtedly experience salary
CASE NOS. AVU-E-09-1/AVU-G-09-t70
OS/29/09 ENGLISH, D. (Di) 14
STAFF
e
e
e
1 . savings through attrition. As employees retire, or leave
2 the Company, voluntarily or not, their replacements will
3 presumably be paid less. Avista could use these salary
4 savings from attrition to fund a portion of its incentive
5 plan.
6 Q.Given what you just stated about employee
7 incentives, what it your proposal in this case?
8 A.Because Staff has continually recognized the
9 benefit of an incentive plan in an employee's total
10 compensation package, I do not propose to eliminate 100% of
11 the incentive expense proposed by the Company. Also,
12 because the Company's incentive plan does not have a
13 component that directly relates to O&M savings, but rather
14 states that O&M targets must be attained before incentives
15 can be paid, there is not a specific component of the plan
16 that can be reduced. Therefore, my adjustment limits the
17 amount of employee incentive expense to that ,which was
18 accrued during the test year ending September 30, 2008.
19 This is a reduction of approximately $1.2 million system-
20 wide to the Company's proposal.
21 It should be noted that the remaining $2.8
22 million, with the exception of executive bonuses which I
23 discuss shortly, is comparable to the. approximately $3.2
24 million in incentive expense that the Commission awarded to
25 Idaho Power in Case No. IPC-E-08-10. Because Idaho Power
CASE NOS. AVU-E-09-1/AVU-G-09-~71
OS/29/09
ENGLISH, D. (Di) 15
STAFF
e
e
e
1 has. approximately 2,000 employees compared to Avista' s
2 approximately 1,500 employees, on a per employee basis, the
3 amount I recommend for Avista is actually greater than that
4 approved for Idaho Power.
5 Executive Incentive Expense
6 Q.Does the test year incentive expense for Avista
7 include bonuses for its executives?
8 A.Yes, it does. Line 4 of my Staff Exhibit No. 110
9 illustrates the removal from test year incentive expense
10 the amounts included for Avista executives. This is
11 consistent with the Commission's affirmation that senior
12 management pay-at-risk be excluded from test year revenue
13 requirement, and is also consistent with Staff's treatment
14 of executive incentive expense for all other utilities
15 providing service in Idaho.
16 The Avista Executive Officer Incentive Plan is
17 similar to the incentive plan for all employees with
18 standard performance measures based on customer
19 satisfaction and reliability. However, the executive
2 0 incentive plan also has a Capital Spending Budget component
21 as well. Once the standard performance triggers are
22 achieved, 70% of the target award is based on earnings per
23 share targets and the other 30% on O&M cost per customer
24 benchmarks. Becaus~ the Executive Officer Incentive Plan
25 does not payout until shareholder benchmarks are met, this
CASE NOS. AVU-E~09-1/AVU-G-09-~72
OS/29/09
ENGLISH, D. (Di) 16
STAFF
e 1 plan should be paid for with shareholder money and not
2 charged to customers. Removing the executive incentive
3 payments from the test year reduces expenses by $311,028
4 for the total system, or by $19,385 for the Idaho Gas
5 jurisdiction and $78,118 for the Idaho Electric
6 jurisdiction.
7 Board of Directors Expense
8 Q.Please explain the adjustment on line 5 of Staff
9 Exhibit No. 110.
10 A.Line 5 represents the proposed adjustment to
11 remove one-half (50%) of the Board of Directors' retainer
12 fees, travel and meetings expense. The Board of Directors
e 13 is the highest governing authority wi thin the management
structure at any publicly traded company. It is the14
15 board's job to select, ev~luate, and approve appropriate
16 compensation for the company's chief executive officer
17 (CEO), evaluate the attractiveness of and payment of
18 dividends, recommend stock splits, oversee share repurchase
19 programs, approve the company's financial statements, and
20 recommend or discourage acquisitions and mergers. All of
21 these. responsibilities illustrate that the primary
22 responsibility of the Board of Directors is to protect the
23 shareholders i assets and ensure shareholders receive a
24 decent return on their investment.
25 Because the board of directors' fiduciary
e
CASE NOS. AVU-E-09-1/AVU-G-09-\73
OS/29/09 ENGLISH, D. (Di) 17
STAFF
e
-
e
1 responsibility is to protect shareholder value ,and the
2 board serves at the behest of shareholders,. who have the
3 opportunity to elect or retain board members, it is
4 reasonable for shareholders to pay at least half of the
5 expenses associated with board fees, travel and meetings.
6 Q.Are there other reasons supporting your
7 adjustment to Board of Directors Expense?
8 A.Yes. During the course of Staff's audit, it was
9 noted that some board members fly to board meetings via
10 first class and receive limousine transportation from the
11 airport. Also, board retreats consisted of extravagantly
12 catered lunches and dinners, along with cruises on Lake
13 Coeur d' Alene. The expenses for these types of activities
were charged to ratepayer accounts and included in the
15 Company's test-year revenue requirement. I believe it is
14
16 inappropriate to pass these types of expenses onto
. 17 ratepayers, especially because these expenses do not relate
18 to the generation, transportation or distribution of
19 utility services. Staff's removal of one-half of all these
20 expenses acknowledges that as a publicly traded company,
21 Avista is required to have a board of directors and that
22 some level of expense charged to customers may be
23 appropriate. This adjustment reduces expenses by $595,617
24 system-wide or $37,122 for the Idaho Gas jurisdiction and
25 $149,596 for the Idaho Electric jurisdiction.
CASE NOS. AVU-E-09-1/AVU-G-09-5Y4
OS/29/09
ENGLISH, D. (Di) 18
STAFF
e
e
e
1 Information Services Support Adjustment
Q. ,Please explain the adjustment listed on line 6 of2
3 Exhibit No. 110.
4 A.This adjustment is. a two-part adjustment to the
5 pro forma level of Info~mation Services Support proposed by
6 the Company in Mr. Kopczynski's testimony. The Company
7 proposes to capture an additional $2.6 million system-wide
8 for labor and non-labor informational services costs
9 planned for 2009 above the test period levels. Mr.
10 Kopczynski states that an additional $1.3 million is needed
11 for an additional nine positions to support software
12 applications that have been utilized by the Company in
13 recent years. Five of those positions have currently been
14 filled by the Company, while the other four have not. Two
15 of those positions are not expected to be filled until
16 January 2010.
17 Many of the software applications th~ Company is
18 requesting additional labor dollars for were put in place
19 in 2008. Because the Company is currently using these
20 applications, while already providing reliable electric and
21 gas service to customers at its current staffing level, I
22 believe some of these positions may be unnecessary or
23 filling them could at least be delayed. My adjustment
24 removes approximately $560,000 system-wide for the four
25 unfilled positions, or $25,000 for the Idaho Gas
CASE NOS. AVU-E-09-1/AVU-G-09-~75
OS/29/09 ENGLISH, D. (Di) 19
STAFF
e
e
e
1 jurisdiction and $156,000 for the Idaho Electric
2 jurisdiction.
3 Q.What is the second part of your adjustment?
4 A.The second part of my adjustment to Information
5 Services (IS) Support reflects the historical variance
6 between budgeted amounts and actual expenditures. Though
7 Staff generally believes that Avista' s forecasts are an
8 accurate representation of the Company's intentions, during
. 9 the course of Staff's review a large variance existed
10 between 2008 budgets and 2008 actual expenses. The
11 Company's budget or IS Support for 2008 was $2.66 million
12 system-wide, although actual expenses totaled only $2.11.
13 million, for a variance of 20.57%. By applying this
14 variance to the budgeted amounts for 2009, it would be
15 reasonable to reduce 2009 IS support by $550,000 system.
16 Q.Are there any specific examples in which you
17 believe the Company's estimates for Information Services
18 Support may be too high?
19 A.Yes. For example, in late 2008, the Company
20 implemented the ARCOS Rostermonster automated crew callout
21 mechanism for after~hour callouts, eliminating the need for
22 one-on-one callouts while creating operational
23 efficiencies. I have reviewed the Company's agreement with
24
25
CASE NOS. AVU-E-09-1/AVU-G-09-r76
OS/29/09 ENGLISH, D. (Di) 20
STAFF
e
e
e
1 ARCOS, Inc. i The agreement calls for a fixed monthly
2 service fee, and a variable charge based on line usage.
3 After reviewing the invoices from ARCOS, Inc. for the first
4 three months of 2009, I believe the Company over-estimated
5 the annual variable charge for line usage. By annualizing
6 the March 2009 line usage data, the most recent data
7 available, it would appear that Avista overestimated the
8 amount it would need to pay to ARCOS by approximately
9 $38,000. Rather than proposing separate adjustments for
10 each of the applications and contracts, this adjustment
11 incorporates an expected variance between budget and
12 actuals for 2009.
13 It is also important to note that this adjustment
14 is not only a reflection of the budget variance, but also
15 recognizes the operational efficiencies gained but not
16 accounted for in the Company's case.
17 Q.What are the operational efficiencies that you
18 are referring to?
19 A.One of the difficulties of dealing with pro forma
20 test years is that forecasting expenses can. be done with
21 relative accuracy based on historical trends and additional
22 planned projects. However, the benefits obtained by these
23
24 i Details of the agreements were provided confidentially pursuant to
the Protective Agreement between Avista and IPUC Staff dated January 8,
2009. Avista claims this information is exempt from public inspection
under the Commission's Procedural Rule 067 and 233, and Idaho Code §
9-340D. )
25
CASE NOS. AVU-E-09-1/AVU-G-09-t77
OS/29/09
ENGLISH, D. (Di) . 21
STAFF
e
e
e
1 expenditures are not as easily identifiable, even though
2 they do exist. For example , Avista ' s Outage Management
3 . System, as described in Exhibit No.7, page 11, is a
4 software application utilizing a Geographical Information
5 System (GIS mapping system) that allows distribution
6 facilities to be linked to individual customers service
7 points in a computer based model. Customers can report
8 outages quickly by speaking into the Company's Integrated
9 Voice Response (IVR) system. All customer calls are then
10 plotted in the GIS mapping system. The plotting of all
11 commonly affected customers associated with an outage
12 incident enables the Company to more accurately and
13 expedi tiously predict the probable cause of the outage, and
14 thus reduce restoration time. In this specific example,
15 both the Company's IVR system and Outage Management System
16 have created efficiencies that are not quantified in the
1 7 Company's case.
18 When asked about the benefits of the IVR system,
19 the Company responded in an email on April 24, 2009 that
20 the efficiencies will be operational and difficult to
21 quantify. Although Avista also stated that it had no means
22 to quantify the benefits of the Outage Management System,
23 the Company did estimate that it would save approximately
24 two to four hours each day performing restoration of
25 service on normal daily outages.
CASE NOS. AVU-E-09-1/AVU-G-09-~78
OS/29/09
ENGLISH, D. (Di) 22
STAFF
e
e
e
1 While the Company admits that operational
2 efficiencies will be achieved through nearly all of its is
3 applications, there is no attempt to quantify any of those
4 benefits that customers should receive. My calculation of
5 the variance between budgeted amounts and actual
6 expenditures, and the resulting adjustment serves as a
reasonable proxy to quantify those identified customer7
8 benefits.
9 Legal Expenses
10 Q.Please explain the adj ustment to legal expenses
11 listed on line 7 of Exhibit No. 110.
12 A.The adjustment on line 7 consists of two separate
13 components: 1) the removal of 10% of legal expenses
14 related to corporate functions such as Securities and
15 Exchange Commission (SEC) compliance, securities litigation
16 and proxy statements and standards ¡and 2) the amortization
17 of legal expenses associated with the Gas Transmission
18 Northwest Corporation (GTN) natural gas rate case filed
19 with the Federal Energy Regulatory Commission (FERC).
20 Q.Please explain the adjustment for SEC compliance-
21 type issues.
22 A.As a publicly traded company, Avista Corporation
23 is required to file reports and comply with the laws and
24 rules set up by the SEC. Because Avista Corporation
25 consists of more than just Avista Utilities, the other
CASE NOS. AVU-E-09-1/AVU-G-09-l79
OS/29/09 ENGLISH, D. (Di) 23
STAFF
e 1 subsidiaries that contribute to the Corporation should be
2 required to share in these types of corporate expenses.
3 The pressure for profit creates a risk to customers that
4 corporate management may shift the costs and burdens of
5 corporate operations so that the beneficial aspects flow to
6 the unregulated subsidiary and the burdensome aspects flow
7 to the regulated utility. Without the establishment of a
8 definitive percentage or allocation to be shared by
9 subsidiaries, the customers face the continual risk of
10 shouldering the burden of additional expenses required by
11 publicly traded companies.
12 Q.How did you determine that 10 percent was the
e 13 appropriate amount to remove from revenue requirement for
14 SEC compliance issues?
15 A.The President and Chief Executive Officer, the
16 Chief Financial Officer, the Vice President of Human
17 Resources and Corporate Secretary, the Controller and the
18 Vice President of Finance and Treasures all allocate 10
19 percent of their time and compensation to non-utility
20 operations. If the corporate executives have deemed that
21 10% of their time and attention should be assigned to non-
22 utility operations, then it is reasonable to also assign
23 .10% of the securities related expenses to non-utility
24 operations. This adjustment reduces test year legal
25 expenses by $12,000 for the Idaho Electric jurisdiction and
e
580CASE NOS. AVU-E-09-1/AVU-G-09-1
OS/29/09 ENGLISH, D. (Di) 24
STAFF
e 1 $3,000 for the Idaho Gas jurisdictions.
2 Q. . ,Please explain the remaining adjustment to legal
3 expenses for the GTN rate case at the FERC.
4 A.During the test year, Avista paid approximately
5 $47,000 to Portland General Electric for its participation
6 in the GTN rate case with FERC. Staff typically removes
7 non-recurring legal expenses from test year revenue
8 requirement to ensure that the Company is not collecting an
9 annual amount each year for an expense that was' incurred
10 for a nonrecurring event. Staff does not believe that GTN
11 will be filing annual rate cases with the FERC¡ and
12 therefore it would not be reasonable for Avista to recover
e 13 its legal expenses for this nonrecurring event each year.
14 However, because the Company incurred this expense in
15 response to a regulatory action, and because the expense
16 was prudently incurred to protect Avista customers, it
17 would be inappropriate to exclude this amount in its
18 entirety. Therefore, I propose reducing the Company's
19 legal expense related to the GTN rate case by 66.67%,
20 thereby allowing the Company to recover amounts spent over
21 a three-year period.
22 IPUC Regulatory Expense
23 Q.Please explain the adjustment to Regulatory
24 Expense on line 8 of Exhibit No. 110.
25 A.The IPUC Regulatory Expense included by the
e
581CASE NOS. AVU-E-09-1/AVU-G-09-1
OS/29/09 ENGLISH, D. (Di) 25
STAFF
e
e
e
1 Company in this case was calculated by using the 2008
2 assessment rate multiplied by test year revenues. As
3 mentioned previously in my testimony, on May 7, 2009 the
4 Commission issued Order No. 30780 which established a new
5 assessment rate of 0.1662% for 2009. This adjustment
6 simply updates the Company's calculation. The effect of
7 this adjustment reduces Regulatory Expense by $62,541 for
8 the Idaho Gas jurisdiction and $139,497 for the Idaho
9 Electric jurisdiction.
10 Insurance Expense
11 Q.Will you please explain the adjustment to
12 Insurance Expense listed on line 9 of Exhibit No 110?
13 A. When the Company was preparing its case, General
14 Liability Insurance Expense for 2009 was estimated to be
15 $4,668,084.. However, after the filing was made, the actual
16 insurance contracts were executed and the actual insurance
17 expense was $138,143 less than the Company's estimate. I
18 have reduced the Insurance Expense for the Idaho Gas
19 jurisdiction by $8,610 and for the Idaho Electric
20 jurisdiction by $34,697 to reflect this known and
21 measurable change.
22 Miscellaneous/Pròmotional Items
23 Q.Please explain the adjustment listed as
24 Miscellaneous/Promotional Items listed on line 10 of
25 Exhibit No. 110.
582CASE NOS. AVU-E-09-1/AVU-G-09-1
OS/29/09
ENGLISH, D. (Di) 26
STAFF
e
e
e
1 A.This adjustment is a catch-all for many
2 miscellaneous expenses that do not relate to the
3 production, transmission, or distribution of utility
4 services . The Company intended to remove many items that
5 were impróperly booked to utility accounts in the
6 miscellaneous restatement adjustment in its Application.
7 However, during my review of test year expenses, I found
8 numerous expenses that should have also been removed.
9 These inappropriate expenses included things such as
10 chari table contributions and donations, sponsorships for
11 tables and booths and fund raising events, golf scrambles,
12 sympathy flowers for employees, retirement and holiday
13 parties, clothing with the Avista logo emblazed, and many
14 other items that, individually, are small dollar amounts.
15 The detaileq listing of all these items has been provided
16 to the Company with Staff's workpapers. This adjustment
17 reduces expenses by $11,183 and $68,781 for the Idaho Gas
18 and Electri~ jurisdictions, respectively.
19 GAS RATE BASE ADJUSTMNTS
20 Q.Do you propose any adjustment to the Gas rate
21 base?
22 A.Yes. I propose an adjustment to decrease Idaho
23 Gas pro-forma rate base by $462,955.
24 Q.Please describe the basis for this adjustment.
25 A.The Company proposed a pro- forma rate base that
CASE NOS. AVU-E-09-1/AVU-G-09-183
OS/29/09
ENGLISH, D. (Di) 27
STAFF
e 1 included budgeted annual amounts for recurring certain
2 projects, ,known internally as ER's (Expenditure
3 Requisitions). The 2009 pro-formed amounts for Idaho were
4 based on an allocation of total system forecasts. Idaho
5 was allocated 21.83 % of the forecasted amounts based on the
6 Company's direct plant allocation factor. StaffEx.hibit
7 No. 114 illustrates the Company's 2009 system budgets and
8 the Idaho allocation. However, because Avista' s non-
9 contiguous Oregon gas distribution system is older and in
10 greater disrepair than the Idaho gas distribution system,
11 the Oregon system actually incurs a greater cost than the
12 allocation factors indicate. Over the four~year period
13 from 2005-2008, approximately 17% of the annual budget fore14these ER's were incurred by the Idaho system, therefore, I
15 propose to use the historical four-year average for each ER
16 proj ect which, in total, would reduce the Idaho Gas rate
17 base by $462,955 as calculated on Staff Exhibit No. 114.
18 Addi tionally, the depreciation expense in the amount of
19 $14,000, based on a composite depreciation rate of 3%,
20 associated with this adjustment has' been removed.
21 Q.Why did you limit your historical average to four
22 years?
23 A.The Company -changed its accounting system in
24 January 2005. Though it was not impossible to retrieve
25 data prior to 2005, information subsequent to the
e
584CASE NOS. AVU-E-09-1/AVU-G-09-1
OS/29/09
ENGLISH, D. (Di) 28
STAFF
e
e
e
1 conversion is obtained rather easily. The actual transfers
2 to plant for the four-year period since 2005 were readily
3 available and, on average, represent a fair and reasonable
4 amount to include in rate base.
5 Debt Interest Restatement
6 -
Please explain the adjustment to taxes in ColumnQ.
7 s-12 of Staff Exhibit No 111.
8 A.This adjustment restates debt interest using the
9 Company's pro forma weighted average cost of debt, as ,
10 outlined in the testimony of Staff witness Carlock. The
11 restated debt interest is then applied to Staff's proforma
12 level of rate base for Idaho's gas jurisdiction to produce
13 a pro forma level of tax deductible interest expense. The
14 Federal income tax effect of the restated level of interest
15 for the period ending December 31, 2009 increases Idaho Gas
16 net operating income by $5,000.
1 7 SPECIFIC ELECTRIC EXPENSE ADJUSTMNTS
18 Q.Will you please explain Staff Exhibit No. 115?
Staff Exhibit No. 115 is a list of four19A.
20 adjustments that I am proposing to reduce the pro forma
21 revenue requirement for Idaho's Electric jurisdiction.
22 These amounts have been provided to Staff witness Vaughn to
23 incorporate into her calculation of Staff's proposed
24 electric revenue requirement for Idaho.
25 Q.Looking at the first adjustment shown on Staff
CASE NOS. AVU-E-09-1/AVU-G-09-~85OS/29/09 ENGLISH, D. (Di) 29
STAFF
e
e
e
1 Exhibit No. 115, please summarize the Company's proposal
2 for the' Asset Management Program.
3 A.As explained in greater detail in Company witness
4 Kinney's direct testimony, the Asset Management Program
5 attempts to manage key assets throughout their life to
6 provide the best value to customers by minimizing life
7 cycle costs and maximizing system reliability. Though the
8 Asset Management Program is relatively new, many of the
9 aspects of the plan consist of acti vi ties that the Company
10 has been doing for years, such as vegetation management,
11 transformer management and wood pole management.Avista
12 launched the program in March 2004 which essentially
13 combined many of the Company's asset conservation
14 activities under one umbrella, and thus allowing the
15 Company flexibility to shift funds from one aspect of the
16 plan to another if the Company deems it necessary.
17 Staff reviewed the asset management plan and
18 concluded that prudent management of the plan would provide
19 a stream of annual benefits through avoided costs well into
20 the future, and increase system reliability. In evaluating
21 the program, Staff met with Company representatives,
22 reviewed cost calculations, avoided costs and Internal
23 Rates of Return for each project.
24 Q.Please explain the Internal Rates of Return.
25 A.The Internal Rate of Return (IRR) is a means of
CASE NOS. AVU-E-09-1/AVU-G-09~~8 6
OS/29/09 ENGLISH, D. (Di) 30
STAFF
e
e
e
1 making an investment decision by calculating the IRR and
2 comparing it to a market interest rate (i). By definition,
3 the IRRis the discount rate at which the net present value
4 of future benefits will equal the net present value of the
5 cost, and is expressed by the formula:
6
7 Vp = Eo + Ei/(1+r) + E2/(1+r)2 +...+ En/(1+r)n = 0
8
9 Where Vp is the value of the costs in the current period and
10 E represents the future benefits which are then discounted
11 back to present value. If the discount rate (r, IRR) is
12 greater than an available market rate, then one would
13 conclude that the proj ect is cost effective.
14 The Company compared the costs of each project
15 within the Asset Management Program to the potential costs
16 of inactivity, or doing nothing. In each case, it was
17 determined that the program was cost effective.
18 Q.What annual level of O&M Expenses does the
19 Company request for its Asset Management Program?
20 A.Company witness Kinney states that the projected
21 2010 level of O&M expenses for the Asset Management Program
22 are $12,505,000 (system-wide) which is an increase of
23 $4,609,000 over the test year level of $7,896,000 (system-
24 wide.) However, Company witness Andrews' exhibits and
25 workpapers indicate a pro forma adjustment to Idaho's
CASE NOS. AVU-E-09-1/AVU-G-09-f87
OS/29/09 ENGLISH, D. (Di) 31
STAFF
e 1 electric jurisdiction of $749, 000 which is Idaho's
2 allocated portion of 50% of the 2010 proj ected expenses.
3 None of the 2009 O&M Expenses for the Program were included
4 in the Company's case. The Company .was aware of this, but
5 in an attempt to mitigate the impact of the overall rate
6 increase, decided to omit the 6-months of 2009 from its
7 request. Because Company witness Andrews only included
8 six-months of O&M Expense in her revenue requirement
9 calculation, Staff accepts the Company's pro forma
10 adjustment for the Asset Management Program.
11 Q.Then please explain your adjustment to the Asset
12 Management Program.
13 A. My adjustment recognizes that the Assete14Management Program will provide benefits to customers that
15 have not been quantified or captured in the Company's case.
16 If the Company is going to pro form a higher level of
17 expenses, it must balance those expenses with the customer
18 benefits that they will achieve. During 2008, by my
19 conservative estimates from information provided to Staff
20 during an on-site audit, the Asset Management Program
21 achieved savings of $920,000 or 11, 65% of historical test
22 period expenses. By applying the 11.65% as a proxy for
23 projected customer benefits to the pro forma level of O&M
24 Expenses included in the Company's case, the result is an
25 $87,259 reduction to Idaho's electric jurisdiction pro
e
CASE NOS. AVU-E-09-1/AVU-G-09-;88
OS/29/09
ENGLISH, D. (Pi) 32
STAFF
e
e
e
1 forma 2009 expense.
2 Q.Please explain the next adjustment on Staff
3 Exhibi t No. 115, line 2.
4 A.This adjustment reduces the Company's pro forma
5 O&M Expenses for production plant by $2,862,000 (system) or
6 $1,015,000 for the Idaho electric jurisdiction.
7 Q.What is the basis for this adjustment?
The Company's case included $25,721,790 (system)8 A.
9 for O&M expenses for production plant for the period from
10 July 1, 2009 through June 30, 2010. Consistent with
11 Staff's use .of a pro formed test year ending December 31,
12 2009, the pro forma O&M Expenses for production plant are
13 $22,859,655 (system). This adjustment caps the level of
14 O&M Expenses for production plant at the proj ected level
15 for 2009.
16 Q.Similar to the adjustments you propose to capture
17 efficiencies and benefits for customers for Information
18 Systems Services and the Asset Management Program, do you
19 propose an adjustment to O&M Expenses to capture increased
20 efficiencies in production plant?
21 A.No. The Company's Production Property Adjustment
22 proposed by Company witness Andrews and described in
23 further detail in Staff witness Vaughn and Hessing's
24 testimonies attempts to capture those benefits, and thus a
25 separate adjustment is not necessary.
CASE NOS. AVU-E-09-1/AVU-G-09-189
OS/29/09
ENGLISH, D. (Di) 33
STAFF
e
e
e
1 Q..Please discuss the next adjustment on Staff
2 Exhibi t No. 115, line 3.
3 A.This adjustment reduces the pro forma O&M
4 expenses associated with the mercury control project at the
5 Colstrip generation facility as further described in the
6 direct testimony of Company witness Storro.
7 Q.What is the basis for this adjustment?
8 At the time of filing, the Company included inA.
9 its pro forma revenue requirement an estimated amount for
10 the Colstrip emissions control project, to begin in
11 December 2009. The latest estimates, provided to Staff on
12 May 12 by telephone conversation with Liz Andrews, indicate
13 that the annual expense will be $12.8 million. Because
14 Avista is only a 15% owner of Colstrip, its responsibility
15 towards the annual costs is $1.92 million
16 ($12,800,000*0.15). With the project beginning in December
17 of 2009, only 1/12 of this amount, $160,000 should be
18 included in the revenue requirement. This adjustment
19 reduces the O&M expense for the proj ect by $436,659.
"20 Q.Please explain the adjustment listed as Ross
21 Court Building - Abandoned Project on Exhibit No. 115,
22 line 4.
23 As the Company outgrows is Corporate HeadquartersA.
24 office building, it had planned to build an additional
25 office building on the north end of its campus. The
CASE NOS. AVU-E-09-1/AVU-G-09-~90
OS/29/09
ENGLISH, D. (Di) 34
STAFF
e
e
e
1 Company incurred expenses during the test year in the
2 amount of $391,512 for architectural, engineering, and
3 consul ting fees along with permits and other expenses.
4 Midway through 2008, the Company decided that the least
5 cost option would be to purchase an existing building off
6 campus, and move its call center to that location. This
7 adjustment recognizes that the project to build the new
8 office building has been abandoned, and that Company should
.9 not include these expenses in annual revenue requirement.
10 Idaho's electric jurisdiction expenses have been reduced by
11 $136, 649 to reflect that these expenses will not occur on
12 an annual basis.
13 PENSION EXPENSE
14 Q.Please summarize the Company's proposal for
15 pension expense.
16 A.As described in Company witness Thies' direct
17 testimony, the Company intends to contribute a
18 significantly greater amount to the pension plan than the
19 FAS 87 accrual expense included in rates. Though it was
20 originally thought that the Company would make a cash
21 contribution of $67 million to the pension plan in 2009,
22 the actual cash contributions for the year will be $45
23 million. Mr. Thies' concern was with the timing impact of
24 contributing substantially more to the plan than the
25 expense recognized in rates, and therefore requested
CASE NOS. AVU-E-09-1/AVU-G-09-~91
OS/29/09
ENGLISH, D. (Di) 35
STAFF
e 1 deferral accounting treatment to recognize the time value
2 of money on the difference between the cash payment and the
3 level of accrued expense.
4 Q.Does Mr. Thies recommend the deferral of the
5 difference between the FAS 87 expense and the cash
6 contribution?
7 A.No. Recognizing that the difference between cash
8 contributions and FAS 87 expense, overtime, will trend
9 towards zero, Mr. Thies is only proposing to create a
10 regulatory asset for the carrying costs on the cumulative
11 difference between payments to the plan and expenses
12 recovered in rates. In his direct testimony, he provides
e 13 an example by taking the difference of the $67 million
14 planned contribution for 2009 and the approximate $12
15 million expense currently included in rates ($55 million)
16 and multiplying it by the 8.8% requested rate of return to
17 arrive at a $4.8 million carrying charge for 2009..
18 However, that example was intended to only ,provide a scope
19 of the magnitude of dollars, and the detailed accounting
20 treatment is described further in his testimony.
21 Updating Mr. Thies' figures to account for the
22 reduced contribution in 2009, and recognizing that new
23 rates will be in effect .for half of 2009, $2.55 million, or
24 approximately half of the $4.8 million, is more reflective
25 of the actual impact on a system basis.
e 'i:92CASE NOS. AVU-E-09-1/AVU-G-09-~
OS/29/09
ENGLISH, D. (Di) 36
STAFF
e
e
e
1 Q.How did you calculate the $2.55 million estimated
2 impact?
3 A.Recognizing that the current level of expense
4 included in rates for 2009 is $12 . 1 million annually for
5 six months, and the proposed level of expense of $18.2
6 million annually for six months, the total expense included
7 in rates for calendar year 2009 would be $15.15 million.
8 The Company intends to fund $45 million to the plan for
9 2009, or $29.85 million greater than collected in rates.
10 Multiplying the difference by Staff's recommended rate of
11 return of 8.55%, the estimated impact of the time value of
12 money ~ould be $2.55 million.
13 Q. What is your position regarding Avista's proposal
14 in this case to create a regulatory asset for the
15 difference between the contribution and the expense?
16 A.While Staff recognizes Avista' s efforts to
17 maintain a solid pension plan, I do not believe that
18 Avista's proposal is appropriate at this time. Staff would
19 be willing to work with all utilities sponsoring a defined
20 benefit pension plan to discuss the appropriate accounting
21 treatment, or even the necessity, of this type of pension
22 plan.
23 Q.What is your rationale for rej ecting the
24 Company's proposal?
25 A.First, the Company's pension plan assets
CASE NOS. AVU-E-09-1/AVU-G-09-193
OS/29/09
ENGLISH, D. (Di) 37
STAFF
e 1 experienced an investment return of negative 21% during
2 2008. This investment return has led to an additional $6
3 million (system) being requested in rates due to an
4 increased expense. During an economic recession that has
5 an increased impact on northern Idaho, customers are
6 already being asked to cover the Company's increasing
7 pension expense caused primarily by the recession itself.
8 An additional regulatory asset with a carrying charge
9 simply further increases these costs and hits customers
10 with a triple whammy, so to speak.
11 Secondly, I believe it may be time for companies
12 . to evaluate whether or not a defined benefit pension plan
e 13
14
is the most prudent form of retirement benefit that a
utility can provide for its employees. The basic premise
15 of a defined benefit plan is that the future benefit is
16 defined, and therefore the employer bears all of the
17 investment risk. For a regulated utility that collects
18 pension expense in rates, that investment risk is
19 inherently passed on to customers. Current economic
20 conditions have exacerbated the issue, as witnessed by the
21 Avista Pension Plan's decreasing assets and increasing
22 contributions. The question then becomes whether or not it
23 is prudent for customers to bear the direct burden of the
24 pension assets negative returns during recessionary times,
25 and not receive direct benefits when assets perform well.
e
CASE NOS. AVU-E-09-1/AVU-G-09-~4
OS/29/09
ENGLISH, D. (Di) 38
STAFF
e
e
e
1 This asymmetrical relationship creates a natural imbalance
2 that reduces customer assets at a time when they need them
3 most.
4 Though Staff recognizes the important and
5 necessary benefit of a plan to provide retirement benefits
6 to utility employees, now is the appropriate time to begin
7 evaluating other alternatiyes.
8 Q.Could you please explain the differences between
9 a pension ,expense and a pension contribution?
10 A.Certainly. The accrued expense is the Net
11 Periodic Pension Cost as calculated under FAS 87, and is
12 often referred to as FAS 87 expense, or just pension
13 expense. This is the amount accrued on the Company' s ~books
14 and reported on the Company's financial statements. The
15 Financial Accounting Standards Board issued FAS 87 in
16 December of 1985 in an attempt to alleviate investors'
17 concerns regarding accuracy of a company's financial
18 statements and the potential for manipulation of pension
19 costs to affect those statements. The Board's objectives
20 in issuing the statement were:
21 1.To provide a measure of net periodic pension
cost that is more representationally faithful
than those used in past practice because it
reflects the terms of the underlying plan and
because it better approximates the recognition
of. a cost of an employee'8 pension over that
employee's service period.
22
23
24
25
CASE NOS. AVU-E-09-1/AVU-G-09-195
OS/29/09 ENGLISH, D. (Di) 39
STAFF
e
e
e
1 2.To provide a measure of net periodic pension
cost that is more understandable and comparable
and is, therefore, more useful than those used
in the past.
2
3
3.To provide disclosures that will allow users to
understand better the extent and effect of an
employer's undertaking to provide employee
pensions and. related financial arrangements.
To improve the reporting of financial position.
4
5
6 4.
7 The net cost feature of FAS 87 means that the
8 recognized consequences of events and transactions
9 affecting a pension plan are reported as a single net
10 amount on the employer's financial statements. This
11 approach aggregates at least three items that might be
12 reported separately for any other part of an employer's
13 operations: the compensation cost of benefits promised,
14 interest cost resulting from deferred payment of those
15 benefits, and the results of investing what are öften
16 significant amounts of assets.
17 Under normal circumstances, companies have some
18 discretion as to how much they contribute to a pension plan
19 for a given year. There is a cost range and companies can
20 contribute any amount between the Required Minimum
21 Contribution and the Maximum Deductible Contribution.
22 Section 412 of the Internal Revenue Code mandates the
23 minimum funding, while section 404 mandates the maximum
24 funding.
25 Q.Could you briefly explain how that cost range is
CASE NOS. AVU-E-09-1/AVU-G-09-1t6
OS/29/09 ENGLISH, D. (Di) 40
STAFF
e 1 determined?
2 A.The first calculation determines the Normal Cost
3 of the year. The Normal Cost is the annual cost of the
4 pension plan using the plan's actuarial cost method, as
5 established in the plan document. The Normal Cost is a
6 calculation that takes into consideration the present value
7 of future benefits, the actuarial value of the plan's
8 assets, and unfunded liabilities and the present value of
9 the Company's future payroll. With that information, one
10 can then calculate an accrual rate that when multiplied by
11 the Company's current covered payroll will produce the
12 Normal Cost. After the Normal Cost is calculated, any
e 13 charges or credits are added or subtracted to get the
14 Annual Cost. The Minimum Required Contribution is the
15 lesser of the Annual Cost or the difference between the
16 Full Funding Limitation and any credit balance. The
17 Minimum Required Contribution is the amount that a company
18 must fund in order to avoid a funding deficiency in the
19 Funding Standards Account.
20 Q.You mentioned the term "Full Funding Limitation."
21 Could you please describe this limitation?
22 A.The Full Funding Limitation is a calculation that
23 compares the Actuarial Accrued Liability as calculated
24 under the Employee Retirement Income Security Act (ERISA)
25 of 1974, the Current Liability under the Omnibus Budget
e
597CASE NOS. AVU-E-09-1/AVU-G-09-1
OS/29/09
ENGLISH, D. (Di) 41
STAFF
e
e
e
1 Reconciliation Act (OBRA) of 1987, and the Current
2 Liability under the Retirement Protection Act (RPA) of
4
3 1994.
Q.Now that the minimum point in the cost range is
5 established, how is the maximum point determined?
6 A.The Maximum Deductible Contribution is an IRS
7 calculation that determines the deductibility under Section
8 404 (a) (1) (A) of the Internal Revenue Code. This
9 calculation is based on a comparison of any unfunded
10 liabilities and the Full Funding Limitation. A company may
11 choose to contribute to a pension plan any amount that is
12 greater than the Minimum Required Contribution but less
13 than the Maximum Deductible Contribution.
14 Q. What are the funding levels for the Avista
15 pension plan for 2009?
16 While the FAS 87 expense for 2009 is estimated toA.
i 7 be approximately $22 million, the Minimum Required
18 Contribution for 2009 is $0.00. However, because Avista
19 significantly contributed additional funds to the plan over
20 the past few years, the funding standard carryover balance
21 as of December 31, 2008 was nearly $30 million. This
22 amount reduces the Minimum Required Contribution. Without
23 this overfunding, I have estimated that. the Minimum
24 Required Contribution for 2009 would be in the range of $16
25 million - $20 million, which is comparable to the $18.2
598CASE NOS. AVU-E-09-i/AVU-G-09-1
OS/29/09
ENGLISH, D. (Di) 42
STAFF
e
e
e
1 million (system) FAS 87 expense being requested in this
2 case. The Maximum Deductible Contribution that Avista
3 could make to the plan for 2009 is in the range of $225
4 million to $250 million. As mentioned previously, Avista
5 will contribute $45 million to the plan for 2009.
6 Q.How did Avista determine that $45 million was the
7 appropriate level of funding for 2009?
8 A.The requirement that accounting information is on
9 an accrual basis does not necessarily mean that accounting
10 information and funding decisions are completely unrelated.
11 Employers may use accounting information along with other
12 factors in making financial decisions. Some employers may
13 decide to change their pension funding policies based in
14 part on the new accounting information, or new pension
15 regulations, such as the Pension Protection Act (PPA) of
16 2006, and the decision to fund a pension plan to a greater
17 or lesser extent is an economic decision.
18 The Pension Protection Act of 2006 adjusts the
19 Minimum Required Contribution set forth under ERISA in an
20 attempt to shore up the nation's ailing pension plans. The
21 effect of the PPA is to increase pension contributions in
22 order to eventually achieve a fully funded plan. For 2009,
23 it is required that pension plan assets be equal to 94% of
24 the proj ected liabilities. If this benchmark is not met,
25 the entire funding deficit must be added to the
599CASE NOS. AVU-E-09-1/AVU-G-09-1
OS/29/09 ENGLISH, D. (Di) 43
STAFF
e
e
e
1 contribution and amortized over the next seven years in
2 order to be fully funded after the seven year period.
3 Avista has determined that a contribution of $45 million
4 will allow it to meet the 94% funding level benchmark, and
5 avoid additional mandatory contributions.
6 Q.Given the likelihood of increased pension expense
7 and funding levels in the near future, do you propose any
8 alternatives to a defined benefit pension plan?
9 A.In this case, my intent is not to propose any
10 changes to the Company's retirement benefits, but rather to
11 open the door for discussion of possible alternatives. One
12 example of an alternative would be a Money Purchase Pension
13 Plan. A Money Purchase Pension Plan is a defined
14 contribution plan where the employer contributions are
15 fixed, typically stated as a percentage of ariemployee' s
16 income. Much like a 401 (k) plan, the investment risk would
17 then be shifted away from customers, while company
18 employees would continue to accrue retirement benefits. A
19 Money Purchase Pension Plan with a defined contribution of
20 10% of an employee's income would provide substantial
21 retirement benefits to the employee when coupled with the
22 existing 401 (k) and 401 (m) matching contributions. It
23 would also allow economic certainty because the
24 contributions would not fluctuate wildly from year to year.
25 Given the current levels of funding for the
CASE NOS. AVU-E-09-1/AVU-G-09-~0005/29/09
ENGLISH, D. (Di) 44
STAFF
e
e
e
1 pension plan, customers would actually pay less with the
2 defined contribution Money Purchase Pension Plan. Avista' s
3 total covered compensation under IRC 401 (a) (17) for 2008
4 was approximately $132 million. A 10% Money Purchase
5 Pension Plan for 2008 would require a $13.2 million
6 contribution, as opposed to a $45 million contribution,
7 which is greater than one-third of the covered compensation
8 under the plan. Please note that I am not supporting a 10%
9 defined contribution, but rather using it for illustrative
10 purposes only.
11 Q.To reiterate, are you proposing any adjustments
12 to the current level of retirement benefits in this case?
13 A. No. However, given the rapidly increasing costs
14 of pension plans, the inherent customer risk associated
15 with them, and annual increases in wages and 'salaries,
16 Staff will continue to look at other alternatives and may
17 propose adjustments in future rate cases if trends continue
18 in the same direction.
19 Q.Does this conclude your direct testimony in this
20 proceeding?
21 A.' Yes, it does.
22
23
24
25
CASE NOS. AVU-E-09-1/AVU-G-09-i01
OS/29/09
ENGLISH, D. (Di) 45
STAFF
e
e
e
1 Q.Please state your name and address for the
2 record.
3 A. My name is Cecily Vaughn. My business address
4 is 472 West Washington Street, Boise, Idaho.
5 Q.By whom are you employed and in what
6 capacity?
7 A.I am employed by the Idaho Public Utilities
8 Commission (Commission) as an auditor in the Utilities
9 Division.
10 Q.What is your educational and experience
11 background?
12 A.I graduated from Washington State Uni versi ty
13 in 1974 with a Bachelors of Science degree in Veterinary
14 Science; I received my degree as a Doctor of Veterinary
15 Medicine at the same time. I practiced as a veterinarian
16 in the State of Washington until approximately 1987.
17 From 1993 until 1996 I attended the College of Business
18 and Economics at the University of Arkansas in
19 Fayetteville, Arkansas. From 1996 until 1997 I studied
20 at the College of Business at Boise State University with
21 an emphasis in accounting. I passed the Uniform CPA exam
22 in the fall of 1997; I am currently a licensed CPA in the
23 State of Idaho.
24 I was employed as a financial analyst by
25 Hewlett Packard from 1998 until 2000. In that position I
CASE NOS. AVU-E-09-1/AVU-G-09-b02
OS/29/09
VAUGHN, C (Di) 1
STAFF
provided sole financial support for the HP test lab
located in Boise, a cost center with an annual budget in
excess of $50 million. I was solely responsible for
coordinating the semi-annual budgeting process, for
developing and implem~nting the allocation system used to
distribute costs to multiple profit centers, and for
ensuring that costs incurred were appropriate and met
budgetary goals. During this time I also served. as
inventory analyst for the Personal LaserJet Division, a
$2 billion per year profit center. In this role, I was
responsible for accurate valuation of worldwide inventory
and for removal of intra-corporate profit included in
inventory value.
From 2000 until 2003 I was employed as
Grants Accountant (Financial Specialist) for the Center
for Geophysical investigation of the Shallow Subsurface
at Boise State University; i was promoted to Senior
Financial Specialist in 2002. During my employment at
BSU, i was responsible for all aspects of grant
accounting for the Center, including budgeting,
submission, and ensuring that grant funds were expended
and accounted for in accordance with funding agency
regulations. i also assisted in the preparation of the
F&A (Facilities and Administration) request used to set
the overhead rate applied to all Federal Grants awarded
CASE NOS. AVU-E-09-i/AVU-G-09-~03
OS/29/09
VAUGHN, C (Di) 2
STAFF
e
e
e
1 the University.
2 I have been employed by the Commission as an
3 auditor since June 2007. I attended the annual
4 regulatory studies program sponsored by the National
5 Association of Regulatory Utili ties Commissioners (NARUC)
6 at Michigan State University in August 2007. In
7 addition, I have attended numerous professional seminars
8 and workshops related to energy, utility regulation, and
9 accounting.
10 SUMY
11 Q.What is the purpose of your testimony?
The purpose of my testimony is to present12A.
13 the Staff-recommended revenue increase to base rates for
14 the Avista Utilities' Idaho electric jurisdiction. First
15 I will present adj ustments recommended by Staff that
16 affect the Idaho electric net operating income and rate
17 base. Finally I will present the model that develops the
18 Idaho electric revenue requirement and shows how the
19 Staff recommendation differs from the revenue requirement
20 proposed by Company witness Andrews in her pre-filed
21 testimony at page 5, line 10.
22 Q.In addition to the Company revenue
23 requirement, does your testimony address any other
25
24 issues?
A.Yes. I reviewed the allocation and
CASE NOS. AVU-E-09-1/AVU-G-09-~04
OS/29/09 VAUGHN, C (Di) 3
STAFF
jurisdictional separation methodologies used by the
Company to assign costs to the different geographic
jurisdictions (Idaho, Oregon, or Washington) and to the
different functional areas (electric or gas). My review
of these methodologies included (a) development of the
four-factor allocation factors and (b) the jurisdictional
separation methodology and it's linkage to the cost of
service methodology.
Q. Did your review of these areas affect the
revenue requirement proposed by Staff?
A. No.
Q. Does Staff recommend any changes to these
allocation models at this time?
A. No. The allocation models employed by the
Company have been in use for some time. Staff reviewed
these models and believes the methodology to be
reasonable and does not recommend any change to the
allocation methodology at this time.
Q. Are you sponsoring any exhibits?
A. Yes, I am sponsoring Exhibit Nos. 116
through 118.
STAF ADJUSTMNT SUMY AN REVENU REQUIRENT
Q. Please describe the method by which Avista
developed its forecast test year.
A. Avista developed a pro formed year for the
CASE NOS. AVU-E-09-1/AVU-G-09-~05
OS/29/09
VAUGHN, C (Di) 4
STAFF
e
e
-
1 period of July 1, 2009 through June 30, 2010. This year
2 was developed as follows.(1) The actual data for the
3 12-month period ending September 30, 2008 was modified by
4 routine regulatory and normalization adjustments to
5 develop th~ base year.(2) Base year amounts were
6 adjusted by category to develop the pro formed 2009-2010
7 year. The model for the development of the historical
8 test year is shown in the electronic workpapers provided
9 with this testimony.
10 Q.Please explain how Staff audited and made
11 adjustments to the Company pro formed year .
12 A.First, Staff audited the base year data.
13 Second, Staff evaluated the various pro formed
14 adjustments proposed by the Company to determine if the
15 adjustments were known and measurable and to determine if
16 the adjustments were reasonable for ratemaking purposes.
17 Q.Does Staff recommend any changes to the pro
18 formed year?
19 A.As discussed by Staff witness Lobb, Staff
20 believes the year ending December 31, 2009, is more
21 reasonable for ratemaking purposes. Therefore Staff
22 recommends that pro formed adjustments, with the
23 exception of power supply, be consistent with the year
24 ending December 31, 2009.
25 Q.Please summarize Staff's recommendations in
CASE NOS. AVU-E-09-1/AVU-G-09-~06
OS/29/09
VAUGHN, C (Di) 5
STAFF
this case.
A. Staff recommends a total electric revenue
requirement of $250,621,000. This is the sum of
$241,999,000 adjusted test year revenues plus the
$8,622,000 revenue deficiency calculated by Staff. This
results in a 3.91% overall increase in base revenues.
Staff's recommended revenue requirement is based on an
Idaho electric rate base of $564,144,000; total electric
,
operating income of $42,721,000; total electric operating
expenses of $186,708,000 for the Idaho jurisdiction; and
a rate of return of 8.55%.
Although Staff recommends an increase of
3. 91% in base rates, Staff also recommends that this
increase be offset by a decrease in the Power Cost
Adj ustment (PCA) for a net average increase of zero. The
decrease in the PCA is discussed further by Staff witness
Hessing in his testimony.
Sumary of Adjustments
Q. Please explain Exhibit No. 116.
A. Exhibit No. 116 consists of two pages.
Column (c) on page 1 summarizes the calculation of the
$8,622,000 revenue requirement at the 8.55% rate of
return recommended by Staff. Staff witness Carlock
discusses the cost of capital and rate of return in her
testimony. Column (b) shows the calculation of the
CASE NOS. AVU-E-09-1/AVU-G-09-q07
OS/29/09
VAUGHN, C (D¡) 6
STAFF
e
e
e
1 revenue requirement proposed by the Company at an 8.80%
2 rate of return. Column (d) shows the difference between
3 the Company proposal and Staff's recommendation.
4 Q.Please explain Exhibit No. 116, page 2.
5 A.Exhibit No. 116, Page 2, Column (c) shows
6 the derivation of the net operating income to gross
7 revenue conversion factor used by Staff and compares the
8 conversion factor to that used by the Company as shown in
9 Column (b). The only difference between the Company
10 conversion factor and that used by Staff is due to a
11 change in Commission regulatory fees and appears on line
12 (4). This change is discussed further in Staff witness
13 English's testimony.
14 Q.Please explain Exhibit No. 117.
15 A.Exhibit No. 117 consists of two pages and
16 compares the pro forma electric operating results and
17 rate base recommended by Staff to that proposed by the
18 Company for the Idaho jurisdiction as described by
19 Company witness Andrews in her prefiled testimony at page
20 14, line 15, through page 15, line 8.
21 Column (b), pages 1-2, of Exhibit No. 117
22 shows the pro forma results of operations as proposed by
23 the Company under existing rates. Column (c) shows the
24 revenue increase proposed by the Company to earn an 8.80%
25 rate of return. Column (d) reflects pro forma electric
CASE NOS. AVU-E-09-1/AVU-G-09-~08
OS/29/09 VAUGHN, C (Di) 7
STAFF
e
e
-
1 operating results with the Company-proposed increase of
2 $31,233,000. Column (e) shows the adjustments Staff
3 believes should be made to the Company's pro forma
4 results of operations. Column (f) shows the pro-forma
5 total results of operations recommended by Staff. Column
6 (g) reflects the revenues and related exp~nses required
7 for the Company to earn the recommended 8.55% rate of
8 return. Column (h) shows the pro forma electric
9 operating results with the Staff-recommended increase of
10 $8,622,000.
11 Q.Please explain Exhibit No. 118.
12 A.Exhibit No. 118 summarizes the adjustments
13 recommended by each Commi s s ion S taf f member. Exhibi t No.
14 118 consists of 4 pages and lists all adjustments
15 recommended by Staff that affect revenue requirement.
16 Page 1 of Exhibit No. 118 summarizes total adjustments
17 recommended by Staff and shows the impact of the
18 adjustments on net operating income and rate base. Pages
19 2-4 list the individual adjustments recommended by Staff
20 and also shows how each individual adjustment affects net
21 operating income and rate base.
22 Page 1 of Exhibit No. 118 summarizes total
23 adjustments for each Staff witness. Column (b) shows the
24 pro formed revenues, expenses, net operating income and
25 rate base as proposed by the Company. Column (c) shows
CASE NOS. AVU-E-09-1/AVU-G-09-~09
OS/29/09
VAUGHN, C (Di) 8
STAFF
e
e
e
1 the total of all adjustments recommended by Staff witness
2 English. Adjustments recommended by Mr. English have no
3 effect on revenues, decrease electric expense by
4 $3,132, 000, and increase net operating income by
5 $2, 036, 000; there is no impact on rate base. Staff
6 witness English discussed these adjustments in his
7 testimony. Column (d) shows the total of all adjustments
8 recommended by Staff witness Leckie. Adjustments
9 recommended by Mr. Leckie have no effect on revenues,
10 decrease electric expense by $2,113, 000, and increase net
11 operating income by $1,374, 000 . Mr. Leckie recommends
12 reducing rate base by $14,832, 000. He discusses these
13 adjustments in his testimony. Column (e) shows the total
14 of all adjustments recommended by Staff witness Sterling.
15 Adjustments recommended by Mr. Sterling decrease revenues
16 by $11,670, 000 and decrease electric expense by
17 $25,886, 000, thus increasing net operating income by
18 $9,241,000; Mr. Sterling's adjustments have no impact on
19 rate base. Staff witness Sterling discussed these
20 adjustments previously in his testimony.
21 Column (f) shows the total of all
22 adjustments recommended by me. These adjustments
23 increase revenues by $509, 000, increase electric expense
24 by $1,492,000, and so decrease net operating income by
25 $792, 000; rate base is increased by $1,542, 000. Column
CASE NOS. AVU-E-09-1/AVU-G-09-~10
OS/29/09 VAUGHN, C (Di) 9
STAFF
e
e
-
1 (g) shows the pro formed revenues, expenses, net
2 operating income, and rate base recommended by Staff to
3 be used in calculation of the revenue requirement in this
4 case.
5 Q.Please explain pages 2-4 of Exhibit No. 118.
6 A.Pages 2-4 show each adjustment recommended
7 by Staff witnesses. Columns (c-o) and Column (r) show
8 each adjustment recommended by Staff witness English.
.9 Column (q) and Columns (s-t) show the individual
10 adjustments recommended by Staff witness Leckie. Column
11 (p) shows the adjustments to power supply costs
12 recommended by Staff witness Sterling. Columns (u-v)
13 show the adjustments that I recommend. Column(w) shows
14 the pro formed revenues, expenses, net operating income,
15 and rate base recommended by Staff to be used in
16 calculation of the revenue requirement in this case. Row
17 (3) shows the workpaper reference for each of the
18 individual adjustments.
19 Q.Please explain the adj ustments you recommend
20 in Exibit No. 118, Columns (u-v).
21 A.Column (v) of Exhibit No. 118 shows the
22 production property adjustment. This Staff adjustment
23 mitigates other Staff changes and modifies the Company's
24 production property adjustment. This adjustment
25 increases revenues by $509,000, increases electric
CASE NOS. AVU-E-09-1/AVU-G-09-d11
OS/29/09
VAUGHN, C (Di) 10
STAFF
e
e
e
1 expenses by $1,492,000, and thus decreases net operating
2 income by $639,000. In addition this adjustment
3 increases rate base by $1,542,000. This calculated
4 adjustment corrects a timing difference between the
5 forecast load growth and the time rates are expected to
6 go into effect. This adjustment is discussed further in
7 Staff witness Hessing's testimony.
8 Column (u) shows the debt reconciliation.
9 This adjustment restates debt interest by using the Staff
10 proposed pro forma weighted average cost of debt and
11 applying it to Idaho's pro forma level of rate base.
12 This calculation produces a pro forma level of tax
13 deductible interest expense. The federal income tax
14 effect of the restated level of interest for the test
16
15 period decreases Idaho net operating income by $153,000.
Q.Does this conclude your direct testimony in
18
17 this proceeding?
19
20
21
22
23
24
25
A.Yes, it does.
CASE NOS. AVU-E-09-1/AVU-G-09-al2
OS/29/09 VAUGHN, C (Di) 11
STAFF