20041008Final Order No 29602.pdf

Office of the Secretary
Service Date
October 8, 2004
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION OF
VISTA CORPORATION FOR THE
AUTHORITY TO INCREASE ITS RATES AND )
CHARGES FOR ELECTRIC AND NATURAL
GAS SERVICE TO ELECTRIC AND NATURAL
GAS CUSTOMERS IN THE STATE OF IDAHO.
CASE NO. A VU-04-
VU -04-
ORDER NO. 29602
ISSUED OCTOBER 8, 2004
BOISE, IDAHO
TABLE OF CONTENTS
Summary...................................................................................................................................... 1
Application...................................................................................................................................
Appearances .................................
,...............................................................................................
Public Workshops, Hearings and Comments...............................................................................
A vista Utilities - Electric and Gas ............................................................................................ 4
Test Year ......................................................""""""""""""""""""""""""""".............Capital Structure and Rate of Return ............................................................................... 5
1. Capital Structure................................................................................................
2. Cost of Debt ......................................................................................................
3. Cost of Trust Preferred Securities..................................................................... 6
4. Cost of Preferred Stock ......................................................
................................
5. Cost of Common Equity Capital....................................................................... 7
A vista s Electric Case .............................................................................................................. 10
Adjustments to Electric Test Year Revenues, Expenses and Rate Base.................................... 10
A. Agreed Upon Adjustments......................................................................................
1. Accounts Receivable Program Fees................................................................
2. Debt Interest Restatement Adjustment............................................................
3. Low Income Weatherization Assistance (LIW A) Funding ............................
4. Demand Side Management (DSM) Funding Levels.......................................
5. Coyote Springs 2 (CS2) Deferred Return .......................................................
B. Disputed Adjustments.... ..........................................................................................
1. Transmission Projects
.....................................................................................
2. Boulder Park Small Generation Proj ect .......................................................... 1 7
3. Prudency of Coyote Springs 2 (CS2) .............................................................. 19
4. Vegetation Management (Tree Trimming) ..................................................... 22
5. Pension Expense..............................................................................................
6. Legal Expenses..................................... ................... ........................................ 25
Rate Base.. ........... ........ .....................
........................................................................ .....
Revenue Requirement................................................................................................... 26
Summary of Adjustments to Electric Test Year Revenues, Expenses and Rate Base............... 26
Calculation of Revenue Deficiency ...........................................................................................
Jurisdictional Separations, Cost of Service and Rate Design 27 ...............................................
1. Jurisdictional Separations.........................................................................................
2. Class Cost of Service Methodology......................................................................... 27
A. Weather Normalization
..................... ..................... .................. ............ ..........
B. Power Supply Adjustments ............................................................................
3. Class Revenue Allocations ....................................................................................... 32
4. Rate Design and Tariff Issues................................................................................... 32
A. Residential Service (Schedule 1)....................................................................
B. General Service (Schedules 11 and 12).......................................................... 34
C. Large General Service (Schedules 21 and 22) .............................. ............ ..... 35
D. Extra Large General Service (Schedule 25) """"""""""""""""""""""""'" 3
E. Potlatch's Lewiston Plant ...............................................................................
F. Pumping Service (Schedules 31 and 32) ........................................................
G. Street and Area Lighting (Schedules 41 and 49)............................................ 39
Electric Rates ......................................................""""""""""""""""""""""""""".................
Power Cost Adjustment (PCA) Issues....................................................................................... 40
1. Deal "A" and Deal "B" (PCA Issues) ...................................................................... 40
2. Updated PCA Components.......................................................................................
3. PCA Rate Recovery.................................................................................................. 47
4. PCA Rate Design......................................................................................................
Other Issues................................................................................................................................
1. After Hours Connection Fees..
................ ................... ........... ........... ....... ............
..... 48
2. Winter Payment Plan.......... ............................................................................. .........
3. Telephone Call Center....... ........................ ............................................................... 49
4. Prudency of DSM Expenditures................ ................................................ ............... 50
5. Advanced Meter Reading (AMR) ............................................................................
6. Intervenor Funding............. ............................................................................. .........
A vista s Natural Gas Case....................................................................................................... 52
Adjustments to Gas Test Year Revenues, Expenses and Rate Base.......................................... 53
A. Agreed Upon Adjustments ......................................................................................
1. Gas Inventory....... ........................................................................................... 54
2. Accounts Receivable Program Fees................................................:............... 55
3. Restate Debt Interest .......................................................................................
B. Disputed Issues ........................................................................................................
1. Pension Expense.............................................................................................. 55
. 2. Legal Expense. ....................................................................... ......................... 55
Summary of Adjustments to Gas Test Year, Revenues, Expenses and Rate Base .................... 55
Rate Base ...................................................................................................................................
Revenue Requirement................................................ ........... ..................... ................................ 56
Calculation of Revenue Deficiency.......
......
...................................... ........................................ 56
Gas Jurisdictional Separations, Weather Normalization and Cost of Service ........................... 57
1. Gas Jurisdictional Separations.................................................................................. 57
2. Weather Normalization........................ ........ ..................... ................. ...................... 57
3. Gas Cost of Service ..................................................................................................
4. Cost of Gas in Base Rates ........................................................................................ 58
Natural Gas Rate Design and Tariff Issues........................................... .....................................
1. Residential (Schedule 101).......................................................................................
2. Large General Service (Schedule 111)..................................................................... 59
3. Extra Large General Service (Schedule 121) ........................................................... 60
4. Interruptible Service (Schedule 131) ........................................................................
5. Transportation Service (Schedule 146) ....................................................................
6. Special Contracts ......................................................................................................
Other Issues................................................................................................................................
1. Prudency ofDSM Expenditures...............................................................................
2. Tariff Summary Sheet ..............................................................................................
Conclusions of Law ........,..........................................................................................................
ORDER......................................................................................................................................
Appendices
Office of the Secretary
Service Date
October 8, 2004
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION OF
VISTA CORPORATION FOR THE
AUTHORITY TO INCREASE ITS RATES AND )
CHARGES FOR ELECTRIC AND NATURAL
GAS SERVICE TO ELECTRIC AND NATURAL
GAS CUSTOMERS IN THE ST ATE OF IDAHO.
CASE NO. A VU-04-
A VU -04-
ORDER NO. 29602
SUMMARY
On February 6, 2004, Avista Corporation dba Avista Utilities (Avista; Company)
filed an Application with the Idaho Public Utilities Commission (Commission) for authority to
increase its rates and charges for electric and natural gas service in the State of Idaho. The
Company serves approximately 109 315 electric customers and 61 799 natural gas customers in
northern Idaho. A change in the Company s current Power Cost Adjustment (PCA) surcharge
was also requested. On September 9, 2004, the Commission issued Amended Interlocutory
Order No. 29588 that contained our initial findings in these cases and authorized changes in the
Company s electric and natural gas rates. In this final Order we reaffirm the rate changes set out
in Order No. 29588 and provide our detailed findings.
By this final Order the Commission affirms the change in electric rates authorized in
Amended Interlocutory Order No. 29588 and authorizes the Company to increase its Idaho
electric base revenue requirement by $24 716 195' or approximately 16.90%. This increase is
offset by disallowances in the Power Cost Adjustment (PCA) coupled with an adjustment in the
PCA recovery period and a reduction in the Energy Efficiency Rider. These offsetting
adjustments reduce the authorized net revenue increase to $3 182 000 or 1.9% of current annual
revenue. The electric rates we approve as just and reasonable are set out in attached Appendix
A. Idaho Code ~ 61-502. The net amount of actual increase varies by class of customer and
usage. The resultant increase for an electric residential customer using an average of 941 kWh
per month is $4., or a 7.1 % increase in the customer s electric bill.
The Commission also affirms the change in natural gas rates authorized in Amended
Interlocutory Order No. 29588 and authorizes the Company to increase its Idaho natural gas
revenues by $3 311 000 or approximately 6.38%. The natural gas rates we approve as just and
reasonable are those set forth in attached Appendix B. Idaho Code ~ 61-502. The base rates we
ORDER NO. 29602
approve are the embedded fixed base rates used in the updated weighted average cost of gas
(W ACOG) calculation of $0.44989 per therm and incorporated in the Company PGA
adjustment authorized in Order No. 29590, Case No. A VU-04-2. The net amount of actual
increase varies by class of customer and usage.The resultant increase for a natural gas
residential customer using an average of 73 therms of gas per month is $12.84 per month, or
21.390/0.
In this Order the Commission approves a pro forma electric rate base of
$424 114 000; a pro forma natural gas rate base of $59 653 000; a return on equity of 10.4%;
and an overall rate of return of9.25%.
APPLICATION
A vista is a public utility engaged in the generation, transmission and distribution of
electric power and the distribution of natural gas. The Company in its Application requested a
Commission Order approving revised electric and natural gas rates and charges effective March
, 2004. The proposed effective date was suspended pending hearing on the Application and
further Order of the Commission. Order No. 29432; Idaho Code ~ 61-622.
Avista s last electric general rate case in Idaho was completed in 1999. (Case No.
WWP-98-, Order No. 28097.) Since that time, Avista s overall electric rates in Idaho have
been modified under the Company s Power Cost Adjustment (PCA) mechanism to reflect
changes in power costs related to streamflow and wholesale market conditions. A vista contends
that an electric rate increase is necessitated by new generating projects reduced wholesale
revenue and increased fuel costs. The Company s original Application request of $35.2 million
or a 24.1 % increase in electric revenue was revised at hearing to $31.1 million or 21.20/0.
A vista s last natural gas general rate case in Idaho was completed in 1989. (Case
No. WWP-88-, Order No. 22749.Since that time, Avista s overall natural gas rates in
Idaho have been modified under the Company s Purchased Gas Cost Adjustment (PGA)
mechanism to reflect changes in variable gas-related costs. Avista contends that a natural gas
rate increase is necessitated by decreased therm usage and increased general business expenses.
The Company s original request of $4.754 million or a 9.160/0 increase in natural gas revenue
costs was revised at hearing to $4.06 million or 7.8%.
The Company s requested revenue increase in its Application is predicated on a
proposed 9.82% rate of return, including an 11.50/0 return on equity. Tr. at 98; 104. Avista
ORDER NO. 29602
alleges that the rates in its present tariffs are no longer reasonable or adequate and do not allow
it to earn a fair and reasonable return on investment.
Appearances
A technical hearing in Case Nos. A VU-04-1 and A VU-04-1 was held in Boise
Idaho the week of July 19, 2004. The following parties appeared by and through their respective
counsel of record:
A vista Corporation
Potlatch Corporation
Coeur Silver Valley, Inc.
David S. Meyer, Esq.
Conley E. Ward, Esq.
Charles L. A. Cox, Esq.
Brad M. Purdy, Esq.
Scott D. Woodbury, Esq.
Lisa Nordstrom, Esq.
A continued technical hearing was held in Boise on August 16, 2004.
Community Action Partnership
Association of Idaho (CAP AI)
Commission Staff
Public Workshops, Hearings and Comments
Prior to the technical hearings in this case, the Commission Staff in May 2004
conducted public workshops in Coeur d' Alene and Moscow to discuss the Company
Application and to answer customer questions. Public testimony hearings conducted by the
Commission were held in Kellogg and Sandpoint on July 26 2004 and in Lewiston on July 27
2004. Six customers attended the workshops and about 100 people attended the three public
hearings. Of those who attended, 25 people testified at the hearings. Among those testifying
were Idaho State Senator Shawn Keough and Representative Bonnie Douglas. The Commission
also solicited public written comments regarding the Company s Application. By August 6
2004, the Commission had received written comments from 81 residential customers and 15
non-residential customers. The Commission also received written comments from area taxing
authorities - four school districts Shoshone and Clearwater County Commissioners, and a
sewer district, all concerned about the impact of a rate increase. Additionally, more than 1 500
signatures were attached to four separate petitions from the Company s customers. All those
who commented and signed petitions opposed any rate increase.
The Commission greatly appreciates the efforts customers made to express their
opinions regarding their electric and natural gas rates. Approximately one-half of the comments
were from low and fixed income customers concerned about being able to afford any increases
ORDER NO. 29602
in their utility bills. More than one-half of the residential customer comments also asked that
the Commission consider the poor economy in northern Idaho before granting any rate
Increases.
We have reviewed and considered the record in Case Nos. A VU-04-1 and A VU-
04-1 including: the Prehearing Memorandum filed by Potlatch; the transcript of technical
proceedings; the transcript of public testimony and filed public comments; and the Petition for
Intervenor Funding filed by CAP AI. Although this Order grants an increase, our decisions on
Low Income Weatherization Assistance, DSM programs and the Winter Payment Program can
help customers manage their bills. With this background in mind we now discuss the test year
capital structure and rate of return issues presented in this case and common to both the
Company s electric and natural gas operations.
Avista Utilities - Electric and Gas
As set out in greater detail below, the Commission approves a normalized 12-month
test year ending December 31 2002 for net operating income and an average of monthly
averages 2002 test year for rate base for A vista Utilities. We approve an embedded capital
structure for Avista at December 31 , 2003 consisting of 50.080/0 debt, 5.57% trust preferred
securities, 1.760/0 preferred stock and 42.59% common equity. We accept an embedded cost of
debt of 8.68%, embedded cost for trust preferred securities of 6.150/0 and embedded preferred
stock cost of 7.350/0. We approve a return on common equity of 10.4% and an overall weighted
cost of capital and rate of return of9.25%.
Test Year
A vista proposed a 2002 test year presented on a pro forma basis for net operating
income and an average of monthly average 2002 test year for rate base items. Tr. at 147. Staff
accepted the 20.02 test year proposed by the Company. Tr. at 1117. Potlatch witness Peseau
argues that use of a 2002 test year, adjusted for allegedly known and measurable changes
produces a mismatch of revenues from 2002 and year-end expenses and rate base from 2004.
This mismatch, Potlatch contends, should be corrected by: (1) reversing the pro forma entries
. and properly matching test year averages for both sides of the ledger, (2) updating revenues to
the 2004 level in the same manner as rate base and expenses (preferred method), or (3)
employing the rate base adjustments adopted in the Idaho Power rate case. Tr. at 922-926.
ORDER NO. 29602
Addressing Potlatch's contention that there is a mismatch between revenues and
expenses, A vista witness Falkner contends that each of the Company s test year adjustments fall
into an accepted category of adjustment.Revenues, the Company maintains, cannot be
annualized to 2004 year-end levels to correct a Potlatch-perceived mismatch because: (1) the
2004 year-end levels of revenues would not be "known and measurable" for another six months
(2) expenses would also need to be adjusted to year-end, and (3) additional revenue from load
growth caused by new customers would be offset by additional costs. Tr. at 214-217.
The Commission finds that the timing of the Company s rate case filing was dictated
by Company commitment and Commission direction in the Company s 2003 PCA filing, Case
No. A VU-03-, Order No. 29377. Avista had a deadline of March 31 2004 to file its electric
general rate case. The timing of the rate case influenced the Company s selection of the test
year. The Commission finds use of a 12-month test year ending December 31 , 2002 for net
operating income and an average of 2004 monthly averages for rate base to be reasonable and
appropriate. The matching of test year adjustments will be discussed later with other revenue
expense and rate base adjustments.
CAPITAL STRUCTURE AND RATE OF RETURN
1. Capital Structure
In its initial filing, A vista witness Malquist recommended a pro forma capital
structure consisting of 48.190/0 long-term debt, 5.79% trust preferred securities, 1.720/0 preferred
stock, and 44.30% common equity, that included adjustments to reflect known and projected
changes in long-term debt issuances/redemptions and associated costs through September 30
2004. Tr. at 97-100; 105; 421-426.
Potlatch witness Thornton recommended no changes to A vista s pro forma capital
structure. Tr. at 975. Staff witness Carlock, however, contended that the pro forma changes
proposed by A vista were not adequately known and measurable. Staff recommended instead
using the embedded capital structure at December 31 , 2003 consisting of 50.08% debt, 5.570/0
trust preferred securities, 1.760/0 preferred stock and 42.59% common equity. Tr. at 1474.
A vista in rebuttal agreed with Staff to use the capital structure at the embedded December 31
2003 actual levels. Tr. at 193.
ORDER NO. 29602
The Commission finds A vista s actual embedded capital structure at December 31
2003 as proposed by Staff and agreed to by the Company, to be appropriate for calculating the
Company s overall rate of return.
2. Cost of Debt
A vista testified that its embedded cost of long-term debt on December 31 , 2003 was
68%. Exh. 2 , p. 2. The Company proposed making certain pro forma adjustments to update
the debt cost through September 30 2004 to 8.70%. Tr. at 101; Exh. 2, p. 2. Staff accepted and
recommended use of the Company s average actual cost of long-term debt outstanding on
December 31 2003, i., 8.680/0. Tr. at 1475.
The Commission finds it reasonable based on the evidence of the record to rej ect the
pro forma adjustments to be consistent with the capital structure adopted and to use the
Company s year-end 2003 embedded cost of debt calculation, 8.68%.
3. Cost of Trust Preferred Securities
A vista testified that its embedded cost of trust preferred securities on December 31
2003 was 6.150/0. Exh. 2, p. 2. The Company proposed making certain pro forma adjustments
to update the debt cost through September 30, 2004 to 7.01 %. Tr. at 102-103; Exh. 2, p. 2.
Staff accepted and recommended use of the Company s embedded cost of trust preferred
securities on December 31 , 2003, 6.150/0. Tr. at 1475.
The Commission finds it reasonable based on the evidence of the record to reject the
pro forma adjustments to be consistent with the capital structure adopted and to adopt the
Company s 6.150/0 year-end 2003 embedded cost for trust preferred securities as the appropriate
cost rate.
4. Cost of Preferred Stock
A vista witness Malquist testified that the Company s embedded cost of preferred
stock on December 31 2003 was 7.35%. Exh. 2 , p. 2. The Company proposed making certain
pro forma adjustments to update the preferred stock cost through September 30, 2004 to 7.34%.
Tr. at 102-103; Exh. 2, p. 2. Staff witness Carlock accepted and recommended use of the
Company s embedded cost of preferred stock on December 31 2003 350/0.' Tr. at 1475.
The Commission finds it reasonable based on the evidence of the record to reject the
pro forma adjustments to be consistent with the capital structure adopted and to adopt the
Company s 7.350/0 year-end 2003 embedded cost for preferred stock as the appropriate cost rate.
ORDER NO. 29602
5. Cost of Common Equity Capital
A vista, Staff and Potlatch disagree as to the appropriate cost of common equity
capital. The cost of common equity capital, stated as a rate of return on common equity, is a
function of several variables. It is primarily an attempt to quantify a rate of return required by
investors for that particular investment that is equal to returns earned at the same time by entities
of similar risk and uncertainty. The return should also be reasonably sufficient to allow the
utility to support its credit and attract new capital needed for utility operations. A vista s electric
operation was previously authorized to earn an 8.979% overall return and a 10.750/0 return
common equity.Case No. WWP-98-, Order No. 28097.For its gas operation the
Company was authorized to earn an 11.020/0 overall return and a 12.75% return on equity. Case
No. WWP-88-, Order No. 22749.
Avista in this case requests a rate of return of 11.5% on the common equity portion
of its capital structure. Tr. at 98; 104. The Company s cost of capital witness , Dr. Avera
proposes a range for equity return of 10.4-11.90/0 (eight Western Electric Utilities Benchmark
Group) and advocates a higher return within that range. Tr. at 372. Avista witness Malquist
believes that the requested 11.5% return will support a bond upgrade and will minimize
customer impacts. Tr. at 103-105. Dr. Avera contends that Avista s unique investment risks are
significantly greater than the benchmark group. The 11.50/0 return requested by Avista, Avera
contends, is too low given expectations for higher utility bonds going forward, unsettled power
markets, below investment-grade credit rating, and hydro uncertainties. Tr. at 372-373.
Staff witness Carlock proposes a range for equity return of 9.10.9% and
recommends a return on equity of 10.4%. Tr. at 1475. Staff uses the results of discounted cash
flow (8.11.3%) analysis and the comparable earnings method for industrials and utilities (10-
110/0) in its computation. Tr. at 1471 , 1473.
Potlatch witness Thornton proposes a much lower range for equity return based on a
capital asset pricing model (7.700/0- 9.90%) and discounted cash flow model analysis (7.50/0-
20%) and recommends a return on equity of 8.50/0. Tr. at 1001. Thornton contends that
Company witness Malquist bases his return on equity recommendation on personal belief and
provides no financial analysis or cost of equity calculations. Tr. at 1003. Thornton believes
Company witness Avera s results are upwardly biased and that the eight-company benchmark
sampling is too small to impart sufficient confidence. Tr. at 1004-1005. Potlatch witness
ORDER NO. 29602
Peseau offers simple updates to Avera s data (i., growth rate, dividend yields , interest rates)
that lowers Avera s ROE estimate by 140 basis points (1.4%). Tr. at 941-952.
Commission Findings
In this case, as in A vista s most recent electric rate case (WWP-98-11), the parties
have advanced different methodologies to analyze and ascertain a fair rate of return on common
equity capital, including discounted cash flow (DCF) method, risk premium analysis, and
comparable earnings method. Each method attempts to establish a rate of return on common
equity at a point sufficiently attractive that free market investors will consider purchasing
common equity shares in the company. As with other analytical tools used in the ratemaking
process, the methods to evaluate a common equity rate of return are imperfect predictors of
future performance. Additionally, the rate of return on equity specified by a regulatory agency
is but one factor considered by prudent investors when evaluating a utility s stock. A utility
stock performance in the marketplace is determined by many variables, including management
decisions, weather, streamflow conditions, and a host of separate economic factors.Also
considered in the instance of A vista Utilities is the corporate structure of Avista Corporation and
the Company s unregulated activities.
This Commission has found it reasonable in the past to primarily rely onDCF and
comparable earnings methods to determine an appropriate rate of return on common equity~ We
have confidence in those approaches and primarily rely on them again in this case. The DCF
analysis utilizes the dividend rate, stock price and expected growth rate of a company to
quantify the return required by the investor. Flotation costs have also been reflected with the
DCF method. The comparable earnings method evaluates returns earned by other companies
including utilities, to quantify an investors expected return, taking into account the risks
associated with a particular investment. A third methodology to determine a required rate of
return on common equity is the risk premium analysis. The risk premium method starts with the
rate of return for a low-risk investment, such as government or utility bonds, and adds a
premium based on the relative risk associated with a utility s stock A fourth method, the capital
asset pricing model (CAPM) measures risks using the Beta coefficient. The return on equity is
measured in relation to the market as a whole. As markets change, new concerns develop in
various financial circles related to the calculations used to determine the cost of equity. One
such concern continues to be the measurement and proper use of Beta. This Commission has
ORDER NO. 29602
not focused on Beta or CAPM for determining the cost of equity; therefore any new concerns or
methods are not at issue in this case and will not be specifically addressed.
The Commission has considered all methodologies and rationale in the cost of
capital testimony of the witnesses and finds the middle ground position advanced by Staff
witness Carlock to be reasonable. The evidence in this case supports a rate of return on common
equity for Avista ranging from 9.10.9%. This range encompasses the lower end of Avista
recommended range from 10.4-10., and the upper range of 9.90/0 from Potlatch'
recommendations. We find A vista s reasonable required rate of return on common equity to be
10.4%. This return on equity with the December 31 , 2003 capital structure and cost results in an
overall rate of return of 9.25%.In authorizing a 10.4% return on common equity, this
Commission acknowledges its desire to maintain Avista as a financially viable utility with credit
ratings at or above the current level. The Staff proposal, adopted by this Order, results in a pre-
tax interest coverage ratio of 2.71 times. Tr. at 453. This is at the bottom of S&P's BBB-
rating. Id. A rating of BBB would be an increase for A vista. As A vista continues to strengthen
its capital structure, refinance high cost debt and address other rating agency concerns, the pre-
tax interest coverage ratio will also improve. This is a move in the right direction to improve
A vista s utility bond rating. We anticipate that non-utility operations/affiliates will also be
making similar efforts to reduce risk and improve earnings contributions to improve ratings.
encourage Avista to investigate with the Staff reasonable ring fencing efforts to further reduce
utility risk and improve ratings. The use of this cost of common equity, together with the cost of
debt, cost of trust preferred securities, cost of preferred stock and capital structure previously
found, yields the following overall return for rate base:
Component Percentage of Cost Weighted Cost
Capital Structure
Debt 50.080/0 680/0 350/0
Trust Preferred Securities .34
Preferred Stock 1.76
Common Equity 42.0.40 4.43
TOTAL 100.000/0 250/0
ORDER NO. 29602
A VISTA'S ELECTRIC CASE
ADJUSTMENTS TO ELECTRIC TEST YEAR REVENUES,
EXPENSES AND RATE BASE
Once a test year is selected, adjustments are made to test year accounts and rate base
to reflect known and measurable changes so that test year totals accurately reflect anticipated
amounts for the future period when rates will be in effect. The Idaho Supreme Court has
described "rate base" as "the utility s capital investment amount." Industrial Customers of
Idaho Power v. Idaho PUC 134 Idaho 285, 291 , 1 P.3d- 786, 792 (2000). Adjustments to test
year accounts generally fall into three categories: 1) normalizing adjustments made for unusual
occurrences, like one-time events or extreme weather conditions, so they do not unduly affect
the test year; 2) annualizing adjustments made for events that occurred at some point in the test
year to average their effect as if they had been in existence during the entire year; and 3) known
and measurable adjustments made to include events that occur outside the test year but will
continue in the future to affect Company income and expenses.
Staff witnesses Stockton and Harms accepted A vista proposed Standard
Commission Basis Adjustments (Falkner Exh. 14, pp. 4-, columns c through x), Pro Forma
Insurance Adjustment that decreases net operating income by $649 000 (Falkner Exh. 14, p. 8
column ad) and Pro Forma Power Supply Adjustment (Falkner Exh. 14, p. 8, column ab) that
decreases net operating income by $7 832 000. Tr. at 1118-1119, 1075.
The Company on rebuttal agreed to and incorporated into its Rebuttal Exhibit 26
pages 10-12 the following Staff proposed adjustments to net operating income and/or rate base:
Net Operating
Income after
Adjustment Reason Taxes Rate Base
Cabinet Gorge Update estimates to actuals 000 ($110 000)
Boulder P~rk Yllchronize depreciation between
Depreciation states 000 000
Skookumchuck Sale of plant approved by the
CommissIon, plant and related
operating items no longer to be
recovered through rates 000 (104 000)
Deferred Federal Appropriate deferred tax accounting
Income Tax treatment 966 000)
Coyote Springs 2 Update estimates to actuals 172 000 621 000)
ORDER NO. 29602
Small Gen. Options Remove capital costs, treatment similar (539 000)
to other unfinished plant
Labor (Non-Exec.Update estimates to actuals 000
Labor (Exec.Update estimates to actuals 000
Depreciation Synchronize depreciation between 432 000
states
Corp. Fees Similar treatment for Idaho utilities
split 500/0/500/0 000
Miscellaneous Similar to prior Commission treatment
Expense exclude contributions, dues, and
expenses benefiting affiliates 250~000
Western Electricity Remove expense to reflect Company
Coordinating Council non-member status 000
Advertising Expense Similar to prior Commission treatment
exclude charitable contributions, image
advertising and non-electric ads 000
Avista Foundation Correctly assigns expenses to affiliate 000
By accepting these uncontested adjustments the Company revises its requested electric revenue
increase to $31 070 000 or 21.24%. Avista Reb. Exh. 26, at 2; Tr. at 195-196 217.
A. Agreed Upon Adjustments
1. Accounts Receivable Program Fees
Avista s Accounts Receivable Sale Program was initiated in 1988 when the
Company entered into a five-year agreement to sell $30 million of its accounts receivable. At
that time, the effect of the program was to reduce the Company s need for financing and provide
the Company with a source of funds at a much lower effective cost. Since 1988, the Company
has expanded the limit to sell up to $125 million of the Company s accounts receivable. Staff
witness Stockton recommends removing the fees associated with the Company s Accounts
Receivable Sale Program because it is analogous to (or a substitute for) a working capital
addition to rate base. A vista, Stockton states, has a negative working capital requirement
indicating that shareholders were not the source of working capital and thus no return to
shareholders should be allowed on working capital. Staff s adjustment increases net income by
$357 000 and decreases total revenue requirement by $558 000. Tr. at 1116; 1127-1131; Tr. at
1087-1088.
On rebuttal A vista witness Falkner states that the Commission has previously
allowed the fees as recoverable expense. The Account Receivable Program, he states, is a cost
effective method of carrying customer receivables on the Company s balance sheet. The
ORDER NO. 29602
alternative to selling the accounts receivable, he contends, would be a working capital addition
to rate base at the Company s authorized rate of return. The Company has not included a
working capital adjustment in the past due to the complexity of doing such a study. Falkner
contends Staff misinterpreted the results of its working capital study, that actually, he states
shows that working capital is, in fact positive, not negative. Falkner contends that Staff s study
supports including the fees associated with the accounts receivable sale as an operating expense.
Tr. at 201-202.
As reflected in Stockton s rejoinder testimony, Staff and Avista agreed to reduce
Staffs proposed adjustment by 500/0. This amended adjustment increases Idaho net operating
income after taxes by $179 000 and decreases total revenue requirement by $280 000. Tr. at
1141-1142. The Commission has considered the merits of both Staff and Company positions.
The Commission finds the compromise adjustment reached by the Company and Staff to be a
reasonable resolution of this issue.
2. Debt Interest Restatement Adjustment
A vista restates debt interest using the Company s pro forma weighted average cost
of debt and pro forma rate base to produce a pro forma level of tax-deductible interest expense.
Tr. at 163. Staff s adjustment restates debt interest using the Staff-proposed embedded weighted
average cost of debt to Staffs pro forma rate base. Tr. at 1093-1094. Avista witness Falkner in
his rebuttal testimony listed Staff s Debt Interest Adjustment amongst the Company s contested
adjustments. Tr. at 196. At hearing, however, Mr. Falkner explained that he agreed with Staff s
calculation methodology to restate debt interest and the only.difference between his calculation
and Staff s calculation was the level of rate base that is utilized in the calculation. Tr. at 224-
225.
As noted below, Avista contests two adjustments (transmission projects and Boulder
Park project costs disallowance) that affect the rate base used in Staffs debt interest restatement
calCulation. The Commission finds that the calculation methodology is not contested and should
be applied to the rate base amount we ultimately approve.
3. Low Income Weatherization Assistance (LIW A) Funding
The Community Action Partnership Association of Idaho (CAP AI) in the direct
testimony of its witness Stamper recommended: 1) elimination of the "R" number requirement
that is the total kilowatt usage per year so that all households with electricity as the primary heat
ORDER NO. 29602
source can automatically qualify for weatherization; 2) a change in the current contract between
Avista and Community Action Partnership (CAP) to add windows, doors, and base load
measures as allowable weatherization measures funded by Avista toward meeting the 1.0
savings to investment ratio; and 3) an increase in low-income weatherization funding from the
current 2004 level of $108 208 (Idaho only) to $490 000 to fund the weatherization of 123
A vista units in North Idaho. Tr. at 1061-1064. CAP AI estimates that there are approximately
000 households currently eligible for A vista s weatherization program. At current funding
levels and program design, it would take nearly 50 years to meet all the needs in north Idaho.
Tr. at 1038 , 1039.
To be equivalent to Idaho Power on a per customer basis, Staff witness Anderson
noted that A vista would have to increase electricity Demand Side Management (DSM) funding
for LIW A to $320 000 per year. Staff did not take a position on this issue. Tr. at 849-850.
A vista in rebuttal notes that the Company reached separate agreement with CAP AI.
A vista agreed to increase annual limited income electric and gas DSM and BP A Conservation
and Renewable Discount (C&RD) funding to $350 000 commencing in 2006. This is slightly
higher than the $320 000 calculation appearing in Staffs testimony, but less than the $490 000
originally proposed by CAP AI. The funding will come from the Company s gas and electric
DSM tariff riders. The Company also agrees to extend funding eligibility to include doors
windows, and customers who use permanently installed electric or natural gas heating
appliances regardless of historic electric usage, and agrees that customers that qualify under U.
Department of Energy financial standards would be eligible for any measure meeting a savings
to investment ratio of 1.0 or above. Tr. at 747-749.
The Commission believes that funds devoted to LIW A are a wise investment that
will benefit all A vista ratepayers not just those who experience reduced power bills. Increased
LIW A funding can provide significant benefits in terms of lowering uncollectibles and creating
permanent load reduction. The Commission commends CAP AI and A vista for the compromise
agreement that they presented. As part of the agreement, the Company agreed to increase
annual low income weatherization funding from current levels to $350 000 for qualifying
electric and gas customers for 2006 and beyond. We find the terms and Company commitments
to be both reasonable and acceptable. We note further that the Company s agreement will
provide considerable flexibility to the community action agencies in leveraging the funds
ORDER NO. 29602
available so they can do their best job in weatherizing homes. CAP AI estimates that Avista has
approximately 17 500 customers below 150% of the federal poverty guidelines in its Idaho
service area. Exh. 403; Tr. at 1038; 1048. CAP AI's participation in this case we find was a
great benefit to the many small communities and low-income customers served by A vista in
northern Idaho.
4. Demand Side Management (DSM) Funding Levels
Avista at its May 19, 2004 meeting of its External Energy Efficiency (EEE)
Advisory Board proposed reducing the Company s electricity DSM surcharge from the current
950/0 to about 1.250/0 of base revenues or approximately a $1 million annual reduction. Exh.
132
, p.
10. The Company also proposed that the DSM surcharge be set as a cents-per-kWh rate
rather than a percentage of base revenues. Tr. at 845, 846. Staff witness Anderson testifies that
in light of anticipated DSM expenditures and the need for relief from a likely base rate increase
in this case, he agrees to a reduction to the DSM tariff rider with the following conditions: (1)
assurance that a reduction in DSM revenues will not negatively impact A vista s pursuit of cost-
effective energy measures, regardless of whether such measures result in A vista s DSM fund
balance being negative, and (2) an increase in Avista s LIW A contribution to a level determined
reasonable by the Commission. Even with the reduction, Anderson notes that A vista s DSM
revenue will still be higher than Idaho Power s. Staff supports a surcharge change from a
percentage of base revenues to a cents-per-kWh base charge. Tr. at 845-849; 851.
On rebuttal, A vista witness Powell states that a tariff rider equal to 1.25% of current
base revenues should be sufficient to meet the Company s forecasted funding needs for year
2005. The Company commits to incur a negative tariff rider balance' if cost-effective DSM
resource acquisitions require more funds than are available from DSM tariff rider resources.
The Company proposes to correct any negative or positive balances in the electric or gas DSM
tariff rider through annual revisions. The Company also proposes to revise its DSM surcharge
from a percent of revenues to an amount equal to a percent of the current retail rate. Tr. at 745-
749. The Company s proposal is not a flat cents per kilowatt hour across all rates, Powell
explains, it is a reduction from an amount equal to 1.95% of current base revenues to an amount
equal to 1.25% of current base rates. Tr. at 750-751; also at 753.
The Commission finds Avista s proposal to reduce the DSM surcharge from 1.950/0
to 1.250/0 of base revenues to be both justified and acceptable. We also find it reasonable to
ORDER NO. 29602
apply the surcharge on a cents/kWh basis. In doing so we commend the Company for its
continued commitment to cost-effective DSM resource acquisitions and we expect the Company
to continue to pursue cost effective DSM regardless of DSM funding balances.
5. Coyote Springs (CS2) Deferred Return
Coyote Springs 2 (CS2) is a 280 MW natural gas combined cycle combustion
turbine (CCCT) located near Boardman, Oregon. It was selected by Avista as a supply side
resource in the Company s 2000 Request for Proposal (RFP) process. A vista owns 500/0 of the
plant and is requesting a ratebasing of its investment as part of this rate case. Staff witness
Harms proposed reducing the Company s revenue requirement by deferring the Company
return on the Coyote Springs 2 project. A return on the project would not be denied, but full
recovery of this return deferral would take 10 years to be completed. The Company s annual
revenue requirement is reduced by $13 054 per million dollars of Coyote Springs 2 gross plant.
Tr. at 1094. While Avista witness Falkner in his rebuttal testimony and schedules did not
reduce the revenue requested by the Company for this deferral, during the hearing he stated that
the Company agreed with this proposal. Tr. at 225. The Commission accepts Staffs CS2
deferred return proposal as reasonable. Deferring the return serves to mitigate the associated
rate increase. The Company will receive the same net present value over 10 years because the
~eferred balance accrues a carrying charge at the return authorized in this case.
B. Disputed Adjustments
1. Transmission Projects
To reflect project estimated costs, depreciation, property taxes and income taxes of
three transmission projects, i., Pine Creek 2003 kV substation, the Beacon-Rathdrum 230 kV
line and the Beacon-Bell #4 230 kV line, Avista proposed a pro forma adjustment increasing
rate base by $8 849 000 and decreasing net operating income by $249 000. Tr. at 172-173; Tr.
at 247.
Staff witness Harms recommends removal of the Beacon to Bell line ($438 000), a
project that was suspended until 2005; recommends that the estimated costs for Beacon to
Rathdrum line and Pine Creek Substation Rebuild be updated from estimates to lower actual
amounts resulting in a rate base reduction of $615 000; and contends that Avista did not reflect
proper matching of revenues and expenses as if projects had been in service the full year. To
include the plant investment as if the plant had been in operation the full year without
ORDER NO. 29602
corresponding revenue and expense adjustments, Staff contends, is unreasonable and creates a
mismatch between test year revenues and expenses. The Commission could disallow the entire
adjustment because of this mismatch. One alternative to denYing the plant adjustment, Staff
suggests, is to remove annualization and show reduced costs for only one month of the test year.
Harms stated that the effect of this adjustment reduces rate base by $8 518 000, operating
expenses by $358 000, and revenue requirement by $1 592 000. A second alternative is to
annualize the proj ects' costs using a proxy for imputed revenues and expense reductions
producing approximately $270 000 of imputed Idaho revenue and $30 000 of reduced Idaho
electric expense. The corrected annualized costs increase rate base by $7 801 000. Tr. at 1076-
1080; Exh. 103.
Potlatch witness Peseau contends that A vista pro formed into rate base $26.3 million
in transmission projects but made no similar revenue adjustment.This mismatch, Peseau
contends, should be corrected by: (1) reversing the pro forma entries and properly matching test
year averages on both sides of the ledger, or (2) updating revenues to the 2004 level in the same
manner as rate base and expenses, his preferred method, or (3) employing the rate base
adjustments adopted in the Idaho Power rate case (5% of the rate base additions). Tr. at 925-
926.
Avista witness Falkner on rebuttal contends that the multi-year transmission
upgrades included in the Company s filing are complete, known and measurable. The financial
benefits of import/export energy revenue, he states, are captured in the power supply model.
Should the Commission determine, however, than an adjustment to revenues and/or expenses in
conjunction with the full rate base treatment of the new transmission adjustment was necessary,
Falkner contends that Staff s proposed proxy alternative of including approximately $270 000 in
additional revenues and a $30 000 expense reduction would be reasonable. Tr. at 197-199.
Commission Findings
The Commission has reviewed the testimony and recommendations of the parties.
is reasonable as Potlatch surmises that there is an offset or savings related to transmission
investment. When significant plant improvements are completed late in the test year or after the
test year, the challenge is to reasonably include the investments in the test year in a way that
fairly compensates the Company for its investment, but also fairly treats ratepayers by matching
investment revenues with investment expenses. We encourage the Company to develop means
ORDER NO. 29602
of computing the expense savIngs and revenue enhancements associated with transmission
investment. We accept as reasonable Staffs proposed Beacon-Bell adjustment and the proposal
to update the Beacon-Rathdrum and Pine Creek construction estimates to actuals. Rather than
deny the Company s annualizing plant rate base adjustment outright or require the Company to
wait for its next rate case to include the plant in rates, we accept Staffs proxy proposal for
calculating imputed revenues and expense reductions. We do so reluctantly, however, because
the Company has not adequately attempted to calculate expense savings and revenue producing
effects. We put the Company on notice that this is not a method we want to use in the future.
Henceforth, if the Company seeks full recovery of plant investment as if the plant had been in
operation a full year, it must present a corresponding adjustment to revenues and expenses.
2. Boulder Park Small Generation Project
Avista witness Lafferty contends that the 25 MW Boulder Park natural gas-fired
reci procating engine generation proj ect was a reasonable addition to A vista s energy resource
portfolio and was economic compared to market alternatives at the time the decision to build
was made during the "energy crisis." The project was fast-tracked, Lafferty states, in order to
mitigate the high prices and volatility in the electric power market in the 2000-2001 energy
crisis. Lafferty contends that the Company reasonably managed Boulder Park project costs
under the circumstances even though costs were higher than projected due to the fast-track
design and construction approach. The May 2001 construction cost estimate was $21 million;
the total actual cost was approximately $31.9 million. Contractor costs were approximately $4.
million over budget due to such factors as the additional design scope, change orders, overall
project complexity and project management costs due to the extra time required to complete the
project. Avista construction costs were over budget by approximately $2.2. million due to
changes in project scope and complexity. Tr. at 541; 592-598.
Staff witness Sterling believes the Company s decision to pursue the Boulder Park
project during the 2000-2001 energy crisis was a reasonable response to extremely low water
conditions and high market prices.Completion of "fast-track" construction, however, was
delayed by eight months, from September 2001 until May 2002. There were also considerable
cost overruns. The final cost of Boulder Park was $32.1 million, $11 million over the $21
million construction cost estimate, a greater than 50% cost overrun.Although not new
technology for the power industry, the natural gas fuel reciprocating engine generators were the
ORDER NO. 29602
first project of its kind for Avista, a factor which Avista states contributed in part to actual
construction costs being higher than original estimates. Tr. at 1220; Avista summary of cost
variations, Exh. 129. It is common, Sterling contends, to include a contingency amount in the
cost estimate for large construction projects to insure that funds are available in the event of
unplanned problems, circumstances or conditions. Contingency amounts for projects similar to
this one, Sterling estimates, are typically in the range of 5-15%. Sterling believes ratepayers
should be able to expect a utility to have the ability to construct projects at least cost. Staff
recommends 100/0 of the final project cost be disallowed, that equates to a $205 000 reduction in
annual Idaho revenue requirement and a $1 085 000 reduction in rate base. Tr. at 1082-1083;
Tr. at 1218-1224; Exh. 129.
On rebuttal A vista contends that Staff s recommended 100/0 Boulder Park
disallowance is not appropriate given the challenges presented by the market conditions and the
project's unique characteristics. Avista also contends that the slow down of the project was
justified by a change in circumstances, lower market energy prices in the summer of 2001 and a
financial need to preserve cash. Tr. at 632-633.
Commission Findings
The Commission has considered the testimony regarding Boulder Park and finds that
a 530/0 construction cost overrun is unreasonable. We expect a utility such as Avista to have the
expertise and experience to plan, construct and manage any project it undertakes at a reasonable
cost. This project was planned as a "fast track" response to poor water and a volatile energy
market. It was not completed on time and was 53% over budget. The Company must assume
some responsibility for the excessive cost. Staff recommends a 10% disallowance and identifies
specific cost category overruns. We believe that the Company should be held to a higher
standard. Ratepayers will not be asked to pay for what we find to be a Company learning
expenence.Staff notes that the CS2 and Kettle Falls ovemlns totaled 160/0 and 80/0
respectively. We find it reasonable to limit the authorized rate base amount for Boulder Park to
the project construction estimate plus a 15% contingency. The original construction estimate for
Boulder Park was $21 000 000 (Exh. 8 , Sch. 35; Exh. 129). An additional 150/0 increases the
total rate base allowed to $24 150 000. . The final cost of Boulder Park was approximately $32
million. The total disallowed amount is $7.62 million on a system basis. The Idaho
jurisdictional share of the disallowance is $2.6 million.
ORDER NO. 29602
3. Prudency of Coyote Springs (CS2)
Company witness Lafferty testifies that A vista in a spring 2000 update to its 1997
Integrated Resource Plan (IRP) identified a need for new resources. The Company issued an all-
resource 2000 Request for Proposal (RFP) for 300 MW of capacity and energy. The Company
received 32 proposals from 23 bidders for a total of 2700 MW of supply-side and demand-side
resources. The RFP process included third-party review and critique. Resource alternatives
were ranked in an evaluation matrix. The Company selected the 280 MW CS2 combined cycle
combustion turbine as the preferred supply-side option. CS2 is a project acquired by Avista
Power from Enron and was included in the RFP process at an "at cost" price. In addition to
overall cost effectiveness, a key factor cited by the Company in selecting the CS2 project was
that it included a fully licensed site. The major equipment had already been ordered and an
Engineering, Procurement and Construction Contractor (NEPCO) an Enron affiliate, had already
been selected.
Due to financial challenges facing the Company because of low water conditions
and high market prices in the first half of 2001 and difficulty encountered in finding project
financing, Avista sold 50% of the CS2 project to Mirant on December 12, 2001. As part of the
transaction, Mirant pays one-half of all capital costs and one-half of all operation and
maintenance costs for the project. Mirant is responsible for securing its own natural gas supply
and transportation and for making its own arrangements for transmission to move power from
the plant. Avista maintains it took reasonable steps to bring the CS2 project to commercial
completion as quickly as practicable, and to manage the failure of and damage to CS2' s
transformers. The proj ect start-up delays, the Company contends were unforeseeable 'and
uncontrollable. A vista s management of the cost overruns caused by the bankruptcies of Enron
and NEPCO, the Company contends, was reasonable. A vista s share of CS2' s construction
costs as of 9/30/03 was approximately $109 million rather than the $94 million originally
projected. Tr. at 540; 542-563.
Staff witness Sterling contends that the CS2 resource was needed by Avista to
address projected generation deficits identified in the Company s IRP. One of the primary
reasons for the deficit identified in the Company s IRP was the sale of the Company s 201 MW
share of the 1340 MW Centralia coal-fired generating plant. Sterling believes that the
ORDER NO. 29602
Company s RFP process was fair and Staff confirms that CS2 was transferred by A vista Power
to Avista Utilities "at cost." It is Staffs position that Avista should not be denied recovery of
$15 million in cost overruns, overruns which, Sterling contends, were neither foreseeable nor
within the Company s control. Tr. at 1210-1217.
Potlatch witness Peseau notes that in the Company s corporate structure (Exh. 1
, p.
5), A vista Utilities is not a separate business entity, only an operating division of A vista Corp.
This organizational relationship, he contends, blurs the distinction between regulated and
umegulated activities. Tr. at 899. In A vista s last rate case, Peseau reminds the Commission
that Potlatch expressed concern that A vista s corporate structure, and its practice of not
contemporaneously making trades to its regulated or non-regulated arm, left it with the latitude
to subsequently allocate trades based on their profitability. Tr. at 899-900. The transactional
facts surrounding CS2, Peseau contends, presents a case that is far worse. Tr. at 900.
As Potlatch recounts events, CS2 was originally a Portland General Electric (PGE)
project to be built as a companion to PGE's Coyote Springs 1 generating station located near
Boardman, Oregon. At that time PGE was a regulated Emon subsidiary. In mid-1999, Emon
and PGE decided to sell CS2. On October4, 1999, Avista Power, an umegulated Avista Corp.
subsidiary, entered into an "evaluation agreement" with PGE that allowed it to begin a due
diligence investigation of the plant. On March, 4, 2000, A vista Power signed a Letter of Intent
with Emon to buy both CS2 and a turbine purchased by Emon for CS2. The total purchase price
when the deal was finally concluded was approximately $59.5 million. Tr. at 900-903.
In December 2000 Avista Corp. announced it would acquire CS2 from Avista
Power. Tr. at 553; 606-607. But Potlatch contends that Avista did not in fact immediately
follow through on this announcement. Tr. at 905. Avista responds that the Company chose to
keep ownership of the plant with the CS2, LLC until construction was completed citing the
benefit of forming LLCs to separate costs and liabilities during construction and the Company
initial intent to obtain separate construction financing. Tr. at 607. Potlatch contends that Avista
Power was never under a legal obligation to sell to A vista Corp. A vista discovery responses to
Potlatch revealed no contract, memorandum of understanding, or any other document that would
evidence an intention to proceed with the sale. Tr. at 907. Once A vista began experiencing cash
flow problems, Company memos indicate that A vista Power was trying to sell the entire plant to
third parties in the summer and fall of 2001 , months after the announcement that A vista Utilities
ORDER NO. 29602
would acquire CS2 from A vista Power. Tr. at 905. Ultimately A vista Power sold a 50 percent
share of CS2 to Mirant on December 12, 2001. Tr. at 552. The remaining 50 percent of CS2
was not transferred to Avista Corp. until January 1 , 2003, after construction was substantially
complete. The project began commercial operation for the utility in July 2003. Tr. at 607.
In April 2002, CS2' s prime contractor, NEPCO , an Enron affiliate, filed for
bankruptcy and CS2 lost the benefit of its fixed price construction contract, while at the same
time incurring the cost of replacing the prime contractor and settling with subcontractors. Tr. at
553.The history of CS2, as characterized by Potlatch, has been and continues to be
economic and operational nightmare. The construction problems caused the estimated cost of
A vista s half of the plant to increase from approximately $94 million to $109 million. Tr. at
903-904.
Potlatch contends that CS2 should not be recovered in rates until it is proven "used
and useful." Peseau contends that is not currently used and useful, and there is no indication it
will ever be after the three failures experienced thus far. If CS2 is included in rate base, Peseau
recommends that costs be limited to the plant's fair market value as of the January 1 , 2003
transfer date, $84 560 000 by his calculations, to prevent an unregulated affiliate from profiting
at ratepayer expense. Tr. at 906-908. The basis for Potlatch's fair market value number was a
$604/kW construction cost estimate advanced by Avista in rebuttal testimony in a 2002 generic
PURPA Surrogate Avoided Resource (SAR) case (GNR-02-1). On cross, Potlatch conceded
that the Commission did not accept Avista s avoided capital cost in that case, but instead in
Order No. 29124 adopted a Northwest Power Planning Council (NWPPC) generating resource
advisory committee number ($679/kW), a year 2000 number that when escalated forward two
years to provide a comparable comparison to CS2 results in a $99 094 000 value. Tr. at 968.
On rebuttal Avista notes that between July 1 2003 and January 15 , 2004 CS2
performed with a 92% availability factor, generating approximately 85 aMW. The Company at
hearing expected CS2 to return to service in mid- to late-August 2004. Tr. at 602; 604-608.
Commission Findings
Despite a rather involved history of resource acquisition and construction and the
Company s unfortunate entanglement in the Enron bankruptcy, the Commission finds that CS2
was a needed resource and that the acquisition of CS2 by A vista Utilities was reasonable and
prudent. We find the purchase cost was reasonable in the context of other resource alternatives
ORDER NO. 29602
offered in the Company s 2000 RFP. The question of whether there was a legal obligation to
transfer CS2 following a simple Company announcement of resource selection and the timing of
the transfer from Avista Power to Avista Corporation (Avista Utilities) raise questions of
opportunistic gamesmanship between regulated and unregulated entities in the Avista Corp.
family. The transactional history of the CS2 acquisition suggests that a ring fencing mechanism
needs to be put in place to insulate the regulated utility from risks undertaken by non-regulated
affiliates. Techniques to be explored include pro-active regulatory oversight, financial
restrictions , structural separations, and operational controls.
The "used and useful" issue raised by Potlatch as an argument against ratebasing is
perceived by this Commission on the facts of this case to be one of operational and regulatory
timing. If the project rate base question had been considered prior to the January 15, 2004
transformer failure, the Company would have been able to demonstrate that CS2 was used and
useful and no party would have challenged the Company assertion. CS2 was indeed
operational from July 2003 to January 2004. It performed with a 92% availability factor
generating approximately 85 aMW. It was economically dispatched for two weeks and was
ostensibly available for the remainder of that period. We also cannot ignore the fact as stated
above that the CS2 project was the low cost resource selected in the Company s 2000 RFP, and
that there was a need for the resource.
Applying the reasoning advanced in our discussion above of Boulder Park, we find
that Company self-build projects should be subject to a cost overrun cap. We find it reasonable
to limit the authorized rate base amount for CS2 to the project construction estimate plus a 150/0
contingency. The original construction estimate of CS2 was $93 933,400. Rev. Exh. 6, Sch. 15
3. An additional 15%, $14 090 010, increases the total rate base authorized to $108 023,410
(system). The resultant Idaho Commission authorized gross plant is $37 172 000. This
compares to the Company and Staff agreed CS2 gross plant (Idaho) number of $37 291 000.
Exh. 109. The calculated amount of rate base disallowance is $119 000.
4. Vegetation Management (Tree Trimming)
To reflect planned increases in vegetation management, Avista witness KopczYnski
proposes a $1.2 million Idaho jurisdictional adjustment using a 2004-2007 four-year average of
scheduled Company vegetation management projects. Company witness Falkner contends that
the proposed expenditure level is necessary for the proper management of vegetation around
ORDER NO. 29602
both transmission and distribution lines to most effectively ensure reliability levels, improve
safety and reduce customer outages. The effect of this adjustment reduces Idaho electric net
operating income by $785 000. Tr. at 256; Tr. at 172.
Staff witness Stockton proposes to replace the Company s requested vegetation
management expense adjustment with an average of the actual amounts expended during the
six-year period of 1998-2003 to reflect variability of expenses and an abnormally low 2002 test
year expense. Staff s proposed adjustment increases net income by $288 000 and decreases
total revenue requirement by $451 000. Tr. at 1116; 1125-1127; Tr. at 1086-1087.
In response to Staff concerns, A vista witness Falkner recommends use of a "one...
way" balancing account. If the Commission were to authorize the Company-requested level of
expenses ($1.8 million Idaho), the Company would commit that level of resources annually to
vegetation management going forward. If less is spent, the difference would be recorded as a
liability and either spent in a future period or returned to customers through an appropriate
tracking mechanism. If the Commission.were to adopt a six-year historical average as suggested
by Staff, Falkner recommends that the Commission exclude the 2002 level of $550 255 as
abnormally low. Tr. at 199-200; Tr. at 264-265.
The Commission appreciates the importance of the Company tree trimming
program for system reliability. A good vegetation management program reduces customer
outages and maintains system integrity. We also note the level of vegetation management
expense approved by the Commission in the Company s last general rate case and recognize the
need to enhance expenditures as time passes. This is particularly true in light of the Company
limited expenditures on vegetation management in 2002. Consequently, we find it reasonable to
fund the $1.8 million level of expense recommended by Avista for Idaho tree trimming.
5. Pension Expense
Avista included in its test year expenses $14 000 000 on a total system-wide basis
for employee pension expenses, including an expense adjustment of $900 153 to reduce pension
expense from the 2003 Net Periodic Pension Cost of $14 900 153 to the 2004 estimated Net
Periodic Pension Cost.Tr. at 168.This pension expense equates to an Idaho electric
jurisdictional expense of $2.1 million. Staff witness English disagreed with using 2004 pension
expense on the premise that the expense proposed by the Company is simply an estimate and not
known and measurable. Tr. at 1155. Staff witness English also disagreed with the use of Net
ORDER NO. 29602
Periodic Pension Cost and proposed the use of the Required Minimum Contribution under the
Employee Retirement Income Securities Act of 1974 (ERISA). Tr. at 1162.
Staff proposed reducing system-wide test year pension expense of $14 000 000 by
305 315 , bringing the test year pension expense to $8 694 685, thus, increasing Idaho
operating income by $554 000 and reducing the Company s revenue requirement by $867 000.
Tr. at 1088; Tr. at 1158. Staff witness English explained that the adjustment is a reconciliation
between cash and accrual accounting. In other words, although the Company accrues a pension
contribution on its books for financial reporting purposes, A vista is only required to contribute
to the plan the amount calculated under the ERISA calculations. The recovery of pension
expense, English contends, should be based on the actual amount of cash a company is required
to contribute to the plan to meet its minimum funding liability. Any funding over the Required
Minimum Contribution under ERISA, English contends, penalizes ratepayers. Tr. at 1158-1163.
Company witness Falkner responded in rebuttal that FAS 87 has been the standard
for pension expense since its adoption in 1987 and has been previously accepted in Idaho. The
reduction of the return on asset assumption, he contends, is supported by actual fund return
history, as well as consistency with return reductions by other northwest utilities. Actual
contributions to the pension fund have exceeded the level included in Idaho general rates by $29
million since 1999. Absent a larger than minimum contribution in 2002, the minimum 2003
contribution level would have been approximately $14 million, that is the F AS 87 accrual level
proposed in this case. Had the Company not contributed additional money to the plan in 2002
Falkner contends, the Required Minimum Contribution for 2003 would be greater than Staff
proposal and by accepting Staff s proposal, the Commission would penalize the Company for
attempting to achieve a fully funded pension plan. Tr. at 202-210.
On the evidence presented in this case
, '
the Commission finds the adjustment
proposed by the Staff for the pension plan expenses to reconcile cash and accrual accounting to
be fair and reasonable. However, the Commission does not wish to unduly impose a penalty
upon the Company for its additional contributions in 2002. Therefore, the Commission accepts
the amortization of the additional $4.5 million contribution in 2002 over a two year period.
A vista will be allowed to recover in rates a total pension expense of $10 347 343 on a system
basis or $1 549 386 from the Idaho electric jurisdiction. This results in an adjustment increasing
Idaho net operating income by $381 000.
ORDER NO. 29602
6. Legal Expenses
Staff witness English proposes removing expenses from the test year for legal costs
that should have been directly assigned to unregulated affiliates (A vista Labs; A vista
Communications) or that were for extraordinary events that will not recur (i., Enron
bankruptcy; or the now closed 2002 FERC investigation into electricity trading practices). This
adjustment increases net operating income by $366 000 and reduces Avista s revenue
requirement by $73 000. Tr. at 1168-1170; Tr. at 1090.
In response, Avista witness Falkner agrees that legal expenses related to Avista Labs
and A vista Communications should be removed. Tr. at 211. Falkner argues, however, that legal
fees related to the Enron bankruptcy and FERC investigation are representative of ongoing legal
expense, that has remained constant at $3.8 million over the last six years. Such a level, the
Company contends, should be reflected in rates absent a showing of imprudence. Alternatively
the Company proposes use of a six-year average of legal expense charged to operational
accounts to "smooth out" extraordinary items. Such an average would reduce Idaho legal
expense allocations to the electric system by $32 500. Tr. at 210-214.
The Commission finds Staff s adjustments removing non-recurring extraordinary
legal expense to be reasonable and appropriate. A vista contends that some extraordinary
expense always comes up and should not be a reason for excluding the level of expense
requested. Our view is that the level of legal expense incurred by the Company is somewhat
within its control. Further, we note that the regulatory accounting system does not permit
inclusion of unusual expenses in a test year for ratemaking purposes. The Commission has
confidence that Avista Corp. will continue to act in good faith to protect the interests of its
utility customers and its shareholders.
Incorporating the foregoing adjustments, the Commission approves the following for
rate base and revenue requirement.
Rate Base
Avista proposed a pro forma electric rate base of $440 270 000 for the Idaho
jurisdiction. Exh. 14
, p.
2. As we indicated in our prior Amended Interlocutory Order No.
29588 the Commission approves as just and reasonable an electric pro forma rate base of
$424 114 000. See attached Appendix C.
ORDER NO. 29602
Revenue Requirement
Current revenue recovered in Idaho s electric base rates is $146 248 000.The
Commission in this case approves a base revenue requirement of $170 964 195 , an increase in
electric base rates of $24 716 195 or 16.90%. The resultant average cents per kilowatt hour for
base rates is 5.47 cents.
Summary of Adjustments to Electric Test Year Revenues, Expenses and Rate Base
Considering all the evidence presented, and including all adjustments, the
Commission finds just and reasonable Idaho jurisdictional expenses for the 2002 test year in the
amount of $140 696 000, and Idaho jurisdictional operating revenues in the amount of
$168 191 000 for an operating income before federal income tax of $27 495 000. The after tax
Idaho operating income is $23 121 000. After all adjustments, we find a 2002 total Idaho
jurisdictional rate base amount of $424 114 000 to be just and reasonable. Appendix C to this
Order summarizes the Commission s findings on rate base and operating results for the test year.
Calculation of Revenue Deficiency
Based on ultimate decisions determining the Idaho rate base, net operating income
requirement, and return on common equity, we proceed to determine the Idaho revenue
deficiency with the following calculation:
Rate Base
Rate of Return
$424 114 000
250%
Net Operating Income Requirement
Operating Income
Revised Revenue Requirement Deficiency
$39 231 000
$23 121 000
$16 110 000
63926135
$25 201 000
( 485 000)
$24 716 000
Income Deficiency
Conversion Factor
Revenue Requirement Deficiency
Levelized Deferred Return on Coyote Springs 2
ORDER NO. 29602
JURISDICTIONAL SEPARATIONS, COST OF SERVICE
AND RATE DESIGN
The Commission, for the purposes of electric rate design maintains existing
customer/service charges, approves a separate rate schedule for Potlatch, approves a two-block
energy rate and declining tail-block for electric general service Schedules 11 , 21 and 25 , and
moves all customer classes to within 100/0 of full Cost of Service.
The Commission also accepts the Company Cost of Service study methodology and
allocation factors including the four factor allocation adjustment proposed by Potlatch witness
Peseau and accepted by A vista in rebuttal testimony and the A vista rebuttal compromise to the
Schedule 25 primary plant distribution adjustment proposed by Coeur Silver witness Yankel.
The accepted Cost of Service results were used as the starting point for revenue allocation to
customer classes.
1. Jurisdictional Separations
The jurisdictional separations methodology is used by A vista to allocate total electric
system costs to its Idaho Washington or Federal Energy Regulatory Commission (FERC)
jurisdictions. The FERC jurisdiction is comprised of A vista s wholesale sales of energy to other
utilities. A vista witness Falkner uses the same jurisdictional separation methodology approved
by the Commission in the Company s last general rate case, WWP-98-4. The methodology
directly assigns revenues, costs and investments to jurisdictions where appropriate and allocates
the remaining amounts. The methodology uses 2002 test year booked amounts without
adjustment. All adjustments are included on an Idaho system basis at the beginning of the cost
of service process.
Staff witness Hessing, noting the value of consistency from case to case, accepts the
Company s jurisdictional separation methodology. Tr. at 1259-1260.
The record in this case s~pports a Commission finding that the methodology the
Company used to separate costs between the Idaho Washington and FERC jurisdictions is
reasonable and appropriate. The jurisdictional separations study results in an Idaho system
revenue requirement allocation of $169.3 million.
2. Class Cost of Service Methodology
Once Idaho jurisdictional test year costs are determined with the jurisdictional
separations study, the next step is to allocate the adjusted costs or the revenue requirement to a
ORDER NO. 29602
serIes of functional costs and then to the different customer classes served by A vista in
accordance with recognized principles and generally accepted procedures in order to obtain an
indication of relative cost responsibilities of each class of customer. This allocation is done in
two parts. First, a class cost of service (COS) study is conducted that identifies what the
revenue allocation for each class would be at full COSo Finally, if some increases are
considered to be too large, a maximum increase cap is established and unrecovered revenue is
spread to other classes.
A vista witness Knox uses the "Peak Credit" Cost of Service methodology approved
by the Commission in the Company s last two general rate cases. The Peak Credit method for
COS separates the Company s generation costs into demand and energy components. It then
allocates demand on a 12 coincident peak basis and energy on a class consumption basis. A vista
in this case, however, departs from its standard 60 percent (customer)/40 percent (energy)
allocation and proposes to allocate "common costs" on the basis of four factors: direct O&M
expenses, direct labor, net direct plant and number of customers. Common costs are typically
defined as those costs necessary for the utility to function, but which are left over after most
directly assignable costs have been identified and "functionalized;' to production, transmission
distribution or customer accounts. Knox provides an alternative scenario to illustrate the impact
of different allocations.Under either scenario , residential and extra large general service
customers still provide less revenue than the cost to serve them. Tr. at 320-328. Starting with
the COS result, A vista witness Hirschkorn proposed a rate spread moving the relative rate of
return for each schedule approximately one-half way toward cost of service, with the exception
of the lighting schedules. Tr. at 777.
As in the case of Jurisdictional Separations, Staff witness Hessing states that there is
value in applying a consistent class cost of service methodology from case to case. Use of a
consistent methodology, he states, allows usage, and customer characteristics and the accounting
data to drive the results. Hessing accepts the Company s proposed cost of service methodology
which he states is the same methodology with minor modifications that the Commission
accepted as the starting point for revenue allocation in the Company s last general rate case. Tr.
at 1259-1260.
Changes to cost-of-service methodology shift costs among classes and affect
revenue requirement responsibility. Staff witness Schunke also proposes an incremental move
ORDER NO. 29602
(200/0) toward full cost of service in recognition that cost of service results are not precise and
unacceptably large increases to some classes would occur. If a second step adjustment in cost of
service is needed, Schunke recommends reviewing cost of service after the Power Cost
Adjustment (PCA) balance drops to zero. Tr. at 1321-1325; Tr. at 1318; Exh. 143.
Coeur Silver Valley witness Yankel contends that if data is utilized that is more
reflective of cost causation, the rate of return for the Schedule 25 class comes out to be above
the jurisdictional average. Mr. Yankel recommends that Schedule 25 customers be given the
average jurisdictional increase. Yankel notes that A vista did not directly assign identifiable
primary plant (i., lines, towers, and overhead conductors in Accounts 364-367)
corresponding Schedule 25 customers, as it did for Potlatch. Yankel proposes that certain
Schedule 25 Primary Distribution costs be directly assigned. Yankel contends that rates should
be established that better reflect load factor differences and cost causation. Tr. at 515-523.
Potlatch witness Peseau contends that the change proposed by A vista witness Knox
to move to a four-factor allocator for common costs is a significant change that improperly shifts
costs to higher load factor customers. Tr. at 957-959. Peseau contends that Knox in her cost of
service analysis has improperly defined direct O&M expenses as one of the four-factors to
allocate common costs. Peseau contends that this can be corrected by removing the fuel and
purchased power expenses.
A vista, Peseau notes, has historically allocated common costs to customer groups
with a 600/0 customer/40% energy allocation factor. Peseau recommends that the Commission
continue to use its previously adopted 600/0/40% method for common cost allocation or adopt
the four-factor method with his corrections. Tr. at 926-933; 958-959.
If the overall approved increase is less than 100/0 Peseau recommends that all
customer classes be moved to full cost of service. If the increase is greater than 10%, residential
and large general service rate customers, he states, should be moved at least halfway toward rate
of return parity, with two annual automatic adjustments thereafter to close the remaining gap.
Tr. at 938. Peseau contends that Staff's proposal to move various rate schedules only 20%
toward cost of service will perpetuate the longstanding subsidies among customer classes. The
PCA reduction proposed by the Company in this case, he states, provides an opportunity to
make a bold move toward cost of service.Tr. at 959-962.Peseau proposes to allocate
transmission costs strictly on a demand basis as, he states, was done in the recent Idaho Power
ORDER NO. 29602
rate case, Case No. IPC- E-03-13. Peseau contends that A vista s cost of service study overstates
the annual cost of serving Potlatch by approximately $1.4 million per year. Tr. at 926-938.
A vista witness Knox on rebuttal agreed with Potlatch that resource costs should be
excluded from the O&M portion of the four-factor allocator used for common costs in cost of
service. She revised her COS study accordingly. Tr. at 338. Knox contends that the 1000/0
demand allocation advocated by Peseau for all transmission costs represents a material change
from the peak credit methodology the Company has historically applied and opposes its use. Tr.
at 339-341. Regarding Couer Silver s proposal Knox contends that the cost of primary
distribution plant Yankel proposes to assign to Schedule 2? customers is understated and cannot
be reasonably estimated without further investigation. Knox proposes an intermediate cost
assignment between the Company s allocation and Y ankel' s estimated assignment , a change
which materially increases the rate of return for Schedule 25 customers (including Potlatch'
Lewiston Facility) and shifts cost responsibility to other customer classes. Tr. at 341-344.
Hirschkorn recommends that the Commission use the ratio of the revenue increase it
proposes for each schedule as a guideline to move halfway toward COS regardless of the overall
approved increase. Tr. at 815-817.
Recommended Spread of Revenue Increase
Residential Schedule 1
General Service Schedule 11
Large General Service Schedule 21
Extra Large General Service Schedule 25
Potlatch (Schedule 25)
Pumping Service Schedule
Street and Area Lighting Schedules 41-
TOT AL
.401
101
236
076
155
017
014
1.00
Hirschkorn disagrees with Peseau s recommendation that all schedules be moved to full COS
over the next 2 years based on the current COS study if the rate increase is greater than 100/0.
Hirschkorn contends that the cost of service study should only be used as a guide in establishing
rates. The testimony has shown, he states, that one or two adjustments in cost allocation can
significantly change the results of a study. Tr. at 822.
The Commission has reviewed and considered the Company cost-of-service
allocation study, Potlatch and Coeur Silver s critique of same and Staffs support of the study.
ORDER NO. 29602
The Commission finds A vista s Peak Credit Cost of Service methodology with the Company
proposed revisions to allocation of common costs suggested by Potlatch and allocations of
primary distribution costs as suggested by Coeur Silver to be an appropriate starting point to
allocate costs to customer classes. Recognizing cost-of-service studies are a balance of art and
economic principles, we find that the COS study methodology proposed by the Company reflect
a reasonable approximation of class revenue responsibility.
A. Weather Normalization
An adjustment is used to calculate the change in kWh usage required to adjust loads
experienced to the amount expected given "normal" weather. A vista witness Knox proposes a
change in the prior weather normalization methodology to include the effect of weather sensitive
cooling and reflect exactly five heating seasons rather than five and a half. The change
reflective of increased saturation of the air conditioning market in the region. It also reflects that
although normally a winter peaking utility, in recent years the Company has experienced
summer peaks near the same level as the winter peaks. Without incorporating cooling
sensitivity, the prior method would add usage during an abnormally hot summer due to fewer
than normal heating degree days. Tr. at 319-320. Staff witness Sterling accepts A vista
electric weather normalization performed as accurate and reasonable. Tr. at 1190; 1192-1194.
The Commission has reviewed the record and approves the change in the weather
normalization method as reasonable and comporting with changes in the Company s heating
degree days and customer usage.
B. Power Supply Adjustments
Avista witness Johnson states that the Company s power supply expense has
increased by approximately $11 million (Idaho) from the prior general rate case. The increase is
primarily driven by reduced wholesale net revenues and an increase in fuel expense. The
Company proposed 67 pro forma adjustments to 2002 test year power supply revenue and
expenses, the majority of which are associated with contracts, the expiration of an existing
contract or the initiation of an existing contract, or due to specific, projected or estimated
changes in contract rates or charges. The remaining charges result from the AURORA dispatch
simulation model, and projected fuel expenses. Expenses have been reduced by $85.9 million
and revenues have been reduced by $55.4 million for a net $30.5 million decrease in the system
ORDER NO. 29602
revenue requirement from the 2002 test year (a $7.832 million decrease in Idaho). Tr. at 270-
277; Tr. at 167-168.
Staff witness Sterling agrees that it is appropriate to pro form the normalized 2002
test year power supply expenses to the period of September 1 , 2004 through August 1 , 2005.
Fifty-two of the adjustments are to test year expenses; 15 adjustments are to test year revenues.
Exh. 128.Staff reviewed information related to the underlying contracts including some
contracts and Company workpapers and excerpts. Sterling concludes that the power supply
adjustments proposed by A vista are reasonably known and measurable. Sterling also concludes
that the adjustments are based strictly on test year loads and are independent of future retail load
conditions. Staff recommends approval of the Company s power supply adjustments. Tr. at
1194-1204.
The Commission has reviewed the record and is satisfied that the pro forma
adjustments to power supply are proper.
3. Class Revenue Allocations
Accepting the Cost of Service results as a starting point, the Commission must
determine the appropriate revenue requirement to be recovered in the rates of the different
customer classes. In doing so we strive to achieve an equitable apportionment of the revenue
requirement among the customer classes. The closer customer classes are moved to full cost of
service the fairer the rates that are set. In this case A vista s COS study indicates that Schedule
residential customers and Schedule 25 Extra Large General Service customers are receiving
substantial subsidies from all remaining customer classes. Tr. at 321.
Although cost of service studies are not precise, we find it is important that cross
subsidies among customer classes be minimized. We find it reasonable in this case that all
customer classes be moved to within 100/0 of full cost of service; no class less than 90%, no class
greater than 110%. See Appendix E.
4. Rate Design and Tariff Issues
A vista proposes a number of changes to rate design for the customer classes
including increasing the fixed customer charge for residential customers.The Company
proposes a declining tail block for Schedule 11 customers to preserve class identity and revenue
responsibility and to discourage customer migration between classes.The Company also
proposes to increase energy charges for every customer class in order to generate the authorized
ORDER NO. 29602
revenue requirement. This section of the Order addresses each customer class and the changes
proposed.
A. Residential Service (Schedule 1)
A vista proposes to increase the basic customer or minimum monthly charge for
residential customers from $4.00 to $5.00.The customer charge is a fixed component in rates
that recovers a portion of the cost required to serve a customer. The Company recommends that
the remaining revenue requirement be recovered through an equal increase to both energy
blocks. Tr. at 782.
Staff recommends no increase in the $4.00 basic and minimum charges. Tr. at 1325.
Citing a Commission ruling in a recent Idaho Power rate case, Order No. 29502 at 53, Staff
witness Schunke testified that the basic charge should be based on the direct cost of meter
reading and billing and should not include any fixed plant cost. The monthly cost associated
with meter reading and billing for Avista is $2.62 for residential customers. The 25% increase
in the basic charge recommended by the Company, Staff contends, would have a
disproportionate affect on customers with low usage. Tr. at 1326-1327. Staff recommends that
the two-block energy rate continue to be priced with a higher second block rate for usage in
excess of 600 kWh (month). Staff recommends an average overall increase in base rates of
18.80/0 for Schedule 1. Tr. at 1325-1326.
On rebuttal A vista proposes a revised rate spread that would provide an identical
increase in rates for each of the two energy blocks. If the proposed increase in the monthly
basic charge is not approved, A vista proposes that a higher percentage increase be applied to the
first block rate. The Company argues that an increase to the basic charge is appropriate to
recover the costs associated with the plant that is on the customer s property and dedicated to
serve that customer. Tr. at 818-819.
The Commission is unwilling to dampen the incentive for customers to conserve
, energy. For the residential customer that incentive is generally a price signal and the ability to
control the total bill amount. We find that the present customer charge for residential customers
is sufficient to provide the Company with recovery of those costs that are directly attributed to
the customer taking service. We find that those charges are related to meter reading and
customer billing costs, in this case approximately $2.62/residential customer. While we are not
inclined to increase the charge; neither do we find a compelling reason to decrease it. We also
ORDER NO. 29602
approve an increase in the inverted block energy rates that recover the class revenue requirement
and use the ratio between blocks proposed by Staff.
B. General Service (Schedules 11 and 12)
A vista proposes adding an additional energy usage block that would provide a lower
energy rate for usage in excess of 3650 kWh per month than for usage below that amount
because, under present rates, customers whose monthly peak demand exceeds 20 kW are billed
at a higher average amount per kWh even though these high load factor customers cost less to
serve on a per kWh basis. No increase to the customer or demand charge for monthly peak
demand in excess of20 kW is proposed. Tr. at 783-785.
Having both demand-metered and non-demand metered customers on a demand
schedule, Staff contends, is the real problem that the Company is attempting to address with a
declining tail-block. This is because higher use customers effectively pay more per kWh
because Avista does not bill the first 20 kW. Although opposed to Avista s proposed declining
block rates, Staff recommends acceptance in this case with the requirement that A vista be
directed to gather additional information so that the Company can provide a proposal in its next
rate case to: (1) divide Schedule 11 into two separate schedules, one demand metered and one
not; (2) eliminate declining block rates in Schedules 11 , 21 and 25; and (3) implement time of
use (TOU) rates wherever practical. Staff recommends an average overall increase in base rates
of 11.4% for General Service Schedules 11 and 12. Staff recommends no change in the basic
charge, the minimum charge, or the demand charge. Tr. at 1319; 1327-1329.
On rebuttal the Company committed to conduct a study to split the schedule prior
its next general filing and to assess whether Staff s proposal should be implemented. Tr. at 819-
820.
The Commission agrees with Staff that demand metered and non-demand metered
customers should be separated to allow for a more appropriate billing of demand and energy.
However, we recognize that the information necessary to make such a separation is currently
unavailable. We therefore direct the Company to gather the required information and submit its
findings to the Commission as part of its next general rate case. We accept the Company and
Staff proposal to move to two block declining energy rates. Our rates recover the class revenue
requirement and incorporate the ratio between blocks proposed by the Staff.
ORDER NO. 29602
C. Large General Service (Schedules 21 and 22)
A vista proposes adding an energy usage rate block to Schedules 21 and 22 so that
the larger customers would pay a lower incremental energy rate for usage beyond 250 000
kWh/month than for usage below that amount. The Company is proposing that the base tariff
rates be the same for usage over 250 000 kWh under Schedule 21 and for usage under 500 000
kWh under Schedule 25. Approximately 1 800 customers take service under Schedule 21.
Customers served under the schedule can have a monthly demand anywhere from 50 kW up to
2500 kW, the minimum level required for service under Schedule 25. Generally, larger use
customers under the schedule are less costly to serve than smaller use customers on a per kWh
basis. Several Schedule 21 customers have a higher load factor than many customers served
under Schedule 25 - yet they pay an average energy rate under Schedule 21 that is presently up
to 500/0 higher. Because of the present rate differential between Schedules 21 and 25 , a
customer switching from Schedule 21 to 25 can see a lower annual energy bill well in excess of
$100 000 , that represents a revenue/margin loss to the Company until corrected in a general rate
case. The Company reports that two of the 15 customers presently served under Schedule 25
switched from Schedule 21 in 2003. The Company proposes to increase the minimum demand
charge from $225 to $250, and increase the demand charge for kW over 50/month from $2.75 to
$3.00. Tr. at 785-789.
Staff recommends that A vista s proposal for the second block energy rate and for
increases to the demand charges be accepted. Staff recommends that A vista be directed to
develop additional information before the next rate case assessing the economic impact of the
second block and justifying the continued use of a declining block energy charge. Tr. at 1319;
1329-1330. Staff proposes an overall increase in base rates of 12.90/0 for Schedules 21 and 22.
The Commission accepts the demand charge as supported by both the Company and
Staff. We also accept a second block energy rate with the caveat that the Company further
justify a declining block rate before the next rate case. Finally, we establish the energy rates to
achieve the allocated revenue requirements with the Staff proposed ratio between first and
second block energy rates.
D. Extra Large General Service (Schedule 25)
The Company proposes a declining block energy charge whereby the Schedule
customers would pay a lower incremental energy rate for usage beyond 500 000larger
ORDER NO. 29602
kWh/month, than for usage below that amount. The Company proposes to increase the
minimum demand charge from $7 500 to $9 000, and to increase the demand charge for kva
over 3 000/month from $2.25 to $2.75 per kva. Tr. at 788-789.
A vista includes Potlatch's Lewiston facility in this Schedule but proposes changes to
the rate structure so that Potlatch will pay an average rate per kWh that is lower than the average
rate(s) paid by other Schedule 25 customers. Tr. at 769; 780; 785-794.
Staff recommends that A vista s proposal for the declining second block energy rate
and for increases to the demand charges be accepted. Staff recommends that Avista be directed
to demonstrate in its next rate case that the Schedule 25 tail-block rate exceed the Company
variable costs and provides a contribution to the Company s fixed costs. Staff recommends an
overall increase in base rates of 20% for Schedule 25, with Potlatch receiving a 14.90/0 increase.
Tr. at 1319; 1330-1331.
Coeur Silver recommends that Schedule 25 customers be gIven the average
jurisdictional increase. By way of critique, Coeur Silver recommends that A vista should be
directly assigning as opposed to allocating distribution plant to Schedule 25 customers with
identifiable primary plant. Coeur Silver also recommends that rates be established that better
reflect load factor differences and thus cost causation. After Potlatch- Lewiston, Coeur Silver
contends that it is the next largest customer in Schedule 25 and has a significantly higher load
factor than the others. Those customers with a high load factor, it contends, should be rewarded
with lower rates. Coeur Silver recommends that the Commission (1) increase the demand
charge and lower the energy charge(s), or (2) develop a declining block energy rate that is load-
factor dependent (i., the first so many kWh per kW are priced at one rate while usage above
that level is priced at a lower rate). Although Coeur Silver has no preference as to which
method should be adopted, it suggests that the Commission target a ratio of demand to energy
charges of at least 120. Tr. at 500-501; 508-513.
Based on the significant increase in the present rate of return for Schedule 25 that
results from the revised allocation of common and distribution costs, A vista on rebuttal proposes
to reduce the original proposed rate increase. The first block energy rate would be decreased
and the second block increased. The reduction in the proposed increase for Schedule 25 is offset
by an additional increase to Residential Schedule 1. Tr. at 814-815; 818.
ORDER NO. 29602
Coeur Silver is troubled by Staff comments regarding the declining block and
though it welcomes the development of additional data, it does not believe that its intended
purpose should be the elimination of the declining block rates. Tr. at 520. Coeur Silver dislikes
Staff s rate design because in spite of the inclusion of a declining block energy rate, it reduces
rates too little for higher load factor usage. Yankel proposes a rate design that better rewards
high load factor customers. Instead of $9 000 for the first 3 000 kW and $2.75 per kW for each
additional kW, Yankel proposes the initial 3000 kW be priced at $10 500 and that each
additional kW be priced at $3.25 per kW - similar to Idaho Power s rate. Tr. at 520-523.
Potlatch on rebuttal expresses support in principle for Coeur Silver s proposal to
directly assign primary facilities costs to Schedule 25 customers. Peseau is convinced that all
cost of service models - including his own significantly overstate Schedule 25' s cost of
servIce. Tr. at 962-963.
The Commission hereby adopts the increase in demand charges as proposed by the
Company and accepted by Staff. We also approve the creation of a second block energy rate
and establish energy rates that achieve the revenue requirement for the class while maintaining
the Staff proposed first and second block rate differential ratios. However we find the
testimony of Potlatch and Coeur Silver persuasive regarding the make up of Schedule 25. We
believe it is not appropriate to continue to include Potlatch as a customer in Schedule 25 and we
therefore establish a separate stand alone schedule for Potlatch as discussed more fully in the
following section.
E. Potlatch's Lewiston Plant
On January 15, 2004, in Order No. 29418, this Commission approved a new Power
Purchase and Sale Agreement (Agreement) between Avista and Potlatch. The Agreement is for
a 10-year term, beginning July 1 , 2003 and ending June 30, 2013. As the sole purchaser of
Potlatch's generation at the plant, Avista pays Potlatch $42.92 per megawatt-hour for up to
543 120 megawatt-hours (62 average megawatts) generated by Potlatch during each "Operating
Year" (July 1 through June 30) of the Agreement. This amount is equivalent to 62 average
megawatts and is referred to in the Agreement as the "Base Generation Amount." There are
special provisions in the Agreement for the purchase of additional amounts generated by
Potlatch in excess of the Base Generation Amount. Avista will serve Potlatch's entire load
requirements at the Lewiston Plant, approximately 100 average megawatts, under its Extra
ORDER NO. 29602
Large General Service Schedule 25 rates, including the present Power Cost Adjustment (PCA)
surcharge and all other applicable rate adjustments, unless the Commission issues an Order in
the future authorizing different billing rates.Nothing in the Agreement prejudices either
Avista s or Potlatch's right to propose, or the Commission to order in future rate proceedings
that Avista s service to Potlatch should be priced at rates other than Schedule 25. Tr. at 790-
791.
Avista is proposing that Potlatch continue to be served under Schedule 25 , however
the Company is proposing changes to the present Schedule 25 rate structure that will result in
Potlatch paying a lower average rate per kWh than the average rate(s) paid by other Schedule 25
customers. Tr. at 769; 785-794. The Company is proposing a two-tier declining block energy
rate structure for Schedule 25 , as compared to the present single energy rate for all usage under
the Schedule. Tr. at 791. Because of the magnitude of Potlatch's load requirement, over 99% of
their 2002 energy usage would be priced at the lower second block rate. For all other Schedule
25 customers in total, only 720/0 of their usage is priced at the lower second block rate.
Additionally, Potlatch's load factor is substantially higher than other Schedule 25 customers.
Tr. at 792.
Potlatch contends that the A vista and Potlatch power supply agreement is a unique
contract that governs A vista s service to only one customer - the Potlatch Lewiston facility. In
that agreement, the parties agreed to the temporary use of Schedule 25 rates for service to the
facility, pending the next rate case. But Potlatch did not agree to become a Schedule 25
customer. It has always been a "special contract customer.Potlatch recommends rejection of
A vista s proposal to include Potlatch's Lewiston facility in Schedule 25 because Potlatch is
three times the size of the entire Schedule 25 class and should have its own tariff as a special
contract customer. Tr. at 938-939.
Peseau s recommendation to create a separate rate schedule for Potlatch's Lewiston
facility, the Company concedes on rebuttal, has merit, especially as rates are moved closer to the
cost of providing service in the future. If the Commission creates a separate rate schedule for
Potlatch, A vista proposes that the original proposed energy rates for Schedule 25 be reduced by
a uniform percentage to yield the revised overall increase for the Schedule. Tr. at 821-822.
ORDER NO. 29602
Coeur Silver on rebuttal contends that Potlatch-Lewiston should not be included in
Schedule 25 rates because no other Schedule 25 customers have load characteristics that are
remotely similar. Tr. at 520.
As indicated in our Schedule 25 discussion, the Commission finds it reasonable to
establish a separate stand alone service schedule for Potlatch's Lewiston facility. As stated by
witness Peseau, Potlatch is three times larger than all other Schedule 25 customers combined.
We believe establishing a separate schedule for Potlatch will result in rates for Potlatch and
Schedule 25 that more accurately reflect cost of service. The Commission hereby approves
demand rates for Potlatch equal to those established in Schedule 25 but establishes a single
block energy rate that generates the Potlatch revenue requirement.
F. Pumping Service (Schedules 31 and 32)
A vista proposed that an increase be applied to the present energy blocks of pumping service
schedules on an equal cents per kWh basis. Tr. at 789-790. Staff agrees with the Company that
all of the proposed increases to the pumping class should be applied to the energy rate. The
basic charge under both Company and Staff proposals would remain at $6.00. Staff
recommends that Schedule 31 and 32 base rates be increased by 13.5% Tr. at 1331.
The Commission agrees that the basic charge for service Schedules 31 and 32 should
not be changed. We increase the declining block energy rates in the ratio proposed by Staff.
G. Street and Area Lighting (Schedules 41-49)
A vista proposes to increase all present street and area light rates on an equal percentage basis.
Tr. at 790. Staff recommended a uniform increase to lighting customers and recommends that
Schedule 41-49 base rates be increase by 17.2%. Tr. at 1332.
The Commission approves a uniform increase to Street and Area Lighting schedules
and increases rates in the ratio proposed by Staff.
Electric Rates
The electric rates we approve as just and reasonable are set out in attached Appendix
A. Idaho Code ~ 61-502. Base electric rates increase by $24 716 000 while PCA rates decrease
by $20 337 000 and DSM rates decrease by $1 197 000. This results in a net increase of
182,459 or 1.90/0. The authorized electric revenue to be recovered in rates including
residential exchange credit, Centralia credit, PCA surcharge and DSM rider is $175 029,459 for
a total average rate of 5.60 cents or 1.9% increase. The increase for an electric residential
ORDER NO. 29602
customer using an average of 941 k Whs per month is $4., or a 7.1 % increase in their electric
bill.
POWER COST ADJUSTMENT (PCA) ISSUES
1. Deal'~" and Deal "B" (PCA issue)
In Avista PCA Order No. 29377 , Case No. A VU-03-, the Commission deferred
to this rate case a PCA recovery decision regarding the Company s acquisition and later sale at a
loss of natural gas to fuel the Coyote Springs 2 (CS2) combined cycle combustion turbine or
other less efficient Company generation resources.During the first half of 2001 Avista
experienced a combination of low water conditions and high market prices. Tr. at 551. A vista
entered into a series of contracts, purchases and financial swaps, beginning in March 2001 to
secure gas and gas transportation, i., Deal A and Deal B. CS2 was initially scheduled for
testing in early 2002 and was expected to be commercially available in July 2002.
The first gas supply contract (Deal A) was to be delivered November 1 , 2001
through November 1 , 2004. Deal A consists of two transactions of 10 000 dth/day each, for a
36-month delivery term, that were entered into for the purpose of hedging or fixing, the natural
gas price for the period November 1 , 2001 through October 31 , 2004. Tr. at 564. One
transaction was entered into on April 11 , 2001 at a price of$6.75/dth and the second transaction
was entered into on May 2 2001 at a price of $6.50/dth. Tr. at 564. The price for October 2004
gas was locked-in for three and one-half years into the future. Exh. 139, p. 7. The system net
loss attributed to Deal A gas is $47 936 000 through May 31 , 2004.
The second gas supply contract (Deal B) was for delivery to begin June 1 , 2002 and
continue through October 31 , 2003. Deal B consists of two hedge transactions of 10 000
dth/day each, for the l7-month delivery term June 2002 through October 2003. One transaction
was entered into on April 10, 2001 and another transaction on May 10, 2001 at prices of
$6.50/dth and $5.35/dth, respectively. Tr. at 565. The October 2003 price was locked-in two
and one-half years into the future. Exh. 139 , p. 7. The system net loss attributed to Deal B gas
is $21 755 640 through May 31 , 2004.
In March 2001 , Avista Energy secured a physical supply of natural gas for CS2. Tr.
at 572, 573; 609, 610. The purchase price, however, was not fixed but was index based. Avista
maintains that the purchase of firm indexed based natural gas satisfied the fuel requirement for
CS2 project financing. Tr. at 571.
ORDER NO. 29602
The Deal A and Deal B transactions fixed the price for 840/0 of the gas purchased at
index based prcies. Tr. at 574. The Deal A and B transactions were financial hedge transactions
as opposed to physical transactions. A financial gas transaction as explained at hearing involves
no actual exchange of physical gas. Instead, a financial deal is agreed upon by a buyer and
seller who take "price positions." The buyer bets that future gas prices will rise, while the seller
bets that future gas prices will fall. Depending upon the future monthly movement of gas prices;
the loser, or the counter-party on the wrong side of the bet writes a monthly check or "settles
with the other party. BP and Mirant were the counter-parties on Deal A. Tr. at 909-910. Avista
Energy was the counter-party on Deal B.
A vista argues that the purchases were necessary because A vista had an electric
resource deficit, hedge prices compared favorably to forward prices, and that the purchases were
reasonable given energy crisis market conditions. Tr. at 540-541; 564-591. It is also worth
noting, the Company states, that prior to the acquisition of CS2, the Company s gas-fired units
were all peaking units. The ownership of CS2, a base-load gas-fired project, brings with it a
greater need to enter into hedge transactions. Tr. at 615. The Company maintains that at the
time the natural gas was purchased, it was anticipated that when the gas was to be delivered CS2
would be operational and more economical to operate than making market energy purchases.
However, as the Company states, as with all forward transactions the market conditions at the
time of delivery will undoubtedly be different from what they were at the time the transactions
were executed. Tr. at 585. As it turn out at the time the gas was scheduled for delivery CS2
was not operational nor was it economical to use the gas purchased for CS2 at the Company
other facilities. Instead Avista simply purchased its power needs on the electric market and sold
the gas back into the gas market at a loss because gas prices had declined. Tr. at 1261.
Taking simultaneous and opposite positions on the same Deal B financial hedge
transaction, Potlatch contends, cannot be deemed prudent. Tr. at 917. Potlatch contends the
energy trader at A vista who was buYing the fixed-price hedge on behalf of A vista Utilities was
the same energy trader who was selling it on behalf of A vista Energy. The length of the Deal A
and B hedges based on Potlatch's investigation appears to be unprecedented, outside the
Company s normal business practice, and seemingly unmatched in the industry. Tr. at 918-919.
A vista disputes Potlatch's contention that the Deal A and B transactions were of unprecedented
length. Tr. at 615-616.
ORDER NO. 29602
Potlatch contends that the only thing that made simultaneously taking opposite sides
of the bet on the Deal B swap an attractive transaction for Avista Corp. was that the PCA
mechanism insulated the shareholders of the parent company by passing through to ratepayers
the excess of the locked in hedged natural gas prices over and above the actual market prices
that existed at the time. Tr. at 910-911. A vista Energy s role as a broker for the utility division
Potlatch contends, placed it in a fiduciary position to disclose that it considered Deal B to be a
bad deal for Avista Utilities. Tr. at 912. Speaking to the roles and responsibilities of Avista
Utilities and A vista Energy in Deal A, A vista Utilities states that it requested that A vista Energy
enter into the Deal B hedge transactions due to the non-standard 17-month term. Also there
were limited counterparties willing to transact with A vista Utilities. Tr. at 618.
The high costs associated with Deals A and B, Potlatch contends, are the result of
imprudent decisions and self-dealing between A vista Corp. and A vista Energy that resulted in
more than $62 million in excess gas costs on a system-wide basis. These unprecedented long-
term financial swaps were never "in the money" nor did they allow for physical delivery. Both
deals ($62.4 million) should be disallowed for imprudence, Potlatch contends, but at a
minimum, Deal B ($18.3 million) must be disallowed due to self-dealing. Tr. at 908-922.
Potlatch contends that the Company s normal practice (for its retail natural gas
business) was to hedge for periods approximately six months prior to a season (November-
March or April-October). Forexample, May 1 , 2001 prices were used for the November 2001-
March 2002 season. Exh. 203. If A vista had hedged for Deal A in the same manner it was
hedging other natural gas purchases in the same time frame, Deal A gas costs would have been
$30 365 240 lower. Tr. at 921; Exh. 203. Potlatch contends that should the Commission not
disallow the entirety of the Deal A costs, it should disallow the $30.4 million of Deal A costs the
Company would not have lost had it engaged in normal hedging practices, adjusted for both the
Idaho jurisdiction allocation as well as PCA sharing. Tr. at 921-922. A vista responds that it is
important that the purchasing practice and hedging strategies for the Company s natural gas
distribution business not be confused with the purchasing practices and strategies of the
vertically integrated electric utility. Tr. at 613. The Company s natural gas purchasing practices
and hedging strategies, it states, were developed in consultation with the Commission Staffs in
Idaho, Washington and Oregon, both through informal communications, through the natural gas
IRP process and through the current Benchmark Mechanism. Tr. at 614.
ORDER NO. 29602
Staff recommends that $6,496 669 of Idaho net losses from Deal "B" gas purchases
to run Coyote Springs 2 should be denied because A vista violated risk policy provisions (in
excess of the 150MW long limit) in the Company s Energy Resources Risk Policy and
transacted with an unregulated affiliate without appropriate safeguards (a proper code of conduct
or a requirement of lower-of-cost or market pricing). Tr. at 1262; Exh. 141; Tr. at 1274. Staff
contends that its Deal B proposal amounts to giving the customer the better deal, cost or market.
Tr. at 1270. Staff proposes to leave the $8 677 766 in Idaho Deal "A" losses in the PCA. Staff
contends that Deal A hedges were not done with an A vista affiliate and that Deal A did not put
Avista over the long limit contained in its Risk Management Policy. Tr. at 1270. Potlatch notes
however that Deal A and B were both financial only - and not the physical index-priced gas
purchases. Potlatch contends that its irrelevant that the physical purchases were, or were not
over some designated volumetric or long limit. Tr. at 955.
Both Deal A and B purchases, Staff states, were ongoing at the 18-month short-term
risk policy transition point in October 2002. Tr. at 1264. In contrast to Staff's near term risk
policy point of view, Avista analyzes this issue with a long-term (greater than 18 months)
resource planning point of view. Staff argues the short-term risk policy should be used because
the long-term IRP does not include gas acquisition criteria and the load balance was not
consistent with the long-term acquisition process.Staff contends that the Company took
unusual risks for both A vista Energy and its customers when hedging the price for the length of
the Deal B contracts. Avista Energy s risk was that gas prices would go up and that when it
needed gas for delivery it would be more costly. The utility was exposed to several types of
risk. It had the risk that gas prices would both go down and gas would cost less when it was
needed. The utility also had the risk that electric and gas prices would go down such that the
gas could not be economically used to produce electricity. Because the deal with A vista Energy
was not provided to A vista Utilities at cost, A vista Energy had the opportunity to profit
keeping the difference between the actual cost and fixed price of gas sold to the utility. In the
end Avista Energy profited and the regulated utility is proposing that its customers pay 900/0 of
the costs. Because A vista did not enter into similar long-term gas purchases for its gas
customers , Staff contends that it was inconsistent and highly speculative to do so for electric
customers. Tr. at 1260-1274; Exh. 140.
ORDER NO. 29602
A vista maintains that the costs associated with the Deal A and Deal B contracts were
prudent given the information and circumstances at the time and should ultimately be
recoverable through the Idaho PCA mechanism. Tr. at 586. The Company maintains that the
transactions were reasonable and consistent with the Company s long-term planning criteria and
risk policy. The duration of these purchases was not of an unusual length to cover open power
positions.It cannot be assumed A vista Energy profited by $18 million from the Deal
transactions as suggested by Peseau. If the Commission determines part of the Deal
transactions should be disallowed, the Company proposes two alternative methodologies to
calculate disallowance ($2.7 million or $4 million v. Staff's $6.5 million). Tr. at 193-194; 602;
609-631.
Potlatch on rebuttal maintains that Staff should not have accepted the Deal A excess
gas costs because Hessing s compelling argument to disallow Deal B gas costs applies to Deal A
as well. Both transactions lack cost-benefit analyses, were irregular, and were speculative. Tr.
at 953-957.
Commission Findings
Before the Commission can address the Deal A and B losses we must first consider a
threshold issue, the propriety of the A vista Energy transactions themselves. Relevant to our
consideration is the affiliate relationship that exists between A vista Energy and A vista Utilities.
The Commission has authorized A vista Energy to act as an agent for A vista Utilities gas. As a
condition of such approval a benchmark mechanism and agency agreement were put in place.
We established some sideboards, a code of conduct and rules that established transparency and
governed the transactions performed by A vista Energy on behalf of A vista Utilities. This
operational infrastructure was put in place to provide an auditable paper trail and to insulate
A vista Utilities and its customers from the risk associated with the Company s non-regulated
subsidiary operations.
A vista Energy had authorization by this Commission to act on behalf of A vista
Utilities-gas, not on behalf of A vista Utilities-electric. The record reflects that there was an
understanding between the Company and Commission Staff that there would be no transactions
between Avista Utilities-electric and Avista Energy. Tr. at 54, 55. A protocol had not been
established for such transactions. When asked whether a similar protocol was followed for
A vista Utilities-electric, the Company s policy witness Morris stated that A vista follows FERC
ORDER NO. 29602
guidelines with respect to its electric operations. Tr. at 54. He contends that the Company also
follows its Risk Management P~licy. Tr. at 58. During the time of these transactions the
Company was in a severe liquidity crisis. Because of its financial troubles it was also having
difficulty doing business with other counterparties. The Company made a choice at that time
that it was in the best interest of its customers to be able to lock-in a $38 to $48 product. The
Company preceded to hedge and lock-in a price at market. Tr. at 58.
A vista may have had the best intentions.The best intentions however cannot
overcome the perception that it also had a divided loyalty, an obligation to shareholders to
maximize profits and an obligation to treat its utility customers fairly. There was no protocol in
place for electric side gas procurement. In choosing to act without regulatory approval the
Company assumed the risk of loss. We have reviewed the documentation provided by the
Company. Tr. at 590; Exh. 7. The paper trail that the Commission and our auditing Staff rely
on for gas benchmark transactions was not present for Deal A and B. The appearance at hearing
was that the justification for the transactions was cobbled together after the fact. Other than a
notational entry that the financial hedges were required by lenders to obtain construction
financing (financing that was ultimately not secured), there was no lender documentation to
support such a requirement.
Regarding Deal B hedge losses, we find absolutely no justification for authorizing
PCA recovery. Avista Energy assumed a financial position directly at odds with Avista
Utilities. At a minimum it was highly irregular. Certainly it was speculative. The Company
was operating outside its own risk management policy. When it chose to act without regulatory
approval of an affiliate methodology, it was risking its own money, not its ratepayers
Regarding Deal A hedge losses, we find that many of the reasons justifying our
disallowance of Deal B are also present for Deal A. However, there are differences that create a
basis for different treatment. Among those differences are the counterparties themselves, neither
of whom were affiliates of A vista Utilities, and Staff s analysis that demonstrates that these
transactions, had an operating protocol been in place, would have been viewed by Staff to be
within the Company s established risk management limits.
This Commission acts knowing that it's decisions may have financial repercussions
in the lending community and on Wall Street. At the same time we send a signal to the
regulated utility and its parent that affiliate transactions between regulated and unregulated
ORDER NO. 29602
entities must be guided by protocol. In failing to put such a protocol in place, the Company
acted at its peril. We find that as to Deal A losses there should be a sharing of risk between
ratepayers and shareholders. We find a reasonable disallowance to be one-third of the total
losses.
As developed at hearing in Exhibit 141 , Idaho PCA deferral balance at the end of
May 2004 was $26 261 334. Deal A losses through May amounted to $47 936 010 on a system
basis; $15 905 167 on an Idaho jurisdictional basis. With 90/10 PCA sharing the Idaho PCA
amount related to Deal A losses is $14 314 651. Of that amount $5 636 885 was previously
authorized for PCA recovery (July 1 - June 2002). Based on our consideration of the record and
Deal A findings , the Commission finds it reasonable to exclude or disallow one-third of the
Idaho system Deal A losses, or $4 771 550.Our mathematical calculation of the Idaho
jurisdictional disallowance is based on the total Deal A losses through May 2004. This decision
will also apply to Deal A losses after May 31 , 2004 that otherwise may be in next year s PCA.
We also direct A vista to work with Staff to make the appropriate interest adjustments to the
PCA deferral account. The Commission disallows the losses associated with Deal B, in the
amount of $6,496 669.
2. Updated PCA Components
Avista s electric Schedule 66 Power Cost Adjustment (PCA) is a rate adjustment
mechanism that annually adjusts a portion of customer rates to allow A vista to recover or refund
900/0 of the amount above or below the base power supply costs established in a general rate
case and included in the revenue requirement and base rates for the customer classes.
The new authorized level of annual power supply expense proposed by the Company
is $71,456 998. This is the sum of Accounts 555 (Purchased Power), 501 (Thermal Fuel), and
547 (Fuel) less Account 447 (Sale for Resale). Base power supply costs are updated in general
rate cases for use in the PCA. The Company also proposes to update the load change revenue
adjustment multiplier (average annual variable power supply cost of meeting new load as
determined from the Company power supply model) from 21.23 $/MWh to 36.38 $/MWh. Tr. at
279-280.
Staff witness Hessing agrees with the Company s calculations and supports Avista
base power supply amounts and update to the load change revenue adjustment multiplier. Tr. at
1274-1276. The Commission approves these proposed updates.
ORDER NO. 29602
3. PCA Rate Recovery
Avista s witness, Mr. Hirschkorn proposes to reduce PCA rates in this case to
recover one-half of the estimated Idaho PCA deferred balance each year for two years. Tr.
767; 779; 820. Staff witness Hessing supports the Company s proposal to calculate rates to
recover the remaining PCA balance over two years but recommends use of an actual known end
of month balance instead of an estimated balance. Tr. at 1276-1277.
With respect to PCA issues deferred to this rate case in Order No. 29377 regarding
Coyote Springs 2 (CS2), the Commission notes an audited PCA deferral account balance May
, 2004 of $26 261 334 (reference Case No. A VU-04-3); disallows CS2 Deal B losses of
$6,496 669; and disallows $4 771 550 of Deal A losses for a net PCA account balance total of
$14 993 115. The Commission approves the Company proposal to recover the remaining PCA
deferral balance over a two-year period. The resultant annual PCA recovery is $7,496 558
subject to annual PCA review and adjustment. The Commission authorizes changing in the
future from the current uniform percentage recovery method to a recovery method based on
energy consumption.
The Commission in this Order also approves the assignment and recovery from the
residential class through the PCA of authorized CAP AI intervenor funding in the amount of
$12 622.75.
4. PCA Rate Design
A vista witness Hirschkorn recommends recovery of the PCA surcharge by a uniform
percentage allocation to each customer class and a single rate for all energy usage within the
class (except for residential block rates). Tr. at 780.
Staff witness Hessing agreed with the Company proposal while there is a remaining
deferral balance.However, he proposes that once the current PCA deferral balance is
eliminated, PCA costs be recovered from ratepayers on a uniform cents per kWh basis rather
than a uniform percentage of revenue by class. The PCA rate would then be the same for all
schedules except lighting. Staff advocates this as a more appropriate way to collect variable
energy costs. Tr. at 1277-1279.
A vista on rebuttal agrees that from a cost causation viewpoint, an equal cents per
kWh application to all schedules is more appropriate than the present PCA methodology. The
ORDER NO. 29602
Company also agrees that the change in methodology should not occur until the present deferral
balance is fully recovered. Tr. at 821.
Potlatch witness Peseau opposes Staff s proposal on both theoretical and practical
grounds and recommends that it be rejected or modified. Potlatch contends that power supply
costs are not 100% energy or kWh-based and should not therefore be spread on an energy-only
basis. There is both a fixed or capacity component and a seasonal differential cost component to
power supply costs, he contends, that makes spreading balances on a flat, equal kWh basis
inaccurate. A cents per kWh recovery method, Peseau contends, would expose high load factor
customers to greater volatility because the surcharge and rebates will be greater than under the
current system thus making business planning and management decisions more difficult. Rate
Increases can cause disruption and losses, he contends, that cannot be recovered by
corresponding decreases in subsequent years.If Staff s proposal is adopted, Potlatch
recommends that the Commission "seasonalize" the cents/kWh recovery on a monthly or
quarterly basis in a manner similar to avoided costs rates. Tr. at 963-965.
The Commission finds that a cents per kWh recovery method for the PCA is
superior to the percentage basis currently used. While we recognize the difficulties pointed out
by Potlatch, we find the cents per kWh rate more equitable to all customers than the percentage
allocation. We recognize that the variable cost of energy fluctuates from year to year based on
the amount of energy consumed and should therefore be surcharged or credited on an equal
cents per kWh basis. We authorize the change to an equal cents per kWh when the present
deferral balance is eliminated. We reject Potlatch's proposal to seasonalize PCA recovery
amounts on a monthly or quarterly basis as being administratively burdensome and unnecessary
to achieve fairness and equity.
OTHER ISSUES
1. After Hours Connection Fees
Avista witness Hirschkorn proposes reconciling changes to non-recurring charges
for reconnection rates so there is only one set of charges that applies to any reconnect or service
turn-on situation. The proposed rate is $24 for reconnections occurring during normal business
ho~rs and $48 for after-hours, plus $4.00 for each additional service connected at the same time.
Tr. at 811.
ORDER NO. 29602
Staff witness Parker recommends approval of Avista s proposed changes for: (1)
reconnection of seasonal gas customers, and (2) after-hours connection charges for both gas and
electric customers. Staff recommends, however, that the tariff provision allowing an additional
$4.00 charge to connect a second meter at the same location be eliminated. Tr. at 865.
Rebuttal witness Kopczynski was generally supportive of Staff positions while
noting that several issues are concurrently being reviewed in the Staff-hosted Best Practices
Task Force. Tr. at 258-264. The Company supports Staffs proposal to eliminate the $4.
reconnection of additional meters at the same premises. Tr. at 826.
The Commission based on its review supports the changes in reconnection and after-
hours connection fees agreed to by the Company and Staff. The Commission understands that
there will not be a significant net change in revenue.
2. Winter Payment Plan
Staff witness Parker recommends that Avista take steps to resolve its computer
programming issues so that a customer who has declared Moratorium eligibility can also
participate in the Winter Payment Plan. Staff also recommends that the Company improve its
communication with customers about the Winter Payment Plan and Moratorium. Tr. at 865.
On rebuttal A vista witness Kopczynski states that the Company s computer system
does in fact allow customers to be set up on both the Winter Payment Plan and the Idaho
Moratorium. The Company commits that all of its customer service representatives will be
provided additional training by November 1 2004. Tr. at 258-260.
3. Telephone Call Center
In a 2002 Edison Electric Institute/American Gas Association (EEl! AGA) study
cited by Staff witness Parker, the average service level (the percentage of calls answered within
a defined number of seconds) among the 62 reporting utility companies was 73.80/0 of calls
answered in 32.3 seconds. Avista has recently set its internal service level goal at answering
700/0 of incoming calls within 60 seconds. Staff recommends that Avista be encouraged to
answer 800/0 of calls within 30 seconds by January 2005 and significantly reduce the number of
abandoned calls per month. Tr. at 865.
A vista witness Kopczynski on rebuttal notes that in the past 18 months, A vista has
added 6.5 full time equivalent (FTE) positions to the Company s contact center and is improving
its response time. To meet Staffs recommendations, however, Kopczynski states, an additional
ORDER NO. 29602
nine full-time positions would be required. The need for flexible staffing means that 9 FTE
translates to approximately 13 new employees. Avista intends to add this additional contact
center staff in the next year and establish 80% of incoming calls answered in 30 seconds as a
target. This additional FTE complement would increase expense over that requested by the
Company s Application by $162 735 for Idaho and Avista believes it is appropriate to reflect
these additional costs in the Company s revenue requirement. Tr. at 260-263. As the Company
moves to an 800/0 answered-calls-in-30-seconds standard, it believes the number of customers
who hang up before they reach a contact representative (or abandoned calls) should be reduced.
Addressing Kopczynski'rebuttal testimony, Staff at hearing noted that the
Company failed to indicate that they have five FTE positions in customer service that are
currently vacant, and additionally, they have four FTE positions where the employees have been
reassigned. Also in the last year or so the Company has filled 6.5 FTEs. And so , to the extent
the Company has had all these positions vacant, Staff concludes that its not surprising that with
the call volumes increasing, service levels and employee morale have declined. Even if the
Company fills the vacant FTEs immediately, Staff contends that it will take some time for them
to be trained. Staff recommends that the Company be given time to improve service and to
explore some technology-based solutions designed to help improve service levels. Staff
recommends that the Company be directed to file a report with the Commission in July 2005
reporting on the prior 12 months and indicating what progress it has made in improving the
average service level. Tr. at 887, 888.
The Commission encourages the Company to improve its response time to customer
calls and to reduce the number of abandoned calls. We find that this issue should be addressed
by the Company and direct the Company to file a status and progress report with the
Commission in July 2005 detailing the steps the Company has taken and implemented to
improve the average service level. Until this issue is more fully explored, we find no basis for
providing an increase in authorized revenue for additional Company FTEs.
4. Prlldency of DSM Expenditures
When the Commission approved the Company s energy efficiency programs in
1995, A vista committed to demonstrate the prudence of program expen~itures in future general
rate cases. Avista witness Hirschkorn requests that the Company s electric DSM expenditures
from January 1 , 1999 through December 31 , 2003 be found to have been prudently incurred and
ORDER NO. 29602
gas DSM prudent from March 13 , 1995 through December 31 , 2003. Tr. at 808-810. Since
1995, the Company calculates that over 286 million kWh (and 5.8 million therms) have been
saved through its energy efficiency programs. Tr. at 809. A 15-year levelized utility cost per
saved kWh of 1.4 cents per kWh has been achieved. The levelized avoided cost during this
same period has been 4.7 cents per kWh. Hirschkorn also said the 15 year levelized cost per
saved therm has averaged 14 cents per thermo Tr. at 809. Staff witness Anderson offered two
corrections to Hirschkorn s testimony. Anderson said that the prudency review of both gas and
electricity DSM for this case should have ended October 31 , 2003. Tr. at 844. Anderson also
said the average levelized cost of gas DSM savings was 25 cents per therm, not 14 cents per
thermo Tr. at 845. A vista did not rebut these corrections.
Avista collects revenues for its DSM programs from surcharges. Currently tariff
Schedule 91 electric surcharges amount to 1.95% of base revenues. The Company collected
about $2.million in 2002.Staff witness Anderson finds A vista DSM approach
conscientious, cost-effective, and reasonable. Tr. at 844-845.
The Commission finds that the DSM programs of A vista have been demonstrated to
be successful. Participating customers have benefited through lower bills and cost-effective
energy efficiency measures. Non-participants benefit from the Company s acquisition of low
cost resources. We find that the Company s DSM expenditures from January 1 , 1999 through
October 31 , 2003 to have been prudently incurred.
5. Advanced Meter Reading (AMR)
A vista apprises the Commission in this case of its proposal to install AMR devices
on all Idaho electric and natural gas meters over a four-year period commencing January 2005.
The Company estimates that its annual electric net cost would increase $188 700.The
Company estimates a $63 000 decrease in annual gas costs over a 15-year period. Avista
requests that the estimated $16.3 million AMR project cost be capitalized as Construction Work
in Progress (CWIP) until the entire project is completed and depreciation begins. Avista is not
proposing a change in rates in this filing to pay for AMR. Tr. at 733-739; Tr. at 190.
Staff witness Anderson supports in principle the Company s proposal to install AMR
facilities without specific time of use (TOU) pricing facilities at this time. He noted that the
estimated $188 700 annual net cost increase equates to approximately a 7-cent increase on a $50
customer bill. He also noted that the estimated $63 000 annual net cost decrease to gas service
ORDER NO. 29602
equates to about a 7 cent decrease on a $57 customer bill. Although A vista will benefit from
AMR before completion of the entire four-year installation Staff wants to promote
implementation and is not opposed to the requested deferred accounting treatment. Anderson
anticipates critical peak TOU pricing will become cost-effective by about the time Avista
completes its AMR project and that additional components necessary for such a pricing system
should begin to be installed at that time. Tr. at 851-854.
The Commission supports the Company s plans to install AMR and authorizes the
Company-requested deferral accounting treatment for its related investment. In doing so we
acknowledge and support Staff s TOU comments.
6. Intervenor Funding
The Commission approves CAP AI's Petition for Intervenor Funding in the requested
amount of $12 622.75. Reference Idaho Code ~ 61-617 A. Our award is based on a finding that
CAP AI's participation materially contributed to the Commission s decision, that the costs of
intervention are reasonable and would be a significant financial hardship for CAP AI if no award
is given, that the recommendations made by CAP AI differed materially from Staff s case, and
that CAP AI's participation addressed issues of concern to residential and low income customers.
The award is to be recovered from residential customers through the Company s electric PCA
mechanism.
AVISTA'S NATURAL GAS CASE
The Company in this general rate filing requested an overall Idaho natural gas base-
rate increase of $4 754 000 or 9.160/0. Avista contends that a rate increase is needed because of
decreased therm usage and increased general business expenses. Tr. at 15-18; Tr. at 147; 180
Exh. 15, p. 2 of 8. From 1999 to 2002, Idaho residential and small commercial customers
decreased their gas usage from an average of 82 therms per month to 73 therms per month, or
about 11 0/0. During this same time period the number of residential and small commercial
customers served in Idaho increased by 11 %, or about 5 800 customers. Tr. at 799.
Because A vista is a combined natural gas and electric utility many of the
Commission s findings regarding the Company s utility operations are generic in scope and to
the extent they have been discussed above will not be repeated in this section of the Order. To
the extent they bear repeating for purposes of identifying the revenue requirement effect it will
only be referenced below in brief fashion.
ORDER NO. 29602
Specifically addressed above and not discussed below are the Commission
decisions regarding Test Year, Capital Structure, Cost of Debt, Return on Equity, and Rate of
Return. Also not discussed are the Commission s decisions regarding Reconnections and After-
Hours Connection Fees; Winter Payment Plan, LIW A Funding and Advanced Meter Reading.
Adjustments to Gas Test Year Revenues, Expenses and Rate Base
Once a test year is selected, adjustments are made to test year accounts and rate base
to reflect known and measurable changes so that test year totals accurately reflect anticipated
amounts for the future period when rates will be in effect. As indicated in our discussion of
electric service, adjustments to test year accounts generally fall into three categories.1 )
normalizing adjustments made for unusual occurrences, like one-time events or extreme weather
conditions, so they do not unduly affect the test year; 2) annualizing adjustments made for
events that occurred at some point in the test year to average their effect as if they had been in
existence during the entire year; and 3) known and measurable adjustments made to include
events that occur outside the test year but will continue in the future to affect Company income
and expenses. Order No. 29505. This section of the Order addresses the proposed adjustment to
test year revenues, expenses and rate base associated with natural gas service.
Staff witness Stockton and Harms accepted A vista s proposed Standard Commission
Basis Adjustments except for the Company s gas inventory adjustment (Falkner Exh. 15 , pp. 4-
, columns c through 0) and also accepted the Company s Pro Forma Insurance Adjustment that
decreases net operating income by $131 000 (Falkner Exh. 14, p. 7, column r). Tr. at 1097-
1098, 1135-1136.
The Company on rebuttal agreed to and incorporated into its Rebuttal Exh. 27, pages 8-
the following Staff proposed adjustments to net operating income and/or rate base:
Net
Operating
Income
Adjustment Reason after Taxes Rate Base
Deferred Federal Appropriate deferred tax accounting
Income Tax treatment 639 000)
Labor (Exec.Update estimates to actuals 000
Labor (Non-Exec.Update estimates to actuals 000
Depreciation Synchronize depreciation between 000
states
ORDER NO. 29602
Corp. Fees Similar treatment for Idaho utilities
split 50%/500/0 000
Misc. Exp.Similar to prior Commission treatment
exclude contributions, dues, and
expenses benefiting affiliates 000
Ad. Exp.Similar to prior Commission treatment
exclude charitable contributions and
Image advertising 000
A vista Foundation Correctly assigns expenses to affiliate 000
Actual Therm Usage Updated to actual 000
Schedule M Allocator Conforms to electric system treatment 000
By accepting these uncontested adjustments the Company revises its requested gas revenue
increase to $4 061 000 or 7.820/0. Avista Reb. Exh. 27, p. 2, Tr. at 218.
A. Agreed Upon Adjustments
After Avista filed its rebuttal testimony, Staff and Avista agreed to reduce Staffs
originally proposed Gas Inventory and Accounts Receivable Sale Program Fees Adjustments by
50%. Tr. at 1142-1143. These revised adjustments increase net operating income after taxes by
$29 000 and decrease rate base by $786 000. Tr. at 1142-1143.
1. Gas Inventory
Avista witness Falkner adjusts rate base for the average of monthly average value of
gas stored at Jackson Prairie underground storage facility and the Plymouth LNG Plant. The
Company adjustment increases Idaho rate base by $1 572 000. Tr. at 182.
Staff witness Stockton removed the Company s Pro Forma Gas Inventory
adjustment from rate base because A vista has a negative cash working capital and thus Staff
contends that it is not an appropriate rate base addition. Staff s adjustment decreases rate base
by $1 572 000 and decreases total revenue requirement by $227 000. Tr. at 1116; 1137; Tr. at
1099.
A vista on rebuttal contends that Staff s interpretation of its working capital analysis
is incorrect. The Company s working capital, it states, is actually positive, not negative. Also
Staff s classification of gas inventory in the working capital analysis excludes it from working
capital. The Company notes that the Commission has historically allowed gas inventory to be
included in rate base and recommends that it continue to do so in this case. Tr. at 219.
ORDER NO. 29602
Staff on rejoinder represents that Staff and Avista have agreed to reduce Staffs
adjustment by 500/0. This amended adjustment decreases Idaho gas rate base by $786 000 and
the total revenue requirement by $114 000. Tr. at 1142-1143.
2. Accounts Receivable Program Fees
As per Staff witness Stockton Rejoinder, the Company and Staff agreed to an
amended adjustment increasing Idaho gas net operating income by $29 000 and decreasing the
total revenue requirement by $45 000 for the same reasons as described in the electric section of
this Order. Tr. at 1141-1142.
3. Restate Debt Interest
Adoption of Staff adjustment increases the Idaho gas federal tax accrual by $36 000
and increases revenue requirement by $56 000. Tr. at 1107; Rev. Exh. 107. For further detail
regarding the nature of the adjustment, please refer to the electric section of this Order.
The following issues were discussed earlier in the electric rate section and are treated
consistently with our findings there.
B. Disputed Issues (Resolved in Electric)
1. Pension Expense
Staffs proposed adjustment to gas penSIon expense to reflect the 2003 ERISA
required minimum contribution increases Idaho gas net operating income by $137 000 and
decreases the Company s Idaho gas revenue requirement by $214 000. Tr. at 1101-1102; 1171-
1172. However, for the reasons discussed in the electric section of this Order, the Commission
allows A vista recovery of $381 311 pension expense in its Idaho gas jurisdiction on the
evidence presented in this case. This results in an adjustment increasing Idaho net operating
income by $93 000.
2. Legal Expense
Adoption of Staff adjustment increases net operating income by $13 000 and reduces
Avista s revenue requirement by $20 000. Tr. at 1102-1103; 1173.
Summary of Adjustments to Gas Test Year Revenues, Expenses and Rate Base
Considering all the evidence presented, and including all adjustments, the
Commission finds just and reasonable Idaho jurisdictional expenses for the 2002 test year in the
amount of $48 368 000, and Idaho jurisdictional operating revenues in the amount of
$52 575 000 for an operating income before federal income tax of $4 207 000. The after tax
ORDER NO. 29602
Idaho operating Income is $3,402 000. After all adjustments, we find a 2002 total Idaho
jurisdictional rate base amount of $59 653 000 to be just and reasonable. Appendix D to this
Order summarizes the Commission s findings on rate base and operating results for the test year.
Rate Base
Avista in Exhibit 15, p. 2 proposed a pro forma rate base of $63 078 000 for the
Idaho jurisdiction. As we indicated in our prior Amended Interlocutory Order No. 29588 the
Commission approves as just and reasonable a gas pro forma rate base of $59 653 000. See
Appendix D.
Revenue Requirement
Current revenue recovered in Idaho gas base rates is $51 919 000.The
Commission in this case appro~es a base revenue requirement of $55 230 000, an increase in gas
base rates of $3 311 000 or 6.380/0. The resultant average base rates for sales therms is 81 cents
per thermo
Calculation of Revenue Deficiency
Having determined the Idaho gas rate base, net operating income requirement, and
return on common equity, we proceed to determine the Idaho revenue deficiency with the
following calculation:
Rate Base
Rate of Return
$59 653 000
2500/0
Net Operating Income Requirement
Operating Income
Income Deficiency
Conversion Factor
518 000
$3,402 000
116 000
639
311 000Revenue Requirement Deficiency
The Commission approves a pro forma rate base of $59 653 000. See attached
Appendix D. The Commission approves additional natural gas revenues of $3 311 000 for a
total revenue requirement of $55 230 000, a 6.380/0 revenue increase.
ORDER NO. 29602
Gas Jurisdictional Separations, Weather Normalization and Cost of Service
1. Gas Jurisdictional Separations
A vista used the same jurisdictional separation methodology approved by the
Commission in the Company s last natural gas rate case. This general methodology has been
approved for the Company in all of its other operating jurisdictions. Staff witness Fuss accepts
Avista s Gas Jurisdictional Separation Study using the four-factor methodology with one minor
adjustment. He used the four-factor allocator for Schedule "M" accounts instead of "allocator 5-
Actual Therms Purchased." Staffs adjustment reduces Idaho s share of taxes and increases the
Idaho gas net operating income by $1 888. Tr. at 1238-1242; Revised Exh. 107, p. 2. The
Commission accepts Avista s Gas Jurisdictional Separation Study using the four-factor
methodology with Staff-proposed adjustments.
2. Weather Normalization
No change was made to the historical methodology used to calculate natural gas
weather sensitivity. Tr. at 328-329. Staff witness Sterling accepts Avista s gas weather
normalization performed as accurate and reasonable. Tr. at 1190; 1192-1194. The Commission
accepts A vista s weather normalization as accurate and reasonable.
3. Gas Cost afService
A vista used the same Base Case (aka "Peak Credit") Cost of Service methodology
(with minor modifications) approved in the Company s last natural gas rate case. The proposed
rate spread of the increase results in approximately a one-half movement to the cost of service
for each schedule. Tr. at 329-334; Tr. at 801.
Staff witness Fuss accepts Avista s Gas Cost of Service Study (aka Washington
Accepted Methodology) with two adjustments: (1) adjust usage within the pro forma revenue
calculation resulting in a $23 000 revenue increase, and (2) allocate storage expenses and credits
based on winter therm usage not annual usage as proposed by A vista to better allocate value
received by each class. Staff s adjustments result in a net Idaho revenue requirement decrease
of $23,414. Tr. at 1238; 1242-1249. The Commission accepts the Company s Gas Cost of
Service Study (aka Washington accepted methodology) with Staff-proposed adjustments.
A vista on rebuttal accepts Staff s recommendation for allocation of underground
storage costs and related capacity release revenues. Tr. at 335-337; Tr. at 826. The Commission
ORDER NO. 29602
finds Staff s proposed allocation of underground storage costs and related capacity release
revenues to be reasonable.
4. Cost of Gas in Base Rates
Avista proposes adding the current PGA W ACOG adjustment of $0.27186/therm to
base rates to produce a total base rate gas cost of $0.44989/therm. Tr. at 1249.
Staff agrees with A vista s request and believes increasing the cost of gas in base
rates to reflect the best estimate of future gas costs will reduce the overall magnitude of future
PGA adjustments. Tr. at 1238-1239; 1249-1250.
The Commission adopts A vista s proposal to add the current PGA weighted average
cost of gas (W ACOG) adjustment of $0.27186/therm to base rates to produce a total base rate
gas cost of $0.44989/therm.
Natural Gas Rate Design and Tariff Issues
A vista witness Hirschkorn contends that the rates for natural gas Schedules 101 , 111
and 121 provide a clear distinction for customer placement as well as a reasonable classification
of customers for analyzing the costs of providing service: customers who use less than 200
therms/month should be placed on Schedule 101; customers who use between 200 and 10 000
therms/month should be placed on Schedule 111; and only those customers who generally use
over 10 000 therms/month should be placed on Schedule 121. Tr. at 805.
In calculating the revenue allocation between the natural gas customer classes, Staff
witness Schunke balanced the objective to move each class customer closer to cost of service
with the objective of achieving an equal contribution to the non-gas related costs (which is
referred to the margin) from Schedules 121 , 131 and 146. Staffs proposed revenue allocation
between classes was achieved by starting with the cost of service results. Then Schedules 121
131 and 146 were moved closer to an equal contribution to the margin in order to discourage
switching between schedules and to protect against a revenue shortfall. Tr. at 1332, 1333.
The natural gas base rates the Commission approves as just and reasonable are those
set forth in attached Appendix B. Idaho Code ~ 61-502. The base rates we approve in this case
are the fixed base rates incorporated in the Company s PGA adjustment authorized in Order No.
29590, Case No. A VU-04-2. The resultant proposed increase for a natural gas residential
customer using an average of73 therms of gas per month will be $12.84 per month, or 21.390/0.
ORDER NO. 29602
With this Order the Commission approves an increase in all gas commodity rates
maintaining the relationships between the classes as proposed by Staff to achieve the revenue
requirement for each class. The increase for each class are those reflected in Appendix F.
rej ect an increase in customer charges for Schedule 101. We accept a customer charge of $200
for Transportation Schedule 146 and approve increases in first block minimum charges for
Schedules 111 and 121. For Schedule 131 we approve an increase in the annual minimum
deficiency charge to be reflective of the Company s margin rate.
1. Residential (Schedule 101)
A vista witness Hirschkorn proposes to increase the residential basic and minimum
charges from $3.28 to $5.00 to recover one-half of the basic fixed costs of providing service.
Tr. at 802-804. Staff witnesses Schunke and Parker recommend that the basic and minimum
charges remain at $3.28. Staff contends that the customer charge should be based on the direct
cost of meter reading and billing and should not include any fixed plant cost. The cost of meter
reading and billing for Schedule 101 is $2.46. Staff also cites customer opposition to this type
of charge. See discussion in electric. Tr. at 1319; 1333-1334; Tr. at 866. Staff recommends an
average overall increase in base rates of 6.97% to Schedule 101.
A vista on rebuttal states that the cost of providing service to residential customers
has increased over the 15 years since the $3.28 basic charge was last set. The basic charge
Avista contends, should recover not only meter reading and billing, but also the cost associated
with providing a meter and service line. A vista contends that the average cost associated with
these expenses is well over $9.00 per customer per month. Avista believes that Staffs
minimum charge proposal incorporates current PGA gas costs under Schedule 150, regardless of
the customer s usage. A vista believes it is more reasonable to increase the fixed minimum
charge under this schedule by the increase in margin and bill the present Schedule 150 rate only
for those therms used by the customer. Tr. at 824-825.
The Commission rej ects an increase in the customer charge for Schedule 101 and
approves an increase in the commodity rate as reflected in Appendix F.
2. Large General Service (Schedule 111)
Schedule 111 is a three tier declining block rate structure. Avista proposes a $12.
increase to the monthly minimum charge for Schedule 111 customers. Tr. at 802; 805. Staff
recommends an increase in the basic or minimum charges to reflect the overall base rate
ORDER NO. 29602
increase for the first block. Tr. at 1334-1335. Staff recommends an average overall increase in
base rates of2.78% to Schedule 111. Tr. at 1319.
On rebuttal A vista recommends increasing the fixed minimum charge under this
Schedule by the increase in margin and billing the present Schedule 150 rate only for those
therms used by the customer. The Company s proposed rates, it states, incorporate the present
Schedule 150 rate in the block usage rates under this Schedule and as an additional variable
charge to the monthly minimum charge. The monthly minimum charge would increase from
$97.30/month to $108.26/month, plus a 27 .186~/therm charge under the present Schedule 150
(W ACOG adjustment). Tr. at 825.
The Commission approves an increase in the commodity rates for Schedule 111 as
reflected in Appendix F and approves an increase in the minimum charge to reflect the resultant
increase in first block rates.
3. Extra Large General Service (Schedule 121)
Schedule 121 has a four-tier declining block rate structure. The $267.63 monthly
mInImum charge is in addition to a 27 .186~/therm charge under the present Schedule 150
(W ACOG adjustment). Avista proposes a $29.30 increase to the monthly minimum charge.
There is also a minimum annual load factor requirement of approximately 58%. The Company
proposes adding an annual minimum usage requirement of 60 000 therms for service under this
schedule. Tr. at 802-803; 805-806. Staff recommends an increase in basic or minimum charges
to reflect the overall base rate increase for the first block. Staff recommends an average overall
increase in base rates of 1.86% to Schedule 121. Tr. at 1319; 1335.
A vista on rebuttal recommends increasing the fixed minimum charge under this
schedule by the increase in margin and billing the present Schedule 150 rate only for those
therms used by the customer. The Company s proposed rates incorporate the present Schedule
150 rate in the block usage rates under this schedule and as an additional variable charge to the
monthly minimum charge. The monthly minimum charge would be $265.74/month plus a
27 .186~/therm charge under the present Schedule 150 (W ACOG adjustment). Tr. at 825.
The Commission approves an increase in the commodity rates for Schedule 121 as
reflected in Appendix F and approves an increase in the minimum charge to reflect the resultant
increase in first block rates.
ORDER NO. 29602
4. Interruptible Service (Schedule 131)
Schedule 131 is a single rate tariff. The present annual minimum charge is based on
a usage requirement of 250 000 therms per year. A vista recommends revising the annual
minimum charge to an annual minimum deficiency charge based on margin as it appears
unreasonable to charge the customer for gas costs when the gas was not used. The annual
deficiency charge will be determined by subtracting the customer s annual usage from 250 000
therms. Any resulting usage deficiencies will be multiplied by the present margin (revenue less
gas costs) per therm under the Schedule, with the proposed margin level being 10.739
cents/thermo Tr. at 803; 806.
Staff to be reflective of the Company s margin rate recommends an increase in the
annual minimum deficiency charges. Tr. at 1319; 1335-1336.
The Commission accepts an increase in the annual minimum deficiency charge to
reflect the margin rate for Schedule 131 and approves an increase in the commodity rates as
reflected in Appendix F. The Company is directed to calculate and file tariffs reflective of their
margin rate as of September 9, 2004.
5. Transportation Service (Schedule 146)
Schedule 146 is a single rate tariff for all volumes transported on the Company
distribution system and includes an annual minimum charge based on 250 000 therms per year.
The Company is proposing to add a $200 monthly customerlbasic charge reflective of the
administrative costs associated with gas scheduling, balancing and billing transportation
customers. Tr. at 769; 801; 803; 807.
Staff recommends an average overall increase in base rates of 6.94% to Schedule
146. The proposed increase for transportation Schedule 146 excludes gas costs. If gas costs
were included the resulting increase would be approximately 1.50/0. Staff recommends that the
Company-proposed basic charge of$200/month be approved. Tr. at 1317-1318; 1336; 1320.
The Commission approves the $200/month basic charge for Schedule 146 agreed to
by the Company and Staff and approves an increase in the energy rate as reflected in Appendix
6. Special Contracts
A vista included all expenses associated with providing serVIce to Idaho s Gas
Special Contract customers in the general rate filing. The Company has three transportation
ORDER NO. 29602
servIce customers under special contract (Potlatch-Lewiston, Lignetics and IMCO formerly
IMSAMET). All three of the contracts were negotiated, executed and approved based on the
customers' close proximity to an interstate pipeline and their reasonable ability to by-pass the
Company s distribution system. Tr. at 798-799.
Staff recommends acceptance of A vista s treatment of Idaho gas special contracts
within the Gas COS study without changes. Tr. at 1239; 1250-1252.
The Commission acknowledges the Company s special contracts with Potlatch-
Lewiston, Lignetics and IMCO. The terms and conditions of those contracts have been
previously approved by this Commission.
Other Issues
1. Prudency of DSM Expenditures
The Commission finds Avista gas DSM expenditures from March 13, 1995 through
October 31 , 2003 to be prudently incurred.
2. Tariff Summary Sheet
Staff recommends that Avista be required to add a tariff summary sheet (sheet D) to
its gas tariff schedules because it will provide clarity for customers without being
administratively burdensome. Tr. at 1239; 1252; Tr. at 884.
A vista on rebuttal agrees to file the tariff summary sheet each time rates change. Tr.
at 826.
The Commission directs the Company to prepare and file a tariff summary sheet for
natural gas rates.
CONCLUSIONS OF LAW
The Idaho Public Utilities Commission has jurisdiction over this Application and
A vista Corporation dba A vista Utilities, an electric and natural gas utility, pursuant to the
authority and power granted under Title 61 of the Idaho Code and the Commission s Rules of
Procedure, IDAP A 31.01.01.000 et seq.
The Commission has jurisdiction and authority pursuant to the above identified
statute and rules to authorize and require Avista to re-allocate its revenues among the customer
classes to change its rate components within the customer classes, to award intervenor funding
and to address the other issues in the manner set forth in the text of this Order.
ORDER NO. 29602
ORDER
In consideration of the foregoing and as more particularly described above and
reflected in Amended Interlocutory Order No. 29588 issued September 9, 2004, IT IS HEREBY
ORDERED and the Commission hereby authorizes A vista Corporation dba A vista Utilities to
increase its net electric revenues by $3 182 000 or approximately 1.9%.This increase
incorporates the base revenue increase approved by the Commission, a two year recovery of the
adjusted PCA deferral balance, and a decrease in DSM rates. We approve for rates and charges
in compliance with the terms of this Order the amended tariff sheets filed by A vista in
compliance with Order No. 29588 and for service rendered on and after September 9 2004.
IT IS FURTHER ORDERED and the Commission hereby authorizes Avista
Corporation dba Avista Utilities to increase its net gas revenues by $3 311 000 or approximately
38%. We approve for rates and charges in compliance with the terms of this Order the
amended tariff sheets filed by Avista in compliance with Order No. 29588 and for service
rendered on and after September 9, 2004.
IT IS FURTHER ORDERED that Avista Corporation dba Avista Utilities comply
with all other directives of the text of this Order.
IT IS FURTHER ORDERED that Community Action Partnership Association of
Idaho is awarded intervenor funding in the amount of $12 622.75. Avista Utilities is directed to
pay this amount within 28 days of the date of this Order.
THIS IS A FINAL ORDER. Any person interested in this Order (or in issues
finally decided by this Order) or in interlocutory Orders previously issued in this Case Nos.
A VU-04-1 and A VU-04-1 may petition for reconsideration within twenty-one (21) days of
the service date of this Order with regard to any matter decided in this Order or in interlocutory
Orders previously issued in this Case Nos. A VU-04-1 and A VU-04-1. Within seven (7)
days after any person has petitioned for reconsideration, any other person may cross-petition for
reconsideration. See Idaho Code ~ 61-626.
ORDER NO. 29602
DONE by Order of the Idaho Public Utilities Commission at Boise, Idaho this g-f4-.
day of October 2004.
/r dtL
, PRESIDENT
MARSHA H. SMITH, COMMISSIONER
nnZ
IS S. HANSEN, COMMISSIONER
ATTEST:
bls/O:A VUEO40 1 A VUG040 1 sw7
ORDER NO. 29602
" ,, ,
A VISTA UTILITIES
AVU-O4-
, Present and Commission Ordered Electric Rates
Present Rates
Basic Charge
First 600 kWhs
All over 600 kWhs
PCA Rate 0 - 600 kWh
All over 600 kWh
Energy Efficiency Rider
Present Rates
Basic Charge
Energy Charge
Demand Charge:
20 kW or less
Over 20 kW
PCA Rate
Energy Efficiency Rider
Present Rates
Energy Charge
Residential Service - Schedule
Commission Ordered Rates
$4.00 Basic Charge $4.
555 if./kWh
303 if./kWh
First 600 kWhs
All over 600 kWhs
717 if./kWh
6.487 if./kWh
939 if./kWh
1 .092 if./kWh
104 if./kWh Energy Efficie~cy Rider
General Service - Schedule
Commission Ordered Rates
$6.00 Basic Charge
PCA Rate 0.286 if./kWh
081 if./kWh
$6.
564 if./kWh First 3650 kWh
All Over 3650 kWh
148 if./kWh
076 if./kWh
no charge
$3.50/kW
Demand Charge:
20 kW or less
Over 20 kW
no charge
$3.50/kW
391 if./kWh PCA Rate
140 if./kWh Energy Efficiency Rider
Large General Service - Schedule
Commission Ordered Rates
First 250 000 kWh 4.688 if./kWh
All Over 250 000 kWh 3.985 if./kWh
335 if./kWh
095 if./kWh
996 if./kWh
Demand Charge:Demand Charge:
50 kW or less $225.50 kW or less $250.
Over 50 kW $2.75/kW Over 50 kW $3.00/kW
Primary Voltage Discount 20if./kW Primary Voltage Discount 20if./kW
011 if./kWh PCA Rate
100 if./kWh Energy Efficiency Rider
Extra Large General Service - Schedule 25Present Rates Commission Ordered Rates
874 if./kWh First 500 000 kWh 3.862 if./kWh
All Over 500 000 kWh 3.259 if./kWh
PCA Rate
Energy Efficiency Rider
Energy Charge
Demand Charge:
000 kva or less
Over 3 000 kva
Primary Voltage Discount
Annual Minimum
PCA Rate
Energy Efficiency Rider
Rates Exhibit 9/9/2004 KDH
256 if./kWh
073 if./kWh
500.
$2.25/kva
Demand Charge:
000 kva or less
Over 3 000 kva
$9,000.
$2.75/kva
20if./kva Primary Voltage Discount 20if./kva
$406 140 Annual Minimum $502,670
607 if./kWh
068 if./kWh
PCA Rate
Energy Efficiency Rider
181 if./kWh
052 if./kWh
- -
APPENDIX A
Page of
Order No. 29602
Case Nos. AVU-04-
/\ \ /I I (\/1 -1
AVISTA UTILITIES
A VU -O4-
Present and Commission Ordered Electric Rates
Present Rates
Energy Charge'
Demand Charge:
000 kva or less
Over 3 000 kva
Primary Voltage Discount
Annual Minimum
PCA Rate
Energy Efficiency Rider
Present Rates
Basic Charge
First 85 kWh/kW
Next 80 kWh/kW
All additional kWhs
Potlatch - Schedule 25P
First 3650 kWh
874 ~/kWh.Energy Charge 333 ~/kWh
Demand Charge:
500.000 kva or less $9,000.
$2.25/kva Over 3 000 kva $2.7 5/kva
20#kva Primary Voltage Discount 20~/kva
$406 140 Annual Minimum $474 630
163 ~/kWh
046 ~/kWh
607 ~/kWh PCA Rate068 ~/kWh Energy Efficiency Rider
Pumping Service - Schedule
Commission Ordered Rates
Basic Charge $6.$6.
716 ~/kWh
716 ~/kWh
548 ~/kWh
6 .440 ~/kWh
6 .440 ~/kWh
5.474 #kWh
First 85 kWh/kW
Next 80 kWh/kW
All additional kWhs
PCA Rate 0.888 ~/kWh PCA Rate 0.265 ~/kWh
Energy Efficiency Rider 0.1 02 ~/kWh Energy Efficiency Rider 0.076 ~/kWh
Street and Area Lights - Schedules 41-49Present Rates Commission Ordered Rates
Base Rates Various Base Rate Increase 20.19%
PCA Surcharge 19.37%PCA Surcharge 385%
Energy Efficiency Rider 95%Energy Efficiency Rider 25%
Rates Exhibit 9/9/2004 KDH
APPENDIX A
Page 2 of 2
Order No. 29602
Case Nos. A VU-04-
A \/1 1-
(',-
04-
AVISTA UTILITIES
AVU-O4-
Present and Commission Ordered Natural Gas Rates
Present Rates
General Service - Schedule 101
Commission Ordered Rates
$3.28 Basic Charge $3.Basic Charge
All Therms 7 4.197 ~rrherm All Therms 80.050 ~/Therm
Present Rates
Lan:te General Service - Schedule 111
Commission Ordered Rates
1 st 200 Therms
Next 800 Therms
Over 1 000 Therms
75.836~rrherm
74.197~rrherm
64.975~/Therm
1 st 200 Therms
Next 800 Therms
Over 1 000 Therms
78.301 ~fTherm
76.481 ~/Therm
66.239~/Therm
Minirnum - $97.30/Month
plus 27 .186~rrherm
Minimum - $156.60/Month
Present Rates
LarQe General Service - Schedule 121
Commission Ordered Rates
1 st 500 Therms
Next 500 Therms
Next 9 000 Therms
Over 10 000 Therrns
7 4.852~rrherm
74 .197 ~rrherm
64.975~/Therm
63.284#Therrn
1 st 500 Therms
Next 500 Therms
Next 9 000 Therms
Over 10 000 Therrns
77 .209~/Therm
76.481 ~rrherm
66 .239~fTherm
64.361 ~/Thenn
Minimum - $238.33/Month
plus 27 .186~rrherm
fv1inimum - $386.05/Month
Present Rates
Interruptible Service - SchE!dule 131
Commission Ordered Rates
All Therms 55.724~fTherm All Therms 56.586~fTherm
Annual Minimum $78 385 Annual Minimum
Present Rates
Transportation Service - Schedule 146
Commission Ordered Rates
Basic Charge $0.Basic Charge $200 / Month
All Therms 10.574strrherm All Therms 10.960stfTherm
, Includes Purchase Gas Adjustment Schedule i50/Excludes all other rate adjustments
...,
.. Does not include Schedule 150 or any other rate adjustment. 3 Annual Minimum: Each Customer shall be subject to an Annual Minimum Deficiency Charge if their gas
usage during the prior year did not equal or exceed 250 000 therms. Such annual Minimum Deficiency
Charge shall be determined by subtracting the Customer s actual usage for the tvvelve-month period
ending each August from 250 000 therms multiplied by 11.597~ per thermo
---------_..
Rates Exhibit tabRate Exh
MJF
APPENDIX B
Order No. 29602
Case Nos. A VU-04-
A VU-O4-
AVISTA UTILITIES
CALCULATION OF GENERAL REVENUE REQUIREMENT
IDAHO ELECTRIC SYSTEM
TEST YEAR 2002
(OOO'S OF DOLLARS)
Description
Pro Forma Rate Base
Proposed Rate of Return
Net Operating Income Requirelnent (Line 1 x Line 2)
Pro Forma Net Operating Income
Net Operating Income Deficiency (Line 3 - Lille 4)
Conversion Factor
Revenue Requirement Deficiency (Line 5/Line 6)
Levelized Deferred Return on Coyote Springs 2
Revised Revenue Requirement Deficiency (Line 7 + Line 8)
Total General Business Revenues
Percentage Revenue Increase (Line 9/Line 10)
Commission
Decision
$424 114
250%
$39 231
$23 121
$16 110
63926135
$25 201
485)
$24 716
$146 248
16.900/0
APPENDIX C
Order No. 29602
Case Nos. AVU-04-
A VU-04-
AVISTA UTILITIES
CALCULATION OF GENERAL REVENUE REQUIREMENT
IDAHO GAS
TEST YEAR 2002
(ODD'S OF DOLLARS)
Line Commission
No.Description Decision
Pro Fornla Rate Base $59 653
Proposed Rate of Return 250%
Net Operating InconleRequirelnent (Line 1 x Line 2)518
Pro Forma Net Operating Inconle 402
Net Operating Inconle Deficiency (Line 3 - Line 4)116
Conversion Factor 639
311 Revenue Requirelnent Deficiency (Line 5/Line 6)
Total General Business Revenues $51 919
Percentage Revenue Increase (Line 7/Line 8)38%
APPENDIX D
Order No. 29602
Case Nos. A VU-04-
A VU-04-
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