28097.pdf

Office of the Secretary
Service Date
August 11 , 1999
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION OF
THE WASHINGTON WATER POWER
COMPANY (NOW A VISTA CORPORATION
DBAAVISTA UTILITIES-WASHINGTON
WATER POWER DIVISION) FOR AN ORDER
APPROVING INCREASED RATES AND
CHARGES FOR ELECTRIC SERVICE IN THE
STATE OF IDAHO.
CASE NO. WWP-98-
ERRATA NOTICE TO
ORDER NO. 28097
On July 29, 1999, the Idaho Public Utilities Commission issued Order No. 28097, in
the above referenced case. The following correction should be made to Appendix D of that
Order.
Extra Large General Service - Schedule 25, Commission Ordered Rates
Where it reads:
Annual Minimum $419.230.
Should read:
Annual Minimum $397 670.
DATED at Boise, Idaho this
/'
X,c:day of August 1999 .
~fi~
aJ. Walters
Commission Secretary
O:wwpe9811 err
Office of the Secretary
Service Date
July 29, 1999
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION OF
THE WASHINGTON WATER POWER
COMPANY (NOW A VISTA CORPORATION
DBAAVISTA UTILITIES-WASHINGTON
WATER POWER DIVISION) FOR AN ORDER
APPROVING INCREASED RATES AND
CHARGES FOR ELECTRIC SERVICE IN THE
STATE OF IDAHO.
CASE NO. WWP-98-
ORDER NO. 28097
On December 18, 1998, the Idaho Public Utilities Commission (Commission)
received an Application from The Washington Water Power Company, now Avista Corporation
dba Avista Utilities Washington Water Power Division (A vista; Company; WWP) requesting
authority to increase its rates and charges for electric service in the state of Idaho. The
Company s original request of $14 223 000 or 11.56% was revised at hearing to $13,456 000 or
10.94%. By this Order the Commission authorizes the Company to increase its revenues by
330 000, or approximately 7.58%. We approve a pro forma rate base of $360 546 000, a
return on equity of 10.75% and an overall rate of return of 8.979%.
APPLICATION
A vista is a public utility engaged in the generation, transmission and distribution of
electric power and the distribution of natural gas. A vista serves approximately 100 000
customers in northern Idaho ranging from Grangeville to Sandpoint. The Company in its
Application requested a Commission Order approving revised rates and charges effective
January 22, 1999. The proposed effective date was suspended pending hearing on the
Application and further order of the Commission. (Commission Order Nos. 27852 and 28098;
Reference Idaho Code 9 61-622.
The Company s last general rate case in Idaho was in 1986 (ref. Case No. U-1O08-
256, Order No. 20905). Since that time, Avista s overall electric rates in Idaho have been
modified with the implementation in March 1995 of a non-bypassable 1.5% energy surcharge to
fund energy efficiency improvements and a Power Cost Adjustment (PCA) mechanism
ORDER NO. 28097
implemented in 1989. The PCA has resulted in several temporary rate adjustments, both
surcharges and rebates, to reflect changes in power costs related to stream flow and wholesale
market conditions.
A vista amended its original request at hearing to an overall increase in annual
revenue for its Idaho electric jurisdiction of $13 456 000, or 10.94%. Reference Exh. 24, Sch. 1
p. I; Tr. p. 678. A vista proposes to set rates for individual customer classes based in part on a
cost of service study. Therefore, the amount of the Company proposed percentage increases
varies by class of customer and by usage.
The Company s proposed rate increase will also apply to those customers formerly
served by PacifiCorp (Clark Fork, Hope, East Hope, Old Town, Priest River and Sandpoint).
The four-year rate transition period applicable to those customers expired in January 1999 when
they were transferred to the Company s comparable rate schedules. Reference Case No. WWP-
94-
The Company s requested revenue increase is predicated on a 9.446% rate of return
including an 11.75% return on equity and a proposed 25 basis point equity adder as a bonus
incentive. The Company states that for its proposed test year, 1997, its rate of return in Idaho, on
a pro forma basis, was 7.075%, significantly below its authorized rate ofretum of 10.95%. Exh.
, p. 7. A vista alleges that the rates in its present tariff are no longer reasonable or adequate and
do not allow it to earn a fair and reasonable return on investment.
HEARING
The technical hearing on this Application was held in Sandpoint, Idaho, on June 8-
1999. The following parties appeared by and through their respective counsel:
A vista Corporation dba A vista Utilities-
Washington Water Power Division David 1. Meyer, Esq.
Potlatch Corporation Conley Ward, Esq.
Hecla Mining Company
Silver Valley Resources Corp
Sunshine Mining & Refining Company M. Karl Shurtliff, Esq.
Commission Staff Scott Woodbury, Esq.
ORDER NO. 28097 2-
Also held on June 8 was an evening hearing for the purpose of receiving public
comment and testimony on the Company s Application. Two members of the public appeared
and commented. The remarks of Shawn Keough, State Senator for Legislative District 1 are
discussed starting at page 28 ofthis Order. Tr. pp. 549-565.
Motion to Dismiss
After some initial questions of A vista s Board Chairman and Chief Executive Officer
regarding Centralia, Potlatch made a Motion to Dismiss the Company s Application without
prejudice to refiling at such later time when uncertainty regarding the potential sale of Centralia
has been settled. Tr. p. 51; Reference IDAPA 31.01.01.056; -256.
Potlatch contends based on an item reported in recent industry publications that
Avista has entered into an agreement to sell its 15% interest in the Centralia coal-fired generating
station. Tr. p. 49. Centralia represents approximately 200 megawatts of Avista s thermal
generating capacity. Reference Exh. 3. The proposed sale is subject to regulatory approval, a
process that the Company anticipates may take 12 to 18 months.
In this rate case Avista uses a 1997 test year. As part of its adjustments to the test
year, however, the Company uses a projected July 1999 - June 2000 time period for pro forma
power supply expense. Tr. p. 50. Centralia is included in the Company s power supply or
dispatch simulation model. The dispatch model is used to normalize for ratemaking purposes
power costs that are dependent upon stream flow and wholesale market conditions. Tr. p. 379.
Potlatch argues that if the sale of A vista s interest in Centralia is approved, the result
will be a reduction in the Company s rate base, a related power supply expense adjustment and a
distribution back to ratepayers of depreciation. Tr. p. 52. Idaho s allocated revenue deficiency in
this case as filed by the Company is roughly $9 million before it is grossed up for taxes. Potlatch
concludes that any combination of reduction in power supply, reduction in rate base or rebates or
credits to customers for depreCiation previously paid that total $9 million will remove or simply
wipe out the Company s rate case. Tr. p. 53. The Commission, Potlatch contends, cannot
simply set rates now and adjust for Centralia later. To do so, it suggests, will result in a
mismatch of revenues, expenses and accounting items.
Avista opposes Potlatch's Motion to Dismiss pointing out substantial uncertainties
surrounding the sale as to timing, regulatory approvals, and related conditions. A vista argues
ORDER NO. 28097
that the results of the sale, if it does occur, including questions regarding replacement power, are
neither known nor measurable. Tr. pp. 55, 56. At hearing the Commission took Potlatch'
Motion under advisement.
Findings:
We have now had the opportunity to fully consider Potlatch's Motion to Dismiss and
the related arguments of the parties. Although the possible ramifications of the Centralia sale
have been identified by Potlatch, it was done only on a general basis. We find that there are
presently too many unknowns, and too many uncertainties regarding the proposed sale for that to
be the basis of a ruling in this case. The facts presented in this case regarding the Centralia sale
neither support nor justify dismissal of the Company s Application.
It is the Commission s understanding that there have as yet been no regulatory filings
regarding the proposed sale. Although raised at hearing (Tr. p. 52), the Commission reserves
judgment as to the applicability of Idaho Code 9 61-328-Electric Utilities-Sale of Property to
be Approved by Commission. We note that the Company s ownership interest in Centralia is
part of its rate base in Idaho on which it receives a return on investment. We therefore put
A vista on notice that prior to any transfer of its ownership interest in Centralia we expect a filing
by A vista with this Commission addressing the proposed sale its ramifications, rate
consequences and the Company s proposed treatment of same.
Test Year
In this case A vista proposes use of a historical twelve-month test year period ending
December 31 , 1997, with operating adjustments to both rate base and operating results for post-
test year changes. Tr. p. 571. Staff and Intervenors object to some of the adjustments but no
party objects to the proposed test year.
Findings:
The Commission finds the use of a historical test year period ending December 31
1997 to be reasonable for the purposes of this rate case.
ORDER NO. 28097
Operating Results-Adjustments to Test Year Revenues and Expenses
Having selected a 1997 test year, Avista, and subsequently Staff and Potlatch
proposed adjustments to specific booked amounts for revenues, expenses and rate base.
Adjustments to test year revenues and expenses often are necessary 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. Some of the adjustments to revenues and expenses also
affect rate base. As set forth in Company Rebuttal Exhibit 24, Sch. 1 p. 1 a revised annual
revenue increase of $13 456 000 or 10.94% is requested.
The Company has agreed to and incorporated into its Rebuttal Exhibit 24, Sch. 1 results
of operations, the Staff proposed adjustments to operating expense for depreciation, tree
trimming, and income tax. Tr. pp. 133, 134. The net income after taxes agreed to by the
Company is as follows:
Depreciation Adjustment
Tree Trimming Adjustment
Income tax Adjustment
$463 048
$322 471
$ 16 670
Pro Forma Revenue Adjustments Staff and Potlatch
Commission Staff, based on its analysis, calculates a revenue deficiency of
$10 234 000 and recommended an 8.32% increase.Reference Exh. No. 118 , p. 3.The
difference between the Company requested and Staff calculated revenue requirement is
222 000.
Potlatch, based on its analysis, concluded that the Company s original rate increase
request was overstated by approximately $11.5 million. Tr. p. 1222
Of the Staff proposed adjustments, four remain contested by the Company: Hydro
Re-licensing costs-Clark Fork Settlement Agreement; CIAC adjustment (line extension);
Injuries And Damages (1996 Ice Storm); and Miscellaneous General Expense (FERC Acct 930).
Potlatch provides testimony and recommendations regarding A vista s marketing
efforts-specifically: allocation of costslbenefits regarding secondary transactions. Potlatch also
proposes adjustments regarding depreCiation, normalized net power supply cost, hydro-
relicensing, amortization of 1996 ice storm costs and rate of return.
ORDER NO. 28097
Hydro Relicensing Costs-Clark Fork Settlement Agreement
The Company is presently attempting to relicense two of its hydro generation
facilities, Cabinet Gorge and Noxon Rapids (Clark Fork projects). Unless renewed, the FERC
licenses are scheduled to expire in 2001. Beginning in 1996 the Company initiated a
collaborative negotiation relicensing process referred to as the Living License TM. Tr. pp. 619
620. The negotiation group includes over 100 representatives from nearly 40 organizations
including federal and state agencies and local governments from Idaho and Montana, five
American Indian Tribes, nongovernment organizations, conservation groups, property owners
and the Company. Tr. p. 620. As part of a negotiated Settlement Agreement, the Company
committed to begin implementation related to Protection, Mitigation And Enhancement (PM&E)
in March of 1999, two years before the present licenses expires. Early implementation of these
measures, the Company contends, became the Company s greatest point of leverage in
negotiating an agreement among parties at what it argues is a much lower cost to the Company
than certain agenCies have the unilateral authority to approve. Tr. pp. 621 , 622. With this
Settlement Agreement, the Company estimates that on a system basis it will incur incremental
hydropower relicensing operation and maintenance (O&M) expense at a levelized amount
018 000. Tr. p. 623. On rebuttal the Company reduced and amended its PM&E expense
projections to $1 861 820. Tr. p. 644; Exh. 25. The Company proposes in this case to pro form
in the O&M expense levels contained in the Settlement Agreement. Capital expenditures
associated with the settlement are not a component ofthe Company s filing. Tr. p. 644.
Staff witness Lobb recommends that $860 000 of the $2 018 000 hydro power
relicensing expenses be excluded from the pro formed test year. $180 000 of the adjustment is a
transpositional error in total PM&E; the remaining $680 000 is hydro relicensing expense that
Staff contends is either a one-time expense or not presently "known or measurable." Reference
Exhs. 104, 105.
The $860 000 recommended disallowance is a "system" number. As reflected in
Exh. No. 118 , p. 2, Col. E, the original adjustment on an Idaho jurisdictional basis translates to a
reduction in production and transmission expenses of $285 376. Associated adjustments are an
increase in state income tax in the amount of$4 191 and an increase in federal income tax in the
amount of$98 415. The resultant increase to net operating income is $182 770.
ORDER NO. 28097
Staff expressed concern regarding the potential mismatch between the projected
O&M level of Settlement costs included in the Company s revenue requirement (and recovered
in rates) and the actual amounts expended by the Company. The Company in rebuttal proposes
that a balancing account be utilized to capture the differences between the O&M level of
settlement costs ultimately allowed in rates and the amounts that get expended on an annual
basis. The Company proposes using FERC Account 253 , Other Deferred Debits, to accumulate
a running balance that would represent either a regulatory asset or a regulatory liability. The
Company proposes that any balance in the hydro relicensing deferred balancing account be
consolidated with any balance in its Power Cost Adjustment (PCA) deferral account and that it
be subject to refund or surcharge based upon the currently authorized $2.2 million PCA trigger
mechanism. Tr. pp. 642, 643.
Staff at hearing indicated that while it is not opposed to the concept of a balancing
account for Settlement O&M costs; it is opposed to combining the balancing account with the
PCA. Tr. pp. 937, 938. The PCA has a $2.2 million trigger. Staff believes that the Company
could delay or manipulate reaching the trigger by simply altering the timing of expenditures
reflected in the relicensing account. Staff further notes that the PCA was intended to adjust for
power supply expenses, especially expense variations that occur due to changing water
conditions. Including another adjustment of unknown magnitude, Staff contends, would change
the operation of the PCA and would be inappropriate. Staff recommends that separate
subaccounts in FERC Account 253 be established and used to identify the specific relicensing
O&M expenses that vary from the costs included in base rates. Staff proposes that the
Commission approve its suggested relicensing expense in base rates with modifications for the
bull trout adjustment ($125 000 total Company) for a total system adjustment of $735 000.
Acceptance of the Staff s modified proposed adjustment results in a reduction of operating
expenses of $235 997, an increase in state income tax of $3 466, and an increase in federal
income tax of $81 386. The resultant increase in net operating income is $151 145. Staff
recommends that costs be looked at every two to three years so they have a chance to balance out
rather than adjusting every year. Tr. pp. 937-939.
Potlatch recommends that the Company s pro forma hydro relicensing cost
adjustment be rejected. Potlatch contends that the adjustment will cause a mismatch of costs and
benefits between present and future ratepayers. Potlatch suggests that what the Company is
ORDER NO. 28097
proposing is the equivalent of putting construction work in progress (CWIP) into rate base. Tr.
p. 1212; Reference Idaho Code 961-502A. Furthermore, FERC, Potlatch contends, mayor may
not relicense the Clark Fork projects. Potlatch recommends that the Company s hydro re-
licensing adjustment be reduced by $1.4 million. Tr. p. 1222.
Findings:
The Commission has reviewed and considered the testimony and exhibits regarding the
Company s proposal to recover O&M costs related to its obligations under the Clark Fork
Settlement Agreement as well as the Company s proposed method of recovery. We have also
considered the related comments of Staff and Potlatch. We commend the Company for its
relicensing efforts. While Potlatch would have this Commission liken the Settlement PM&E
expenditures to CWIP (Tr. p. 1212), we do not believe that the comparison is valid. This is not
construction work in progress. By agreeing to early implementation, the Settlement Agreement
benefits to the Company and its customers are clear and immediate.
We find the proposed use of a balancing account (FERC Account 253 , Other Deferred
Debits) to be an acceptable method of addressing the potential mismatch between recovery and
expense. We find that to avoid questions related to timing of expenditures, the balanCing
account for Clark Fork Settlement Agreement O&M should be maintained and operated
separately from the PCA. Interest shall accrue in this account in the same manner as it does in
the Company s PCA account. We accept Staffs modified proposed adjustment as reasonable.
The Company is encouraged to request recovery every two to three years, rather than annually.
Should the Company, however, fail to make application, amortization of accrued balances will
begin after three years.
CIAC Adjustment (line extensions)
Staff recommends that revenue of $1 178 835 be imputed as Contribution in Aid of
Construction (CIAC). Staff contends that this additional amount should have been collected from
new customers added to the Company s system between 1989 and 1997. Staff argues that the
neglect and/or failure of the Company to keep line extension costs in its Schedule 51 tariff up to
date, as ordered by the Commission in 1989 in Order No. 23071 , has caused the Company
ORDER NO. 28097
annual revenue requirement to be higher than it otherwise should be. Tr. pp. 967, 968.1 The
proposed amount of Staff s adjustment is based on the difference between the amount of CIAC
actually collected between the years 1988 and 1997 and the amount of CIAC calculated by Staff
that should have been collected. In its calculation Staff assumes that the Company s line
extension costs for all the years between 1988 and 1997 escalated at the same rate of escalation
as the Standard & Poor s (S&P) DR! Price Index for public utility structures. Exh. No. 110.
Staff compares the assumed level of CIAC to the actual CIAC collected by the Company for
each year from 1988 through 1997. The cumulative difference for the ten-year period is
178 835. The Company on rebuttal challenges Staffs adjustment as based more on
assumptions than actual data. Tr. p. 867.
Staff s proposed adjustment results in a reduction in distribution plant depreciation
expense of $26,435, an increase in state income tax of $388, and an increase in federal income
tax of$9 116. The resultant increase in net operating income is $16 960. Related adjustments to
rate base are a reduction in distribution plant in service of $1 152 075, a reduction in
accumulated depreciation of $110 000, and an increase in deferred taxes of $403 000 for a net
decrease in rate base of$639 075.
Staff also recommends that a new line extension case be opened once the rate case
has been concluded in order to more closely examine the Company s line extension tariff
(Schedule 51) to ensure that upward pressure on rates due to growth and new distribution plant
additions is minimized. Tr. p. 968. The Company agrees with Staff that its line extension tariffs
need to be more closely examined, that its line extension costs need to be updated and that
allowances may need to be revised. The Company states that it is willing to initiate a
collaborative effort with the Commission Staff within 90 days after the conclusion of this case to
review the Company s line extension tariffs. Tr. p. 875.
Findings:
The Commission finds the Staffs proposed adjustment and method of calculation to
be reasonable. A vista has failed since 1990 to provide the annual updates required by
1 See Exh. 107 - Order No. 23071, p. 15 (4/18/90): "Company is to provide the Commission annually with updated
worksheets and average unit costs for Schedule 51 construction and is to update its tariff as necessary to keep costs
current"; Exh.108 - Company acknowledgement letter (1/25/91).
ORDER NO. 28097
Commission Order No. 23071. It has not kept the extension costs current. It either did not have
or failed to provide information relating to these costs. When a utility fails to maintain and/or
provide the information necessary for the Commission to set rates that are fair, just, reasonable
and non-discriminatory, then the best information available must be used to make the needed
calculations. It is disingenuous for the Company to challenge this adjustment on the basis that
some assumptions were used; it is the only entity that could have provided the actual information
and it did not.
Furthermore, we note that in 1994 the Company was assessed a civil penalty of
$75 000 for violating its Schedule 51 line extension tariffs by failing "to assess and collect line
extension costs calculated in accordance with its tariffs.Reference Case No. WWP-94-
Order No. 25838. Apparently nothing was learned from that experience and Company practices
have not changed. The Company s disregard of its tariffs and this Commission s Orders is
inexcusable. The Company is advised that a collaborative effort to review its line extension
tariffs shall commence within 90 days of this Order and that compliance with the tariffs
approved as part of that process is expected. Anything less than full compliance will cause the
Commission to use its powers under Idaho Code 9 61-706 and 61-707 to impose penalties.
Injuries and Damages (1996 Ice Storm)
The Company in this case proposes replacing the current accrual for Injuries and
Damages with a six year rolling average of injuries and damage payments not covered by
insurance. Reference Company Exh. 11 , Col. 0; Exh. 24, p. 7, PF 13. Included within the
Company s rolling six-year average are uninsured damages related to the ice storm of 1996.
Staff adjustment removes this amount. The Company agrees with the Staff calculation of the
revised annual accrual for Injuries and Damages that corrects for the payment of an expense that
was allocated to Idaho electric operations when it should have been directly assigned to
Washington electric operations. The Company did not, however agree with Staffs removal of
the 1996 ice storm expenses. The Staff adjustment corrects the allocation of the injury and
damages expenses, and excludes the 1996 ice storm expenses. Staff contends that the ice storm
was an out of test year event, extraordinary and non-recurring, not reflective of on-going
expenses. Tr. p. 1063. As shown in Staff Exh. 118, Col. I, removal of the ice storm expense
results in a reduction in Administrative and General (A&G) operating expense of $67 001 , an
ORDER NO. 28097 10-
increase in state tax of $984, and an increase in federal taxes of $23 106. The resultant increase
in net operating income is $42 911.
Potlatch contends that the ice storm costs were incurred prior to the test year and that
what the Company is proposing is retroactive ratemaking. Tr. p. 1214. Potlatch recommends
that the Company s proposed adjustment be eliminated. Tr. p. 1222.
Findings:
The Commission finds removal of 1996 ice storm related expense from this case to be
reasonable. While we make no judgment regarding the Company s risk management or
uninsured expenditures, we do find that this is an extraordinary non-recurring expense that
cannot be allowed. The Company s own publication "Ice Storm 96 Overview" states "the
National Weather Service categorized this ice storm as the only event of its kind in 115 years of
record. . .no comparable ice storm has occurred since the recording of weather statistics." Tr.
693. On rebuttal the Company asserts that it cannot be guaranteed that storm damages of this
level will not reoccur. Tr. p. 651. The Company provides no evidence, however, to show with
any degree of certainty how much those storm damage expenses will be. In this regard we find
the transcript reference to our treatment of Idaho Power s Pacific Hide hazardous waste clean-up
costs to be on point. Tr. p. 682-683; reference Idaho Power Order No. 25880. Avista s proposal
to recover its uninsured costs of 1996 ice storm damage through rates would violate the principle
that rates must be prospective and may not be used to recoup past losses. The proscription
against retroactive ratemaking means that ice storm costs expended by the Company in the past
are not recoverable through future rates unless they are preserved for that purpose by deferral or
other regulatory action. When it became aware that the uninsured ice storm costs would be
substantial, the Company had the opportunity to request rate relief or deferral of these costs for
future recovery. It did neither. Accordingly, we cannot in this case authorize the requested
recovery of this expense by including such expense in a six-year historical average.
Miscellaneous General Expense (FERC Account 930)
Based on a review of a sampling of Miscellaneous Account 930 entries (direct
assignment and allocated), Staff proposes to disallow 20% of the account test year expense
$259 344 as not beneficial to customers and below-the-line expenses. Account 930 consists of
ORDER NO. 28097 11-
12 sub accounts, such as miscellaneous labor not elsewhere provided for, industry association
dues, contributions for conventions and meetings of the industry, research, development &
demonstration expenses not charged to other O&M expense accounts, and communication
service not chargeable to other accounts. Tr. pp. 1066, 1067. Staff contends that included by the
Company as Account 930 expense were below the line activities associated with lobbying,
enhancing the image of A vista in the community and efforts to maximize shareholder value. Tr.
p. 1068. The Company disputes Staff s across the board adjustment contending that the 20%
reduction is an unsupported percentage which disallows a percentage of otherwise appropriate
expense. The Company notes that "general" management costs often do not provide "a direct
benefit to customers " yet still are essential to the operations of a major utility. Tr. p. 958.
Staffs adjustment removes $259 344 of expense and provides a related increase in state income
tax of $3 809, an increase in federal income tax of $89,437 for an overall increase in net
operating income after taxes of$166 098. Tr. p. 1068.
Findings:
The Commission finds that the percentage adjustment to Miscellaneous Account 930
proposed by Staff is reasonable. This is an account that is a catch all for general expenses not
otherwise chargeable to other accounts. The Company does not dispute that disallowable
expenses have been included within the account but challenges only that some expenses are
clearly appropriate utility expenditures. Allowance of 80% of the total recognizes that fact. The
Company on rebuttal did not elect to provide a more detailed analysis of account entries or a
better ratemaking treatment for this account. The percentage adjustment we approve IS a
percentage disallowance of total dollars and not a specific accounting transaction.
Secondary Transactions
Avista in this case proposes that commercial short-term purchases and sales (one year
or less) be excluded from the 1997 pro forma results because the majority of such transactions
were for speculative purposes and unrelated to operation of the Company s resources or serving
retail load. The contracts for the commercial transactions that occurred during the 1997 test
ORDER NO. 28097 12-
period have all terminated? Speculative transactions include wholesale purchases of power that
are made exclusively for resale to other wholesale parties. They also include wholesale sales of
power that are covered later with purchases, also known as selling short. These transactions are
unrelated to purchases made to serve retail load, as well as sales of surplus power from the
Company s system. Because they are speculative in nature Avista maintains that the risks and
benefits associated with these transactions should reside with the shareholders and be excluded
from the retail ratemaking process. See Tr. pp. 410 414 415 431-432.
Potlatch opposes the Company s proposed exclusion of secondary transactions.
Utilities, Potlatch contends, have always bought and sold on the secondary market to balance
loads and resources and to take advantage of attractive market conditions. Tr. pp. 1182, 1183.
Secondary purchases have been used by utilities to supplement resources until load growth
justifies construction of new generation, and to take advantage of prices below the variable
operating costs of Company resources. Secondary sales have been used to minimize resource
surpluses. Tr. p. 1183.
Potlatch contends that short-term sales are not inherently speculative. As important
as who bears the gain or loss, Potlatch contends, is who was entitled to seize the opportunity and
who faCilitated the transaction. Tr. p. 1187. If a particular transaction relied either in whole or in
part on the utility's resources, then the ratepayers, Potlatch contends, have a legitimate claim to
at least a portion ofthe proceeds. Tr. p. 1187. Potlatch contends, that it is virtually impossible to
tell in retrospect which secondary transactions are actually associated with retail loads and which
were purely speculative. Tr. p. 1187. There exists, it states, some potential for self dealing and
other mischief. Tr. p. 1189.
Potlatch contends that A vista recently has chosen to enter the secondary transaction
market with a vengeance. Tr. p. 1176. Reference Exh. 202.
Operating Revenues Operating Expenses
1996
$ .
944 billion 1996
$ .
758 billion
1998 $3.68 billion 1998 $3.51 billion
2 During the 1997 test period the Company made short-term purchases of 12 283 000 mwh (1,402 aMw), and short-
term sales of 12 103 000 mwh (1,382 aMw). The Company s actual net system fll1Tlload for 1997 was 933 aMw.
Tr. p. 411.
ORDER NO. 28097 13-
Only the tiniest fraction of this growth, Potlatch contends, was attributable to increased retail
sales. Tr. p. 1176. The Company s power marketing activities, Potlatch notes, are not confined
to unregulated affiliates. Tr. p. 1178. This transition, Potlatch contends, introduces a whole new
set of financial and business risks for the utility. Tr. p. 1181.
The Company s solution, Potlatch states, is to substitute the power supply models
predicted short-term transactions for actual figures. Tr. p. 1189. This, Potlatch contends, puts
the model to a use that it was not intended. Tr. pp. 537, 1191. Reference Avista Exh. 6--actual
1997 short-term purchase $191.1 million adjusted to test year pro forma $16.3 million; actual
1997 short-term sales $192.4 million reduced to $9.7 million. The Company at hearing admits
that future commercial trading activities or speculative transactions are not picked up, projected
or calculated in the model, but contends that the model continues to do what it has in the past
, calculating the costs associated with operating the resources to serve retail load and firm
contract obligations. Tr. pp. 537 538.
Potlatch suggests that A vista has not met its burden of proof in justifying the
exclusion of short-term purchases and sales. Tr. p. 1193. A best estimate, Potlatch contends, is
that approximately 10% of these transactions are due to hydro and 90% to market opportunities.
Thus, a reasonable pro forma adjustment to the test year would be to include 90% of actual 1997
short-term sales and purchases. Tr. p. 1193. Ratepayers, Potlatch argues, should be
compensated for partially underwriting these market transactions. Potlatch also proposes to
allocate an additional portion of the corporate overhead and A&G expense as well as general
plant rate base to speculative transactions. Tr. p. 1195; Exh. 203. The resultant Potlatch
adjustment is a decrease in the revenue requirement of $3.9 million, on an Idaho jurisdictional
basis. Potlatch recommends a formal rulemaking regarding speculative transactions at the
conclusion of this case. Tr. p. 1197.
Based on its investigation, Staff recommends that the Commission accept the pro
forma power supply adjustments proposed by the Company for the twelve-month period
beginning July 1 , 1999 and ending June 30, 2000, including the proposed exclusion of short-term
purchases and sales not otherwise projected by the Company s power supply model. Reference
Exh. 6; Tr. pp. 920, 925, 926. Staff recommends that Avista be directed, however, to separately
account for short-term speculative and retail load serving transaction revenues and expenses as
well as the operational costs of those activities. Tr. pp. 918 , 928.
ORDER NO. 28097 14-
It is Staff s belief that the speculative trading engaged in by the Company is a
discretionary activity that is risky and not always profitable. If ratepayers are allowed to share in
the profits, they would also be subject to the losses if they should occur. Staff believes that the
Company s retail customers should not be subject to such risks. Staff recommends that the
operational expenses incurred by the Company for these activities be excluded, but states that it
has been unable to identify all of the direct and overhead costs associated with the marketing
functions or to determine an appropriate method of allocation. Tr. p. 927.
The Company on rebuttal recommends that Potlatch's proposal to include 90% of the
secondary sales and purchases as a pro forma adjustment be rejected and addresses the
incremental A&G costs associated with its short-term commercial or speculative trading. The
net difference between short-term sales and purchases, the Company argues, cannot be used as a
measure of profit because the net difference is derived primarily by the Company s load and
resource balance. Tr. pp. 420, 421 , 446-449. The Company agrees that there are some
incremental A&G costs associated with these commercial transactions that should be excluded.
Tr. pp. 449, 450. The Company contends that the costs associated with these commercial
speculative activities, however, do not even begin to approach the costs Potlatch proposes to
allocate to them. Potlatch's proposal to use energy to allocate the costs to the commercial
trading activities, the Company contends, is inappropriate and is inconsistent with the very
important ratemaking principle of "cost causation.Commercial secondary transactions, the
Company notes, generally involve high volumes of energy and thin margins. Tr. p. 451.
The Company was able to estimate and identify approximately $157 200 in A&G
costs associated with short-term commercial or speculative trading for the Idaho jurisdiction
including such items as payroll, square footage, floor rental, janitorial service, building
maintenance, etc. Reference Exh. 23 , p. 12; Tr. pp. 421 , 455. The Company estimates that
approximately four net positions could possibly be eliminated if the short-term trading activity of
the Company did not exist. Tr. p. 452. Contending that the regulated company benefits from
this commercial trading activity, the Company makes no adjustment to allocate costs to
commerCial trading activities. Tr. pp. 414 455 457.
ORDER NO. 28097 15-
Findings:
The Commission has reviewed and considered the testimony and exhibits regarding
the Company s increased trading activity and involvement in short-term commercial purchases
and sales. A vista has not adequately shown that it has procedures in place and that they were
adequately followed to assure this Commission that the ratepayers have not paid any of the costs
associated with non-system sales. These costs must be allocated on a fully allocated basis, not an
incremental basis. We are not inclined to accept Potlatch's recommendation to include the full
amount or a percentage of short-term purchases and sales.
Recognizing that the Resource Optimization department of the Company does engage
in some level of speculative transactions not otherwise associated with the operation of Company
resources or serving retail load, we find it appropriate to make an A&G related adjustment. The
Commission believes that if costs were fully allocated they would be considerably more than the
incremental amounts indicated by the Company. Exhibit 210 shows actual loaded labor and
other expenses for Resource Optimization for the years 1997 and 1998. These numbers include
labor, taxes and benefits. The growth rate for Resource Optimization from 1997 ($8 319 969) to
1998 ($9,244 246) is calculated to be 11.1 %. The Company notes that there were eight gas
personnel along with thirty electric personnel in Resource Optimization. Tr. p. 514. The portion
of total estimated costs allocated to electric is 30/38 or 79% of the 1997 total, i., $6 572 775.
The calculated per person electric cost is $219 093 , 79% of the total divided by 30. Only four of
these personnel are identified as needed for speculative trading activities. We find the
speculative trading activity costs to be four times the per person cost or $876 370 on a total
system basis. The system cost adjusted to Idaho is $283 944, the retail trading cost times the
32.4% jurisdictional allocation factor. Accordingly, the Commission finds an appropriate
expense adjustment for commercial secondary transactions to be $283 944. We direct Avista to
develop more complete procedures to fully allocate costs to these transactions and to provide
these procedures to the Commission s Staff for review.
Depreciation
Based on a Depreciation Study performed for the Company by Deloitte and Touche
Avista proposes to change depreciation rates as follows:
ORDER NO. 28097 16-
Functional Electric Group
Steam production plant
Hydraulic production plant
Other production plant
Transmission plant
Distribution plant
General plant
Depreciation RatesExisting % Proposed %12 3.1.04 1.5818 2.2.41 2.27 2.4500 12.
Tr. p. 611.
The Company proposes a $2.4 million increase in Idaho jurisdiction depreciation. The
effect of the Company s proposed adjustment decreases Idaho net operating income by
573 000 and reduces Idaho rate base by $807 000. Tr. pp. 617, 1034.
Staff recommends the following adjustments to the Company s depreCiation request:
1. Error in applying the rate of depreciation $182 000
2. Transmission net salvage adjustment $258 000
3. Distribution net salvage adjustment $283.000
Total $723 000
Staff also recommends related adjustments to accumulated depreciation totaling $383 000 and to
deferred income tax totaling $268 000. Tr. p. 1035. The level of depreciation expense
recommended by Staff is set out in its Exhibit 115. The Company has requested an increase in
overall composite depreciation rates from 2.46% to 2.98%. Staffs recommended increase in
overall composite depreciation rates is from 2.46% to 2.85%. Tr. p. 1037.
Potlatch opposes increasing A vista plant depreciation rates. Tr. p. 1199. The
depreciation rates of electric utilities, Potlatch contends, are too high as evidenced by the fact
that virtually all sales of utility assets in preparation for open markets are being made at
significant multiples of the regulated book value. Reference Exh. 205. Potlatch compares the
depreciation rates of A vista with other utilities and believes that with the exception of
distribution plant they are comparable. Potlatch proposes to limit the depreciation adjustment to
distribution plant. Tr. pp. 1203 , 1204. Potlatch recommends a $2.1 million decrease in the
Company s recommended $2.4 million depreciation adjustment. Tr. p. 1222.
The Company by way of rebuttal contends that absent planned deregulation and
divestiture, the logic of Potlatch's depreciation argument fails and should be rejected. Avista
the Company states, has not proposed any divestiture in this case and has spoken publicly against
ORDER NO. 28097 17-
forced divestiture. Additionally, it is noted that neither this Commission nor the Idaho
Legislature have come forth to promote electric deregulation and divestiture of utility generating
assets. Tr. p. 144. The Company also notes that rate base in Idaho is calculated on the basis of
original cost, not market cost or replacement cost. Potlatch, it states illogically wants
depreciation to be influenced by market value while regulated rates are being set using original
cost. Tr. p. 146.
Findings:
The Commission has reviewed and considered the Company s proposed increase in
depreciation rates and expense, its related depreciation study, Staffs proposed adjustments to
depreciation rates and expense, Potlatch's arguments regarding depreciation and the Company
rebuttal.
The Company s depreciation rates were last changed in 1990. The established rates
were tentative and subject to later rate case justification. We note that the Company in this case
is not proposing a change in its depreciation methodology. Tr. p. 611. We find the underlying
depreciation methodology utilized by the Company to be sound and not in need of change.
The depreciation rates and resultant changes in expense we find to be reasonably
based on updated information or change in accounting estimates (study and analysis of historical
retirement experience, salvage and cost of removal experience and determination of updated unit
remaining lives and net salvage factors).Tr. pp. 611 , 633. The Company accepts Staffs
proposed depreciation adjustments, which we also find to be reasonable. Tr. p. 133. The
schedule of final depreciation rates that we adopt is that depicted in Staff Exhibit 115. However
in light of the testimony regarding Centralia and its likely sale, we find it reasonable in this case
to reject the proposed change in terminal net salvage percentage related to Centralia (25.9%).
Reference Exh. 211 , p. 2, excerpt from Deloitte and Touche Depreciation Study. The rates for
Centralia should remain at the existing rates reflected in Exhibit 15, p. 1.
Normalized Net Power Costs
Avista in this case proposes utilizing 60 water years (1927-28 to 1987-88) for
normalization of power supply costs in its power supply model. Tr. p. 1207.
ORDER NO. 28097 18-
Potlatch contends that shorter periods e., 50-year, 40-year, 30-year and 20-year
averages all produce lower test year net power supply expense estimates than A vista s 60-year
average. Tr. p. 1207; Exh. 206. Potlatch recommends a 30-year average reducing net power
supply expenses from $42 million as proposed by Avista to $37.088 million, with a related
resultant decrease in revenue requirement of$1.6 million. Tr. pp. 1211; 1222.
A vista on rebuttal notes that in the current case, as well as in previous cases, the
Company has consistently used the full water record from the regional Northwest Power Pool
hydro regulation studies for the normalization of power supply costs. Tr. p. 424. The Company
specifically notes that water record data prior to 1928 is not available for the Clark Fork River
where the majority of the Company s hydroelectric generation resides. Tr. p. 428. Absent
credible and conclusive studies demonstrating an identified trend or cycle in water record data
which the Company contends has not been presented, A vista argues that the use of the maximum
amount of reliable data will produce the best estimate. Tr. pp. 393, 394 417-419. The Company
charges Potlatch with "selectively choosing" water records to manipulate normalized power
supply cost. Tr. p. 425.
Findings:
The Commission has reviewed and considered Potlatch's objection to the Company
use in its power supply model of the most recent 60 water years included in the Northwest Power
Pool's regional study (1927-28 to 1987-88). While we would prefer to also capture the most
recent ten-year period, we understand that the updated study has not yet been completed and
indeed may not be available until the year 2003. Accordingly, we are satisfied that the
Company s use ofthe Power Pool's present 60-year study presents us with the best regional data
for the Company s hydro generation resources. We have been presented with no persuasive
reason to require that the Company abandon the use of its Power Pool data in its power supply
model. We also find it more reasonable to use the full 60-years of data as opposed to a selected
shorter period.
Rate Base
Avista in its Application proposed a pro forma rate base of $360 534 000 for the
Idaho jurisdiction. Reference Exh. 11 , p. 8. Based on evidence presented by Staff, Avista
ORDER NO. 28097 19-
accepted a depreciation related adjustment to rate base resulting in an increase of $651 000 for a
revised Company proposed rate base of $361 185 000. Reference Company Rebuttal Exh. 24
Sch. 1 , pp. 1-
Staff calculates an adjusted rate base of $360 546 000. The difference in Company
revised and Staff adjusted rate base is a Staff proposed $639 000 line extension (CIAC)
adjustment. Exh. 118, pp. 1 , 2. Potlatch proposes no change or adjustment in Company
proposed rate base. Reference Exh. 208.
Findings:
The Commission has reviewed the Company s revised and Staff proposed rate base
calculations. Because in our discussion of operating assets-pro forma adjustments, we find
Staff s CIAC adjustment to be reasonable (including related rate base) we find a 1997 total rate
base of $360 546 000 to be just and reasonable.
Capital Structure
A vista proposes a capital structure based on outstanding debt, preferred securities and
common equity balances at December 31 , 1997, adjusted for known and measurable changes
through September 30, 1998. The Company has elected to reduce common equity by the amount
of its equity investment in certain non-regulated subsidiaries, resulting in capitalization of
48.030% long-term debt, 3.958% short-term debt, 10.588% preferred securities and 37.424%
common equity. Exh. 5, Sch. 6, p. 1. Staff agrees with the Company s proposed capital
structure. Tr. p. 1126; Exh. 122, Sch. 14. Potlatch expresses no opinion.
Findings:
The Commission adopts the capital structure proposed by A vista and accepted by
Staff as appropriate and reasonable for calculating the Company s overall rate of return. We also
recognize and appreciate the willingness of A vista to adjust the capital structure for investment
in non-regulated subsidiaries.
ORDER NO. 28097 20-
Cost of Capital and Rate of Return
Debt and Preferred Equity
The Company calculates its embedded costs of debt and preferred equity assoCiated
with its proposed capital structure to be 8.011 % for long-term debt, 6.255% for short-term debt
113% for preferred trust securities and 8.151 % for preferred stock. Exh. 5, Sch. 6. Staff
accepts the Company s calculation of debt and preferred costs. Tr. p. 1126; Exh. 122.
Findings:
The Commission finds the debt and preferred costs proposed by A vista and accepted
by Staff to be reasonable.
Common Equity/Equity Adder
The Company, 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, and is primarily an attempt to quantify a rate of return required
by investors for that particular investment. A vista proposes a range for equity return of 11.25-
12.25% and requests a rate of return of 11.75% on the common equity portion of its capital
structure. Tr. p. 213.
Staff proposes a lower range for equity return of 10.25-11.25%, recommends a return
on equity of 10.75%. Exh. 122, Sch. 14; Tr. p. 1107. Potlatch states that there has been a
dramatic drop in cost of both equity and debt since 1986 and suggests that a more reasonable rate
of return for equity is in a range of 10.4-10.9% (estimated revenue requirement impact of ($2.4
million)). Tr. p. 1221 , Exh. 208.
The Company in this case recommends that an equity adder of 25 basis points
added to the equity return of A vista to recognize innovative management and strategic initiatives.
Tr. pp. 124-126 214. Without such an award, the Company contends that there is not sufficient
differentiation in rate setting between a well-managed and a poorly-managed utility. Tr. p. 112.
Commission Staff agrees to the Company proposed equity adder. In doing so, Staff
contends that the adder should not necessarily be viewed as a reward for past exemplary
performance but as an incentive to continue programs and processes that lead to noted qualities
and initiatives with continued betterment of performance as the goal. A vista is making
improvements, Staff contends, and deserves recognition for those improvements. Tr. p. 1128. In
ORDER NO. 28097 21-
determining the appropriateness of such an award, however, areas of noted concern that must
also be weighed by the Commission, Staff contends, are: 1) the Company s failure to comply
with Commission Order No. 23071 (1990) by not providing annual updated line extension costs
for Schedule 51 construction; and 2) the Company s failure to comply with the Customer
Information Rules requirement of individual customer notice of rate changes (e., PCA tracker
adjustments). Reference IDAPA 31.21.02.102; Tr. p. 1129. The Company characterizes its
omissions as administrative oversights. Tr. pp. 140, 152 901 902 904.
Findings:
Different methodologies exist to analyze and ascertain a fair rate of return
common equity capital, including discounted cash flow (DCF) method, risk premium analysis
and comparable earnings method. Each method attempts to ascertain a rate of return on common
equity at a point sufficiently attractive that free-market investors will consider purchasing
common equity shares in a 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's stock
performance in the market place is determined by many variables, including management
decisions, weather, streamflow conditions, and a host of separate economic factors.
The Commission in previous cases has relied on DCF and comparable earnIngs
methods to determine an appropriate rate of return on common equity. The DCF analysis utilizes
the dividend rate, stock price and expected growth rate of a company to quantify the return
required by the investor. The comparable earnings method evaluates returns earned by other
companies, including utilities, to quantify an investor s expected return, taking into account the
risk associated with the 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.
The DCF methodology was used by both A vista witness Avera and Staff witness
Carlock. While both witnesses agree in this case that a constant growth DCF methodology is not
appropriate, they do not necessarily agree on the reasons.Potlatch's witness, Dr. Peseau
ORDER NO. 28097 22-
provides no DCF analysis but presents a debt to equity cost relationship analysis comparing 1986
debt costs and interest rates to today , concluding that comparable interest rates today are 200 to
250 basis points below the September 1986 levels. Tr. pp. 1218, 1220, 1253 , 1254.
A vera contends that future growth equally weights regulated and non-regulated future
growth. Tr. p. 297. Carlock states that a constant growth method is not reasonable to use for
A vista because the dividend change for A vista minimizes the benefit of historical trends and that
growth projections for the next three years are not representative of ongoing growth due to the
exchange offer. Tr. p. 1123. Carlock has not specifically weighted the growth rate for expected
changes in regulated and non-regulated operations.
We are not inclined to accept Avera s methodology as it can put too much weight on
deregulated operations without assuring that regulated operations are not paying an excessive
share of investor growth expectations for deregulated operation. We are also uncomfortable with
the projections Avera uses through 2008 to develop his recommended return requirements. We
accept Carlock's two-stage methodology, as it does not focus on non-regulated growth. It is also
for this reason we decline to accept Avera s added risk premium that he claims is associated with
the lower common equity ratio used for regulatory operations. Tr. p. 213. We agree with
Carlock that non-regulated operations must bear the equity return requirements caused by non-
regulated operations. There is insufficient evidence in this record to demonstrate that this
segregation and assignment of responsibility for required returns has occurred. With this in mind
we authorize a return on equity of 10.75%. The 10.75% is within the range of reasonableness
recommended by Carlock (10.25% - 11.25%) and also within the range Peseau indicates is
reasonable (10.4% - 10.9%). We have chosen a return at the midpoint of the Staff recommended
range. The overall rate of return authorized is 8.979% as shown in Appendix B to this Order.
The Commission recognizes that A vista has achieved excellence in many areas of
utility performance including competitive efficiency, business excellence and innovation, and
customer service. The Company has also pioneered industry activities including pilot customer
choice programs, a non-bypassable distribution charge for conservation, a fuel-switching
program, and a collaborative model for hydro relicensing.
However, while it is obvious that the Company is doing many things well and
receiving deserved recognition within the industry, as regulators we cannot ignore the instances
cited in this Order where the Company has failed to follow its tariffs and has ignored express
ORDER NO. 28097 23-
Commission directives and/or rules. The Company notes that "the regulatory compact expects
management competency." Tr. p. 113. It is suggested that a minimum standard of management
competency is compliance with Company tariffs and Commission Orders and rules.
encourage the Company to pay greater attention to the details of regulatory compliance. The
Company should consider such compliance as a threshold qualification for any adder
consideration. In this case we decline to include an equity adder.
Summary of Adjustments to Test Year Revenue, Expenses and Rate Base
Considering all of the evidence presented, and including all adjustments, we find total
Idaho jurisdiction operating revenues for the 1997 test year in the amount of $187 136 000, and
total Idaho jurisdiction operating expenses and related adjustments in the amounts of
$154 762 000 for a Idaho jurisdiction net operating income of $32 374 000 to be reasonable and
just. After all adjustments we find a 1997 total rate base amount of $360 546 000 to be just and
reasonable. Appendix A to this Order shows the Commission s findings on rate base and net
operating results for the test year.
Calculation of Revenue Deficiency
Having determined 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
Net Operating Income Requirement
Operating Income
Income Deficiency
Incremental Tax Multiplier
Revenue Deficiency
$360 546 000
979%
$ 32 374 000
$ 26 435 000
$ 5 939 000
1.571042
$ 9 330 000
Appendix B to this Order shows the calculation of cost of capital and calculation of revenue
deficiency for A vista.
Cost-of-Service Study
cost-of-service allocation study allocates total cost-of-service (i., the revenue
requirement) to a series of functional costs and then to classes of customers in accordance with
ORDER NO. 28097 24-
recognized principles and generally accepted procedures in order to obtain an indication of the
relative cost responsibilities of each class of customers.
The basic cost-of-service (COS) methodology, peak credit method, used by the
Company in this case is the same as the COS study filed in its last rate case with two exceptions:
1. Distribution costs are classified to customer and demand by the Basic
Customer Method in this case, whereas in 1986 the Minimum Distribution
Method was used.
2. Administrative and general costs are directly assigned to function where
possible and the remaining general costs are included with the distribution
function and classified 40% to energy and 60% to customer. In the 1986
case most administrative and general costs were allocated by the sum
other operating expenses or plant which implies a functional allocation
based on the components ofthe sums. Tr. p. 744; Exh. 17.
The Company notes that its cost-of-service study in this case differs from the Idaho
unbundling study methodology in the treatment of administrative and general costs and some
refinements to the primary/secondary categorization of distribution plant. Tr. p. 777.
Staff believes that the two changes in the Company s COS study tend to improve
COS results. Tr. p. 1161. Staff notes that changes to cost-of-service methodology shift costs
among classes and affect revenue requirement responsibility. The effects of the changes in this
Company s current COS study are to increase costs of Residential, General Service and
Pumping classes, and to decrease costs for Large General Service, Extra Large General Service
and Lighting classes. Tr. p. 1154. The rate impact, Staff contends, is softened by the Company
proposal in this case to only move one-third ofthe way toward full cost-of-service rates. Tr. pp.
1153 1155. Staff supports the Company s proposal. A more aggressive move toward full cost-
of-service in rate design, Staff contends, would produce unacceptably large rate increases. Tr.
p. 1155.
Staff accepts the Company proposed cost-of-service methodology. Tr. p. 1154. Staff
notes however that there is no such thing as one and only one correct methodology. Each
method has perceived advantages and disadvantages for each class of service. See Exh. 26
relative rate of return (ROR) by class.
Potlatch contends that the Company s cost-of-service study is flawed and that
departs from prior Commission positions. Tr. p. 1172. Potlatch addresses the Company
classification and allocation of distribution costs, the demand allocators for both generation and
ORDER NO. 28097 25-
distribution costs, classification of transmission costs and the allocation of conservation costs.
Correcting for the perceived flaws in the Company s cost-of-service study, Potlatch concludes
that Schedule 25 customers are currently paying rates that cover their cost of service. Tr. pp.
1173 , 1246; Exh. 209, 1. 58.
A vista proposes to classify and allocate distribution, transmission and generation
costs, Potlatch contends, in such a way as to penalize high load factor customers. Tr. p. 1224.
A vista in this case proposes a move from the Minimum Distribution System (MDS) method to
the Basic Customer Method (BCM). Tr. p. 1226. MDS, Potlatch contends, produces a fairer
classification of distribution costs. The Avista proposal to switch to BCM (used in Washington),
Potlatch contends, under-estimates the customer component and over-estimates the demand
component of distribution costs. The inherent bias in this method, Potlatch contends, greatly
exaggerates the costs to high load factor customers. Tr. pp. 1228, 1248.
Regarding demand allocators, Potlatch notes that A vista proposes the use of an
average 12 CP allocator to allocate production and transmission demand-related costs. Potlatch
disagrees. Potlatch recommends that demand cost allocation be made on the basis of customer
class contribution to system peak demand, which occurs in January (1CP). Exh. 209, Tr. pp.
1233-1236.
A vista by way of rebuttal characterizes the changes proposed by Potlatch to the cost-
of-service methodology as designed to selectively shift costs away from the Schedule 25
customer group and incidentally on to residential customers. Tr. p. 775. Addressing Potlatch'
contention that A vista is departing from the only Commission approved method of classifying
distribution costs, Avista notes that PacifiCorp s UP&L jurisdiction utilizes essentially the same
Commission approved classification method the Company proposes. Tr. pp. 778, 779. Potlatch
disputes the Company s representation or inference that PacifiCorp in not choosing the minimum
distribution system approach had adopted or was using the basic customer method. Instead
Potlatch contends that PacifiCorp follows a facilities or engineering approach. Tr. p. 1250.
Addressing Potlatch's proposed use of single peak allocator (1 CP) to a monthly average
allocator (12 CP), Avista contends that a 12 CP allocator is more reasonable because (1) single
peak allocators are subject to weather-related variability, (2) capacity concerns are important
throughout the year, not just at a single peak; and (3) monthly peak allocators approximate
ORDER NO. 28097 26-
demand billing determinants thereby capturing the annual contribution when measured by kW
month. Tr. pp. 779, 780.
Findings:
The Commission has reviewed and considered the Company cost-of-service
allocation study, Potlatch's critique of same and Staffs support of the study. Dr. Peseau, on
behalf of Potlatch, correctly characterizes cost-of-service studies as a balance of art and
economic principles. Tr. p. 1224. It is only natural, Dr. Peseau contends, for each rate class to
want to pay the lowest possible power bills and to avoid subsidizing other classes. Tr. p. 1224.
Cost-of-service, however, is only one of many factors to be considered by this Commission in
tariff design; there is no required correlation. The Company and Staff correctly note that COS
methodology changes can have profound impacts on cost responsibility. We find the two
changes proposed by the Company in its COS methodology, however, to be improvements and
reasonable. We reject Potlatch's recommended changes to cost-of-service methodology and
accept the Company s submitted cost-of-service allocation study.
Rate Design - Class Revenue Allocation
Having determined the Idaho jurisdictional revenue requirement, we must now
determine the appropriate revenue requirement for each customer class. Based on its cost-of-
service study the Company proposes a one-third move to full cost-of-service, a move which Staff
supports. Tr. p. 105. The primary goal of the Company s rate spread is to move the rates of
return of the individual schedules closer to the Company s overall rate of return. Tr. pp. 831
832; Exh. 21.
The Company in this case proposes three structural changes to its electric customer
class rates, two in the residential class and one in the pumping class.
Residential Service - Schedule 1
For the residential class the Company proposes to collapse the existing three-
block inverted energy rate structure to a two-block inverted energy rate
structure (with the break point at 600 kWhs) and to move from a customer
minimum ($8.50/mo.), which includes 203 kWhs of energy, to a basic charge
($5.50), which includes no energy.
ORDER NO. 28097 27-
Pumping Service - Schedule
F or the pumping class schedule which provides service for pumping water
(and water effluents) for irrigation, municipal systems and other purposes, the
Company proposes to add a $6.00 basic charge where there currently is none.
The proposed charge, the Company contends, will recover approximately 82%
of related service costs, a meter, meter reading and billing. Tr. pp. 861 , 862.
Tr. p. 1156; Exh. 26, p. 3.
Staff accepts the Company proposed structural changes except as to the residential
basic charge amount. Tr. p. 1157. Regarding the residential basic charge, Staff recommends a
$4.00 basic charge as opposed to the Company proposed $5.50. Staff contends that a $4.00 basic
charge allows the Company to introduce residential customers to a new type of charge, recovers
a reasonable portion of its embedded costs through a fixed fee, reduces the high percentage
increase on low consumption customers, and is consistent with other basic charges found in
Avista s tariffs (e., $4.30 residential basic charge MOPS II; $4.00/mo optional seasonal chg-
Residential Sch 1). Tr. p. 1089. A $4.00 basic charge also, Staff contends, comports with Avista
unbundling information identifying a total cost for metering, meter reading and billing for small
customers of$3.87/month. Tr. p. 1090.
The Company contends that a $5.50/month basic charge for residential customers is
more reasonable and fair and will still provide only partial recovery of the average embedded
costs for serving customers, i., service line, meter, meter reading and billing costs. Tr. p. 107.
The Company calculates the total customer allocated cost at $14.96/customer. The Company on
rebuttal notes that based on survey results the average monthly electric consumption for gas-heat
customers is approximately 800 kWh/mo, whereas the average monthly electric consumption for
non-gas heat customers is approximately 1200 kWh/mo. Tr. p. 878. The Company
documentation and testimony, as indicated by Staff, shows that 11 100 of its Idaho customers are
in households whose annual income falls below $15 000. The number of those customers whose
primary heat source is electricity is 5 198. Of those, 3 500 customers received energy assistance
during 1998. Tr. p. 1092.
Speaking to the justness and reasonableness of the proposed increase, Senator
Keough in her comments, indicated that northern Idaho was a troubled economy; that the most
recent unemployment figures for Bonner County show a 9.8% unemployment rate, over double
the statewide average. In fact, she states that across the area proposed for the rate increase are
ORDER NO. 28097 28-
the counties with the highest unemployment rates in the state. Tr. p. 553. The unemployed, the
underemployed and the business sector, she maintains, can ill afford the proposed increase. Tr.
p. 554. Low power rates, while the envy of others, she notes, do not reflect the absence of and
the struggle to obtain adequate roads and infrastructure. This is an area of increasing and
documented numbers of people lining up at local food banks. How, can this reality, she queries
be squared with a company that is paying its CEO a huge salary asking for more money. Tr. p.
555. It is reported, she states, that the Company is making only 7% on its investment and is
asking for a 9-10% return. Where, she asks, can the public sign up for such a return on savings?
Tr. p. 556. Why should the people in her district, she queries, be forced to choose or in fact
perhaps not be given any choice between feeding their families and paying their power bill? Tr.
556.
The present and proposed electric rates are reflected in A vista Exhibit 26, p. 3 and
Staff Exhibit 127. The Company in its Application proposes the following changes:
General Service-Schedule 11
To recover additional fixed system costs, the Company is proposing an increase in the
basic charge for General Service - Schedule 11 customers from $4.00 to $6.00. Tr. pp. 855 , 856;
Exh. 26, p. 3 , Exh 21 , p. 5. Additionally, the Company proposes to increase the Schedule
demand charge for kW in excess of20 kW/month from $3.15/kW to $3.50/kW. Tr. p. 856.
Large General Service-Schedule 21
F or the Large General Service Schedule 21 tariff, the Company is proposing to
increase the monthly minimum charge from $200 to $225 per month and the present demand
charge from $2.30/kW to $2.75/kW. To provide additional economic incentive for a new
customer to take service at primary voltage, the Company is also proposing to increase the
present primary voltage (11 kv or higher) discount from $.10/kW to $.20/kW. Tr. p. 857.
Primary voltage customers are required to own and maintain electric facilities (step-down
transformers, conductor, etc.) on their side of the meter. Tr. pp. 857, 858. Presently, the
Company serves only 18 out of 1 700 total Schedule 21 customers at primary voltage. Tr. p.
859.
ORDER NO. 28097 29-
Extra Large General Service-Schedule 25
The Company s Extra Large General Service Schedule 25 tariff requires a minimum
monthly demand level of 2500 kilovolt-amperes (kva). Eleven customers (14 account metering
points) are served under the schedule. The Company is proposing to increase the monthly
minimum charge from $5 500 to $7 500 per month for the first 3 000 kva or less (an implied
demand charge of $2.50 per kva), and to increase the demand charge for all kva in excess of
000 from $1.10/kva to $2.25/kva. The proposed demand charge, the Company contends, will
provide customers with a more reasonable indicator of demand.,.related costs and encourage them
to further improve their load factor. Also proposed is an increase in the annual minimum charge
from $361 350 to $419 230 and an increase in the primary voltage discount from $.lO/kva to
$.20/kav. Tr. pp. 859-861.
Street and Area Light-Schedules 41-
Street and Area Light schedules contain monthly fixed charges for different light
types and sizes, as well as pole types. The Company proposes a uniform increase to present rates
and charges. Tr. p. 863.
Findings:
The Commission has considered the proposals and testimony of the parties regarding
rate design and class revenue allocation. The Commission finds that moving all class revenue
requirements to the levels suggested by the Company and Staff would be unreasonable. In Order
No. 28078 in this case, we recognized having received in excess of 250 petitions, letters and/or
E-mail comments from A vista customers. The customers relate individual accounts regarding
the Company s Idaho service territory, its depressed timber, mining and agricultural industries
and the pervasive level of poverty, unemployment and underemployment including the impact of
the proposed increase on themselves, their families, their communities and their businesses.
Important interests in rate stability and continuity preclude adopting the extremely large double
digit shifts in revenues from one class to another that were requested. In addition, we recognized
that the results of cost-of-service studies are not so precise that the determination of appropriate
revenue shifts is an exact certainty. The number of years between examinations of cost-of-
service and revenue allocation issues for the Company has allowed several classes (Residential
ORDER NO. 28097 30-
Schedule 1 and Extra Large General Service Schedule 25) to drift a considerable distance from
full cost-of-service rates and requires gradual, incremental moves to cost-of-service rates. We
approve a two step move to accomplish the Company s proposed one-third move to full cost-of-
service, a 20% move the first year reflected in the rates approved by this Order, and an additional
15% move to begin one year from the date of this Order.
The Commission also finds Staffs proposed $4.00/month basic charge for residential
customers to be a reasonable transition step away from the existing customer minimum that
includes an energy allowance. The resulting revenue allocation and tariff rates that we approve
in this case are depicted in Appendices C and D to this Order.
MISCELLANEOUS
DSM / Electric Energy Efficiency
The Demand Side Management (DSM) or electric energy efficiency programs of
Avista are described in its electric Tariff Schedule 90. The programs are presently financed by a
Yz % energy surcharge (electric Tariff Schedule 91). The Company s year end 1998 estimated
energy savings for completed projects (31 452 304 kWh) and related expenditures for these
program of $4,461 775 are set out in Company revised Exhibit No. 12. Tr. p. 1007. The cost
effectiveness methodology used by the Company in assessing its energy efficiency programs is
described in Company Exhibit No. 13.
Noting that the Company s energy efficiency expenditures differ by class and that
DSM related expenditures for Schedule 25 are only 3.3% of total, Potlatch objects to a uniform
allocation of DSM expenditures during periods of relative resource surplus and recommends that
DSM program costs be allocated in direct proportion to the expenditures made on each class. Tr.
p. 1244. During periods of surplus Potlatch contends that no cross benefits or savings accrue to
non-participants. Tr. p. 1244.
Disagreeing with Potlatch, the Company and Staff contend that all of the Company
customers benefit from cost effective DSM programs, albeit with program participants receiving
a larger share ofthe benefits. Tr. pp. 150, 1009. Staff further contends, that in addition to energy
and cost savings there are often non-energy, societal benefits, (such as greater productivity,
cleaner air and reduced need for damming rivers) associated with reduced or at least more
efficient energy usage. Tr. p. 1009.
ORDER NO. 28097 31-
Regarding the Company s DSM expenditures from March 1995 to December 1998
Staff contends that the Company has otherwise engaged in prudent planning, implementation and
evaluation. Tr. pp. 1017, 1018. The Company, Staff states, has created both internal and
external organizations in its efforts to optimally design, implement, coordinate, verify and
evaluate its DSM programs. It is a dynamic, not a static process, Staff contends. Tr. p. 1017.
Also assessed to be reasonable and prudent by Staff are the Company s jurisdictional
expenditures to the Northwest Energy Efficiency Alliance (NEEA) of $155 000 for 1997 and
$310 000 for 1998 , or $465 000 total. Tr. pp. 1018, 1019. The Company has requested and Staff
recommends a Commission finding that Company DSM expenditures, including NEEA, through
December 1998 have been prudently incurred. Tr. pp. 1008, 1011.
Staff quantifies the balance of DSM revenues beyond expenses incurred by A vista
and recommends that 10% annual interest be imputed on past account balances as specified in
the Company s 1994 DSM tariff rider application and that the rider surcharge be reduced by one-
third to 1.0%. Tr. p. 1008. Staff notes that Avista has collected $5 330 274 from its Idaho
customers through its DSM surcharges. This is $868 499 or 20% more than it has spent for its
conservation and efficiency efforts in Idaho. Tr. pp. 1011 , 1012. Staff contends that it was never
intended for such a large deferred balance to be carried. Reference Company Application Case
No. WWP-94-10/WWP-94-5 Attachment D, ~4 Tariff Rider Implementation:
As the DSM programs in Schedule 91 and 191 are modified over time, the
DSM tariff rate would also be adjusted, up or down, to match funding with
DSM program costs and to keep the deferred balances as close to zero as
possible.
Tr. p. 1102; Exh. 130.
Regarding Staff s recommendation that 10% interest be imputed to the DSM
balance, Staff notes that such was the Company s proposal in the DSM tariff rider application
that 10% annual interest be added to the balance of the one month lagged differences between
revenue and expenses." Exh. 130; Tr. pp. 1012, 1013. Staff computes that $189 000 in interest
should be added to the end-of-year 1998 DSM balance of $868 498 bringing the balance up to
approximately $1.06 million. See revised Exh. 131. Staff estimates that an additional $60 000
of interest will have accrued by June 30, 1999. Tr. p. 1013. Based on projected extension of
past average revenues, expenditures and interest rate, Staff estimates that at the end of 2003 there
will be a positive balance of $3.2 million in the DSM tariff rider account. Exh. 131; Tr. p. 1013.
ORDER NO. 28097 32-
Staff therefore recommends that the DSM tariff rider energy surcharge be reduced in this case by
one-third to 1.0%. Tr. p. 101
The Company opposes a reduction in the present funding level noting that the
prudence of DSM expenditures is not being challenged; DSM programs and proposed funding
levels were and continue to be the result of a formal, extensive region wide collaborative process
called the External Energy Efficiency Board (Triple E Board); and that an extension of the DSM
Sch. 91 tariff rider at the present Yz% level was most recently approved in November 1998 in
Order No. 27794. Tr. pp. 147, 148, 197, 198.
A vista in rebuttal contends that "the Company has always planned to maintain a
surplus of funds in the DSM balance account" stating that many DSM projects in the commercial
and industrial sectors require over a year to build out and, ultimately fund, and that it is
necessary and prudent to maintain a positive balance. Tr. pp. 148, 195, 656. The Company
agrees with Staff that some level of interest should be credited to Schedule 91 revenues but
suggests rather than the 10% interest rate proposed and approved in the DSM Tariff Rider
Application that the amount be 6%, the 1998 interest rate on Idaho customer deposits, and that
the amount be offset by corporate service expense (floor space, telephone usage, and the like) as
well as programmable lease investments. A 10% interest rate would result in an interest
adjustment of $124 565. A 6% interest rate over the life of the rider through 1998, would
provide an interest adjustment of$71 422. Tr. p. 656; Exh. 24, Sch. 2, p. 2.
As per its underlying Application in Case No. WWP-94-10 and related
Commission Order, A vista is required to notify customers of the DSM surcharges once a year.
The Company, Staff notes, has not being doing this. Reference Exh. 129 "Each year the rider
will be shown in the annual How to Calculate Your Bill brochure.Order No. 25917
Stipulation ~8, Case No. WWP-94-10. Tr. p. 1011.
Staff also recommends a change in how A vista evaluates the cost effectiveness of its
programs. Tr. p. 1008. Staff notes that the Company does not explicitly estimate base line
activity that would have occurred absent each of its programs. Staff contends that such an effort
should be undertaken. Doing so, Staff states, would be consistent with how the NEEA will
evaluate its programs, programs that are funded in part from Avista s surcharges. Tr. pp. 1015
1016. A vista, Staff contends, does not believe estimating base line activity would be a prudent
allocation of its resources and instead of hazarding guesses about such, it carefully monitors its
ORDER NO. 28097 33-
programs and suggests modifying or dropping those that show only marginal benefit/cost ratios.
Tr. pp. 1015 , 1016.
Findings:
At a time when many electric utilities were discontinuing investment in DSM, A vista
proposed a non-bypassable distribution charge to fund energy efficiency. This Commission
continues to support the Company s efforts and investments in conservation. We find that the
Company s DSM investment benefits all of its customers, both participants and non-participants.
Prudent conservation continues to make sense from both a societal, environmental and economic
perspective. As indicated in prior Orders, it is the Company s obligation in a rate case to
demonstrate the prudence of its conservation investment and our responsibility to ratepayers to
determine that the Company has satisfied its obligation. In reviewing the Company s Schedule
90 DSM programs, identified costs and projected benefits we find that the Company has
sufficiently demonstrated the requisite prudence and cost effectiveness of its DSM related
expenditures. Reference Exh. Nos. 12, 13. We agree with Staff that the Company s evaluation
of cost effectiveness could be improved by developing estimates of baseline activities that would
occur without the DSM programs. We encourage the Company to pursue development of such a
baseline estimate for future program offerings.
We also find the Company s 1997 and 1998 investments and participation in the
regional Northwest Energy Efficiency Alliance to be prudent and of benefit to its customers. As
reflected in our transcript referenced Idaho Power Order No. 27877 (Tr. p. 1019) "NEEA'
efforts are directed to market transformation... there is the expectation that through incentives
and the establishment of governmental standards certain energy efficient products, services and
consumer education will become available and, ultimately result in improved energy efficiency.
At p. 10. This Commission does not find it necessary to assess the various programs and
projects of NEE A on an individual project by project basis. Rather we find that it is appropriate
to consider them as a whole.
The Company s underlying Application for Schedule 91 tariff rider approval (Case
No. WWP-99-10) contained representations and commitments regarding interest accrual on
deferred balances and required annual notice to customers. Despite a clear statement in the prior
tariff rider application that the Company intended "to match funding with DSM program costs
ORDER NO. 28097 34-
and to keep the deferred balance as close to zero as possible the Company now states "the
Company has always planned to maintain a surplus of funds" in the account. Tr. p. 654.
It also appears from the record that the Company in administering Schedule 91 DSM
surcharge monies has not been calculating the 10% interest on expended deferral balance
amounts approved in the application. Despite no mention of it in the prior tariff rider application
and no direct testimony submitted in this case, the Company now proposes to offset calculated
interest amounts with "corporate service expense" and "programmatic lease investment." Exh.
, Sch. 2, p. 2. The Company also requests that rather than using the stated 10% interest rate on
DSM deferral balances that the Commission in this case authorize for calculation purposes the
use of a lower 6% interest rate, or a link to the Commission approved interest rate for customer
deposits currently at 5%. Reference IDAPA 31.21.01.106; Tr. p. 134
We find the Company s representations and recommended accounting changes to be
inconsistent with the application approved by this Commission. We accept Staff s interest
calculation on Schedule 91 deferred balances without offset or adjustment. We find that the
appropriate interest rate going forward is the overall return authorized in this Order. Because it
is the stated program intent to keep the current balance as close to zero as possible, we also find
it reasonable to reduce the Schedule 91 energy surcharge rider from Yz% to 1
The Company is reminded that the Triple E Board is an advisory board and has no
power to abrogate Company obligations and requirements pursuant to Commission Orders.
Accordingly, the Company is reminded of its annual obligation to provide customers with DSM
surcharge information.
CONCLUSIONS OF LAW
The Idaho Public Utilities Commission has jurisdiction over this Application and
Avista Corporation dba Avista Utilities Washington Water Power Division, an electric utility,
pursuant to the authority and power granted under Title 61 of the Idaho Code and the
Commission s Rules of Procedure, ID AP A 31.01.01.000 et seq.
This Commission has jurisdiction and authority pursuant to the above identified
statute and rules to authorize and require A vista to reallocate its revenues among the customer
classes, to change its rate components within the customer classes and to address the other issues
in the manner set forth in the text ofthis Order.
ORDER NO. 28097 35-
ORDER
In consideration of the foregoing and as more particularly described above, IT IS
HEREBY ORDERED and the Commission hereby authorizes Avista Corporation dba Avista
Utilities-Washington Water Power Division to increase its revenues by $9 330 000 or
approximately 7.58%. The Company is directed to file amended tariff sheets for rates and
charges in compliance with the terms of this Order. The rate increase that we authorize is for
service rendered on and after August 1 , 1999.
IT IS FURTHER ORDERED that Avista Corporation dba Avista Utilities-
Washington Water Power Division comply with all other directives of the text of this Order.
THIS IS A FINAL ORDER. Any person interested in this Order may petition for
reconsideration within twenty-one (21) days ofthe service date of this Order. Within seven (7)
days after any person has petitioned for reconsideration, any other person may cross-petition for
reconsideration. See Idaho Code 9 61-626.
ORDER NO. 28097 36-
DONE by Order of the Idaho Public Utilities Commission at Boi~e, Idaho, this ~~ZL
day of July 1999.
MARSHA H. SMITH, COMMISSIONER
ATTEST:
~~A-
Myrna J. Walters
Commission Secretary
bls/O:wwpe9811 sw5
ORDER NO. 28097 37-
AViSTA UTILITIES. WASHINGTON WATER POWER DIVISION
PRO FORMA RESULTS
TWELVE MONTHS ENDED DECEMBER 31, 1997
(OOO'S OF DOLLARS)
Column
Re-state State & Increase in Pro Forma atLine I Company Pro Total Federal Tax Pro Forma Revenues &ProposedNo.DESCRIPTION Forma Total Adiustments on Adiustments Total Related Exo Rates
REVENUES
Total General Business $123 029 $123 029 330 $132 359Interdepartmental Sales $63 $63 $63Sales for Resale $47 662 $47 662 . $47 662Total Sales of Electricity $170 754 $170 754 $9,330 5180 064Other Revenue 052 052 57,052Total Electric Revenue 5177 806 $171,806 $9,330 $187,136
EXPENSES
Production and Transmission
Operating Expenses 530 339 (5236)530 103 530,103Purchased Power 553 813 553 813 553 813Depreciation and Amortization 388 (5576)812 812Taxes55.492 55.492 492Total Production & Transmission 599 032 ($812)$98,220 $98,220
Distribution
Operating Expenses 108 (5504)604 604Depreciation007(5309)$4,698 698Taxes060060060Total Distribution 513 175 (5813)$12 362 . $0 $12 362
Customer Accounting 720 $3,720 535 755Customer Service & Information 970 $2,970 $2,970Sales Expenses 5131 $131 $131
Administrative & General
Operating Expenses 516 443 (5610)515 833 522 515 855Depreciation664664664Taxes$44 $44 $44Total Admin. & General 519 171 ($610)$18 561 $22 518 583Total Electric Expenses $138 199 (52 235)$135 964 $56 $136 020
OPERATING INCOME BEFORE FIT & SIT 539607 235 $41 642 $9,274 $51 116
STATE INCOME TAX
State Income Tax Expense 442 5345 533 820 5137 957Amortized Investment Tax Credit (5154)(5154)(5154)Total State Income Tax 442 5191 533 666 $137 803
FEDERAL INCOME TAX
Current Accrual 204 (5174)5771 801 198 999Deferred Income Taxes 248 248 248Net Federal Income Taxes 58.452 (5174)5771 049 198 512 247Amortized Investment Tax Credit (523)(523)(523)Total Federal Income Tax 429 (5174)5771 026 $3,198 $12 224
SETTLEMENT EXCHANGE POWER $4,715 $4,715 $4,715
NET OPERATING INCOME $25,021 218 (5804)$26435 939 $32,374
RATE BASE
PLANT IN SERVICE
Intangible 850 850 850Production$253 904 5253 904 5253 904Transmission$64 372 564 372 564 372Distribution5204248(51 152)5203 096 5203 096General533672533672533672Total Plant in Service 5582 046 (51 152)5580 894 5580 894ACCUMULATED DEPRECIATION 5170 993 ($493)5170 500 5170 500ACCUM. PROVISION FOR AMORTIZATION 616 616 616Total Accum. Depreciation & Amort.5172 609 ($493)5172 116 5172 116GAIN ON SALE OF BUILDING (5940)(5940)(5940)DEFERRED TAXES ($47 963)$671 ($47 292)($47 292)
TOTAL RATE BASE $360 534 512 $360,546 $360 546
332%979%
APPENDIX A
ORDER NO. 28097
Line
No.
AVISTA UTILITIES - WASHINGTON WATER POWER DIVISION
REVENUE REQUIREMENT
TWELVE MONTHS ENDED DECEMBER 31,1997
(OOO'S OF DOLLARS)
Description
Commission
Order
Numbers .
Commission Pro Forma Rate Base $360 546
Commission Overall Rate of Return 979%
Net Operating Income Requirement $32 374
Commission Pro Forma Net Operating Income $26,435 .
Net Operating Income Deficiency 939
Conversion Factor 636520
Additional Revenue Required 330
Current Total General Business Revenues $123 029
Percentage Revenue Increase 58%
CAPITAL STRUCTURE AND WEIGHTED COST OF CAPITAL
Line Composite Rate ofNo.Component Ratio Cost Return
Long-Term Debt 48.030%011 %848%Short-Term Debt 3 958%255%248%Total Debt 51.988%096%
Preferred Securities
Preferred Trust Security 032%113%652%Preferred Stock 556%151%0.208%Total Preferred 10.588%860%
Common Equity 37 424%10.750%4 023%
Total 100%979%
APPENDIX B
ORDER NO. 28097
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AVISTA UTILITIES - WASHINGTON WATER POWER DIVISION
WWP-98-
Present and Commission Ordered Electric Rates (First Year)
Present Rates
First 600 kWhs
Next 700 kWhs
All over 1300 kWhs
Minimum Charge
Present Rates
Basic Charge
Energy Charge
Demand Charge:
20 kW or less
Over 20 kW
Residential Service - Schedule
Commission Ordered Rates181 rt/kWh Basic Charge
945 rt/kWh
591 rt/kWh
$4.
First 600 kWhs
All over 600 kWhs
4.419 rt/kWh
168 rt/kWh
$8.
General Service - Schedule
Commission Ordered Rates
$4.00 Basic Charge $6.
617 rtlkWh Energy Charge 849 rt/kWh
Demand Charge:
no charge 20 kW or less no charge
$3.15/kW Over 20 kW $3.50/kW
Large General Service - Schedule 21Present Rates Commission Ordered RatesEnergy Charge 3,897 rt/kWh Energy Charge 4.134 rt/kWh
Demand Charge:
50 kW or less
Over 50 kW
Primary Voltage Discount
$200.
$2.30/kW
10rt/kW
Demand Charge:
50 kW or less
Over 50 kW
Primary Voltage Discount
$225.
$2.75/kW
20rt/kW
Extra Large General Service - Schedule 25Present Rates Commission Ordered RatesEnergy Charge 2.685 rt/kWh Energy Charge 2.797 rt/kWh
Demand Charge:Demand Charge:
000 kva or less $5,500.000 kva or less 500.
Over 3 000 kva $1.10/kva Over 3 000 kva $2.25/kva
Primary Voltage Discount 10rt/kva Primary Voltage Discount 20rtlkva
Annual Minimum $361 350.Annual Minimum $419 230.
Present Rates
First 85 kWh/kW
Next 80 kWh/kW
All additional kWhs
Rates Exhibit.xls 7/27/99 KDH
Pumping Service - Schedule
Commission Ordered Rates962 rt/kWh Basic Charge
962 rt/kWh
181 rt/kWh
$6.
First 85 kWh/kW
Next 80 kWh/kW
All additional kWhs
870 rt/kWh
870 rt/kWh
702 rt/kWh
APPENDIX D
ORDER NO. 28097