990712_sw.doc

MEMORANDUM

TO: COMMISSIONER HANSEN
COMMISSIONER SMITH
COMMISSIONER KJELLANDER

FROM:

DATE: JULY 6, 1999

RE: CASE NO. WWP-E-98-11 (AVISTA)
GENERAL RATE CASE

On December 18, 1998, the Idaho Public Utilities Commission (Commission) received an Application from The Washington Water Power Company (Water Power; Company; WWP) in Case No. WWP-E-98-11 requesting approval of increased rates and charges for electric service in the state of Idaho. Water Power is a public utility primarily engaged in the generation, transmission and distribution of electric power and the distribution of natural gas. Water Power serves approximately 100,000 customers in northern Idaho in an area which ranges from Grangeville, Idaho in the south to Sandpoint, Idaho in the north. The Company in its Application requested a Commission Order approving revised rates and charges for a proposed effective date of January 22, 1999. The proposed effective date was suspended pending hearing on the Application and further order of the Commission. (Commission Order No. 27852. Reference Idaho Code § 61-622.)
The Company reports that its last general rate case in Idaho was in 1986 (ref. Case No. U-1008-256, Order No. 20905). Since that time, Water Powers overall electric rates in Idaho have been modified with the implementation of a 1.5% surcharge to fund energy efficiency improvements in March 1995 and a Power Cost Adjustment (PCA) mechanism implemented in 1989 that has resulted in several temporary adjustments, both surcharges and rebates.
A public hearing in Case No. WWP-E-98-11 was held in Sandpoint, Idaho on June 8 (09), 1999. The following parties appeared by and through their respective counsel:
Avista Corporation dba Avista Utilities—
Washington Water Power Division David J. 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.

As amended at hearing the overall increase in annual revenue Avista requests for its Idaho electric jurisdiction is $13,456,000, an increase of 10.94%. Reference Exh. No. 26; Exh. 24, Sch. DMF-1 p. 1; Tr. p. 678. The amount of the actual percentage increase varies by class of customer and by usage. The requested revenue change in percentage, in total and by major customer class is as follows:

Residential Schedule 1
General Service Schedule 11
Large General Service Schedule 21
Extra Large General Service Schedule 25
Pumping Service Schedule 31
Lighting Schedules 41-49
Total
$ 7,233,000 15.1%
999,000 6.5%
3,100,000 9.8%
1,670,000 15.5%
175,000 8.6%
180,000 11.9%
$13,456,000 10.9%
It is noted that the Companys proposed rate increase will also affect those customers acquired from PacifiCorp (Clark Fork, Hope, East Hope, Old Town, Priest River and Sandpoint), whose four year rate transition period expired in January 1999 when they were transferred to the Companys comparable rate schedules. Reference Case No. WWP-E-94-1.
The Companys requested revenue increase is predicated on a 9.446% rate of return, including a 12.00% return on equity. The Company states that for its proposed test year 1997, its rate of return in Idaho, on a pro forma basis, was 6.904%, significantly below its authorized rate of return of 10.95%. Water Power 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.
Staff after review of the Company’s filings and audit has calculated a revenue deficiency of $10,234,000 and recommends an 8.32% increase. Reference Exh. No. 118, p. 3. The difference between the Company requested and Staff calculated revenue requirement is $3,222,000.

Potlatch
Potlatch’s Lewiston facility is a special contract customer and is not affected by the present case. Potlatch, however, has three separate facilities that are Schedule 25 customers. Tr. p. 1171.
Potlatch provides testimony and recommendations in three areas.
Avista marketing efforts—specifically the allocation of costs/benefits regarding secondary transactions.

Revenue requirement. Potlatch proposes adjustments regarding depreciation, net power supply, hydro relicensing, amortization of ice storm costs and rate of return.

Cost of Service. Potlatch contends that the Company’s cost-of-service study is flawed and that it departs from prior Commission positions. Potlatch addresses the Company’s classification and allocation of distribution costs, the demand allocators for both generation and 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 paying rates that cover their cost of service.

Secondary Transactions
Potlatch contends that Avista has chosen to enter the secondary transaction market with a vengeance. Tr. p. 1176. Reference Exh. 202.
Operating Revenues Operating Expenses 1996 $944 million
1998 $3.68 billion $758 million
1998 $3.51 billion
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.
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.
Avista’s position, Potlatch states, is that the short-term purchases/sales should be excluded from the 1997 pro forma results because “the majority of the short-term purchase and sales transactions were for speculative purposes” and the risks and benefits associated with these transactions should therefore reside with the shareholders and be excluded from the retail ratemaking process. See Tr. pp. 414, 415.
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 of the 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.
The Company’s solution, Potlatch states, is to substitute power supply models predicated short-term transactions for actual figures. Tr. p. 1189. This, Potlatch contends, puts the model to a use that it was not intended. Tr. p. 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.
Potlatch suggests that Avista 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. A reasonable adjustment to test year pro forma, Potlatch contends, would be to include 90% of actual 97 short-term sales and purchases. Tr. p. 1193. Ratepayers, Potlatch contends, 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). Potlatch recommends a formal rulemaking regarding speculative transactions at the conclusion of this case. Tr. p. 1197.

Revenue Requirement
A. Depreciation Issues
Avista in this case, Potlatch states, proposes to increase general plant depreciation from 6% to 12.24%. Potlatch opposes increasing Avista 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. Potlatch also attempts to compare the depreciation rates of Avista with other utilities and believes that they are comparable except distribution plant. Avista, Potlatch contends, is requesting a related $2.4 million revenue requirement increase. Potlatch proposes to limit the depreciation adjustment to distribution plant, decreasing that amount to $300,000, a decrease of ($2.1 million). Tr. pp. 1203, 1204.

B. Normalized Net Power Costs
Avista in this case proposes utilizing 60 water years (1927-28 to 1987-88) in its power supply model. Tr. p. 1207. 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. p. 1211.

C. Clark Fork Relicensing
Avista proposes approximately $2 million per year for relicensing costs. Potlatch contends that there will occur a mismatch of costs and benefits between present and future ratepayers and that what the Company is proposing is the equivalent of putting construction work in progress CWIP) into rate base. Tr. p. 1212. Furthermore, FERC, Potlatch contends, may or may not relicense the Clark Fork projects. Potlatch recommends that the proposed adjustment be eliminated.

D. 1996 Ice Storm Costs
Avista is proposing to recover approximately $125,000 per year in a rolling six year average related to 1996 ice storm costs. Potlatch contends that these costs were incurred prior to the test year and that what the Company is proposing is retroactive ratemaking. Tr. p. 1214. Potlatch recommends that this amount be eliminated.
E. Rate of Return
Avista has requested an overall rate of return of 9.446%. Tr. p. 1218. Regarding the included 12.0% return on equity requested, Potlatch knows that there has been a dramatic drop in cost of both equity and debt since 1986. Potlatch proposes that a more reasonable range for equity is 10.4 to 10.9%. Tr. p. 1221, Exh. 208. This change, Potlatch contends, would result in a reduction of between $2.368 million to $3.383 million. Tr. p. 1222.
A summary of revenue requirement adjustments by Potlatch is as follows:
Short-term sales/purchases ($3.9 million)
Depreciation rates ($2.1 million)
Number of water years in average ($1.6 million)
Clarkfork relicensing ($1.4 million)
Ice storm ($ .125 million)
ROR ($2.4 million)

3. Cost of Service
Avista proposes to classify and allocate distribution, transmission and generation costs, Potlatch contends, in such a way as to penalize high load factor customers. Avista 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 fair 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. p. 1228.
Regarding demand allocators, Potlatch notes that Avista 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. Exh. 209, Tr. pp. 1233-1236.
The Company in its rebuttal essentially rejects, refutes and disputes (yada, yada, yada) all of Potlatch’s contentions and proposed adjustments.

Rate Base
The difference in Company proposed ($361,185,000) and Staff adjusted ($360,546,000) rate base is the ($639,000) Staff line extension (CIAC) adjustment.

Rate of Return/ Equity Adder
Company proposed Staff proposed ROR 9.446%

ROE 12.0% (Incl. .25% equity adder)

Tr. pp. 213, 214 ROR 9.073%
Range 8.792-9.166%
ROE 11.000% (incl. .25% equity adder)
Range 10.25-11.25
Exh. 122, Sch. 14; Tr. p. 1107
The Company in this case recommends that an equity adder of 25 basis points (translates to approx. $500,000/yr) be added to the equity return of Avista to recognize innovative management and strategic initiatives. See Dukich, Tr. pp. 124-126. Compare IPC-E-94-5, ON 25880. Tr. p. 1127. Staff in agreeing to the equity adder states that it is not necessarily a reward for past exemplary performance but an incentive to continue programs and processes that lead to noted qualities and initiatives—continued betterment of performance is the goal. Avista is making improvements, Staff contends, and deserves recognition for those improvements. Tr. p. 1128. Areas of noted concern that must also be weighed are 1) 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) failure to comply with Customer Information Rules requirement of individual customer notice of rate changes (PCA). Tr. p. 1129. The Company characterizes its omissions as oversights.

Staff Pro Forma Revenue Adjustments
Of the Staff proposed adjustments only three remain unaccepted by the Company. (1) Hydro relicensing costs—Clark Fork Settlement Agreement, (2) CIAC adjustment (line extension), and (3) Injuries And Damages (1996 Ice Storm).

1. Hydro Relicensing Costs—Clark Fork Settlement Agreement
Staff witness Lobb recommends that $860,000 of the $2,018,000 hydro power relicensing expenses (a total system #) be excluded from the pro formed test year. $180,000 of the adjustment is a transpositional error in total Protection, Mitigation and Enhancement (PM&E); the remaining $680,000 is hydro relicensing expense that Staff contends are either one-time expenses or not now “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 adjustment on an Idaho jurisdictional basis translates to a reduction in production and transmission expenses ($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.
Avista in its direct testimony recommends that the Company be allowed to pro form in the O&M expense levels contained in the Clark Fork Settlement Agreement. Staff raises concerns regarding the potential mismatch between recovery and expense associated with the O&M level of Settlement costs authorized. 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 balancing to current Idaho 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.
Staff at hearing indicated that it is not opposed to the concept of a balancing account; however, it is opposed to combining the balancing account with the PCA. Tr. pp. 937, 938. Staff contends that the PCA has a $2.2 million trigger that it believes that the Company could delay or manipulate by simply altering the expenditures for the relicensing account. Staff further notes that the PCA was intended to adjust for power supply expenses, expense variations that occur due to changing water conditions. Including another adjustment of unknown magnitude, Staff contends, would diminish that intent and would be inappropriate. As an alternative, Staff proposes that the Commission approve the relicensing expense in base rates as proposed by Staff with modifications for the bull trout adjustment ($125,000 total Company). Staff recommends that FERC Account 253 be used and that separate subaccounts be used to identify the specific expenses associated with relicensing at or above those costs that are included in base rates. Staff recommends that rather than every year that the costs be looked at every two to three years so they have a chance to balance out. Tr. pp. 937-939.

2. CIAC Adjustment (line extensions)
Staff recommends that $1,178,835 be imputed as CIAC. Staff contends that the amount computed as CIAC should have been collected from new customers added to the Company’s system between 1989 and 1997. Staff contends 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’s annual revenue requirement to be higher than it otherwise should be. Tr. pp. 967, 968. The proposed amount of Staff 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 extensions costs for all the years between 1988 and 1997 escalated at the rate of escalation of the S&P DRI 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 $1,178,835. The Company on rebuttal challenges Staff’s adjustment as based more on assumptions than actual data. Tr. p. 867.
Staff’s proposed adjustment results in a reduction in distribution 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 $1,152,000, 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 recommends that a new line extension case be opened once the general 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 tariff. Tr. p. 875.

3. 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. O. Included within the Company’s rolling six year average is an amount related to the ice storm of 1996. Staff adjustment removes this amount contending that it is out of test year, it is an extraordinary and non-recurring event and does not reflect on going expenses. Tr. p. 1063. As reflected in Staff Exh. 118, Col. I, removal of the ice storm expense results in a reduction in A&G operating expense of $67,001, an 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.

Cost of Service
The basic Cost-of-Service methodology (peak credit method) used by the Company in this case is the same as the COS study filed in Case No. U-1008-256 with two exceptions:
Distribution costs are classified to customer and demand by the Basic Customer Method in the current case, whereas in 1986 the Minimum Distribution Method was used.
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 of other operating expenses or plant which implies a functional allocation based on the components of the 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 by 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 the effects of the changes are detrimental to Residential, General Service and Pumping Classes, and beneficial to 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 of the way toward full Cost of Service (unity). Tr. pp. 1153, 1155. Staff supports the Company’s proposal. A more aggressive move toward Cost of Service in rate design, Staff contends, would produce unacceptably large increases in rates. 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 ROR by class.

Rate Design
Structural Changes
The Company proposes three structural changes to the class rates, two in the residential class and one in the pumping class.
Residential
For the residential class the Company proposes to change from a three-block inverted energy rate structure to a two-block inverted energy rate structure and to move from a customer minimum, which includes 203 kWhs of energy, to a basic charge, which includes no energy.

Pumping
For the pumping class the Company proposes to add a basic charge where there currently is none.
Tr. p. 1156
Staff accepts the proposed structural changes. Tr. p. 1157. Regarding the basic charge, however, Staff recommends a $4.00 basic charge as opposed to the Company proposed $5.50 basic charge for residential customers.
Present and Proposed Electric Rates
Avista Exh. 26, p. 3.
Staff Exh. 127.
DSM/Conservation
Avista’s Demand Side Management (DSM) programs are described as in its electric Tariff Schedule 90 and are financed by a 1 ½ % energy surcharge (Schedule 91). The Company’s estimated energy savings and costs for these programs are set out in Company revised Exhibit Nos. 12 and 13. Tr. p. 1007.
Staff notes that customers, as a whole, still benefit from cost effective DSM programs, albeit with program participants receiving most of the benefits. Staff 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.
The Company has requested and Staff recommends that the Commission find that the Company DSM expenditures through December 1998 have been prudently incurred. ($4,461,775 DSM expenditures 3/95-12/98, revised Exh. 12). Tr. pp. 1008, 1011. Staff in this case quantifies the balance of DSM revenues beyond expenses incurred by Avista 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 $868,449 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 envisioned that such a large deferred balance would be carried. Reference Company Application Case No. WWP-E-94-10/WWP-G-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 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 the amount of interest that should be added to the end of year 1998 DSM balance to be $189,000. 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. Staff therefore recommends that the DSM tariff rider energy surcharge be reduced in this case by one-third to 1.0%. Tr. p. 101
As per its underlying Application in Case No. WWP-E-94-10 and related Commission Order, Avista 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-E-94-10. Tr. p. 1011.
Staff also recommends a change in how Avista 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 Northwest Energy Efficiency Alliance (NEEA) will evaluate its programs that are funded in part, from Avista’s surcharges. Tr. pp. 1015, 1016. Avista, 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 programs and suggests modifying or dropping those that show only marginal benefit/cost ratios. Tr. pp. 1015, 1016.
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 is the Company’s expenditures to NEEA ($155,000 for 1997 and $310,000 for 1998, or $465,000 total). Tr. pp. 1018, 1019.
Avista 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. Tr. p. 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 proposed and approved in the DSM Tariff Rider Application that the amount be 6%, the present interest on Idaho customer deposits, and that the amount (despite no mention of offset in the underlying Tariff Rider Application) 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. DMF-2, p. 2.

Motion to Dismiss
It was disclosed at the Sandpoint hearing that Avista had entered into an agreement to sell its 15% interest in the Centralia Coal-Fired Generating Station to Trans Alta Corporation. Tr. p. 49. Centralia represents approximately 200 megawatts of generating capacity in Avista’s resource stack. 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 proposes using a 1997 test year. As part of its pro forma adjustments to test year, however, the Company for power supply expense proposes using a projected June 1999 – July 2000 time period. Tr. p. 50. Centralia generation is included in the Company’s power supply model.
After some initial questions of Avista’s Board Chairman and Chief Executive Officer regarding Centralia, Potlatch at hearing moved to dismiss the Company’s Application without prejudice to refiling at such later time when the Centralia matter is settled. Tr. p. 51.
Potlatch contends that if the sale of Avista’s interest in Centralia is approved, it will result in a reduction in the Company’s rate base, a related power supply expense adjustment and a distribution back to ratepayers (depreciation). Tr. p. 52. Idaho’s allocated revenue deficiency in this case as filed by the Company, Potlatch states, is roughly only nine million dollars before it is grossed up for taxes. Any combination of reduction in power supply, reduction in rate base or rebates or credits to customers for depreciation previously paid that totals nine million dollars, Potlatch contends, 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 contending that substantial uncertainties as to timing, regulatory approval, and related conditions exist and that the results of sale (if concluded) including replacement power are neither known nor measurable. Tr. pp. 55, 56.
We find:
The Commission has considered Potlatch’s Motion to Dismiss and the arguments of the parties. Although the possible ramifications of the Centralia sale have been identified by Potlatch, it is only with a broad brush. We agree with Avista that there are presently too many unknowns, and too many uncertainties regarding the sale. We find that the facts presented in this case regarding the Centralia sale neither support nor justify dismissal of the Company’s Application.
It is our understanding that there have been no regulatory filings regarding the proposed sale. We note that the Company’s interest in Centralia is part of its rate base in Idaho on which it receives a return on investment. We therefore put Avista on notice that we expect a filing with this Commission addressing the proposed sale, its ramifications, rate consequences and the Company’s proposed treatment of same.

Depreciation
We find:
The Commission has reviewed and considered the Company’s proposed increase in depreciation rates and expense, its related depreciation study, Staff’s proposed adjustments to depreciation rates and expense, Potlatch’s arguments regarding depreciation and the Company’s rebuttal.
The Company’s depreciation rates were last changed in 1990. The 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 disagree with Potlatch’s contention that a change is necessary. We find the underlying depreciation methodology utilized by the Company to be sound. The Company accepts Staff’s proposed depreciation adjustments, which we also find to be reasonable. Tr. p. 133.
The depreciation rates and result in 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. In light of the testimony regarding Centralia and its proposed sale of same 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.
Based on its Depreciation Study, Avista proposes to change depreciation rates as follows:
Function Electric Group Existing Percentage Recommended Percentage
Steam production plant 3.12 3.38
Hydraulic production plant 1.04 1.58
Other production plant 4.18 2.36
Transmission plant 2.41 2.88
Distribution plant 2.27 2.45
General plant 6.00 12.24

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 $1,573,000 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 ($383,000) and to deferred income tax ($268,000). Tr. p. 1035. The level 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 2.9% ($7 million total system or about 19%); Staff’s recommended increase in overall composite depreciation rates is from 2.46% to 2.85% ($6 million total system or about 15.7%). Tr. p. 1037 – See also discussion of line extension adjustment and related depreciation adjustment. Tr. p. 1038.
[**Note: update schedule transcript page 971 re: revenue requirement by group and percentage.**]

Water Years
Potlatch contends that shorter periods e.g., 50-year, 40-year, 30-year and 20-year averages all produce lower test year net power supply expense estimates than Avista’s 60-year average. Tr. p. 1207; Exh. 206. Similarly Potlatch contends that the 60-year average is inconsistent with longer periods. Tr. p. 1208.
Avista on rebuttal notes that on the current case as well as in previous cases the Company has consistently used the full water record from the Regional Hydro Regulation Studies (Northwest Power Pool) for the normalization of power supply costs. The Company specifically notes that water record data is not available for the Clark Fork River, where the majority of the Company’s hydroelectric generation resides prior to 1928. Tr. p. 428. Absent incredible and conclusive studies demonstrating and identify trend or cycle in water record data, which the Company contends has not been presented, Avista contends that the use of the maximum amount of reliable data will produce the best estimate. Tr. pp. 417-419. The Company charges Potlatch with “selective choosing” water records to manipulate normalized power supply cost. Tr. p. 425.
We find:
The Commission has reviewed and considered Potlatch’s objection to the Company’s use and 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 capture the more recent 1987-88 to 1997-98 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 of the 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 reasonable to use the full 60-years of data as opposed to a selectively shorter period.

Relicensing Costs
The Company is attempting to relicense two of its hydro generation facilities at Cabinet Gorge and Noxen Rapids (Clark Fork projects). Without renewal 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 in March of 1999, two years before the present licenses expires. Early implementation of measures, the Company contends, became the Company’s greatest point of leverage in negotiating an agreement among parties at what it contends is a much lower cost to the Company than certain agencies have the unilateral authority to approve. Tr. pp. 621, 622. Pursuant to settlement agreement the Company estimates that on a system basis in will incur incremental hydropower relicensing operation and maintenance (O&M) expense in the levelized amount of $2,018,000. Tr. p. 623. (See amended level of expense page 644.) The Company proposes in this case to proform in the O&M expense levels contained in the settlement agreement. Capital expenditures associated with the settlement are not a component of the Company’s filing. Tr. p. 644.
We find:
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 applaud the Company for its relicensing efforts. While Potlatch would have this Commission liken the prelicense expenditures to QUIP (Tr. p. 1212) we do not believe the comparison is valid. The settlement agreement benefits to the Company and its customers in agreeing to early implementation 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 agree with Staff that to avoid questions related to timing of expenditures the balancing account for Clark Fork settlement agreement O&M should be maintained and operated separate from the PCA. Interest is to accrue in the same manner as it does in the Company’s PCA account. The level of O&M related settlement costs that we find reasonable to authorize is the level proposed by Staff, ________, a level based more on actual projected expense than the cap amounts recommended by the Company.

Ice Storm of 96
We find:
Staff and Potlatch’s proposal to remove Ice Storm related expense from this case to be reasonable. While we make no judgment regarding the Company’s uninsured expenditures, we do find that this is an extraordinary nonrecurring expense and cannot be allowed. Reference the Company’s own publication “Ice Storm 96 Overview” — where in it 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. p. 693. The Company on rebuttal 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 certainty how much those expenses will be. In this regard we find the reference to our treatment of Idaho Power’s specific high clean up costs to be on point. Tr. p. 682-683; reference Order No. 25880. The Company’s proposal to recover its uninsured costs of 1986 Ice Storm damage through rates we find would violate the principle that rates must be prospective and may not be used to recoup past losses. The prescription against retroactive ratemaking that means Ice Storm costs expended by the Company in the past are not recoverable through future rates unless they 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 to future recovery. It did neither. Accordingly, we cannot in this case authorize the requested recovery of this expense through and including such expense in any six-year historical average.

CIAC Adjustment (Line Extension)
We find:
Staff in this case recommends that the Company’s line extension tariffs be more closely examined in that a more detailed cost analysis be performed. The Company agrees. Tr. p. 875. What troubles the Commission is that line extension cost information was not available and that Staff was required to make assumptions. What troubles us is the Company’s failure to maintain and provide this information and analysis as specifically required by prior Commission Order No. 23051. See footnote 1 above. What further troubles us is that this is the same company that was fined a civil penalty of $75,000 in 1994 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-E-94-9, Order No. 25838.
We accept Staff’s proposed adjustment and method of calculating same. It is the Company’s failure to provide information in accordance with prior Commission Order that makes the use of assumptions in lieu of actual data reasonable. The Company’s disregard of Commission Orders is inexcusable. Reference Idaho Code § 61-706 Penalty For Violations; Idaho Code § 61-707 Continuing Violation.

DSM
We find:
At a time when many electrics were discontinuing investment in DSM Avista proposed a non-bypassable distribution charge to fund energy efficiency. This Commission continues to be supportive of the Company’s efforts and investments in conservation. Prudent conservation continues to make sense from both a societal and economic prospective. 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 costs 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 an estimate of baseline activity that would occur without the DSM program. We encourage the Triple E Board to pursue development of such a baseline estimate for future program offerings.
We also find the Company’s 1997 and 1998 investments and involvement in the Regional Northwest Efficiency Alliance to be prudent and of worthwhile benefit to its customers. We do not find it necessary to assess the various programs and projects of NEEA on an individual project by project basis. Rather we find that it is appropriate to consider them as a whole. As reflected in our reference Order No. 27877 (Tr. p. 1019) “NEEA’s 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.
Staff directs the Commission’s attention in this case to the Company’s underlying Application for Schedule 91 tariff rider approval (Case No. WWP-E-99-10) and related Company representations and commitments regarding interest accrual on deferred balances and required annual notice to customers. It appears from the record that the Company in administering Schedule 91 DSM surcharge monies has not been calculating the required 10% interest on expended deferral balance amounts. Despite no mention of same in its tariff rider application, the Company would now have this Commission offset calculated interest amounts with “corporate service expense” and “programmatic lease investment.” 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 6% interest rate, the present Commission approved interest rate for customer deposits.
Despite a clear statement in the underlying tariff rider application that the Company intended “to match funding with DSM program costs and to keep the deferred balance 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.
We find the Company’s representations and recommended accounting changes to be not only blatantly self-serving but also contrary to the interests of its customers and a breach good faith. We accept Staff’s interest calculation on Schedule 91 deferred balances without offset. Because it is the stated program intent to keep the current balance as close to zero as possible, we further find it reasonable to reflect the Company’s proposed change in interest rate. Because of historic balances maintained in account we also find it reasonable to reduce the Schedule 91 energy surcharge from one and one half percent to one percent.
The Company is also 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.

vld/M:WWP-E-98-11_sw4
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).

MEMORANDUM 17