28297.doc

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

IN THE MATTER OF APPLICATION OF AVISTA CORPORATION FOR AUTHORITY TO SELL ITS INTEREST IN THE COAL-FIRED CENTRALIA POWER PLANT. )
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) CASE NO. AVU-E-99-6

ORDER NO. 28297

On August 10, 1999, Avista Corporation dba Avista Utilities — Washington Water Power Division (Avista) filed an Application with the Idaho Public Utilities Commission regarding the proposed sale by the Company of its 15% ownership interest in the coal-fired Centralia Power Plant.
In the Company’s recently completed general rate case, the Commission made the following findings regarding Centralia:
It is the Commission’s understanding that there have as yet been no regulatory filings regarding the proposed sale. Although raised at hearing, the Commission reserves judgment as to the applicability of Idaho Code § 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 Avista on notice that prior to any transfer of its ownership interest in Centralia we expect a filing by Avista with this Commission addressing the proposed sale, its ramifications, rate consequences and the Company’s proposed treatment of same.

Order No. 28097, Case No. WWP-E-98-11

Avista proposes to sell its 15% interest in the Centralia Power Plant to TECWA Power, Inc. (TECWA Power), a Washington corporation and a wholly-owned subsidiary of TransAlta Corporation, a Canadian energy corporation. TECWA Power has agreed to buy the 1340 megawatt coal-fired Centralia Power Plant for $452,598,000. The other seven co-owners of the power plant and their ownership shares are: PacifiCorp 47.5%, City of Seattle 8.0%, City of Tacoma 8.0%, Snohomish County PUD 8.0%, Puget Sound Energy 7.0%, Grays Harbor County PUD 4.0%, and Portland General Electric (PGE) 2.5%.
As reflected in the Application and by way of background regarding the sale, the Company relates that the Centralia owner’s agreement allows any co-owner of the power plant to veto proposed capital expenditures. Continued operation of the Centralia Power Plant requires the installation of sulfur dioxide scrubbers and low nitrogen burners to meet emission standards. PGE, as well as some other co-owners, vetoed the proposed expenditures. Closure of the plant, the Company contends, would result in mine closure costs, mine reclamation costs and plant dismantling costs. In October 1998, the co-owners put the Centralia Power Plant up for auction. Trans Alta/TECWA Power was selected as the purchaser.
To facilitate the sale to TECWA Power and to begin the process of unifying ownership of the plant so as to more effectively deal with continued operation of the plant, Avista on May 5, 1999, agreed to purchase PGE’s 2.5% interest in Centralia. In addition, Avista notes that it has entered into an agreement with Snohomish County PUD to purchase its 8% share of Centralia in the event the sale to TECWA Power does not close. Should the sale to TECWA Power not close Avista will own a 25.5% (15% original, plus 2.5% PGE, plus 8% Snohomish PUD) interest in the power plant.
The Company requested that its Application in Case No. AVU-E-99-6 be processed pursuant to Modified Procedure, i.e., by written submission rather than by hearing. Reference Commission Rules of Procedure, IDAPA 31.01.01.201-204. On September 7, 1999, the Commission issued a Notice of Application and established a September 17 Deadline for Intervention. The Commission also solicited comment on the Company’s proposal to process its Application pursuant to Modified Procedure. The deadline for filing written comments regarding the Company’s proposed use of Modified Procedure was September 30, 1999. Written comments were filed by Potlatch Corporation and Commission Staff. Based on its preliminary review, Staff supported the Company’s request for Modified Procedure. It was Potlatch’s contention that Modified Procedure was not appropriate. The Commission determined that Modified Procedure was inappropriate and set the matter for hearing.
Public hearing in this case was held on January 19, 2000, in Boise, Idaho. The following parties appeared by and through their respective counsel:

Avista
Potlatch
Commission Staff Gary A. Dahlke, Esq.
Conley Ward, Esq.
Scott Woodbury, Esq.
The parties’ positions can be summarized as follows:
Avista
Avista requests Commission approval of the sale of its 15% interest in Centralia to TECWA. To the extent that approval is required, the Company also requests approval of its purchase and sale to TECWA of PGE’s 2.5% in Centralia. Tr. pp. 3-5, 13.
The Company, for the following quantitative and qualitative reasons, contends that the Centralia sale is in the “public interest”:
Eliminates uncertainties re: mine reclamation costs
Will enable the Company to conduct resource optimization strategies more independently
Will reduce power costs to customers by approximately $7.7 million on a net present value basis over the next 20 years—i.e., “no harm”
TECWA will complete installation of Centralia emission control equipment
Region will continue to benefit from the 1340 megawatt resource
Centralia plant and mine will continue to offer employment.
Tr. p. 15.
As reflected in the Application, the purchase price of the Centralia plant is $452,598,000. This includes a reduction for employee benefit obligations of $2.1 million. Proceeds are further reduced for reclamation expense accruals of $57.4 million. Tr. pp. 131, 132. Avista’s 15% share is $68,204,700, with reductions of $315,000 for employee benefit obligations and $8.61 million for reclamation expense accruals. Exhibit 7; Tr. pp. 42, 131, 132. The after tax gain on the sale (dollar amount of book gain on sale) related to Avista’s 15% interest is $29.6 million. Tr. pp. 17, 75, 133. The actual numbers are subject to adjustment for supply inventory, coal inventory, plant additions subsequent to May 31, 1999, emission control equipment installed, depreciation and PacifiCorp’s actual break even price for the mine. Tr. pp. 42, 132, 133.

Replacement Power—Economic Benefit Analysis
The projected cost of continued operation of Centralia under its current ownership is estimated by Avista to be $26.45/MWh in year 2000 increasing to $35.50/MWh by year 2020. Tr. p. 49; Exh. 1. The projected cost includes the cost of scrubbers and other required capital expenditures. Over the short-term (1- 3 yrs.) the Company plans to satisfy replacement power requirements for the loss of Centralia with short-term market purchases. The Company estimates the price of firm power at mid-Columbia with a monthly shape similar to Centralia at $25-30/MWh. Tr. pp. 49-50. Actual replacement power cost was not disclosed at hearing. Tr. pp. 51, 65, 66, 162. The Company acknowledges that there is some loss of resource flexibility in replacing Centralia, a dispatchable plant, with market purchases, which are not dispatchable. Tr. p. 51. Over the long-term, the Company projects that replacement power may be met with purchases, new generation facilities and/or demand side options. Tr. p. 50. No decision has been made. Tr. p. 31.
Based on its forecasting and present value analysis, the Company projects that the near-term cost replacement power will be lower than the total cost of operating Centralia. Tr. p. 51. The projected cross over point when total Centralia costs are expected to be close to market rates is year 2010. Tr. p. 52.
Based on total cost of the Centralia plant and a medium case projection of replacement power, the Company estimates the 20-year present value benefit of replacement power to be $7.7 million. Tr. p. 53. The Company admits that projections of costs and prices beyond ten years are fraught with uncertainty and highly speculative. Tr. pp. 60-62, 69. The Company admits that no one can definitively determine that the risks of selling outweigh the risks of keeping the plant. There is uncertainty, but the Company states there is a symmetry to the uncertainty on both sides—the projected benefits could be either better or worse than estimated. Tr. pp. 59, 67, 68. It is certainly possible, the Company admits, that the projected $7.7 million benefit could be a $7.7 million loss. Tr. p. 68. For at least the next ten years, however, the Company projects that its customers will either benefit or be held harmless for the sale of the Centralia plant. Tr. pp. 60, 62. In the near term the Company speaks with more certainty projecting that the customers “will not be harmed.” Tr. p. 62.

Allocation of Book Gain
It is the Company’s recommendation that it be permitted to retain all of the $29.6 million after tax gain related to the Centralia sale. Tr. pp. 77, 87, 131. This book gain, it contends, represents additional value over and above the “no harm” customer standard. Tr. pp. 75, 76. The gain on the sale of Centralia, the Company contends, represents economic value over and above the book value of the asset and the amount rate based. Customers have not been charged a return on this economic value (the gain), nor the Company argues, have they paid depreciation based on this economic value. Tr. p. 103.
Relying on the Company’s economic analysis—$7.7 million estimated net present value of cost savings to customers over 20-years—to justify its retention of the “book gain”, the Company urges the Commission to view its request in “historical context”. Tr. p. 77. The Commission, it states, should consider whether the transaction strikes a balance between the interests of ratepayers and shareholders that is fair and equitable and that preserves affordable service. Tr. pp. 78, 89-91, 93.
Regarding fairness, the Company advances the notion that the benefit of the gain should follow the risk of possible loss. It is equitable, the Company contends, that if shareholders take risks, that the risk should result in occasional gains, not just exclusively losses. Tr. p. 79. The Company goes on to discuss actual versus authorized rates of return (Exh. 3; Tr. p. 79), low residential rates (Exh. 4; Tr. p. 80), high quality customer service (Tr. p. 81), and major write-offs (Skagit, WNP-3, Kettle Falls, Creston, Meyers Falls) (Exh. 5; Tr. pp. 81, 94, 95). The Company states that it is not contending that the Commission was wrong in applying “prudence” or “used and useful” standards in its regulation of Avista—but that the Company is simply requesting from a shareholder perspective there be some balancing of unexpected losses with unexpected gains. Tr. pp. 83, 84, 86, 93, 99.
At a minimum, Avista contends that its shareholders should be no worse off than under the Centralia-related depreciation-based proposal of PacifiCorp (PAC-E-99-2). Share-holders should be allowed to retain the portion of the gain that is proportional to the undepreciated amount of Centralia investment. Tr. pp. 87, 135. The remaining portion, Avista proposes, would go to ratepayers in the form of an offset: (1) 1996 ice storm damage, (2) remaining transition obligation for post retirement, health care & life insurance benefits, (3) PURPA contract buy-out costs and (4) NezPerce lawsuit settlement. Tr. pp. 136-139, 186, 187—the last three items being currently amortized in rates; and the first being specifically disallowed in the last general rate case as out-of-time and “extraordinary and non-recurring.” Tr. pp. 234-237. Applying the depreciation method the Company calculates the customer percentage of gain at 69.70% (the ratio of accumulated depreciation to gross plant). The customers’ share of after tax gain would be $20,635,000 on a system basis. Pursuant to the Idaho jurisdiction allocation formula (production/transmission), Idaho customers receive 33.01% with the calculated share of gain or approximately $6,800,000. Tr. p. 135.
If the Commission were to allocate a portion of the gain to customers using the depreciation method, accept the proposed offsets, and determine that a rate adjustment is appropriate for the offsets, the Company calculates that the reduction in Idaho electric annual revenue required would be approximately $816,000, or 0.681%. Tr. pp. 148, 164, 165. The Company recommends that any rate reduction be spread to customer classes, excluding Potlatch, on a uniform percentage basis. Tr. p. 157.
Potlatch is excluded from the sharing of any gain because, the Company contends, it is a special contract customer. The rates for Potlatch are not entirely based on cost of service ratemaking principles. Tr. pp. 177, 178, 191, 192. Potlatch is not subject to price adjustments (either increases or decreases), is exempted from PCA rebates and surcharges, is exempted from the DSM tariff rider, and was exempted from the WWP-E-98-11 general rate increase. Tr. p. 158. Price adjustments for Potlatch are identified in its contract. Tr. p. 180.
The Company in this proceeding is not proposing a rate base adjustment for removal of Centralia. No reliable adjustment, the Company contends, can be made. The sale, the Company argues, has not occurred and the cost of replacement power is unknown, creating a great deal of uncertainty. Tr. pp. 160-162.

Potlatch
Potlatch in its testimony addresses the Company’s proposal to retain the book gain and the Company’s related contentions regarding the relative contribution of shareholders and customers and assumption of risk. The regulatory obligation of customers, Potlatch contends, facilitates the Company’s ability to secure attractive financing, both in terms of the price of debt and the amount of debt leveraging. Tr. p. 200. Once an asset is placed in rate base, regulation in Idaho, Potlatch states, provides for both the return on (ROR) and return of (depreciation) shareholder investment. Tr. pp. 200-201. In legal terms, Potlatch contends, the ratepayers through depreciation have acquired an “equitable ownership interest” in Centralia.
Potlatch challenges the points raised by Avista to support the Company’s proposed allocation of 100% of book gain to shareholders. Tr. p. 202. Regarding historic rate of return, Potlatch contends that the Company presents only one side of the equation, neglecting revenue and expense item offsets to book results (Tr. p. 204) and the declining cost of utility capital (Tr. p. 205). Results below authorized rate of return, Potlatch concludes, are not “ipso facto” unreasonable or confiscatory. Tr. p. 208.
Regarding the Company’s low rates, Potlatch states that Avista attempts to take credit for what is the dominant characteristic of this region’s electric utility industry—low cost hydroelectric generation. Tr. p. 211. Rate levels in and of themselves, Potlatch states, tell us little or nothing about management efficiency. In the absence of evidence to the contrary, Potlatch assumes that Avista is capable and efficient. Tr. p. 211.
Regarding shareholder-ratepayer risk and related benefits, the utility status as a regulated monopoly, Potlatch contends, imposes a unique risk-benefit relationship between shareholders and ratepayers. Regulation places a floor on shareholders’ downside risk and a ceiling on their upside potential. Tr. pp. 214-218. One of the recognized limitations, Potlatch contends, is that ratepayers should not be forced to pay for investments that are not prudently acquired or “used and useful.” Tr. p. 218. Shareholders, Potlatch notes, ordinarily receive the benefit of cost savings between rate cases such as ability to refinance debt, etc. Tr. p. 224. In the instance of Avista, the Company, Potlatch notes, was 13 years between its two most recent rate cases.
Potlatch contends that the customer contribution to Centralia in this case is understated by approximately $4 million, the amount of accumulated deferred income taxes. (Exh. 7, p. 2, Tr. pp. 230-234.) Taking such into account, Potlatch states, increases the customer ratio of investment in gross plant from 69.70% to 76.63%, increasing the customers’ share of after tax gain from $20,635,000 to $22,686,697 and Idaho jurisdictional share from $6,800,000 to $7,488,879. Tr. p. 234.
Avista disagrees with Potlatch’s deferred tax argument. The 1981 Tax Reduction Act mandated deferred accounting for federal income taxes for property additions beginning in 1981 and beyond. Plant existing prior to 1981 using the old flow-through method continued to be under the flow-through method. Tr. p. 172. Avista contends that because of flow-through treatment of tax benefits for plant additions made prior to 1981, customers have received a reduction in rates for the flow-through of those tax benefits amounting to about 93.9% of the total tax depreciation. Tr. pp. 167, 168. Tax depreciation (a number including both normalization and flow-through) exceeded book depreciation, and the tax effect (benefit) of that, the Company maintains, was flowed through to customers and resulted in rates being lower than what they would have been if the tax deduction was based on book depreciation. Tr. pp. 169, 174, 175.
Potlatch rejects the Company’s offset proposal regarding the customers’ share of gain—recommending instead that there be a distribution to all retail customers, including Potlatch, on a simple allocation based on annual energy consumption. The customers’ share of gain is a return of capital that Potlatch contends should be accomplished as quickly as possible. Tr. p. 239.

Staff
Staff in its testimony details accounting rules and regulations for the treatment of gain on the sale of a utility asset setting out applicable sections from the Federal Energy Regulatory Commission (FERC) Uniform System of Accounts prescribed for public utilities. Staff also summarizes prior Commission ordered treatments of related gains or losses. Tr. pp. 253, 255-261.
Staff concurs with the Company’s calculation of regulatory gain on the sale of the Centralia facility and agrees that the customer portion of the regulatory gain for Idaho, pending final sale and adjustment, is $6,811,625. Tr. pp. 261-262. Staff contends that the “depreciation method” (ratio of depreciated plant to total plant) is the appropriate method to determine the customer portion of gain. Tr. p. 262.
Citing Boise Water Corp v. IPUC (99 Idaho 158, 578 P.2d 1089 (1978)) Staff contends that the ratepayers’ payment of depreciation expense on property other than real property establishes a right to the gain on the sale of an asset. Tr. p. 263. Avista on rebuttal attempts to distinguish the Boise Water case, concluding that the Court merely found that customers have an equitable interest and cannot, by law, be excluded from the potential of receiving a portion of the gain—i.e., customers have the right to have a place at the table, as do shareholders, but neither has a legal right, a priori, to any specific portion of the gain. Tr. pp. 99-102.
Staff rejects the Company’s proposed use of offsets regarding the Idaho jurisdiction customers’ portion of gain. Tr. pp. 264-266. Staff recommends that the “customer gain” be credited to Account 254.xx Other Regulatory Liabilities—Centralia sale gain. The unamortized amount in this account would be deducted from rate base, thereby reducing rate base by the gain amount. Staff recommends that current rates be reduced to reflect the current revenue requirement reduction associated with the lower rate base. Staff recommends that Account 254 be amortized over eight years and that current rates be reduced to reflect the yearly amortization expense. Tr. p. 267.
The economic analysis provided by Avista, Staff states, compares the future cost, on a net present value basis, of operating Centralia to the future cost of selling Centralia and replacing the generation with market purchases. The levelized cost of Centralia over the next 20 years is projected by the Company to be $32/MWh while the levelized replacement cost over the same period is projected to be $31.37/MWh. Tr. p. 295. Because of uncertainty in critical assumptions (e.g., coal escalation rates; replacement alternative, etc.), Staff contends that the Company’s quantitative long-term economic analysis is unreliable and that it neither justifies nor precludes the transaction. Tr. pp. 297, 298. A small change in just a single critical assumption, Staff states, can turn a projected expense reduction into an expense increase. Tr. p. 296. Absent a clear economic reason for the sale, Staff concludes that the justification must be based on qualitative factors, e.g., elimination of uncertainty related to reclamation cost risk; elimination of uncertainty associated with multiple project owners—and must be coupled with an equitable distribution of the gain. Tr. pp. 292, 301. Staff believes that the decision in this case amounts to an exercise of business judgment and recommends that the sale be allowed to proceed. Tr. pp. 293, 301.
Staff contends that Centralia should not be removed from the Company’s regulatory rate base (with related rate adjustment) until a replacement alternative is known. Tr. p. 272. The equation, it states, needs to be balanced. Centralia provides 201 MW or approximately 9% of the peak capacity for a system that according to the Company’s 1997 Integrated Resource Plan has little or no peak reserves until wholesale contracts begin to expire in 2001. Tr. p. 294. Allowing the power model to replace Centralia with non-firm spot market purchases, Staff contends, ignores the capacity that is also lost. Tr. p. 306. Staff analysis projects the revenue requirement for Centralia replacement alternatives to be higher in the future than the Centralia revenue requirement presently included in rates. Projections of replacement power costs, Staff contends, are not certainties and provide no basis for departing from test year data. Tr. p. 293.
A reduction in rate base and an associated revenue requirement reduction that can be immediately reflected in current rates, Staff contends, will give customers the full and immediate benefit of the gain in a simple and efficient manner. The total revenue requirement reduction calculated by Staff is $1,579,131. Revised Exh. 104, line 13; Tr. pp. 268, 269. The revenue requirement reduction from the gain represents 1.318% of the total Idaho jurisdictional revenue requirement (WWP-E-98-11). Revised Exh. 104; Tr. p. 302. Staff recommends that the revenue requirement for all customers, excluding special contracts, be decreased by a uniform 1.318%. Tr. p. 302.

COMMISSION FINDINGS
The Commission has reviewed and considered the filings of record, testimony and exhibits in this case. We have also considered the Company’s most recent Integrated Resource Plan (IRP), its capacity reserve margin and the effect of the sale on the Company’s power supply.
The Commission notes that the Company in this case also requested a Commission determination regarding classification of its Centralia generation facility upon sale as an “eligible facility” for purpose of subsequent operation by an exempt wholesale generator (EWG). This matter was handled by separate Notice issued August 31, 1999, and was not the subject of further comment or testimony in this proceeding. The Commission’s Order No. 28186 regarding “eligible facility” status was issued on October 26, 1999.
Avista requests Commission approval of the sale of the Company’s 15% in the Centralia steam generating plant. The Company also seeks approval of a related transaction, its purchase and sale of PGE’s 2.5% interest in Centralia. In support of the sale transaction, the Company advances both quantitative and qualitative reasons. We agree with Staff’s observations regarding the sensitivity of the Company’s economic analysis to small changes in critical assumptions. All parties including the Commission recognize the vagaries in long-term forecasting. In this case the Company frankly admits that its projected $7.7 million net present value benefit for customers could just as easily be a $7.7 million loss. Nonetheless, it is the Company’s contention that its customers will suffer “no harm” resulting from the sale. The Company’s decision to sell in this case was the result of its assessment of operational constraints, of future risk and cost and an attempt to minimize that risk. Staff has characterized it as an exercise of business judgment. We agree. Based on our review of the record and transcript in this case we find no compelling reason to disapprove the proposed sale by the Company of its interest in the Centralia generating plant. We accordingly find it reasonable to approve the sale.
The Commission also finds no reason to object to the Company’s purchase and sale treatment of PGE’s 2.5% interest in Centralia. As the Company frames its argument – the PGE plant was purchased by Avista shareholders and will be sold by the shareholders. The Company’s customers are not paying for this purchase, are not at risk and have no equitable interest in the related gain. We agree.
The Company in this case proposes, as its primary position, to keep all of the $29.6 million gain related to the sale of Centralia. We find no equity or fairness in its argument. We find the projected future ratepayer benefits from this sale to be uncertain and speculative. The only certainty is the gain in hand.
We find the depreciation reserve methodology alternately proposed by the Company to be a reasonable method for distribution of gain associated with the sale of the Centralia plant. We find Potlatch’s deferred tax argument to be unpersuasive and the Company’s rebuttal argument regarding same to be sound. Under the depreciation reserve method (the ratio of accumulated depreciation to gross plant) Idaho customers will receive 69.70% of the gain and shareholders the remaining 30.30% of the gain. The Idaho jurisdictional share of the Centralia asset is 33.01%. The Idaho customers’ calculated portion of gain is $6,811,625 (subject to adjustment at closing).
The Potlatch-Lewiston facility is a special contract customer and its rates are determined within the four corners of its service contract. We find that the Company in this case presents a persuasive argument for denying Potlatch any share of the customer portion of the Centralia gain.
The Company proposes to offset the customer’s portion of the Centralia gain. The effect of the Company’s proposal would be to mask the benefit to customers, provide accelerated amortization for three items already in rates, and recover the cost of an additional item previously rejected as an untimely request. We reject the Company’s proposal. We find the gain should be allocated to customers in the manner proposed by Staff. Reference Exhibit 104 Revised. Customer gain should be credited to Account 254.xx – Other Regulatory Liabilities – Centralia Sale Gain. The unamortized amount in this account is to be deducted from the rate base, thereby reducing rate base by the gain amount. Account 254 is to be amortized over eight years. Current rates are to be reduced to reflect the revenue requirement reduction ($1,579,131 or 1.318%) associated with the rate base reduction and amortization associated with the gain allocated to customers. Current rates for Idaho tariff customers are to be reduced by a uniform 1.318%.
Although Potlatch proposes that we remove Centralia from rate base now and make related adjustments to the revenue requirement and rates, we find the Company and Staff arguments against this change to be persuasive. We will address the regulatory and rate base adjustments for Centralia in the Company’s next general rate case when removal of the resource can be viewed in context with all related revenue, expense, supply and operational ramifications.
CONCLUSIONS OF LAW
The Idaho Public Utilities Commission has jurisdiction over the Application of Avista Corporation dba Avista Utilities – Washington Water Power Division, an electric utility, and the issues presented in this case pursuant to the authority and power granted under Title 61 of the Idaho Code and the Commission’s Rules of Procedure, IDAPA 31.0.10.000 et seq.
O R D E R
In consideration of the foregoing and as more particularly described and qualified above, IT IS HEREBY ORDERED and the Commission does hereby approve the sale by Avista of the Company’s interest in the Centralia steam generating plant to TECWA Power.
IT IS FURTHER ORDERED and the Company is directed to account for the regulatory gain associated with the sale in the manner set forth above.
IT IS FURTHER ORDERED and the Company is directed to file (1) a copy of the Closing Documents and (2) a copy of the accounting entries with this Commission upon completion of the sale.
IT IS FURTHER ORDERED and the Commission does hereby reaffirm its prior Order No. 28186 in Case No. AVU-E-99-6 granting the Company’s request for determination of EWG “eligible facility status” under 15 U.S.C. § 79z-5a(c).
THIS IS A FINAL ORDER. Any person interested in this Order may petition for reconsideration within twenty-one (21) days of the 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 § 61-626.
DONE by Order of the Idaho Public Utilities Commission at Boise, Idaho, this
day of March 2000.

DENNIS S. HANSEN, PRESIDENT

MARSHA H. SMITH, COMMISSIONER

PAUL KJELLANDER, COMMISSIONER

ATTEST:

Myrna J. Walters
Commission Secretary

O:avue996_sw

ORDER NO. 28297 1

Office of the Secretary
Service Date
March 7, 2000