28296.doc

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

IN THE MATTER OF THE APPLICATION OF PACIFICORP FOR AN ORDER APPROVING THE SALE OF ITS INTEREST IN (1) THE CENTRALIA STEAM ELECTRIC GENERATING PLANT, (2) THE RATE BASED PORTION OF ITS CENTRALIA COAL MINE, AND (3) RELATED FACILITIES; FOR A DETERMINATION OF THE AMOUNT OF AND THE PROPER RATEMAKING TREATMENT OF THE GAIN ASSOCIATED WITH THE SALE; AND (4) AN EWG DETERMINATION. )
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CASE NO. PAC-E-99-2

ORDER NO. 28296

On August 12, 1999, PacifiCorp (Company) filed an Application with the Idaho Public Utilities Commission (Commission) regarding the proposed sale by the Company of its 47.5% ownership interest in the Centralia steam generating plant (and related facilities) and the 47.5% rate based portion of its ownership interest in the Centralia Coal Mine. The purchaser of the Centralia generating unit is TECWA Power, Inc. (TECWA Power) and the purchaser of the Centralia Coal Mine is TECWA Fuel, Inc. (TECWA Fuel), both Washington corporations and both wholly-owned subsidiaries of TransAlta Corp., a Canadian energy corporation with $5 billion (Canadian) in assets and guarantor of certain obligations and duties undertaken by TECWA Power and TECWA Fuel. TransAlta is the leading producer of independent power in Canada. TransAlta generates about 4,500 megawatts of electricity annually. About 95% of its production is thermal (coal) and the remainder is hydroelectric.
The Company’s Application includes copies of the Centralia power plant Purchase and Sale Agreement and Centralia coal mine Purchase and Sale Agreement, other transactional documents and the prefiled testimony of company witnesses C. Alex Miller, Managing Director of Planning; Dr. Roger Weaver, Director, Regulatory and Strategy Support; and Ann E. Eakin, Vice President Regulation.
PacifiCorp seeks a Commission Order approving the sale of the Company’s interest in the Centralia steam generating plant and the rate based portion of the Centralia coal mine. Citing Idaho Code § 61-523--Valuation. PacifiCorp also seeks a Commission Order adopting the Company’s methodology to calculate the gain associated with the sale and the proposed ratemaking treatment of the gain.
APPLICATION—BACKGROUND
Description of Plant and Mine
The Centralia plant is coal-fired and has a generation capacity of 1,340 megawatts. The plant which is located near Centralia, Washington entered service in 1972 and consists of two steam units that consume between 5.0 to 6.0 million tons of coal annually at an average capacity factor of approximately 70%.
PacifiCorp owns a 47.5% interest in the power plant. The other seven co-owners of the power plant and their ownership shares are: Avista 15%, City of Seattle 8%, City of Tacoma 8%, Snohomish PUD 8%, Puget Sound Energy 7%, Grays Harbor County PUD 4%, and Portland General Electric (PGE) 2.5%.
The plant’s primary source of coal is the mine located adjacent to the plant site. The mine is owned by PacifiCorp and operated by its wholly-owned subsidiary. Over the last 10 years, 75 to 100 percent of the coal burned at the plant has come from the mine, with the remaining coal imported by rail from the Powder River Basin in Montana and Wyoming. The coal produced by the mine has had an average heating value of approximately 8,000 BTU/lb., moisture content of approximately 20%, ash content of approximately 16% and a sulfur content of approximately 0.7%.
Plant Environmental Requirements
Pursuant to plant operation agreements, capital budgets, including capital expenditures required to meet environmental requirements, require unanimous approval of the owners. The Centralia plant operates under the jurisdiction of the Southwest Air Pollution Control Authority, a regional air quality agency established under Washington law. The plant is required to apply Reasonable Available Control Technology (RACT) to limit the emission of air contaminants. PacifiCorp has been advised that the plant SO2 and NOX emissions exceed acceptable emission levels. To reduce emission levels the plant must implement control measures and install control equipment by December 31, 2001.

Because the plant owners were unable to reach consensus regarding the capital investment required to comply with the RACT order, Centralia was put up for sale. If the sale to TransAlta does not close, the Centralia owners will need to vote to determine whether to continue operation and comply with emission reduction requirements or close the plant.
Mine Reclamation
The Centralia coal mine is operated under the regulatory authority of the federal Office of Surface Mining (OSM). Every mine permit, including Centralia’s, has an approved reclamation plan. Reclamation is a process of returning land that has been mined to approximately its pre-mined state. There are situations, however, in which the regulator will permit the creation of lakes or other land contours not present in the pre-mined state. The Centralia mine is considering applying to the regulators for approval to create lakes.
Current and final reclamation costs are generally included as a cost of mining coal. These costs are either accrued on a company’s financial books (as PacifiCorp does), or funds are put in a trust. The ultimate cost of final reclamation for the Centralia mine depends on many factors and is uncertain. A study was commissioned to determine the potential costs, which study determined could vary widely depending on the reclamation method used. Reference Miller testimony Table 1. The Office of Surface Mining has the final say on what reclamation methods are acceptable. Should the plant be sold to TransAlta the reclamation liability and the accrued reclamation balances transfer to the new owner.

As represented in the Application, the owners of the Centralia facilities decided to sell the assets due principally to the need for additional capital expenditures to meet new emission requirements and the potential impact of US electric utility industry deregulation trends on the prospect for recovery of utility plant-in-service investment. The gross proceeds from the sale of the generating facility and the mine were allocated between the generating plant price of $452,598,000 and coal mine price of $101,400,000.
Sale Proceeds—Gain on Sale
The gross purchase prices are subject to certain adjustments which must be incorporated in any calculation of net gain. PacifiCorp’s share of the gain associated with the sale is estimated to be approximately $83 million on a system-wide basis. (Exhibit Miller 1.7) The actual dollar value of the net gain on the sale will not be finalized until the close of the transaction.
As reflected in the Application, PacifiCorp will receive its book break-even value for the mine. This will remove the mine from PacifiCorp’s books with no earnings impact, and no gain on sale of the mine. The book break-even value was estimated at about $101 million at the time the Agreements were signed, and is the value used in the mine Sale Agreement. The break-even value will be trued-up and audited at the time of closing.
The remaining proceeds will be split among the owners based on their plant ownership percentages. PacifiCorp will receive approximately $215 million for its portion of the plant. Total proceeds to PacifiCorp will be about $316 million for the mine and its share of the plant.
Replacement Power Strategy
Centralia was originally conceived as a seasonal-use generating station. However, as reflected in the Application, the plant has been dispatched as a base load facility over most of its service life. Capacity factors have averaged 70% over the past five years, with a high of 84% in 1994. Availability over the last five years has averaged 88%. The plant produces about four million megawatt hours annually for PacifiCorp. Without Centralia, PacifiCorp intends to balance its loads and resources with market purchases.
Financial Impacts of Sale
The Company’s analysis shows the net present value of the revenue requirement associated with selling the plant is lower than the net present value of the revenue requirement associated with keeping the plant over the short, medium and long term. Sale of the plant and mine, the Company contends, provides greater certainty of benefits to customers, because keeping the resource exposes customers to significant risks of additional cost increases in the future.
If plant ownership is retained, the Company assumes that the plant will be retrofitted with scrubbers to meet pollution control requirements and continue to run through its remaining life till 2023. If the sale closes, the Company forecasts that replacement power will be purchased from the wholesale market under medium, low and high market prices over the remaining life of the plant. The customer portion of the gain is reflected in the studies as a revenue requirement reduction.
Under the Company’s medium market price forecasts, customers are better off if the plant is sold. The Company contends that its analysis is conservative and does not incorporate all the significant cost exposures and uncertainties related to continued ownership and operation of the plant and mine—joint ownership issues, additional reclamation costs, additional pollution control mitigation costs and temporary or permanent closure of the plant and/or mine. In addition, the Company contends, continued ownership could be impacted by potential future CO2 taxes, potential increased force outage rates and higher maintenance costs for an older facility.
As with any forecast, the Company recognizes that the longer forecast period tends to exacerbate forecast inaccuracies. Accordingly, there is less certainty with data in the later years of analysis. Recognizing the uncertainty of long term forecasting the Company also estimated a net present value revenue requirement benefit of selling versus keeping the plant using the medium market prices over a ten-year period. The results project that there are $39 million of net present value revenue requirement reductions in the sell case when compared to the keep case.
Under the Company’s analyses the first year to show that keeping the plant is less expensive than the medium market replacement purchases is 2010. The Company also assessed the ramifications of the sale on the BPA Residential Exchange Program and concluded that it is unlikely that the effects would lead to a different realized level of benefits.
Proposed Disposition of Gain
As stated above, PacifiCorp will not realize any gain related to sale of the mine.
PacifiCorp estimates that it will realize an estimated gain of approximately $83 million on a system-wide basis associated with its 47.5% ownership share of the plant. The actual dollar value of the net gain on the sale of the plant will not be finalized until the close of the transaction.
PacifiCorp proposes the following disposition of the net gain proceeds related to the proposed sale of the plant:
The total net gain would be shared between customers and shareholders consistent with the depreciation reserve method
This methodology results in customers receiving 64.17% of the net gain, and the shareholders receiving 35.83% of the net gain.
Depreciation Reserve Methodology
The depreciation reserve methodology is based on the relationship between net plant and gross plant. This relationship establishes the percentage of the capital costs of the plant that have been recovered over time through customers’ prices and the percentage of these costs that remain on the Company’s books. These percentages are then multiplied by the overall gain to establish the sharing ratio. (Exhibit Eakin 3.1)
The rationale behind this methodology, the Company contends, is straightforward and balances the interests of customers and shareholders. The Company’s proposal acknowledges that over time customers have repaid shareholders for a portion of the up-front capital through their electricity prices. The methodology also recognizes that shareholders continue to bear the risk of recovering the undepreciated portion of the generating facility.
Proposed Ratemaking Treatment of Gain
PacifiCorp proposes to use the customer portion of the net proceeds of the sale to write off generation-related regulatory assets, thereby reducing the Company’s rate base. The Company proposes to record this write off in the year that the transaction closes.
This proposed ratemaking treatment, the Company contends, benefits customers by immediately reducing the Company’s rate base and, by extension, the Company’s revenue requirement. This reduction to revenue requirement, the Company contends, will be reflected in its future results of operations, and will mitigate the upward pressure in customer prices. In future rate cases, the reduction in revenue requirement will be flowed through to customers.

PROCEDURE
On September 7, 1999, the Commission issued a Notice of Application and established a September 17 deadline for intervention. No Petitions for Intervention were filed. The Commission in its Notice also solicited comment on the Company’s proposal to process its Application pursuant to Modified Procedure, i.e., by written submission rather than by hearing. Reference Commission Rules of Procedure, IDAPA 31.01.01.201-204. The deadline for filing written comments regarding the Company’s proposed use of Modified Procedure was September 30, 1999. The Commission Staff was the only party to file written comments. Based on its preliminary review Staff supported the Company’s request to process its Application pursuant to Modified Procedure.
The Commission Notice of Modified Procedure was issued on October 26, 1999. A December 3, 1999, deadline was established for filing written comments regarding issues presented in the Company’s filing pertaining to the sale of its Centralia facilities, calculation of the associated gain, and related ratemaking treatment. The Company was permitted to file reply comments by December 30, 1999.
In its findings the Commission noted 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. The Commission’s Order No. 28186 regarding “eligible facility” status issued on October 26, 1999.
STAFF COMMENTS
The Commission Staff was the only party to file comments in this case. In its comments Staff addressed: (a) prudence of sale—reclamation risk, multiple-owner risk, economics (cost of replacement power, etc.); (b) gain—dollar calculation and regulatory treatment.
Economic Analysis
Staff notes that according to PacifiCorp’s 1997 Integrated Resource Plan (IRP) the Centralia coal-fired power plant represents approximately 6.4% of the Company’s existing summertime capacity. The IRP further states that the Company also plans for a 10% capacity reserve margin. The loss of Centralia, Staff contends, represents a significant portion of the Company’s reserves and must be replaced. To that end, Staff notes that it is the Company’s stated intention to balance its loads and resources with market purchases. The Company utilized its power supply model to estimate the economic impact of removing Centralia from the Company’s resource stack. The change in power supply revenue requirement with and without Centralia is then projected through the year 2023 and combined with the capital recovery revenue requirement for the same period. The net present value of the stream of revenue requirements with and without the Centralia power plant and coal mine are then calculated. Staff concludes that the Company’s analysis methodology demonstrates a sensitivity and potential for inaccurately projecting the economic impact of the sale. In fact, Staff contends that selection of just a few critical variables can determine whether the Company’s net present value economic analysis results in sale benefits or expenses. A comparison of the power supply revenue requirement with and without Centralia shows that six components included in total power supply revenue requirement change when Centralia is replaced. They are (1) secondary sales, (2) secondary purchases, (3) wheeling costs, (4) other thermal plant fuel expenses, (5) Centralia fuel expenses, and (6) Centralia energy and capacity purchases. All of these components entail assumptions. Changes in any of the assumptions affect not only the long-term economic impact of the sale but the short-term economic impact as well.
Qualitative Analysis
Staff notes that in addition to economic reasons advanced by the Company, the Company also describes qualitative benefits to be derived from the sale. These are potential benefits that result from eliminating the uncertainties surrounding multiple owners of Centralia and elimination of the cost risk associated with mine reclamation. Staff recognizes the potential risk associated with both of these issues but, like the Company, has no way of determining how serious these problems might actually be.
Staff believes that by making assumptions within a reasonable range, a net present value economic analysis can either justify or preclude the sale of Centralia. Although the Company has definitively chosen to replace generation with market purchases, Staff contends that the impact on customers is still uncertain given the broad range of possible market prices, coal escalation rates and capital investment scenarios. The qualitative sale benefits described by the Company, Staff states, are simply not quantifiable at this time. Ultimately, however, Staff concludes that the decision to sell Centralia must be based on judgment regarding future conditions. Staff believes that the Company should be allowed to exercise its business judgment regarding the significance of the economic projections and in addressing the qualitative issues. Staff recommends that the sale be allowed to proceed.
Accounting Rules and Regulations—Treatment of Gain
Staff in its comments 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.
The accounting entries for the sale of depreciable property in textbook terms, Staff contends, would be to debit the cash account for the purchase or sale price of the property; credit the property asset account for the original cost of the asset; debit the accumulated depreciation account for the amount of the accumulated depreciation associated with the property; and credit gain on disposal of the property. If the sale resulted in a loss, loss on the disposition of property would be debited. The appropriate regulatory commission, Staff states, would determine the ratemaking treatment of any gain or loss.
The Company, Staff notes, has provided workpapers and assumptions used in calculation of the regulatory gain on sale of the Centralia facility. Staff has reviewed the supplied documents and agrees with the Company’s calculation of the gain. The Company determined the customer portion of the gain, Staff states, using the depreciation reserve methodology. This methodology is based on a ratio of the depreciated plant to the total plant, and Staff contends is consistent with the Commission’s prior Orders that speak to the distribution on the gain on the sale of a utility plant asset. The percentage allocated to customers is the percentage of depreciated plant to gross plant. The percentage allocated to shareholders is the remaining ratio based on undepreciated plant. Idaho customers will receive 64.17% of the gain, and shareholders the remaining 35.83% of the gain. While the total customer portion of gain is $53,042,987, the Idaho jurisdictional portion is 0.291%, or $154,373 using the phased-in full rolled-in interstate allocation method, with two years (as of December 31, 1999) of the five year phase-in included in the calculation of the Idaho jurisdictional gain. The Idaho jurisdictional portion is relatively small since the Centralia plant and mine were not included in Idaho’s rate base until 1990 following the PacifiCorp/Utah Power & Light merger.
PacifiCorp has proposed that the customer portion from the gain of the sale be used to write off generation-related regulatory assets. The Company in its Application does not specify which accounts would be charged. The Commission, Staff notes, has utilized gains on the sale of utility assets in various ways: return to ratepayers through a bill credit, offset expenses, make special contributions to other accounts (i.e., the Idaho Universal Service Fund), amortize the gain over a period of years, or charge (increase) accumulated depreciation or offset plant investment as proposed by PacifiCorp.
In this case, Staff recommends that the gain from the sale of the Centralia facility be used to offset steam generation assets. The accumulated depreciation account associated with steam generation should be charged. This, Staff contends, will reduce the rate base and the associated revenue requirement. This reduced revenue requirement will be reflected in the annual Idaho jurisdictional reports required in the merger that Staff will audit.
PACIFICORP REPLY COMMENTS
PacifiCorp’s reply comments focus on two specific recommendations of Staff:
1. That “firm purchases made by the Company be monitored on an annual basis in conjuction with the required merger reports until the Company’s next general rate case”

2. That the gain from the sale of the Centralia facility be used to write off steam generation assets by charging the “accumulated depreciation” account associated with steam generation. This would reduce the rate base and the associated revenue requirement.

Difficulties in Monitoring Future Market Purchases
To the extent that a future firm market purchase is specifically tied to the replacement of Centralia Power, PacifiCorp admits that Staff’s requirement is straight forward. However, the Company states that it is important to recognize that loads and resources will be balanced through the redispatch of its system as well as through market purchases. Further activities may also affect the Company’s future need for resources. As such, Centralia, PacifiCorp notes, is not likely to be replaced with in-kind purchases of similar size and shape.
Recommendation for Treatment of Gain
PacifiCorp does not believe that “accumulated depreciation” Account 108 is the proper account to use. PacifiCorp believes that it will be administratively easier to track the return of a gain to customers through reduced steam generation rate base by crediting Account 114.5 “Electric Plant Acquisition Adjustments,” Yampa Project.
Consistent with Staff’s proposal, the Company’s proposal to credit Account 114, it states, will result in an immediate reduction of steam generation rate base, and will reduce the amortization over the 22 1/3 year remaining life (of Yampa), which is equivalent to the Centralia life. According to FERC regulations, Account 114, “Electric Plant Acquisition Adjustments,” is used for the difference between cost to the utility of electric plant acquired by purchase, merger, consolidation, liquidation, or otherwise and the book value of the property. PacifiCorp requests that the Commission authorize the Company to reduce rate base by writing off from Account 114 an amount equal to the customer’s share of the gain from the sale of the Centralia plant.
COMMISSION FINDINGS
The Commission has reviewed and considered the filings of record and comments 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.
PacifiCorp requests Commission approval of the sale of the Company’s interest in the Centralia steam generating plant and the rate-based portion of the Centralia coal mine. In support of the 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. We also recognize the vagaries inherent in long-term forecasting. 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 in this case, we find no compelling reason to disapprove the proposed sale of the Centralia generating plant and mine. We accordingly find it reasonable to approve the sale.
The transaction has been structured in such a way that the Company will realize no regulatory gain on the sale of the mine. We find the depreciation reserve methodology proposed by the Company to be a reasonable method for distribution of gain associated with the sale of the Centralia plant. Under this methodology Idaho customers will receive 64.17% of the gain and shareholders the remaining 35.83% of the gain. The Idaho jurisdictional portion under the transmission/distribution formula is 0.291%. The Idaho customers’ portion of gain is approximately $154,373 (subject to adjustment at closing).
The amount of gain allocated to Idaho customers related to Centralia is so very small that a rate adjustment to account for the gain not only is not required but is practically speaking impossible. We agree with the Company’s proposal to use the gain to offset steam generation-related regulatory assets. The Company specifically proposes the use of a Colorado-Ute related sub account for Yampa, Account 114.5. We note that the Yampa facility has not been addressed in a rate case before this Commission and find the proposed offset to be inappropriate. Reference Commission Order No. 24077, Case Nos. PPL-E-91-2, UPL-E-91-4. Instead, the gain is to be accounted for separately as a generic offset to asset accounts, Account 114.XX – Centralia sale, until the next rate case.
The Company has not proposed nor do we make any rate base adjustment in this case related to the loss of Centralia as a Company-owned resource. 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 PacifiCorp dba Utah Power & Light Company, 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 31.01.01.000 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 PacifiCorp of the Company’s interest in the Centralia steam generating plant to TECWA Power and rate based portion of the Centralia coal mine to TECWA Fuel.
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. PAC-E-99-2 granting the Company’s request for determination of EWG “eligible facility status” under 15 U.S.C. Section 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

Vld/O:PAC-E-99-2_sw

ORDER NO. 28296 1

Office of the Secretary
Service Date
March 7, 2000