pace992.swksrl.doc

SCOTT WOODBURY
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, IDAHO 83720-0074
[phone]
IDAHO BAR NO. 1895

Street Address for Express Mail:
472 W. WASHINGTON
BOISE, IDAHO 83702-5983

Attorney for the Commission Staff

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 THE 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 FOR AN EWG DETERMINATION.
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CASE NO. PAC-E-99-2

COMMENTS OF THE COMMISSION STAFF

COMES NOW the Staff of the Idaho Public Utilities Commission, by and through its Attorney of record, Scott Woodbury, Deputy Attorney General, and in response to the Notice of Modified Procedure and Notice of Comment/Utility Reply Deadline issued on October 26, 1999, submits the following comments.

SUMMARY
On August 12, 1999, PacifiCorp filed an Application with the Commission seeking an order approving the sale of the Company’s interest in the Centralia coal fired power plant. The Company proposes to sell the 1340-Megawatt (MW) power plant and accompanying coal mine to TECWA Power Inc. for $452.6 million and $101.4 million respectively. PacifiCorp, currently one of 8 owners of Centralia, has a 47.5% ownership interest in the power plant and a 100% ownership interest in the accompanying coal mine.
The Company states in testimony that the decision to sell the plant was made, in a large part, because of the additional capital investment needed to meet new air emission requirements. The Company believes the investment, estimated at $210 million may be difficult to recover given the potential impact of U.S. electric utility deregulation trends. Other factors considered by the Company in its decision to sell include uncertainties surrounding continued operation of the plant. Opposition from current Centralia owners to installation of emission control equipment at the plant could cause temporary plant shutdown or permanent closure. Uncertainty and cost risks associated with continued mine operation and mine reclamation are also cited.
PacifiCorp states that Centralia generation of about 4 million MWh per year will be replaced by market purchases. The Company then provides the results of a net present value analysis with and without Centralia that shows a $10 million reduction in costs without Centralia under a medium market price forecast. Finally PacifiCorp states that the sale is in the public interest because its net present value economic analysis projects in most cases cost savings without Centralia. In addition, the qualitative factors associated with multiple owners, large capital investment and the cost uncertainties associated with mine reclamation suggest that selling Centralia is more beneficial to customers than keeping Centralia.

JUSTIFICATION FOR THE SALE
According to PacifiCorp’s 1997 Integrated Resource Plan (IRP), the Centralia coal fired power plant represents approximately 6.4% of its existing summertime capacity. The IRP also states that the Company plans for a 10% capacity reserve margin. Therefore, loss of Centralia represents a significant portion of planned reserves and must be replaced. To that end, the Company plans to replace Centralia with firm market purchases.

Economic Evaluation
Company witness Miller states that the Company will balance its loads and resources with market purchases. The load/resource balancing analysis utilizes the Company’s 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. The results are presented in the testimony of Company witness Weaver.
Mr. Weaver states in testimony and shows on Exhibit No. 2.3 that the projected net present value difference in revenue requirement between the keep Centralia scenario and the scenario to sell Centralia and purchase resources at medium market price is approximately $10 million over the 25 year period. This amount represents approximately one tenth of one percent of the Company’s total power supply revenue requirement over the same period or approximately 1% of the projected revenue requirement of Centralia.
Mr. Weaver has subsequently stated in response to Staff Production Request No. 11 that an error was made in the analysis that underestimates the benefits of the sale as shown on Exhibit No. 2.3. Rather than $10 million in benefits, the Exhibit should show $32 million in benefits when the same scenarios are compared. The error was a result of underestimating the projected non-scrubber investment made in Centralia each year after 2003. $32 million in benefits represents less than three tenths of one percent of total Company power supply revenue requirement and slightly more than 2% of the projected Centralia revenue requirement.
The effect of this error on the results demonstrates the sensitivity of the analysis and the potential for inaccurately projecting the economic impact of the sale. In fact, selection of just a few crucial variables can determine whether the net present value economic analysis results in sale benefits or expenses. For example, the Company uses its power supply model to project net power supply expenses with and without Centralia for the next 25 years. However, the power supply model only runs for 20 years so the remaining five years are extrapolated. Initial market purchase prices and escalation rates must be assumed for capacity, firm and non-firm energy in order to perform the analysis. In addition, coal escalation rates must be assumed as well. In PacifiCorp’s analysis, an additional model was used to project the change in market purchase prices from year to year. The result is an uneven escalation in market prices over the 25-year period based on projections of regional load growth and resource availability.
Staff analysis of the Company’s 20-year power supply projection shows that while market purchase prices used in the study increase by an average of 1.83 % over the period, actual increases in any given year may vary from no change to 3.2%. Moreover, the Company uses a coal escalation rate that averages 2.9% in the power supply study to project Centralia fuel costs but uses a 1.4% coal cost escalator to forecast growth in market purchase prices.
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, dependent upon assumptions listed above, are then added to projected capital recovery revenue requirement for Centralia that is dependent upon assumptions regarding Centralia capital budgets through the year 2023. Changes in any of these assumptions will not only effect the long-term economic impact of the sale as shown by Mr. Weaver in Exhibit No. 2.3, but the short-term economic impact as well.

Qualitative Evaluation
In addition to the economic evaluation characterized by the Company as a “clear demonstration” that customers are better off with the sale of Centralia, the Company describes the qualitative benefits to be derived. These are potential benefits that result from eliminating the uncertainty surrounding multiple owners of Centralia and elimination of the cost risk associated with mine reclamation. Staff recognizes the potential risks associated with both of these issues but like the Company has no way of determining just how serious these problems might actually be.
The operating agreement for Centralia clearly requires that all owners agree to plant investment before it is undertaken. The agreement does not address what happens if unanimous agreement is not reached. Therefore, the failure of owners to reach unanimous agreement on scrubber investment without the sale could lead to plant closure with shutdown costs and potential purchase of replacement power or it could simply lead to consolidation of ownership shares by existing owners willing to make the investment. Avista has already agreed to purchase shares of other owners should the sale not proceed.
Staff also understands the concern regarding mine reclamation costs. These costs can be affected by many different factors beyond the control of the Company and they clearly represent a significant cost exposure. However, facility shutdown and reclamation costs are anticipated with all generation facilities and at least the current estimated costs are included in the economic analysis conducted by Mr. Weaver.

SALE CONCLUSION AND RECOMMENDATION
The economic analysis conducted by PacifiCorp shows that keeping Centralia is more costly both in the short term and in the long term than selling the plant and replacing the generation with market purchases. Staff believes that by making assumptions within a reasonable range, a net present value economic analysis can either justify or preclude the sale of the Centralia. Although the Company has definitively chosen to replace generation with market purchases, 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 including elimination of problems associated with multiple plant owners and mine reclamation cost risks are simply not quantifiable at this time. Electric deregulation, while adding to the potential problems of multiple Centralia ownership, is impossible to quantify in terms of whether or not the sale is in the best interest of Idaho ratepayers. Likewise, mine reclamation costs that depend upon the timing of mine closure and the nature of regulations at the time of closure are equally difficult to predict. Ultimately the decision to sell Centralia must be based on judgement regarding future conditions. Staff believes that the Company should be allowed to exercise its business judgement regarding the significance of the economic projections and in addressing the qualitative issues. We therefore recommend that the sale be allowed to proceed.
While Staff applauds the Company’s proposal to share the gain from the sale with Idaho ratepayers, we also recognize that the gain available to Idaho is quite small. Moreover, we believe there is a possibility that Idaho customers could ultimately be harmed by higher than anticipated market purchase prices after the sale. Therefore, Staff recommends that firm purchases made by the Company be monitored on an annual basis in conjunction with the required merger reports until the Company’s next general rate case.

Accounting Rules and Regulations for the Treatment of the Gain on the Sale of a Utility Asset
The Federal Energy Regulatory Commission (FERC) Uniform Systems of Accounts Prescribed for Public Utilities and Licensees Subject to the Provisions of the Federal Power Act defines “Property retired,” as property which has been removed, sold, abandoned, destroyed, or which for any cause has been withdrawn from service.
Section B of Account 108 - Accumulated provision for depreciation of electric utility plant (Major only) states:
At the time of retirement of depreciable electric utility plant,
this account shall be charged with the book cost of the property
retired and the cost of removal and shall be credited with the
salvage value and any other amounts recovered, such as insurance.
When retirement, costs of removal and salvage are entered originally
in retirement work orders, the net total of such work orders may be
included in a separate subaccount hereunder. Upon completion of
the work order, the proper distribution to subdivisions of this account
shall be made …

Item 5, letter F from the Electric Plant Instructions from the Uniform System of Accounts, states:
F. When electric plant constituting an operating unit or system is sold,
conveyed, or transferred to another by sale, merger, consolidation, or
credited to the appropriate utility plant accounts, including amounts carried
in account 1114, Electric Plant Acquisition Adjustments. The amounts
(estimated if not known) carried with respect thereto in the accounts for accumulated provision for depreciation and amortization and in account 252,
Customer Advances for Construction, shall be charged to such accounts
and contra entries made to account 102, Electric Plant Purchased or Sold.
Unless otherwise ordered by the Commission, the difference, if any,
between (1) the net amount of debits and credits and (2) the consideration
received for the property (less commissions and other expenses of making
the sale) shall be included in account 421.1. Gain on Disposition of Property,
or account 421.2, Loss on Disposition of Property. (See account 102, Electric
Plant Purchased or Sold.)

The accounting entries for the sale of depreciable property in textbook terms 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 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 would determine the ratemaking treatment of any gain or loss.

Calculation of the Regulatory Gain on the Sale of the Centralia Facility
The Company has provided Staff with the workpapers and assumptions used in the calculation of the regulatory Gain for the Centralia facility. Staff has reviewed the supplied documents and agrees with the Company’s calculation of the gain. The regulatory gain for Idaho, as calculated by the Company and verified by Staff is $154,373 on a “Phased-In Full Rolled-in” interstate allocation basis.
The Company determined the customer portion of the gain using the depreciation reserve methodology. This methodology is based on the ratio of the depreciated plant to the total plant, and is consistent with prior Commission 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. The rationale for this is that customers have repaid shareholders over time through their electricity prices, specifically through the yearly depreciation expense customers pay through their electric rates. 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 2 years (as of December 31, 1999) of the 5-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.

Company Proposed Treatment of the Gain on the Sale of Centralia
PacifiCorp has proposed that the customer portion of the gain from the sale be used to write off generation-related regulatory assets. The Company does not specify which accounts would be charged. The treatment benefits customers, PacifiCorp asserts, “by immediately reducing the Company’s rate base, and by extension, the Company’s revenue requirement. This reduction to revenue requirement will be reflected in the Company’s future results of operations, and will mitigate the upward pressure on customer prices.” This gain treatment will therefore, according to the Company, lessen the likelihood of a rate increase in the near future. PacifiCorp also states that, “In future rate cases, this reduction in revenue requirement will be flowed through to customers.” In summation, treating the gain as proposed would reduce the revenue requirement and in the short run, lessen the chance of a rate increase, and in the long run, reduce the revenue requirement when a rate increase case is actually filed with the Commission.

Commission Staff Recommendation for Treatment of the Gain
This Commission has utilized gains on the sale of utility assets in various ways (See Attachment 1): 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 write off steam generation assets. The Accumulated Depreciation account associated with steam generation should be charged. This 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.

Dated at Boise, Idaho, this day of December 1999.

________________________
Scott Woodbury
Deputy Attorney General

Technical Staff: Kathy Stockton
Randy Lobb

SW:KLS:RL:gdk:i:umisc/comments/pace992.swksrl
STAFF COMMENTS 4 DECEMBER 2, 1999