28708.doc

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

IN THE MATTER OF THE INVESTIGATION OF THE CONTINUED REASONABLENESS OF USING VARIABLE COSTS ASSOCIATED WITH THE OPERATION OF COLSTRIP FOR ANNUAL ADJUSTABLE RATE CALCULATIONS AS PREVIOUSLY AUTHORIZED IN COMMISSION ORDER NOS. 23449, 26080 AND 23738.
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CASE NO. GNR-E-99-01

ORDER NO. 28708

BACKGROUND
The Public Utility Regulatory Policies Act of 1978 (PURPA) requires electric utilities to enter into fixed term obligations to purchase energy from qualifying cogeneration and small power production facilities (QFs). The rate to be paid for such power is not to exceed the “incremental cost” to the utility of alternative electric energy, commonly referred to as a utility’s avoided cost. The avoided cost rates of Idaho’s major electric utilities consist of fixed and variable components. The variable component is adjusted annually.
This case was established by the Idaho Public Utilities Commission (Commission) in 1999 to examine the continued reasonableness of using variable costs associated with the operation of Colstrip, a coal-fired generating facility in southeast Montana, for the annual adjustable rate portion of avoided costs. Reference Commission Order Nos. 23349, 26080 and 23738. The use of Colstrip costs to determine the variable rate component was adopted as part of the Surrogate Avoided Resource (SAR) methodology developed in Case No. U-1500-170. There are 24 PURPA contracts that use Colstrip in the adjustable rate component of the contract rates.
The –170 SAR methodology variable rate component is based on the variable costs associated with the operation of Units 3 and 4 of Colstrip. The adjustable portion of the avoided cost rate is updated annually. The same calculated rate revision for the variable component under the avoided cost methodology is used by Avista Corporation dba Avista Utilities—Washington Water Power Division (Idaho), PacifiCorp dba Utah Power & Light Company and Idaho Power Company.
Avista by letter dated August 30, 2000, explained that it will be unable in the future to furnish variable cost figures based on actual variable costs of Colstrip Units 3 and 4 for the purpose of determining avoided cost rates in Idaho. Although the Company still retains its ownership share, Montana Power has sold its majority share and is no longer the plant operator. The new owner, PP&L Montana, LLC, operates Colstrip Units 3 and 4 as a non-regulated, non-utility generator. The new owner does not utilize the same reporting criteria for costs as do regulated utilities. Many of the accounts relied upon by Avista Corp, in its avoided rate calculation in the past are now combined into larger categories and are not available.
Avista requests that it be relieved of the obligation of determining the adjustable portion of the avoided cost rates applicable to a coal plant SAR. Avista recommends that consideration be given to utilizing another source of information for purposes of determining the adjustable portion.

Following our review of the filings of record in Case No. GNR-E-99-01, including the August 2000 letter from Avista, the Commission on October 23, 2000, issued a Notice of the Avista letter and solicited alternatives for determining annual adjusted rate calculations for those QF calculations containing Colstrip variable rates. Comments were solicited from Idaho’s major electric utilities and all affected QF project owners. The deadline for filing written comments was December 22, 2000. Comments were filed by Avista, PacifiCorp, Idaho Power, Commission Staff, Sorenson Engineering on behalf of the Birch Creek, Marsh Valley, Dry Creek and Georgetown projects, the City of Preston, Cogeneration Partners (Magic Valley), Glenns Ferry Rupert Cogeneration Partners (Magic West), J.R. Simplot Company (Pocatello) CDM Hydroelectric, CEM (Lava Hot Springs), Dave Snedigar (Bell Mountain and O.J. Hydro), lL&M Angus Ranch (successor to Ingram Warm Springs Ranch), and Robert Fackrell (Mink Creek). The comments and alternative proposals considered by the Commission can be summarized as follows:
Rupert Cogeneration Partners, Ltd., Glenns Ferry Cogeneration Partners, Ltd., and JR Simplot Company (collectively, the “Power Producers”) filed comments recommending that two different producer price indexes be used—one to adjust Colstrip coal costs and one to adjust variable O&M costs. Cogeneration Partners (i.e., Glenns Ferry and Rupert) recommended using indexes when it filed comments in the 1999 annual Colstrip adjustment cases (AVU-E-99-3, IPC-E-99-5, and UPL-E-99-2). However, while one of the indexes now recommended by Power Producers is the same as recommended in 1999, one is different. Power Producers now recommends using a coal cost index specific to western coal.
Staff recommends that FERC Form 1 data be used as the source of information for calculating the fuel component of the Colstrip adjustment, and recommends that a fixed amount of $2/MWh be used to represent the variable O&M cost. Staff is not necessarily opposed to using price indexes as the basis for the annual adjustment, but notes that indexes would not have accurately mimicked avoided cost adjustments in past years.
PacifiCorp’s comments are similar to Staff’s. PacifiCorp recommends that publicly available information be used to the extent possible, and suggests that FERC Form 1 data could be used to represent Colstrip fuel costs. Variable O&M costs could be approximated by using an average that has been calculated over the past decade under the Commission-approved methodology.
Idaho Power believes the initial question that the Commission will need to resolve is whether or not it is still important to the Commission that the mechanism for reviewing the adjustable portion of the coal SAR rates be designed to track as closely as possible, changes in the actual variable operating cost of the Colstrip power plant. If that is still the Commission’s preference, then Idaho Power states, Staff’s proposal to use Avista’s Form 1 coal costs plus $2/MWh appears to be a common sense goal.
If the Commission decides that it is not crucial that the adjustment methodology specifically track Colstrip variable expenses and that an adjustment mechanism based on a broader spectrum of prices would be acceptable, then Idaho Power believes that a workable methodology would be to apply a single coal-related adjustment to both the coal costs and the variable O&M expense. Idaho Power suggests using two indexes—one for the spot price of western bituminous coal and lignite for steam electric utilities, and one for the contract price—weighted twenty-five percent and seventy-five percent respectively.
Comments were also received from numerous owners of QF projects who have power sales agreements with PacifiCorp. All of these owners expressed similar opinions. For the fuel component of the adjustment, they suggest using an average fuel cost as reported in FERC Form1 for PacifiCorp’s Carbon, Hale, Naughton, Huntington and Hunter plants. For variable O&M, they suggest using FERC Form 1 variable cost data for the same five plants. They do not, however, recommend which specific cost figures could be used to accurately represent variable O&M.

On January 26, 2001, the Commission issued a Notice of Proposed Order in Case No. GNR-E-99-01 and established a comment deadline. Reference IDAPA 31.01.01.312. The substance and nature of the proposed Order was set forth in that document in the Commission’s findings:
The Commission finds that with few exceptions, the methods suggested in comments were relatively complete and viable alternatives. While some consensus might be possible to refine either an index-based method or a FERC Form 1-based method, we find that there seems to be little common ground between these two general approaches. Given the disparity between these two suggested approaches, the Commission doubts a single method would emerge from a workshop. Since it seems unlikely unanimous agreement could be achieved, we find it would be more productive to issue a proposed Order and solicit comment thereon.

We find that the parties have presented the Commission with several viable options to the present variable rate calculation methodology. Some alternatives unfortunately present elements that are more conceptual than complete. From a regulatory perspective, of the proposals submitted and reviewed, we are attracted to Staff’s proposal. We find that it would be relatively simple to implement. It further utilizes information (FERC plant operating data) that is of public record. We are further persuaded by an offer of proof that demonstrates its ability to accurately mimic avoided cost adjustments in past years, adjustments that we have previously found to be reasonable.

We therefore find it reasonable to adopt Staff’s proposal, i.e., to determine future Colstrip variable cost adjustments by using FERC Form 1 Colstrip unit coal cost per megawatt hour (MWh) and adding $2/MWh (the average variable O&M cost of Colstrip plus $0.20/MWh for generation taxes = approximately $2/MWh).

Pursuant to Notice, the deadline for filing written comments regarding the Commission’s proposed Order was February 14, 2001. Comments supporting the proposed Order were filed by Idaho Power Company (IPCo), Avista Corporation, and PacifiCorp dba Utah Power & Light Company (PCp). Additional comments were filed by IPCo QFs and PacifiCorp PCP QFs.
IPCo QFs
Rupert Cogeneration Partners Lt’d (Rupert), Glenns Ferry Cogeneration Partners Lt’d (Glenns Ferry) and J.R. Simplot Company (Simplot), collectively the “IPCo QFs”, filed joint comments addressing two areas of concern:
The lack of escalation for variable operating and maintenance costs (variable O&M costs) and
The use of FERC Form 1 data rather than an index for the escalation of coal costs.
Variable O&M Costs
Setting the variable O&M costs at a fixed rate ($1.80/mWh variable O&M + $.02/mWh generation tax) with no escalation, the IPCo QFs contend, fails to acknowledge economic reality. Absent adoption of a more specific index for variable O&M costs, the IPCo QFs now propose as an alternative that the Commission escalate the $1.80/MWH variable O&M cost component of the fixed adder at the rate of the Gross Domestic Product (GDP) Implicit Price Deflater (IPD) as reported by the U.S. Department of Commerce. The GDP IPD, the IPCo QFs contend, is a very broad index that captures general price level changes.
The Staff method that the Commission is proposing to adopt was acknowledged by Staff in its comments (Staff Comments—December 18, 2000, p. 8) to be a less precise method than an alternative formulaic equation. The method nevertheless was demonstrated to closely mimic Colstrip variable costs since 1989, the difference averaged over several years being nearly zero.
FERC Form 1 Data
Although the IPCo QFs do not categorically oppose the use of FERC Form 1 data, they note that there are problems with the project-specific nature of such data. For example, they note that the Colstrip plant is no longer operated to serve native utility loads but is now operated as a merchant plant with the aim of selling electric energy on the wholesale market. There is also, they note, the practical issue of whether the FERC Form 1 data will continue to be available for Colstrip.
Should the Commission choose to not alter the proposed changes in methodology, the IPCo QFs request that the Commission leave the generic docket open for two years to allow for periodic review of the methodology.
PCp QFs
Comments were also filed by CDM Hydroelectric Co., Mink Creek Hydroelectric, Commercial Energy Management, Inc. (Lava Hot Springs) and Sorensen Engineering, collectively the “PCp QFs.” By 1992 addendum, reference Order No. 24253 (attached), the underlying Power Purchase Agreements for PCp QFs were modified. Clarification is requested regarding how the Commission’s proposed Order would affect their contracts. Specifically, they request assurance that the fuel component calculation of their contracts, “average fuel cost as reported in FERC Form 1 for PacifiCorp’s Carbon, Hale, Naughton, Huntington and Hunter plants” is to remain unchanged. PacifiCorp, it is noted, concurs in this understanding. PacifiCorp also notes that the Hale plant was taken out of service several years ago and no longer exists.
Variable O&M under the PCp QF contracts, while presently fixed, is to be tied to Colstrip beginning in 2003. The PCp QFs recommend using a weighted average of PacifiCorp’s FERC Form 1 line 34 expenses per net kWh for the same plants used to derive fuel costs. Line 34 includes the average fuel costs plus the variable O&M costs.
PacifiCorp in its comments notes its understanding that generation taxes would be excluded from the calculation under the PCp QF contract amendments approved in Order No. 24253. Those amendments specifically provide for the exclusion of a generation tax for variable O&M costs. Similarly, the amendments provide for the exclusion of a line loss adjustment. Staff notes that the exclusion of line loss and generation tax from the variable Colstrip adjustment calculation for affected PCp contracts (beginning in 2003) results in an adjusted figure of $1.51/MWh. Reference Staff Comments—supporting workpapers.
COMMISSION FINDINGS
The Commission has reviewed and considered the filings of record in Case No. GNRE-99-01, including the preliminary set of comments, the Commission’s proposed Order and the most recent set of comments. In this case we are determining a replacement methodology for calculating the annual adjusted variable component for a generation of PURPA QF contracts. By proposed Order, we established what we believed to be a reasonable change in methodology. We are confident that our Notice provided all affected QF project owners with an opportunity to participate and express their views.
The Commission continues to find it reasonable to link the variable rate for affected contracts to Colstrip. The methodology proposed by Staff and adopted in our proposed Order remains, in the Commission’s view, the best method for calculating the variable rate for contracts using Colstrip in the adjustable rate component of the contract rates. This continues to be our finding despite proposals to move to an index or in the case of PacifiCorp QFs to use data from other coal plants to calculate the variable O&M portion of the rate. We also find Staff’s demonstration that the chosen method closely mimics Colstrip variable costs since 1989 a persuasive reason to not include an escalator for variable O&M costs.
With the change that we approve, we continue to find that the combination of fixed and variable components in the affected QF contracts remains representative of the utilities’ then avoided costs.
For those PacifiCorp QF contracts with 1992 Addendum language, we note, by way of clarification, that the fuel component calculation is to remain unchanged, i.e., “average fuel costs as reported in FERC Form 1 for PacifiCorp Carbon, (Hale—presently out of service), Naughton, Huntington and Hunter plants.” The variable O&M under the PacifiCorp QF contracts, while presently fixed, is to be tied to Colstrip beginning in 2003. The Commission notes that pursuant to the ‘92 Addendum language in the PacifiCorp QF contracts, generation taxes and a line loss adjustment are specifically excluded from the calculation of any variable O&M. It is not our intention to change this contract term. The Commission notes, as calculated by Staff, that the exclusion of line loss (5%) and generation tax (20¢/MWh) from the variable Colstrip calculation for affected PacifiCorp contracts (beginning in 2003) results in an adjusted O&M figure of $1.51/MWh.
CONCLUSIONS OF LAW
The Idaho Public Utilities Commission has jurisdiction over Idaho Power Company, Avista Corporation dba Avista Utilities—Washington Water Power Division (Idaho) and PacifiCorp dba Utah Power & Light Company, electric utilities, pursuant to the authority and power granted it under Title 61 of the Idaho Code, and the Public Utility Regulatory Policies Act of 1978 (PURPA).
The Idaho Public Utilities Commission has authority under PURPA and the implementing regulations of the Federal Energy Regulatory Commission (FERC) to set avoided costs, to order electric utilities to enter into fixed obligations for the purchase of energy from qualified small power production and cogeneration facilities and to implement FERC rules.
O R D E R
In consideration of the foregoing and as more particularly described above, IT IS HEREBY ORDERED and the Commission does hereby approve the following changed methodology for the annual adjustable rate portion of avoided costs for those QF contracts using variable costs associated with Colstrip.
For those QF contracts with Colstrip-related fuel costs and variable O&M, future Colstrip variable cost adjustments are to be calculated by using FERC Form 1 Colstrip Unit Coal Costs per megawatt hour (MWh) and adding $2.00/MWh (the average variable O&M cost of Colstrip plus 20¢/MWh for generation taxes plus a five percent (5%) adjustment for line loss).
For PacifiCorp QF contracts with ‘92 Addendum language, variable O&M beginning in 2003 will be $1.51/MWh.
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 April 2001.

PAUL KJELLANDER, PRESIDENT

MARSHA H. SMITH, COMMISSIONER

DENNIS S. HANSEN, COMMISSIONER

ATTEST:

Jean D. Jewell
Commission Secretary

vld/O:GNR-E-99-01_sw2

ORDER NO. 28708 1

Office of the Secretary
Service Date
April 17, 2001