Office of the Secretary Service Date April 13, 2010

Exhibit 99.1

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

 

 

IN THE MATTER OF THE APPLICATION OF IDAHO POWER COMPANY TO ESTABLISH ITS BASE LEVEL FOR NET POWER SUPPLY EXPENSES FOR 2010

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CASE NO.  IPC-E-10-01   ORDER NO.  31042

 

                  Idaho Power Company (Idaho Power; Company) filed an Application on January 19, 2010, with the Idaho Public Utilities Commission (Commission) requesting an Order approving an increase in the Company’s base level of net power supply expense (NPSE).  The base level NPSE amount would be used prospectively to set both base rates and establish the base level of net power supply expense for the Company’s 2010-2011 Power Cost Adjustment (PCA) calculations.  The Company in its initial Application in this case requested an increase of $74.8 million in Idaho NPSE ($78.4 million system).  In its reply comments, the Company concurred with Staff-proposed adjustments agreeing to a recommended increase of $63,701,694.  The Commission in this case authorizes an increase of $63,701,694 in the Company’s NPSE as a working number for the Company’s 2010-2011 PCA filing deferring final calculation of authorized NPSE to the PCA case.

BACKGROUND

                  On January 13, 2010, in Order No. 30978 issued in Case No. IPC-E-09-30, the Commission approved a Settlement Stipulation (Stipulation) which included a moratorium on rate case filings by Idaho Power and certain other ratemaking provisions.  The Stipulation included a provision which addresses setting the base level for net power supply expenses. Paragraph 7.1 of the Stipulation reads as follows: 

7.1. Setting the Base Level for Net Power Supply Expense.  Prior to implementing the June 1, 2010, PCA and effective with the coincident PCA rate change, the Company will file with the Commission a request to change the base level for net power supply expenses to be used prospectively for both base rates and PCA calculations.  The Parties will thereafter make a good-faith effort to reach agreement on the maximum change of the base level for net power supply expenses and submit any agreement to the Commission for approval.  The Company's Application in this case is filed in compliance with Section 7.1 of the Stipulation. 

 

 

 

 

 

 

 

Proposed Increase in Base Net Power Supply Expense

The Commission set Idaho Power’s currently authorized base level NPSE in the Company’s 2008 general rate case, Case No. IPC-E-08-10, Order No. 30722, pages 19-21, approving a base level NPSE for the Idaho jurisdiction of $80,243,253.  This amount does not include transmission costs and water for power expenses previously included in base rates.  Including these two additional expense categories results in an Idaho NPSE of $86,048,674.  When PURPA expenses are included total Idaho NPSE is $146,027,664.

                  In this case the Company has calculated that the difference between the 2008 and 2010 base level Idaho NPSE would be $74.8 million ($78.4 million on a system basis).  This difference reflects the maximum adjustment to base level NPSE that would be the subject of negotiations pursuant to paragraph 7.1 of the Stipulation.  Reference Application supporting testimony Exhibit 4.

As reflected in the Company’s Application, net power supply expense includes a number of categories of variable power supply expenses. Modeled variable power supply expenses include fuel expenses (FERC Accounts 501 and 547) and purchase power expenses (FERC Account 555), not including purchases from qualifying facilities (QFs) under the Public Utility Regulatory Policies Act of 1978 (“PURPA”).  To determine net power supply expense, surplus sales revenues (FERC Account 447) are deducted.  In addition to the modeled variable power supply expenses categories, the base net power supply expense used for PCA computations also includes PURPA expenses (FERC Account 555), third-party transmission expense (FERC Account 565), water leasing expense (FERC Account 536), and revenue from marginal cost-based special contract pricing (FERC Account 442).  In each annual PCA, the Company’s forecast of variable power supply expenses is compared to a normalized, approved variable power supply expense level and the difference is the principal driver of the PCA.

The difference between the two above-described NPSE numbers, the Company contends, is driven principally by increases in the payments the Company expects to make to PURPA facilities, increased coal costs for the Company's three coal-fired power plants, and reduced revenues from surplus sales due to decreased gas prices.  Net power supply expenses also are affected by changes in the Company's loads.  The Company's annual normalized system

 

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 load used in its last general rate case was 15.9 million megawatt-hours (MWh).  The Company’s 2010 annual normalized system load based on the 2010 test year is 15.7 million MWh, a decrease of 200,000 MWh.

On January 28, 2010, the Commission issued a Notice of Application and Modified Procedure in Case No. IPC-E-10-01.  The deadline for filing written comments was March 11, 2010.  Comments were filed by Commission Staff and by intervenors Industrial Customers of Idaho Power (also filing protest) and the Idaho Irrigation Pumpers Association, Inc. (Irrigators; IIPA).  Reply comments were filed by Idaho Power on March 24, 2010.  The comments can be summarized as follows:

 

Commission Staff

Staff recommends a 2010 Idaho NPSE increase of $63,701,694 ($66,719,746 on a system basis).  The difference between Idaho Power’s approved 2008 NPSE and its proposed 2010 NPSE, Staff states, is driven principally by increased coal costs for the Company’s three coal-fired plants (Bridger, Valmy and Boardman), increases in the payments the Company expects to make to PURPA facilities, and reduced revenues from surplus sales due to decreased gas and electric market prices.  Staff agrees with some of the Company-proposed changes but disagrees with others.

 

Increased Coal Costs

Higher coal costs account for approximately 43% of the proposed increase in NPSE.  Coal contracts at Bridger and Valmy expired at the end of 2009, and new contracts that begin in 2010 reflect prices that are roughly 30% higher than in the past.  A new coal supplier agreement at Boardman began in 2009 and also reflects higher prices.  Staff accepts the Valmy and Boardman prices, but withholds judgment on the Bridger coal costs pending completion of further analysis regarding the pricing of a portion of Bridger coal purchased from Bridger Coal Company (BCC).  Idaho Energy Resources Company (IERCO), an Idaho Power affiliate, owns a one-third interest in BCC.  Staff recommends that for now, Bridger coal costs be allowed at the level proposed by the Company, but that the Commission reserve the right to make adjustments to Bridger coal costs allowed in base rates in the context of the Company's 2010 PCA filing.  The Company's annual PCA filing pursuant to approved methodology is expected to be submitted on April 15, 2010, with a final Order issuing on May 15 to accommodate a June 1 rate change.

 

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Adjustment to PURPA Costs

                  Increased PURPA costs represent $23 million of the nearly $75 million proposed Idaho jurisdictional increase in NPSE.  Idaho Power has signed 14 new PURPA contracts with scheduled online dates in 2010.  In the past, individual PURPA contract costs have been added to base NPSE in general rate proceedings once there was a signed power sales agreement and a scheduled online date occurring before the end of the test year.  The logic in this approach, Staff contends, was that once there was a signed power sales agreement that obligated the project to a specified online date the costs were “known and measurable” and worthy of being included in base net power supply cost.

                  In this case, Staff suggests that the mere existence of a signed power sales agreement does not guarantee that a project will actually meet its scheduled online date.  Staff identifies 11 PURPA contracts totaling 50.2 a MW of new capacity for wind projects by a single developer that it believes may have difficulty meeting scheduled online dates in 2010, citing a history of online schedule changes for these 11 projects (i.e., from an initial online date of May 1, 2007 – extended to September 1, 2010 – and further extended to December 31, 2010).  Removal of the costs of these 11 contracts reduces Idaho Power’s proposed NPSE by $7,108,922.

 

Adjustment to Hoku Loads and Revenues

                  Hoku Materials, Inc. is a planned polysilicon production facility in Pocatello, Idaho (reference Case No. IPC-E-08-21).  Citing a history of delays in development, Staff proposes that both the expected loads and associated revenues attributed to Hoku be removed from Idaho Power’s proposed 2010 NPSE.  The effect of removing Hoku’s loads and revenues reduces the proposed NPSE by $3,992,955.

 

Other Changes in Load

                  The Company's annual normalized system load used in its last general rate case, Staff notes, was 15.9 million megawatt-hours (MWh).  The Company's 2010 annual normalized system load based on the 2010 test year is 15.7 million MWh, a decrease of 200,000 MWh.  The load forecast used by the Company for 2010 is the same forecast used in the recent Langley Gulch case (IPC-E-09-03) that matches the Company’s 2010 load forecast in its 2009 IRP.

 

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Non-PURPA Purchases and Surplus Sales Revenue

                  Under Idaho Power’s proposal, a projected decrease in surplus sales revenue accounts for an increase in NPSE of nearly $24 million, almost one-third of the approximately $75 million total increase in NPSE (Idaho jurisdiction).  The decrease in surplus sales revenue can be attributed to much lower electric market prices, which in turn, are caused by much lower assumed natural gas prices.  In Idaho Power’s 2008 general rate case, Henry Hub gas prices during the 2009 pro forma year were assumed to be $7.74 per MMBtu.  In this case, the Company has assumed gas prices for 2010 to be $5.79.  Corresponding to the projected decrease in surplus sales revenue, Idaho Power’s analysis also projects an increase in non-PURPA purchases.  Staff concurs with the Company’s projections.

                  In conclusion, Staff proposes a total Idaho NPSE for 2010 of $209,729,358 ($220,770,137 system).  This represents an increase over 2008-authorized Idaho NPSE of $63,701,694.

 

Idaho Irrigation Pumpers Association, Inc. (IIPA)

                  IIPA acknowledges the concerns raised by other parties to this case and recommends that the following expenses be excluded from base NPSE, until such time as they are appropriately resolved, i.e.,

                  1.  Coal costs for Bridger

                  2.  Hoku contract load adjustment

                  3.  PURPA contract adjustment

                  IIPA raises specific concerns regarding the AURORA power supply economic dispatch model used by the Company and what it contends are counter-intuitive results that based on IIPA’s preliminary review of the results of the modeled NPSE do not conform to actual operation.  IIPA believes parties should have a chance to further test the validity of the assumptions and results of AURORA in a true hearing setting citing (a) operation of Bennett Mountain, (b) operation of Danskin, (c) logic areas, (d) DSM curtailment programs, and (e) wholesale market transactions.

                                                                         

 

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                  Why should ratepayers bear the risk of “uncontested” model errors, IIPA queries, and then be refunded only 95% of the difference through the PCA?  IIPA recommends that the Commission authorize an increase no greater than $35 million and hold any further increases until after there has been a full evidentiary review.

                  The normal use of Modified Procedure for a Power Cost Adjustment (PCA) case, IIPA contends, loses all reasonableness when the underlying foundation for a PCA case – the base NPSE – is also processed on Modified Procedure and where there is no universal agreement to the values, procedures, and data being used.  IIPA requests a hearing, workshop, or some other forum to allow IIPA more time to review the prudency of Idaho Power’s modeled power costs.  IDAPA 31.01.01.203.

 

Industrial Customers of Idaho Power (ICIP)

                 ICIP filed both comments and a protest.  ICIP recommends that the Commission disallow inclusion of increased costs of surface coal mined from the Company’s affiliate coal mine for its Jim Bridger coal plant and recommends the establishment of procedures for future affiliate transactions.

                  ICIP argues that the affiliate transactions presented in this case are not the result of arm’s length negotiations and that a higher level of review is necessary to determine the reasonableness of the affiliate transaction costs.  ICIP contends that Idaho Power has not provided adequate information in a timely fashion for the Commission and interested parties to fully consider and vet this issue.  ICIP recommends that the Commission require the Company to prove that there is no other market for additional coal, or on a long-term basis that their affiliate surface-mined coal is cheaper than “market priced coal.”  ICIP also recommends that the Commission require the Company to file for pre-approval of increases in costs for supplies provided by an affiliate.

                  ICIP asserts that the Commission has no official policy on how to charge ratepayers for a utility’s affiliate-provided expenses and recommends that the Commission require that affiliate costs be recorded in the utility’s accounts at the affiliate’s cost or the market rate, whichever is lower.

                  ICIP recommends further that the Company be required to account for projected decreases in energy costs from DSM programs; and that the Company not be allowed to factor signed contracts for PURPA that have yet to come online or projected new Hoku load that is not yet online into its base level NPSE.

 

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Idaho Power Reply

                 Idaho Power notes that the Company’s intention to file this case was set forth in the Settlement Stipulation approved in Case No. IPC-E-09-30.  Idaho Power states it is willing to accept a reduced 2010 NPSE increase of $63,701,694, the increase proposed by Staff.  The Company’s 2010 Bridger coal costs, it contends, as Staff recommends, should be included in base NPSE rates, subject to review and potential refund in the 2011 PCA.  If the Commission were to find that the Company’s acquisition of Bridger Coal Company coal is imprudent, 100% of the imprudent costs would be returned to customers, not 95% as alleged by ICIP.   Arguing that it has made a prima facie case in reply comments for inclusion of same, the Company submits that “Staff, ICIP and the Irrigators should carry the burden going forward with the evidence on Bridger coal costs.”  The Company recommends that the other proposed adjustments be rejected.

                  Idaho Power contends that the Commission since the mid-70s has been aware of and has acknowledged that the transactions between Idaho Power and Bridger Coal Company (BCC) pose no risk of cross-subsidization because of the unique manner by which the Commission addresses IERCO’s operations for ratemaking purposes.  Unlike other utility affiliates, for ratemaking purposes IERCO’s operations, the Company states, are merged with those of Idaho Power.  Idaho Power defends its continued use of surface-mined BCC coal on the grounds that reducing purchases from BCC and buying more coal from Black Butte would result in an increase in overall coal costs.  Additional purchases of Black Butte coal, it states, are not a viable alternative to purchases from BCC.  Nor, it states, are coal purchases from the Powder River Basin or other market alternatives.  ICIP’s speculation that there is less expensive coal available, it argues, is unfounded.  Regarding ICIP’s assertion that the Commission has no policy regarding affiliate transactions, Idaho Power disagrees.  The Company states it is now purchasing, and always has purchased, coal for the Bridger plant at the lower of cost or market.  Citing compliance with Order No. 30530; Revised Code of Conduct ¶ 8(g)

IDACORP and Idaho Power Company commit to use asymmetrical pricing (i.e., lower of cost or market for transactions to Idaho Power Company and higher of cost or market for transactions from Idaho Power Company) for

 

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affiliate charges or costs not covered by provisions of any cost sharing agreement or Service Level Agreements (SLA), if a readily identifiable market for the goods, services or assets exists, and if the transaction involves a cost of more than $100,000.

Revised Code of Conduct, p. 2.  No new Orders or filing requirements, the Company contends, are necessary.

                  The Company agrees with the Staff-proposed adjustments to PURPA costs and Hoku loads and revenues conceding the uncertainty associated with each.

                  The Company disputes the Irrigator criticisms of the AURORA model noting that it is improper to compare actual operation of the Company’s gas peaker plants to the AURORA modeled results for those same units.  The Irrigators, it contends, fail to recognize that the modeling undertaken in this case is based on a normalized annual test period and not actual monthly generation.  The Company notes that Staff concluded that the results that Idaho Power presented in its AURORA analysis were reasonable.  Citing Staff Comments, p. 7.  Perhaps one of the reasons the Irrigators’ conclusions differ from Staff’s, the Company posits, is that the Irrigators did not participate in the settlement workshop held in this case on March 2, 2010.

 

COMMISSION FINDINGS

                  The Commission has reviewed and considered the filings of record in Case No. IPC-E-10-01 including the Application and supporting testimony of the Company, the comments and recommendations of Commission Staff, IIPA and ICIP, and the Company’s reply comments and supporting testimony.  We have also reviewed ¶ 7.1 of the Settlement Stipulation approved in Order No. 30978, Case No. IPC-E-09-30, regarding the Company’s intention to request changes to the net power supply expense (NPSE) base level used for base rates and PCA calculations.  We acknowledge that Idaho Power, Staff, IIPA and ICIP were signatory parties to the Stipulation.

                  We find that the adjustments proposed by Staff, IIPA and ICIP, and agreed to by the Company for PURPA contracts ($7,108,922) and Hoku ($3,992,955) to be reasonable reductions to the Company’s proposed NPSE increase.

                  In arguing the merits of including or excluding the increased cost of coal for the Bridger plant in the NPSE, Idaho Power provided copies of testimony filed at the Oregon Public Utility Commission.  The testimony filings reveal only that the parties are not in agreement.

 

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This Commission has a practice of developing its own record of proceedings for decision and expects the parties to adhere to this protocol.  We find the Company and Staff’s argument for inclusion of increased coal costs in the NPSE base level persuasive.  In authorizing an inclusion of the Company-proposed increase in Bridger coal costs, we provide the Company with a working number for its PCA filing.  Recognizing that Staff, IIPA and ICIP have yet to complete their analysis of the proposed increase in Bridger coal costs, we provide the opportunity for further investigation and assessment in the context of the Company’s 2010-2011 PCA docket.  We expect the Company in that docket to support its proposed adjustment to Bridger coal costs.  We reject its contention that a prima facie case has been made for inclusion of same and accordingly do not shift the burden of proof on this issue to Staff or others.

                  We find that the NPSE includes the actual benefits (and costs) of implemented DSM programs and reject IIPA’s proposal to further adjust for projected program benefits.

                  We are familiar with the AURORA model used by the Company for power supply modeling and our confidence in its use is not changed by the record developed in this case and the misgivings and suspicions of IIPA.  We encourage IIPA to address its modeling concerns and questions to the Company and if still unsatisfied, present them to us in the PCA docket.

                  We acknowledge that IIPA and ICIP requested a hearing (or other forum) for development of further record on the Company’s requested increase in the base level of NPSE.  Our review of the developed record in this case and decision to defer the final calculation of an authorized NPSE base level to the Company’s upcoming 2010-2011 PCA docket, make it reasonable to issue an Order in this case pursuant to Modified Procedure and without further hearing or notice.  IDAPA 31.01.01.204.

                  We find it reasonable in this case to authorize an increase of $63,701,694 in the Company’s base level NPSE as a working number for the Company’s 2010-2011 PCA filing, deferring final calculation of changes to the authorized NPSE in the PCA filing.

 

CONCLUSIONS OF LAW

                  The Idaho Public Utilities Commission has jurisdiction over Idaho Power Company, an electric utility, and the issues presented in Case No. IPC-E-10-01 pursuant to the authority set forth in Idaho Code, Title 61, and the Commission’s Rules of Procedure, IDAPA 31.01.01.000 et seq.

 

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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 authorize an increase of $63,701,694 in the Company’s base level Net Power Supply Expense (NPSE) as a working number for the Company’s 2010-2011 PCA filing, deferring final calculation of authorized NPSE to the PCA case.  The resultant base level NPSE amount authorized for said purpose is $143,944,947.

                  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 2010.

 

                                                                        /s/                                                                    

                                                                        JIM D. KEMPTON, PRESIDENT

 

 

 

 

                                                                        /s/                                                                    

                                                                        MARSHA H. SMITH, COMMISSIONER

 

 

 

 

                                                                        /s/                                                                    

                                                                        MACK A. REDFORD, COMMISSIONER

 

 

ATTEST:

 

 

/s/                                                                    

Jean D. Jewell

Commission Secretary

 

 

bls/O:IPC-E-10-01_sw2

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