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HomeMy WebLinkAbout20070316Application.pdfIDAHO POWER COMPANY O. BOX 70 BOISE, IDAHO 83707 \?"F ~: F~ \ . An IDACORP Company Lu~1 hi\.\\ \ G F;'. ' \: \ ~ATRICKA. HARRINGTON ' ,,( \)0l\ \\(; , Corporate Secretary\l.1".I'\ /"" \88\(, UT\lJ\\C~'-J ,\'\H March 16, 2007HAND-DELIVERED Ms. Jean D. Jewell Secretary Idaho Public Utilities Commission Statehouse Boise, Idaho 83720 Re:In the Matter of the Application of Idaho Power Company for an Order Authorizing up to $450 000 000 Aggregate Principal Amount at any One Time Outstanding of Short- Term Borrowings Case No. IPC-07- Dear Ms. Jewell: Enclosed please find an original and five (5) copies of Idaho Power s Application in the above referenced case, including a proposed order for the Commission consideration. An electronic copy of the proposed order will also be e-mailed to you. Idaho Power will promptly file the $1 000 securities issuance application fee with the Commission in this case. Please feel free to contact me at 388-2878 or at pharrington~idahopower.com if you have any questions regarding this Supplemental Application filing. 1fih.~ ~a 11 ~ ,;t;; Patrick A. Harringt~if ' Steve Keen Randy Mills Terri Carlock Telephone (208) 388-2878, Fax (208) 388-6936 BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION ;: .~: ("'~ :', .. ' ZiJD7 l:';r.::;))1/,1, II L:, J IN THE MATTER OF THE APPLICATION OF IDAHO POWER COMPANY FOR AN ORDER AUTHORIZING UP TO $450 000 000 AGGREGATE PRINCIPAL AMOUNT AT ANY ONE TIME OUTSTANDING OF SHORT-TERM BORROWINGS CASE NO. IPC-E- -L11!1 /;(' (/Mc (t' ~;~gi' - '", '-" J! \.) 0' 0,"APPLICATION IDAHO POWER COMPANY (the "Applicant") hereby applies for an Order of the Idaho Public Utilities Commission (the "Commission ) authorizing the Applicant to make up to $450 000 000 aggregate principal amount at anyone time outstanding of short-term borrowings as set forth herein, pursuant to Chapter 9, Title 61 , Idaho Code, and under Rules 141 through 150 of the Commission s Rules of Procedure (the "Rules (1)The Applicant Applicant is an electric public utility incorporated under the laws ofthe state ofIdaho engaged principally in the generation , purchase, transmission, distribution and sale of electric energy in an approximately 24 000 square mile area in southern Idaho and eastern Oregon. The principal executive offices of the Applicant are located at 1221 W. Idaho Street, P.O. Box 70, Boise, Idaho 83707-0070; its telephone number is (208) 388-2200. (2)Description of Securities Applicant's short-term borrowings hereunder will consist of (1) loans issued by financial and other institutions and evidenced by unsecured notes or other evidence of indebtedness of Applicant and (2) unsecured promissory notes and commercial paper of Applicant to be issued for public or private placement through one or more commercial paper dealers or agents, or directly by Applicant. APPLICATION - Applicant intends to secure commitments for new unsecured lines of credit, or extensions of existing unsecured lines of credit, for its short-term borrowings hereunder. The unsecured lines of credit may be obtained with several financial or other institutions, directly by the Applicant or through an agent, when and if required by Applicant's then current financial requirements (see paragraph (4) Purpose of Issuance). Each individual line of credit commitment will provide that up to a specific amount at anyone time outstanding will be available to Applicant to draw upon for a fee to be determined by a percentage of the credit line available, credit line utilization, compensating balance or combination thereof. Applicant may also make arrangements for uncommitted credit facilities under which unsecured lines of credit would be offered to Applicant on an "as available" basis and at negotiated interest rates. Such committed and uncommitted borrowings will be evidenced by unsecured promissory notes or other evidence of indebtedness of Applicant. The committed and uncommitted line of credit agreements specifying the terms of Applicant's short-term borrowings will be filed with the Commission as Exhibit A to this Application. Unsecured promissory notes will be issued and sold by Applicant through one or more commercial paper dealers or agents , or directly by Applicant, up to the limits imposed by applicable statutes, rules or regulations. Each note issued as commercial paper will be either discounted at the rate prevailing at the time of issuance for commercial paper of comparable quality and maturity or will be interest bearing to be paid at maturity. Each note will have a fixed maturity and will contain no provision for automatic "roll over Applicant expects to enter into a new or amended credit agreement in the spring of 2007, providing a committed line of credit from participating banks for short-term borrowings of up APPLICATION - 2 to $450 million aggregate principal amount at anyone time outstanding, for a period of up to seven years, from April 2007 through April 2014, as further described below (the "Credit Agreement" The Credit Agreement is expected to provide reduced annual fees and expenses as compared with Applicant's current credit agreement. The Credit Agreement would also provide expanded short- term borrowing capacity for Applicant's increasing utility capital expenditure requirements , as well as a longer bank commitment period. Applicant plans to use the Credit Agreement primarily as a backup credit facility to enhance the credit ratings for its commercial paper issuances, but may also borrow directly under the Credit Agreement as it deems necessary or desirable. (a)Amount of Securities Applicant's short-term borrowings will not exceed a maXImum $450 million aggregate principal amount at anyone time outstanding during the term of the Commission authorization hereunder. Applicant expects that its Credit Agreement will initially authorize Applicant to borrow up to $300 million aggregate principal amount at anyone time outstanding, with the option of Applicant to increase the borrowing limit to $450 million during the term ofthe Credit Agreement. Applicant will provide written notice to the Commission in the event Applicant exercises its right to increase the Credit Agreement borrowing limit above $300 million. (b)Interest Rate Applicant anticipates that its short-term borrowings hereunder will include interest rates that may be fixed or variable, and that the rates will be based on LIBOR, the applicable prime rate, or other rate established in the borrowing arrangements , and may vary based upon the ratings of Applicant's first mortgage bonds or Applicant's corporate credit rating. (c)Date of Issue APPLICATION - 3 Applicant requests authority to make short-term borrowings hereunder for a seven (7) year period, from April 1 , 2007 through April 1 , 2014. Applicant expects that the Credit Agreement will allow borrowings for an initial five (5) year period, from April 2007 through April 2012, with the option of Applicant to extend the borrowing period for two one-year extensions , up to April 2014. Applicant will notify the Commission in writing if it elects to exercise either of the one-year extensions to the Credit Agreement beyond April 2012. In no event will the term of any Applicant short-term borrowings hereunder extend beyond April 1 , 2014. Applicant is requesting authorization to make the short-term borrowings as described in this Application during the seven-year period from April 1 , 2007 through April 1, 2014, so long as Applicant maintains at least a BBB- or higher senior secured debt rating, as indicated by Standard & Poor s Ratings Services , and a Baa3 or higher rating as indicated by Moody s Investors' Service, Inc. Applicant requests that if its senior secured debt rating falls below either such rating ("Downgrade its short-term borrowing authority will continue for a period of 364 days from the date of the Downgrade ("Continued Authorization Period"), provided that the Applicant: (1)Promptly notifies the Commission in writing of the Downgrade; and (2)Files a supplemental application with the Commission within seven (7) days after the Downgrade, requesting a supplemental order ("Supplemental Order ) authorizing Applicant to continue to make short-term borrowings and issue commercial paper as provided in the Order, notwithstanding the Downgrade. Until Applicant receives the Supplemental Order, any short- term borrowings made or commercial paper issued by Applicant during the APPLICATION - 4 Continued Authorization Period would become due or mature no later than the final date of the Continued Authorization Period. (d)Date of Maturity The proposed short-term borrowings will have maturities of one year or less. Applicant is seeking authorization to make short-term borrowings at any time hereunder so long as the borrowings made or commercial paper issued mature no later than April 1 , 2014. (e)Voting Privileges Not applicable. (f)Call or Redemption Provisions Not applicable. (g) Sinking Fund or Other Provisions for Secured Payment Not applicable. (3)Manner of Issuance (a)Method of Marketing Applicant's line of credit arrangements are expected to include one or more lead agents, and a number of additional banks as participating agents. The Credit Agreement would likely include the following fees for the lead agent(s) and participating agents: an up-front arrangement fee payable to the lead agent(s) totaling approximately $225 000; up-front agent participation fees payable to all participating agents totaling approximately $87 500; annual commitment agent facility fees payable to all participating agents totaling approximately $210 000 per year; and annual administrative fees payable to the lead agent(s) of approximately $15 000 per year. Other expenses relating to the Credit Agreement line of credit facility are estimated to include: Applicant's legal fees APPLICATION - 5 of approximately $30 000, agent legal fees of approximately $30 000, and miscellaneous expenses of 000. An extension of any existing line of credit syndicated facility would likely involve similar fees. The expected Credit Agreement annual fees would represent a reduction in Applicant's current credit agreement annual fees. The fees are customary for the market and will offset the agents' costs including personnel time, travel and administrative costs associated with negotiating and administering the unsecured lines of credit. The Applicant finds these fees are reasonable given the services provided by the agents. With respect to commercial paper issuances, it is expected that the commercial paper dealers or agents will sell such notes at a profit to them of not to exceed 1/8 of percent of the principal amount of each note. (b)Terms of Sale See paragraph (3)(a), Method of Marketing. (c)Underwriting Discounts or Commissions (A)Reference is made to paragraph (3)(a), Method of Marketing, which specifies the method of payment of fees to the financial or other institutions. (B)It is expected that the commercial paper dealers or agents will sell such notes at a profit to them of not to exceed 1/8 of 1 percent of the principal amount of each note. (iv)Sales Price See paragraph (3)(c), Underwriting Discounts or Commissions. (4)Purpose of Issuance The net proceeds to be received by the Applicant from the short-term borrowings hereunder will be used to obtain temporary short-term capital for the acquisition of property; the construction, completion, extension or improvement of its facilities; the improvement or APPLICATION - 6 maintenance of its service; the discharge or lawful refunding of its obligations; and for general corporate purposes. (5)Statement of Explanation Applicant believes and alleges the facts set forth in paragraph (4), Purpose of Issuance, disclose that the proposed short-term borrowings are for a lawful object within the corporate purposes of Applicant and compatible with the public interest, and are necessary or appropriate for, or consistent with, the proper performance by Applicant of service as a public utility and will not impair its ability to perform that service. (6)Financial Statements; Resolutions Attached to this application as Attachment I are Applicant's financial statements dated as of December 31 , 2006 , consisting of its (A) Actual and Pro Forma Balance Sheet and Notes to Financial Statements , (B) Statement of Capital Stock and Funded Debt, (C) Commitments and Contingent Liabilities , (D) Statement of Retained Earnings and (E) Statement of Income. A certified copy of the resolutions of Applicant s Directors authorizing the short-term borrowings with respect to this Application will be filed as Attachment II after the Directors ' March 2007 board meeting. (7)Proposed Order Attached to this application as Attachment III is a Proposed Order for consideration by the Commission in this matter. (8)Notice of Application Notice of this Application will be published in those newspapers in Applicant service territory listed in Rule 141(h) of the Rules within seven (7) days after the date hereof. APPLICATION - 7 (9)Reports Applicant will file as Exhibit A hereto, a verified report with the Commission pursuant to Rule 143 , listing Applicant's agreements for the committed and uncommitted unsecured lines of credit and other agreements evidencing the borrowing arrangements hereunder. PRA YER WHEREFORE, Applicant respectfully requests that the Idaho Public Utilities Commission issue its Order authorizing Applicant to make up to $450 000 000 aggregate principal amount at anyone time outstanding of short-term borrowings , for the period from April 1 , 2007 through April 2014, under the terms and conditions and for the purposes set forth in this application. DATED at Boise, Idaho this llit~ay of March, 2007. (CORPORA TE SEAL) ~~~fOWE ~ANY :;-- i,-Q-:K~' '---Is/Steven R. Keen Vice President and Treasurer ATTEST: ftn/; 1111. /s/ Patrick A. Harrin Secretary Idaho Power Company 1221 W. Idaho Street O. Box 70 Boise, ID 83707-0070 APPLICATION - 8 VERIFICA TION , Steven R. Keen, declare that I am the Vice President and Treasurer of Idaho Power Company, and am authorized to make this Verification. The application and the attached exhibits were prepared at my direction and were read by me. I know the contents of the Application and the attached exhibits, and they are true, correct and complete to the best of my knowledge and belief. WITNESS my hand and seal of Idaho Power Company this day of March, 2007. ~~. Jsr-steven R. Keen SUBSCRIBED AND SWORN to me this IfI..,J.day of March, 2007. , """""" " ~ Y Oil " +~......... -i . ~ ;,o/ (N~arv. Seal). I ~O"All r -.- \. \ PUB\'\.: I~IP.ro.. ~ .;. .. .. ~ ..."" l'- -f 1'. ........ to- " "E OF \'Q " ",......" 7117 /;;'OID APPLICATION - 9 ATTACHMENT I(A) IDAHO POWER COMPANY BALANCE SHEET As of December 31 2006 ASSETS Electric Plant: In service (at original cost)................................................................. Accumulated provision for depreciation........................................ In service .. Net............................................................................. Construction work in progress............................................................ Held for future use.............................................................................. Electric plant - Net........................................................................ Investments and Other Property: Nonutility property.............................................................................. Investment in subsidiary companies """"".'.""'."".""."".""'."""'" Other.................................................................................................. Total investments and other property................................................. Current Assets: Cash and cash equivalents................................................................ Receivables: Customer....................................................................................... Allowance for uncollectible accounts............................................ Notes............................................................................................. Employee notes ........................................................................... Related party..........................................................."'.""""""""'. Other....................................................."""".'.".".".."""""""'.'" Accrued unbilled revenues................................................................. Materials and supplies (at average cost)............................................ Fuel stock (at average cost)............................................................... Prepayments...... ................................................................................ Regulatory assets .............................................................................. Total current assets....................................................................... Deferred Debits: American Falls and Milner water rights.............................................. Company owned life insurance......................................... ,................ Regulatory assets associated with income taxes............................... Regulatory assets - PCA.................................................................... Regulatory assets - other................................................................... Employee notes.................................................................................. Other.................................................................................................. Total deferred debits.......................................................................... Total................................................................................................... Actual After AdjustmentsAdjustments 583 693 910 (1,406,209 951 ) 177 483 959 210 094 019 809 770 390 387 748 583 693 910 (1,406 209 951) 177 ,483 959 210 094 019 809 770 390 387 748 976 937 223,499 043 654 976 937 223,499 043 654 244 090 244 090 2,404 300 450 000 000 452,404 300 218 159 (968 073) 514 375 568,452 218 159 (968 073) 514 375 568,452 591 728 365 181 078 217 173 831 952 014 1,479 782 591 728 365 181 078 217 173 831 952 014 1,479 782 165 377 965 450 000 000 615 377 965 542 991 055 047 343 572 509 559,464 70,416 373 2,410 706 158 230 542 991 055 047 343 572 509 559,464 70,416 373 2,410 706 158 230 530 715 320 530 715 320 $ 450 000 000 $627 725 124177725124 c:\documents and settings\pah2878\local settings\temporary internet files\olk52f\balance sheet.xls IDAHO POWER COMPANY BALANCE SHEET As of December 2006 CAPITALIZATION AND LIABILITIES Common Shares Common SharesAuthorized Outstanding Equity Capital: 000 000 150 812 Common stock................................................................................... Premium on capital stock................................................................... Capital stock expense........................................................................ Retained earnings.............................................................................. Accummulated other comprehensive income.................................... Total equity capitaL....................................................................... Long-Term Debt: First mortgage bonds ........................................................................ Pollution control revenue bonds ........................................................ American Falls bond and Milner note guarantees ............................. Unamortized discount on long-term debt (Dr).................................... Total long-term debt..................................................................... Current Liabilities: Long-term debt due within one year................................................... Notes payable.................................................................................... Accounts payable .............................................................................. Notes and accounts payable to related parties.................................. Taxes accrued..................................................""""""""""""""""" Interest accrued................................................................................. Deferred income taxes....................................................................... Other.................................................................................................. Total current liabilities................................................................... Deferred Credits: Regulatory liabilities associated with accumulated deferred investment tax credits .................................................................. Deferred income taxes....................................................................... Regulatory liabilities associated with income taxes ........................... Regulatory liabilities-other........................................""""""""""""" Other.................................................................................................. Total deferred credits.................................................................... Total.............................................................................................. Actual Adjustments 877 030 530 757,435 096 925) 404 075 976 737 123) 024 876 394 705 000 000 170,460 000 521 363 097 272) 902 884 091 After Adjustments 877 030 530 757 435 096 925) 404;075 976 737 123) 024 876 394 705 000 000 170,460 000 521 363 097 272) 902 884 091 063 637 200 000 713 626 110 966 688 295 324 003 145 366 955 450 000 000 063 637 502 200 000 713 626 110 966 688 295 324 003 145 366 955 298,484 627 450 000 000 748,484 627 113 142 113 142 489 234 243 489 234 243 825 257 825 257 183 905 786 183 905 786 167,401 584 167,401 584 951,480 011 951,480 011 177 725 124 450 000 000 627 725 124 c:\documents and settings\pah2878\1ocal settings\temporary internet files\olk52f\balance sheet xis IDAHO POWER COMPANY STATEMENT OF ADJUSTING JOURNAL ENTRIES As of December 31 , 2006 Giving Effect to the Proposed issuance of Short-term notes Entry No. Cash,.,.."....."""",........,..,.,....,."""","",."""",'.'...........,.,.....",."450 000 000 Notes payable""""".,.,."",...........,.....""...,.",.""""""'.'""'.',,,,'."..,,,'."..',,'... To record the proposed issuance of short-term notes and the receipt of cash. c:\documents and sel1ings\pah2878\local sel1ings\temporary internet files\olk52f1adjusting entries,xls 450 000 000 IDAHO POWER COMPANY CONDENSED NOTES TO FINANCIAL STATEMENTS As of December 31 2006 1. Management Estimates Management makes estimates and assumptions when preparing financial statements in conformity with accounting principles generally accepted in the United States of America. These estimates and assumptions including those related to rate regulation, benefit costs, contingencies, litigation , asset impairment, income taxes, un billed revenues and bad debt, affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. These estimates involve judgments with respect to among other things, future economic factors that are difficult to predict and are beyond management' control. As a result, actual results could differ from those estimates. 2. Regulation of Utility Operations I PC follows SF AS 71 Accounting for the Effects of Certain Types of Regulation and its financial statements reflect the effects of the different rate-making principles followed by the jurisdictions regulating IPC. The application of SFAS 71 by IPC can result in IPC recording expenses in a period different than the period the expense would be recorded by an unregulated enterprise. When this occurs, costs are deferred as regulatory assets on the balance sheet and recorded as expenses in the periods when those same amounts are reflected in rates. Additionally, regulators can impose regulatory liabilities upon a regulated company for amounts previously collected from customers and for amounts that are expected to be refunded to customers. IPC has a Power Cost Adjustment (PCA) mechanism that provides for annual adjustments to the rates charged to its Idaho retail customers. These adjustments are based on forecasts of net power supply costs which are fuel and purchased power less off-system sales, and the true-up of the prior year s forecast. During the year, 90 percent of the difference between the actual and forecasted costs is deferred with interest. The ending balance of this deferral, called the true-up for the current year s portion and the true-up of the true-up for the prior years' unrecovered or over-recovered portion , is then included in the calculation of the next year s PCA. The effects of applying SFAS 71 are discussed in more detail in Note 12 - "Regulatory Matters. 3. Cash and Cash Equivalents Cash and cash equivalents include cash on hand and highly liquid temporary investments with maturity dates at date of acquisition of three months or less. 4. Derivative Financial Instruments Financial instruments such as commodity futures, forwards, options and swaps are used to manage exposure to commodity price risk in the electricity market. The objective of the risk management program is to mitigate the risk associated with the purchase and sale of electricity and natural gas. The accounting for derivative financial instruments that are used to manage risk is in accordance with the concepts established by SF AS 133 Accounting for Derivative Instruments and Hedging Activities as amended. 5. Property, Plant and Equipment and Depreciation The cost of utility plant in service represents the original cost of contracted services, direct labor and material Allowance for Funds Used During Construction (AFDC) and indirect charges for engineering, supervision and similar overhead items. Maintenance and repairs of property and replacements and renewals of items determined to be less than units of property are expensed to operations. Repair and maintenance costs associated with planned major maintenance are recorded as these costs are incUrred. For utility property replaced or renewed, the original cost plus removal cost less salvage is charged to accumulated provision for depreciation , while the cost of related replacements and renewals is added to property, plant and equipment. All utility plant in service is depreciated using the straight-line method at rates approved by regulatory authorities. Annual depreciation provisions as a percent of average depreciable utility plant in service approximated 2.75 percent in 2006,91 percentin 2005 and 2.96 percent in 2004. CONDENSED NOTES TO FINANCIAL STATEMENTS (Continued) Long-lived assets are periodically reviewed for impairment when events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable as prescribed under SFAS 144. SFAS 144 requires that if the sum of the undiscounted expected future cash flows from an asset is less than the carrying value of the asset, an asset impairment must be recognized in the financial statements. 6. Revenues Operating revenues for IPC related to the sale of energy are generally recorded when service is rendered or energy is delivered to customers. IPC accrues unbilled revenues for electric services delivered to customers but not yet billed at period-end. IPC collects franchise fees and similar taxes related to energy consumption. Th~se amounts are recorded as liabilities until paid to the taxing authority. None of these collections are reported on the income statement as revenue or expense. 7. Allowance for Funds Used During Construction AFDC represents the cost of financing construction projects with borrowed funds and equity funds. While cash is not realized currently from such allowance, it is realized under the rate-making process over the service life of the related property through increased revenues resulting from a higher rate base and higher depreciation expense. The component of AFDC attributable to borrowed funds is included as a reduction to interest expense, while the equity component is included in other income. IPC's weighted-average monthly AFDC rates for 2006 2005 and 2004 were 7.6 percent, 7.4 percent and 6.9 percent, respectively. IPC' reductions to interest expense for AFDC were $4 million for 2006 and $3 million for both 2005 and 2004. Other income included $6 million , $5 million and $4 million of AFDC for 2006 , 2005 and 2004 , respectively. 8. Income Taxes The liability method of computing deferred taxes is used on all temporary differences between the book and tax basis of assets and liabilities and deterred tax assets and liabilities are adjusted for enacted changes in tax laws or rates. Consistent 'with orders and directives of the Idaho Public Utilities Commission (IPUC), the regulatory authority having principal jurisdiction , IPC's deferred income taxes (commonly referred to as normalized accounting) are provided for the difference between income tax depreciation and straight-line depreciation computed using book lives on coal~fired generation facilities and properties acquired after 1980. On other facilities , deferred income taxes are provided for the difference between accelerated income tax depreciation and straight-line depreciation using tax guideline lives on assets acquired prior to 1981. Deferred income taxes are not provided for those income tax timing differences where the prescribed regulatory accounting methods do not provide for current recovery in rates. Regulated enterprises are required to recognize such adjustments as regulatory assets or liabilities if it is probable that such amounts will be recovered from or returned to customers in future rates. See Note 2 for more information. The State of Idaho allows a three-percent investment tax credit on qualifying plant additions. Investment tax credits earned on regulated assets are deferred and amortized to income over the estimated service lives of the related properties. Credits earned on non-regulated assets or investments are recognized in the year earned. 9. Stock-Based Compensation Effective January 1 , 2006, IPC adopted SFAS No. 123 (revised 2004), Share-Based Payment" (SFAS 123(R)) using the modified prospective application method. SFAS 123(R) changes measurement, timing and, disclosure rules relating to share-based payments, requiring that the fair value of all share-based payments be expensed. The adoption of SFAS 123(R) did not have a material impact on IPC's financial statements for the year ended December 31 , 2006. IPC's Consolidated Statements of Income for the years ended December 31 2005 and 2004 do not reflect any changes from the adoption of SFAS 123(R). In those years , stock based employee compensation was accounted for under the recognition and measurement principles of Accounting Principles Board (APB) Opinion 25, Accounting for Stock Issued to Employees and related interpretations. The following table illustrates what net income and earnings per share would have been had the fair value recognition provisions of SFAS 123 been applied to stock-based employee compensation in 2005 and 2004 (in thousands of dollars, except for per share amounts): CONDENSED NOTES TO FINANCIAL STATEMENTS (Continued) IPC Net income, as reported Add: Stock-based employee compensation expense included in reported net income, net of related tax effects Deduct: Stock-based employee compensation expense determined under fair value based method for all awards net of related tax effects Pro forma net income 2005 2004 839 608 108 276 568 977 71 ,379 907 For purposes of these pro forma calculations, the estimated fair value of the options, restricted stock and performance shares is amortized to expense over the vesting period. The fair value of the restricted stock and performance shares is the market price of the stock on the date of grant. The fair value of an option award is estimated at the date of grant using a binomial option-pricing model. Expense related to forfeited options is reversed in the period in which the forfeit occurs. 10. Comprehensive Income Comprehensive income includes net income , unrealized holding gains and losses on marketable securities IPC's proportionate share of unrealized holding gains and losses on marketable securities held by an equity investee and amounts related to pension plans. In 2006, IDACORP adopted SFAS 158 Accounting for Pension and Postretirement Costs an amendment of FAS , 88, 106, and 132(R)"which required the company to record additional amounts related to pension plans in other comprehensive income. SFAS 158 is discussed in more detail in Note 9. Prior to December 2005, other comprehensive income included the additional minimum liability related to a deferred compensation plan for certain senior management employees and directors. The following table presents IDACORP's and IPC's accumulated other comprehensive loss balance at December 31: Unrealized holding gains on securities Defined benefit pension plans Total 2006 2005 (thousands of dollars)311 048) 737) 725 150 (3,425) 11, Other Accounting Policies Debt discount, expense and premium are deferred and being amortized over the terms of the respective debt issues. 12, Reclassifications Certain items previously reported for years prior to 2006 have been reclassified to conform to the current year s presentation. Net income and shareholders' equity were not affected by these reclassifications. 13. New Accounting Pronouncements FIN 48: In June 2006, the Financial Accounting Standards Board (FASB) issued FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes an interpretation of FASB Statement No. 109' (FIN 48), to create a single model to address accounting for uncertainty in tax positions. FIN 48 prescribes a minimum recognition threshold that a tax position is required to meet before being recognized in a company s financial statements and also provides guidance on derecognition, measurement, classification, interest and penalties, accounting in interim periods, disclosure, and transition. FIN 48 is effective for fiscal years beginning after December 15 , 2006. IDACORP and IPC will adopt FIN 48 in the first quarter of 2007, as required. The cumulative effect of adopting FIN 48 will be recorded as an adjustment to 2007 opening retained earnings. IDACORP and IPC have not yet completed their evaluation of the effects the adoption of FIN 48 will have on their financial CONDENSED NOTES TO FINANCIAL STATEMENTS (Continued) positions or results of operations. SFAS 157: In September 2006, the FASB issued SFAS 157 Fair Value Measurements.SFAS 157 defines fair value , establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. SFAS 157 is effective for financialstatements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscalyears. IDACORP and IPC are currently evaluating the impact of adopting SFAS 157 on their financial statements. SFAS 159: In February 2007, the FASB issued SFAS No. 159 The Fair Value Option for Financial Assets and Financial Liabilities Including an Amendment of FASB Statement No. 115" (SFAS 159). This standard permits an entity to choose to measure many financial instruments and certain other items at fair value. Most of the provisions in SFAS 159 are elective; however, the amendment to SFAS No. 115 Accounting for Certain Investments in Debt and Equity Securities applies to all entities with available-for-sale and trading securities. The fair value option established by SFAS 159 permits all entities to choose to measure eligible items at fair value at specified election dates. A business entity will report unrealized gains and losses on items for which the fair value option has been elected in earnings at each subsequent reporting date. The fair value option: (a) may be applied instrument by instrument, with a few exceptions, such as investments otherwise accounted for by the equity method; (b) is irrevocable (unless a new election date occurs); and (c) is applied only to entire instruments and not to portions of instruments. SFAS 159 is effective as of the beginning of an entity s first fiscal year that begins after November 15, 2007. Early adoption is permitted as of the beginning of the previous fiscal year provided that the entity makes that choice in the first 120 days of that fiscal year and also elects to apply the provisions of SFAS No. 157 Fair Value Measurements.IDACORP and IPC are currently evaluating the impact of SFAS 159. 14. Deferred Power Supply Costs Idaho: IPC has a Power Cost Adjustment (PCA) mechanism that provides for annual adjustments to the rates charged to its Idaho retail customers. These adjustments are based on forecasts of net power supply costs, which are fuel and purchased power less off-system sales, and the true-up of the prior year s forecast. During the year 90 percent of the difference between the actual and forecasted costs is deferred with interest. The ending balance of this deferral, called the true-up for the current year s portion and the true-up of the true-up for the prior years unrecovered portion, is then included in the calculation of the next year s PCA. 15. Financing At December 31 2006 and 2005, the overall effective cost of IPC's outstanding debt was 5.71 percent and 84 percent, respectively. On October 3,2006, IPC completed a tax-exempt bond financing in which Sweetwater County, Wyoming issued and sold $116.3 million aggregate principal amount of its Pollution Control Revenue Refunding Bonds Series 2006. The bonds will mature on July 15, 2026. The $116.3 million proceeds were loaned by Sweetwater County to IPC pursuant to a loan agreement, dated as of October 1 2006, between Sweetwater County and IPC. On October 10, 2006, the proceeds of the new bonds, together with certain other moneys of IPC, were used to refund Sweetwater County s Pollution Control Revenue Refunding Bonds Series 1996A Series 1996B and Series 1996C totaling $116.3 million. The regularly scheduled principal and interest payments on the Series 2006 bonds, and principal and interest payments on the bonds upon mandatory redemption on determination of taxability, are insured by a financial guaranty insurance policy issued by AMBAC Assurance Corporation. IPC and AMBAC have entered into an Insurance Agreement, dated as of October 3 2006, pursuant to which IPC has agreed , among other things, to pay certain premiums to AMBAC and to reimburse AMBAC for any payments made under the policy. To secure its obligation to make principal and interest payments on the loan made to IPC, IPC issued and delivered to a trustee IPC's First MortgageBonds, Pollution Control Series C , in a principal amount equal to the amount of the new bonds. Long-Term Financing: IPC has in place a registration statement that can be used for the issuance of an aggregate principal amount of $240 million of first mortgage bonds (including medium-term notes) and unsecured debt. In January 2007, the IPC Board of Directors approved an increase of the maximum amount of first mortgage CONDENSED NOTES TO FINANCIAL STATEMENTS (Continued) bonds issuable by IPC to $1.5 billion. The amount issuable is also restricted by property, earnings and other provisions of the mortgage and supplemental indentures to the mortgage. IPC may amend the indenture and increase this amount without consent of the holders of the first mortgage bonds. The indenture requires that IPC's net earnings must be at least twice the annual interest requirements on all outstanding debt of equal or prior rank, including the bonds that IPC may propose to issue. Under certain circumstances, the net earnings test does not apply, including the issuance of refunding bonds to retire outstanding bonds that mature in less than two years or that are of an equal or higher interest rate , or prior lien bonds. As of December 31 2006, IPC could issue under the mortgage approximately $559 million of additional first mortgage bonds based on unfunded property additions and $452 million of additional first mortgage bonds based on retired first mortgage bonds. At December 31 2006, unfunded property additions were approximately $1.0 billion. The mortgage requires IPC to spend or appropriate 15 percent of its annual gross operating revenues for maintenance , retirement or amortization of its properties. IPC may, however, anticipate or make up these expenditures or appropriations within the five years that immediately follow or precede a particular year. The mortgage secures all bonds issued under the indenture equally and ratably, without preference, priority or distinction. IPC may issue additional first mortgage bonds in the future, and those first mortgage bonds will also be secured by the mortgage. The lien of the indenture constitutes a first mortgage on all the properties of IPC, subject only to certain limited exceptions including liens for taxes and assessments that are not delinquent and minor excepted encumbrances. Certain of the properties of IPC are subject to easements, leases, contracts, covenants, workmen s compensation awards and similar encumbrances and minor defects and clouds common to properties. The mortgage does not create a lien on revenues or profits or notes or accounts receivable, contracts or choses in action , except as permitted by law during a completed default, securities or cash, except when pledged , or merchandise or equipment manufactured or acquired for resale. The mortgage creates a lien on the interest of IPC in property subsequently acquired, other than excepted property, subject to limitations in the case of consolidation, merger or sale of all or substantially all of the assets of IPC. 16. Regulatory Matters Idaho Load Growth Adjustment Rate (LGAR): In April 2006 IPC filed a petition with the IPUC requesting modification of one component of its PCA referred to as the Load Growth Adjustment Rate. The LGAR subtracts the cost of serving new Idaho retail customers from the power supply costs IPC is allowed to include in its PCA. The LGAR was set at $16.84 per megawatt-hour when the PCA began in 1993. This amount was established as the projected marginal cost of serving each new customer and is subtracted from each year PCA expense. In its April 2006 petition , IPC requested using the embedded cost of serving the new load rather than the projected marginal cost and to lower the rate to $6.81 per megawatt-hour. The IPUC Staff recommended against changing to the embedded cost approach; IPUC Staff also recommended increasing the rate to $40.87 per megawatt hour. On January 9, 2007, the IPUC issued its final order in this matter. The IPUC maintained the marginal cost methodology and set the new LGAR at $29.41 per megawatt-hour. The new rate becomes effective on April , 2007 and will first affect customer rates on June 1 , 2008. The impact of the new LGAR on IPC will ultimately be determined by future load growth. Assuming an average 40 megawatt load growth, the new rate would result in approximately $10.3 million subtracted from the next PCA, a pre-tax increase of $4.4 million over the current amount. The impact of the new LGAR can be partially offset by IPC through more frequent general rate case filings with the IPUC or from less customer growth. In its order the IPUC stated that it expected IPC to update its load growth adjustment in all future general rate cases. Oregon: The timing of recovery of Oregon power supply cost deferrals is subject to an Oregon statute that specifically limits rate amortizations of deferred costs to six percent per year. IPC is currently amortizing through rates power supply costs associated with the western energy situation of 2001. Full recovery of the CONDENSED NOTES TO FINANCIAL STATEMENTS (Continued) 2001 deferral is not expected until 2009. For the 2005-2006 deferral , a settlement stipulation drafted by the OPUC Staff provides that, instead of being amortized into rates, the deferral should be offset with the Oregon jurisdictional share of proceeds from the sale of S02 emission allowances and the benefit that IPC will receive from income taxes already paid on the sale of those allowances. An order is expected from the OPUC during the first quarter of 2007. Emission Allowances: During 2005 and 2006, IPC sold 78,000 S02 emission allowances for approximately $81.6 million (before income taxes and expenses) on the open market. After subtracting transaction fees , the total amount of sales proceeds to be allocated to the Idaho jurisdiction was approximately $76.8 million ($46.8 million net of tax, assuming a tax rate of approximately 39 percent). The IPUC allowed IPC to retain ten percent, or approximately $4.7 million after tax, of the emission allowance net proceeds as a shareholder benefit. The remaining 90 percent of the sales proceeds ($69.1 million) plus a carrying charge will be recorded as a customer benefit. This customer benefit will be reflected in PCA rates during the June 1, 2007 through May 31 , 2008, PCA rate year. The carrying charge will be calculated on $42.1 million , the net-of-tax amount allocable to Idaho jurisdiction customers. As discussed above, a stipulation is currently before the OPUC which would offset S02 emission allowance proceeds against the 2005-2006 balance of Oregon deferred power supply costs. The stipulation allows for IPC to retain ten percent of the proceeds from emission allowance sales as a shareholder benefit. Through allowance year 2006 , IPC has approximately 36 000 excess allowances. Deferred (Accrued) Net Power Supply Costs: lPG's deferred net power supply costs consisted of the following at December 31 (in thousands of dollars): 2006 2005 Idaho PCA current year: Deferral for the 2006-2007 rate year Accrual for the 2007-2008 rate year Idaho PCA true-up awaiting recovery (refund): Authorized May 2005 Authorized May 2006 Oregon deferral:2001 costs 6 670 8,4112005 costs 2 889 2 880Total (accrual) deferral $ (5 614) $ 43 542 Includes $69 million of emission allowance sales to be credited to the customers during the 2007- 2008 PCA year 684 (3,484) 567 (11 689) Fixed Cost Adjustment Mechanism (FCA): On January 27, 2006, IPC filed with the IPUC for authority to implement a rate adjustment mechanism that would adjust rates downward or upward to recover fixed costs independent from the volume of IPC's energy sales. This filing is a continuation of a 2004 case that was opened to investigate the financial disincentives to investment in energy efficiency by IPC. This true-up mechanism would be applicable only to residential and small general service customers. The first FCA rate change under this proposal would occur on June 1 , 2007, coincident with lPG's PCA rate change. The accounting for the FCA will be separate from the PCA. As part of the filing, IPC proposes a three percent cap on any rate increase to be applied at the discretion of the IPUC. On March 6,2006, the IPUC reviewed lPG's proposal and acknowledged the intent of IPC and the IPUC Staff to initiate and engage in settlement discussions. The IPUC Staff presented an alternate view of lPG' proposal. Three workshops were held in 2006 and the parties have agreed in concept to a three-year pilot beginning at the first of the year and a stipulation was filed December 18, 2006. The stipulation calls for the implementation of a FCA mechanism pilot program as proposed by IPC in its original application with additional conditions and provisions related to customer count and weather normalization methodology, recording of the FCA deferral amount in reports to the IPUC and detailed reporting of DSM activities. The pilot program began on January 1 , 2007, and will run through 2009, with the first rate adjustment to occur on June 1 , 2008, and subsequent rate adjustments to occur on June 1 of each year thereafter during the term of CONDENSED NOTES TO FINANCIAL STATEMENTS (Continued) the pilot program. The deadline for filing written comments with respect to the stipulation and the use of modified procedure was January 31 , 2007. A final order is expected from the IPUC in the first quarter of 2007. TT A C HME NT I (B ) STATEMENT OF CAPITAL STOCK AND FUNDED DEBT IDAHO POWER COMPANY The following statement as to each class of the capital stock of applicant is as of December 31 2006, the date of the balance sheet submitted with this application: Common Stock (1) Description - Common Stock, $2.50 par value; 1 vote per share (2) Amount authorized - 50,000 000 shares ($125,000,000 par value) (3) Amount outstanding - 39 150,812 shares (4) Amount held as reacquired securities - None (5) Amount pledged by applicant - None (6) Amount owned by affiliated corporations - All (7) Amount held in any fund - None Applicant's Common Stock is held by IDACORP, Inc., the holding company of Idaho Power Company. IDACORP, Inc.'s Common Stock is registered (Pursuant to Section 12(b) of the Securities Exchange Act of 1934) and is listed on the New York and Pacific stock exchanges. STATEMENT OF CAPITAL STOCK AND FUNDED DEBT (Continued) IDAHO POWER COMPANY The following statement as to funded debt of applicant is as of December 31 2006, the date of the balance sheet submitted with this application. First Mortgage Bonds (1 ) Description FIRST MORTGAGE BONDS: 38 % Series due 2007, dated as of Dec 1 2000, due Dec 1 2007 20 % Series due 2009, dated as of Nov 23, 1999 , due Dec 1 , 2009 60 % Series due 2011 , dated as of Mar 2, 2001 , due Mar 2, 2011 75 % Series due 2012, dated as of Nov 15, 2002, due Nov 15, 2012 25 % Series due 2013, dated as of May 13, 2003, due October 1 , 20136 % Series due 2032, dated as of Nov 15, 2002, due Nov 15, 2032 50 % Series due 2033, dated as of May 13, 2003, due April 1 , 2033 50 % Series due 2034, dated as of March 26, 2004, due March 15, 2034 875%Series due 2034, dated as of August 16, 2004, due August 15, 2034 30 % Series due 2035, dated as of August 23, 2005, due August 15, 2035 (2) Amount authorized - Limited within the maximum of $1 500 000 000 (or such other maximum amount as may be fixed by supplemental indenture) and by property, earnings , and other provisions of the Mortgage. (4) Amount held as reacquired securities - None (5) Amount pledged - None (6) Amount owned by affiliated corporations - None (7) Amount of sinking or other funds - None (3) Amount Outstanding 80,000,000 000,000 120,000 000 100,000,000 70,000,000 100,000,000 70,000,000 50,000,000 55,000,000 000,000 785 000 000 For a full statement of the terms and provisions relating to the respective Series and amounts of applicant's outstanding First Mortgage Bonds above referred to, reference is made to the Mortgage and Deed of Trust dated as of October 1 , 1937 , and First to Fortieth Supplemental Indentures thereto by Idaho Power Company to Deutsche Bank Trust Company Americas (formerly known as Bankers Trust Company) and R. G. Page (Stanley Burg, successor individual trustee), Trustees, presently on file with the Commission , under which said bonds were issued. STATEMENT OF CAPITAL STOCK AND FUNDED DEBT (Continued) IDAHO POWER COMPANY Pollution Control Revenue Bonds (A) Variable Rate Series 2000 due 2027: (1) Description - Pollution Control Revenue Bonds, Variable Rate Series due 2027, Port of Morrow, Oregon, dated as of May 17, 2000, due February 1 2027. (2) Amount authorized - $4,360 000 (3) Amount outstanding - $4 360 000 (4) Amount held as reacquired securities - None (5) Amount pledged - None (6) Amount owned by affiliated corporations - None (7) Amount in sinking or other funds - None (B) Variable Auction Rate Series 2003 due 2024: (1) Description - Pollution Control Revenue Refunding Bonds, Variable Auction Rate Series 2003 due 2024, County of Humboldt, Nevada, dated as of October 22 2003 due December 1 2024 (secured by First Mortgage Bonds) (2) Amount authorized - $49 800 000 (3) Amount outstanding - $49,800 000 (4) Amount held as reacquired securities - None (5) Amount pledged - None (6) Amount owned by affiliated corporations - None (7) Amount in sinking or other funds - None (C) Variable Rate Series 2006 due 2026: (1) Description - Pollution Control Revenue Bonds , Variable Rate Series 2006 due 2026, County of Sweetwater, Wyoming, dated as of October 1 2006, due July 15, 2026 (2) Amount authorized - $116 300 000 (3) Amount outstanding - $116 300,000 (4) Amount held as reacquired securities - None (5) Amount pledged - None (6) Amount owned by affiliated corporations - None (7) Amount in sinking or other funds - None For a full statement of the terms and provisions relating to the outstanding Pollution Control Revenue Bonds above referred to , reference is made to (A) copies of Trust Indenture by Port of Morrow, Oregon, to the Bank One Trust Company, N. A., Trustee, and Loan Agreement between Port of Morrow , Oregon and Idaho Power Company, both dated May 17, 2000, under which the Variable Rate Series 2000 bonds were issued, (B) copies of Loan Agreement between Idaho Power Company and Humboldt County, Nevada dated October 1 , 2003; Trust Indenture between Humboldt County, Nevada and Union Bank of California dated October 1 2003; Escrow Agreement between Humboldt County, Nevada and Bank One Trust Company and Idaho Power Company dated October 1 , 2003; Purchase Contract dated October 21 , 2003 among Humboldt County, Nevada and Bankers Trust Company; Auction Agreement, dated as of October 22, 2003 among Idaho Power Company, Union Bank of California and Deutsche Bank Trust Company; Insurance Agreement, dated as of October 1 2003 between AMBAC and Idaho Power Company; Broker-Dealer agreements dated October 22 2003 among the Auction Agent, Banc One Capital Markets , Banc of America Securities and Idaho Power Company, under which the Auction Rate Series 2003 bonds were issued, and (C) copies of Indentures of Trust by Sweetwater County, Wyoming, to Union Bank of California, Trustee, and Loan Agreements between Idaho Power Company and Sweetwater County, Wyoming, dated October 1 2006, under which the Variable Rate Series 2006 bonds were issued. ATTACHMENT I(C) COMMITMENTS AND CONTINGENCIES: Purchase Obligations: As of December 31 2006, IPC had agreements to purchase energy from 92 cogeneration and small power production (CSPP) facilities with contracts ranging from one to 30 years. Under these contracts IPC is required to purchase all of the output from the facilities inside the IPC service territory. For projects outside the IPC service territory, IPC is required to purchase the output that it has the ability to receive at the facility requested point of delivery on the IPC system. IPC purchased 911 132 megawatt-hours (MWh) at a cost of $54 million in 2006, 715,209 MWh at a cost of $46 million in 2005 and 677,868 MWh at a cost of $40 million in 2004. At December 31 2006, IPC had the following long-term commitments relating to purchases of energy, capacity, transmission rights and fuel: 2007 2008 2009 2010 2011 Thereafter (thousands of dollars) Cogeneration and small power production 130 $538 $538 $830 $830 $064 718 Power and transmission rights 80,175 351 390 '781 754 315 Fuel 395 30,035 885 941 821 11 ,005 In addition, IDACORP has the following long-term commitments for lease guarantees, maintenance and services , and industry related fees. 2007 2008 2009 2010 2011 Thereafter (thousands of dollars) Operating leases 531 666 008 059 008 991 Maintenance and service agreements 550 552 240 1,490 320 523 FERC and other industry related fees 970 008 008 970 970 926 IPC's expense for operating leases was approximately $4 million , $4 million and $5 million in 2006, 2005 and 2004 , respectively. Guarantees IPC has agreed to guarantee the performance of reclamation activities at Bridger Coal Company of which Idaho Energy Resources Co., a subsidiary of IPC, owns a one-third interest. This guarantee, which is renewed each December, was $60 million at December 31 , 2006. Bridger Coal Company has a reclamation trust fund set aside specifically for the purpose of paying these reclamation costs. Bridger Coal Company and I PC expect that the fund will be sufficient to cover all such costs. Because of the existence of the fund the estimated fair value of this guarantee is minimal. Legal Proceedings From time to time IDACORP and IPC are a party to legal claims, actions and complaints in addition to those discussed below. IDACORP and IPC believe that they have meritorious defenses to all lawsuits and legal proceedings. Although they will vigorously defend against them, they are unable to predict with certainty whether or not they will ultimately be successful. However, based on the companies' evaluation , they believe that the resolution of these matters , taking into account existing reserves, will not have a material adverse effect on IDACORP's or IPC's consolidated financial positions, results of operations or cash flows. Wah Chang: On May 5, 2004, Wah Chang, a division of TOY Industries, Inc., filed two lawsuits in the U. District Court for the District of Oregon against numerous defendants. IDACORP, IE and IPC are named as defendants in one of the lawsuits. The complaints allege violations of federal antitrust laws , violations of the Racketeer Influenced and Corrupt Organizations Act, violations of Oregon antitrust laws and wrongful interference with contracts. Wah Chang s complaint is based on allegations relating to the western energy situation. These allegations include bid rigging, falsely creating congestion and misrepresenting the source and destination of energy. The plaintiff seeks compensatory damages of $30 million and treble damages. On September 8, 2004, this case was transferred and consolidated with other similar cases currently pending before the Honorable Robert H. Whaley sitting by designation in the U.S. District Court for the Southern District of California. The companies' filed a motion to dismiss the complaint which the court granted on February 2005. Wah Chang appealed the dismissal to the U.S. Court of Appeals for the Ninth Circuit on March 10, 2005. The Ninth Circuit set a briefing schedule on the appeal, requiring Wah Chang s opening brief to be filed by July 6,2005. On May 18, 2005, Wah Chang filed a motion to stay the appeal or in the alternative to voluntarily dismiss the appeal without prejudice to reinstatement. The companies opposed the motion and filed a cross-motion asking the Court to summarily affirm the district court's order of dismissal. On July 8 2005, the Ninth Circuit denied Wah Chang s motion and also denied the companies' motion for summary affirmance without prejudice to renewal following the filing of Wah Chang s opening brief. Wah Chang s opening brief was filed on September 21, 2005. On October 2005 the companies, along with the other defendants, filed a motion to consolidate this appeal with Wah Chang v. Duke Energy Trading and Marketing currently pending before the Ninth Circuit. On October 18, 2005, the Ninth Circuit granted the motion to consolidate and established a revised briefing schedule. The companies filed an answering brief on November 30 2005. Wah Chang s reply brief was filed on January 6 2006. The appeal has been fully briefed and oral argument is scheduled for April 1 0, 2007. The companies intend to vigorously defend their position in this proceeding and believe this matter will not have a material adverse effect on their consolidated financial positions, results of operations or cash flows. City of Tacoma: On June 7, 2004 , the City of Tacoma, Washington filed a lawsuit in the U.S. District Court for the Western District of Washington at Tacoma against numerous defendants including IDACORP, IE and IPC. The City of Tacoma s complaint alleges violations of the Sherman Antitrust Act. The claimed antitrust violations are based on allegations of energy market manipulation, false load scheduling and bid rigging and misrepresentation or withholding of energy supply. The plaintiff seeks compensatory damages of not less than $175 million. On September 8, 2004, this case was transferred and consolidated with other similar cases currently pending before the Honorable Robert H. Whaley sitting by designation in the U.S. District Court for the Southern District of California. The companies' filed a motion to dismiss the complaint which the court granted on February 2005. The City of Tacoma appealed to the U.S. Court of Appeals for the Ninth Circuit on March 10,2005. On August 9, 2005 , the companies moved for summary affirmance of the district court's order dismissing the City of Tacoma s complaint. The City of Tacoma filed a response to the companies' motion for summary affirmance on August 24, 2005. The Ninth Circuit denied the companies' motion for summary affirmance on November 3 2005. The appeal has been fully briefed and oral argument is scheduled for April 1 0,2007. The companies intend to vigorously defend their position in this proceeding and believe this matter will not have a material adverse effect on their consolidated financial positions, results of operations or cash flows. Western Energy Proceedings at the FERC: California Power Exchanqe Charqeback: As a component of IPC's non-utility energy trading in the State of California, IPC, in January 1999, entered into a participation agreement with the California Power Exchange (CaIPX), a California non-profit public benefit corporation. The CaIPX, at that time, operated a wholesale electricity market in California by acting as a clearinghouse through which electricity was bought and sold. Pursuant to the participation agreement IPC could sell power to the CalPX under the terms and conditions of the CalPX Tariff. Under the participation agreement, if a participant in the CalPX defaulted on a payment, the other participants were required to pay their allocated share of the default amount to the CaIPX. The allocated shares were based upon the level of trading activity, which included both power sales and purchases, of each participant during the preceding three-month period. On January 18, 2001 , the CalPX sent IPC an invoice for $2 million - a "default share invoice" - as a result of an alleged Southern California Edison payment default of $215 million for power purchases. IPC made this payment. On January 2001 IPC terminated its participation agreement with the CaIPX. On February 8, 2001 , the CalPX sent a further invoice for $5 million , due on February 20, 2001 , as a result of alleged payment defaults by Southern California Edison, Pacific Gas and Electric Company and others. However because the CalPX owed IPC $11 million for power sold to the CalPX in November and December 2000, IPC did not pay the February 8 invoice. The CalPX later reversed IPC's payment of the January 18, 2001 invoice, but on June 2001 invoiced IPC for an additional $2 million. The CalPX owed IPC $14 million for power sold in November and December including $2 million associated with the default share invoice dated June 20,2001. IPC essentially discontinued energy trading with the CalPX and the California Independent System Operator (CaIISO) in December 2000. IPC believed that the default invoices were not proper and that IPC owed no further amounts to the CaIPX. IPC pursued all available remedies in its efforts to collect amounts owed to it by the CaIPX. On February 20, 2001 , IPC filed a petition with the FERC to intervene in a proceeding that requested the FERC to suspend the use of the CalPX chargeback methodology and provide for further oversight in the CaIPX' implementation of its default mitigation procedures. A preliminary injunction was granted by a federal judge in the U.S. District Court for the Central District of California enjoining the CalPX from declaring any CalPX participant in default under the terms of the CalPX Tariff. On March 9, 2001 , the CalPX filed for Chapter 11 protection with the U.S. Bankruptcy Court, Central District of California. In April 2001 J Pacific Gas and Electric Company filed for bankruptcy. The CalPX and the CallSO were among the creditors of Pacific Gas and Electric Company. The FERC issued an order on April 6, 2001 requiring the CalPX to rescind all chargeback actions related to Pacific Gas and Electric Company s and Southern California Edison s liabilities. Shortly after the issuance of that order, the CalPX segregated the CalPX chargeback amounts it had collected in a separate account. The CalPX claimed it would await further orders from the FERC and the bankruptcy court before distributing the funds that it collected under its chargeback tariff mechanism. On October 7, 2004, the FERC issued an order determining that it would not require the disbursement of chargeback funds until the completion of the California refund proceedings. On November 8, 2004 , IE, along with a number of other parties, sought rehearing of that order. On March 15, 2005, the FERC issued an order on rehearing confirming that the CalPX was to continue to hold the chargeback funds, but solely to offset seller-specific shortfalls in the seller s CalPX account at the conclusion of the California refund proceeding. Balances were to be returned to the respective sellers at the conclusion of a seller s participation in the refund proceeding. Based upon the Offer of Settlement filed with the FERC on February 17, 2006 between the California Parties and IE and IPC discussed below in "California Refund " the California Parties supported a motion filed by IE and IPC with the FERC seeking an Order Directing Return of Chargeback Amounts then held by the CalPX totaling $2.27 million. In the May 22, 2006 order approving the Settlement , the FERC granted the IE and IPC motion for return of chargeback funds held by the CaIPX. On June 2006, IE received approximately $2. million from the CalPX representing the return of $2.27 million in chargeback funds plus interest. California Refund: In April 2001 , the FERC issued an order stating that it was establishing price mitigation for sales in the California wholesale electricity market. Subsequently, in a June 19, 2001 , order, the FERC expanded that price mitigation plan to the entire western United States electrically interconnected system. That plan included the potential for orders directing electricity sellers into California since October 2, 2000, to refund portions of their spot market sales prices if the FERC determined that those prices were not just and reasonable, and therefore not in compliance with the Federal Power Act. The June 19 order also required all buyers and sellers in the CallSO market during the subject time frame to participate in settlement discussions to explore the potential for resolution of these issues without further FERC action. The settlement discussions failed to bring resolution of the refund issue and as a result, the FERC's Chief Administrative Law Judge submitted a Report and Recommendation to the FERC recommending that the FERC adopt the methodology set forth in the report and set for evidentiary hearing an analysis of the Cal ISO's and the CaIPX's spot markets to determine what refunds may be due upon application of that methodology. On July 25, 2001 , the FERC issued an order establishing evidentiary hearing procedures related to the scope and methodology for calculating refunds related to transactions in the spot markets operated by the CallSO and the CalPX during the period October 2, 2000 , through June 20, 2001 (Refund Period). The Administrative Law Judge issued a Certification of Proposed Findings on California Refund Liability on December 12, 2002. The FERC issued its Order on Proposed Findings on Refund Liability on March 26, 2003. In large part, the FERC affirmed the recommendations of its Administrative Law Judge. However, the FERC changed a component of the formula the Administrative Law Judge was to apply when it adopted findings of its staff that published California spot market prices for gas did not reliably reflect the prices a gas market, that had not been manipulated, would have produced, despite the fact that many gas buyers paid those amounts. The findings of the Administrative Law Judge, as adjusted by the FERC's March 26 , 2003, order, were expected to increase the offsets to amounts still owed by the CallSO and the CalPX to the companies. Calculations remained uncertain because (1) the FERC had required the CallSO to correct a number of defects in its calculations, (2) it was unclear what, if any, effect the ruling of the Ninth Circuit in Bonneville Power Administration v. FERC, described below, might have on the ISO's calculations, and (3) the FERC had stated that if refunds would prevent a seller from recovering its California portfolio costs during the Refund Period, itwould provide an opportunity for a cost showing by such a respondent. , along with a number of other parties, filed an application with the FERC on April 25, 2003, seeking rehearing of the March 26, 2003, order. On October 16, 2003, the FERC issued two orders denying rehearing of most contentions that had been advanced and directing the CallSO to prepare its compliance filing calculating revised Mitigated Market Clearing Prices and refund amounts within five months. Two avenues of activity have proceeded on largely but not entirely independent paths, converging from time to time. The Cal ISO continued to work on its compliance refund calculations while the appellate litigation and litigation before the FERC regarding, among other things, cost filings , fuel cost allowance offsets emissions offsets , cost-based recovery offsets, and allocation methods continued. Originally, the CallSO was to complete its calculation within five months of the FERC's October 16, 2003 order. The CallSO compliance filing has since been delayed numerous times. The CallSO has been required to update the FERC on its progress monthly. In its most recent status report, filed February 22 2007 , the CallSO reported that it has completed publishing settlement statements reflecting the basic refund calculations, and is currently in a "financial adjustment" phase, in which it calculates adjustments to its refund data to account for fuel cost allowance offsets, emissions offsets , cost-based recovery offsets, and interest on amounts unpaid and refunds. The CallSO estimates that it will take approximately 10 additional weeks complete the financial adjustment phase, including applicable review and comment periods. The CallSO estimates that it will have completed its calculations by May 2007, subject to such additional time as may be required if unanticipated delays are encountered. The potential expansion of the FERC refund proceedings due to the Ninth Circuit orders and the disposition of additional settlements which the Ninth Circuit has announced it expects to be filed at the FERC in the near future may affect the finality of any CallSO calculations. At present, IDACORP and IPC are not able to predict when the Ninth Circuit mandates may issue, how the FERC will proceed in connection with the possible expansion of the proceedings, the nature and content of as yet un-filed settlements or the extent to which the CallSO calculation process may be disrupted. On December 2, 2003, IDACORP petitioned the U.S. Court of Appeals for the Ninth Circuit for review of the FERC's orders, and since that time, dozens of other petitions for review have been filed. The Ninth Circuit consolidated IE's and the other parties' petitions with the petitions for review arising from earlier FERC orders in this proceeding, bringing the total number of consolidated petitions to more than 100. The Ninth Circuit held the appeals in abeyance pending the disposition of the market manipulation claims discussed below and the development of a comprehensive plan to brief this complicated case. Certain parties also sought further rehearing and clarification before the FERC. On September 21 , 2004, the Ninth Circuit convened case management proceedings, a procedure reserved to help organize complex cases. On October 22, 2004, the Ninth Circuit severed a subset of the stayed appeals in order that briefing could commence regarding cases related to: (1) which parties are subject to the FERC's refund jurisdiction under section 201 (f) of the Federal Power Act; (2) the temporal scope of refunds under section 206 of the Federal Power Act; and (3) which categories of transactions are subject to refunds. Oral argument was held on April 12-, 2005. On September 6, 2005, the Ninth Circuit issued a decision on the jurisdictional issues concluding that the FERC lacked refund authority over wholesale electric energy sales made by governmental entities and non-public utilities. On August 2, 2006, the Ninth Circuit issued its decision on the appropriate temporal reach and the type of transactions subject to the FERC refund orders and concluded, among other things, that all transactions at issue in the case that occurred within or as a result of the CalPX and the CallSO were the proper subject of refund proceedings; refused to expand the refund proceedings into the bilateral markets including transactions with the California Department of Water Resources; approved the refund effective date as October 2, 2000, but also required the FERC to consider whether refunds, including possibly market-wide refunds, should be required for an earlier time due to claims that some market participants had violated governing tariff obligations (although the decision did not specify when that time would start, the California Parties generally had sought further refunds starting May 1 , 2000); and effectively expanded the scope of the refund proceeding to transactions within the CalPX and CallSO markets outside the 24-hour spot market and energy exchange transactions. The IDACORP settlement with the California Parties approved by the FERC on May 22, 2006, and discussed below anticipated the possibility of such an outcome and attempted to provide that the consideration exchanged among the settling parties also encompass the settling parties claims in the event of such expansion of the proceedings. The Ninth Circuit subsequently issued orders deferring the time for seeking rehearing of its order and holding the consolidated petitions for review in abeyance for a limited time in order to create an opportunity for unusual mediation proceedings managed jointly by the Court Mediator and FERC officials. The Ninth Circuit has since extended the deferral for the mediation effort. IDACORP believes that these decisions should have no material effect on IDACORP under the terms of the IDACORP Settlement with the California Parties approved by the FERC on May 22 2006. On May 12, 2004, the FERC issued an order clarifying portions of its earlier refund orders and , among other things , denying a proposal made by Duke Energy North America and Duke Energy Trading and Marketing (and supported by IE) to lodge as evidence a contested settlement in a separate complaint proceeding, California Public Utilities Commission (CPUC) v. EI Paso, et al. The CPUC's complaint alleged that the EI Paso companies manipulated California energy markets by withholding pipeline transportation capacity into California in order to drive up natural gas prices immediately before and during the California energy crisis in 2000-2001. The settlement will result in the payment by EI Paso of approximately $1.69 billion. Duke claimed that the relief afforded by the settlement was duplicative of the remedies imposed by the FERC in its March 26, 2003, order changing the gas cost component of its refund calculation methodology. IE, along with other parties , has sought rehearing of the May 12, 2004, order. On November 23, 2004, the FERC denied rehearing and within the statutory time allowed for petitions, a number of parties, including IE , filed petitions for review of the FERC's order with the Ninth Circuit. These petitions have since been consolidated with the larger number of review petitions in connection with the California refund proceeding. On March 20, 2002, the California Attorney General filed a complaint with the FERC against various sellers in the wholesale power market, including IE and lPG , alleging that the FERC's market-based rate requirements violate the Federal Power Act, and, even if the market-based rate requirements are valid, that the quarterly transaction reports filed by sellers do not contain the transaction-specific information mandated by the Federal Power Act and the FERC. The complaint stated that refunds for amounts charged between market- based rates and cost-based rates should be ordered. The FERC denied the challenge to market-based rates and refused to order refunds, but did require sellers , including IE and lPG, to refile their quarterly reports to include transaction-specific data. The Attorney General appealed the FERC's decision to the U.S. Court of Appeals for the Ninth Circuit. The Attorney General contends that the failure of all market-based rate authority sellers of power to have rates on file with the FERC in advance of sales is impermissible. The Ninth Circuit issued its decision on September 9, 2004, concluding that market-based tariffs are permissible under the Federal Power Act, but remanding the matter to the FERC to consider whether the FERC should exercise remedial power (including some form of refunds) when a market participant failed to submit reports that the FERC relies on to confirm the justness and reasonableness of rates charged. On December 28, 2006, a number of sellers have filed a certiorari petition to the U.S. Supreme Court. The U.S. Supreme Court has not yet acted on that petition. On February 16, 2007 , the Ninth Circuit announced that it was continuing to withhold the mandate until April 27, 2007. In June 2001 , IPC transferred its non-utility wholesale electricity marketing operations to IE. Effective with this transfer, the outstanding receivables and payables with the CalPX and the CallSO were assigned from IPC to IE. At December 31 2005, with respect to the CalPX chargeback and the California refund proceedings discussed above, the CalPX and the CallSO owed $14 million and $30 million , respectively, for energy sales made to them by IPC in November and December 2000. On August 8, 2005, the FERC issued an Order establishing the framework for filings by sellers who elected to make a cost showing. On September 14, 2005, IE and IPC made a joint cost filing, as did approximately thirty other sellers. On October 11 , 2005, the California entities filed comments on the IE and IPC cost filing and those made by other parties. IPC and IE submitted reply comments on October 17, 2005. The California entities filed supplemental comments on October 24 2005 and IPC and IE filed supplemental reply comments on October 27 2005. In December of 2005, IE and IPC reached a tentative agreement with the California Parties settling matters encompassed by the California Refund proceeding including IE's and IPC's cost filing and refund obligation. On January 20, 2006, the Parties filed a request with the FERC asking that the FERC defer ruling on IE's and IPC's cost filing for thirty days so the parties could complete and file the settlement agreement with the FERC. On January 26, 2006, the FERC granted the requested deferral of a ruling on the cost filing and required that the settlement be filed by February 17 , 2006. On February 17, 2006, IE and IPC jointly filed with the California Parties (Pacific Gas & Electric Company, San Diego Gas & Electric Company, Southern California Edison , the California Public Utilities Commission , the California Electricity Oversight Board, the California Department of Water Resources and the California Attorney General) an Offer of Settlement at the FERC. Other parties had until March 9, 2006 to elect to become additional settling parties. A number of parties, representing substantially less than the majority potential refund claims, chose to opt out of the settlement. On March 27, 2006, the FERC issued an order rejecting the IE/IPC cost filing and on April 26, 2006, IE and IPC sought rehearing of the rejection. By order of April 27, 2006, the FERC tolled the time for what otherwise would have been required by statute to be a decision on the request for rehearing. On May 12, 2006, the FERC issued an order determining the method that should be used to allocate amounts approved in cost filings, approving the methodology that IE and IPC and others had advocated prior to the time IE and IPC entered into the February 17 , 2006 settlement - allocating cost offsets to buyers in proportion to the net refunds they are owed through the CallSO and CalPX markets. On June 12 , 2006, the California Parties requested rehearing, urging the FERC to allocate the cost offsets to all purchasers from the CallSO and CalPX markets and not just to that limited subset of purchasers who are net refund recipients. On July 12 , 2006 , the FERC tolled the time to act on the request for rehearing and has not issued orders on rehearing since that time. IDACORP and IPC are unable to predict how or when the FERC might rule on the request for rehearing. After consideration of comments , the FERC approved the February 17, 2006, Offer of Settlement on May 22 2006. Under the terms of the settlement, IE and IPC assigned $24.25 million of the rights to accounts receivable from the CallSO and CalPX to the California Parties to pay into an escrow account for refunds to settling parties. Amounts from that escrow not used for settling parties and $1.5 million of the remaining IE and IPC receivables that are to be retained by the CalPX are available to fund, at least partially, payment of the claims of any non-settling parties if they prevail in the remaining litigation of this matter. Any excess funds remaining at the end of the case are to be returned to IDACORP. Approximately $10.25 million of the remaining IE and IPC receivables was paid to IE and IPC under the settlement. On June 21, 2006, the Port of Seattle, Washington filed a request for rehearing of the FERC order approving the settlement. On July 10, 2006, IPC and IE and the California Parties filed a response to Port of Seattle request for rehearing. On October 5, 2006, the FERC issued an order denying the Port of Seattle s request for rehearing. On October 24, 2006, the Port of Seattle petitioned the U.S. Court of Appeals for the Ninth Circuit for review of the FERC order denying their request for rehearing of the FERC order approving the settlement. The Ninth Circuit consolidated that review petition with the large number of review petitions already consolidated before it. On January 23 2007, IPC and IE filed a motion to sever the Port of Seattle petition for review from the bulk of cases pending in the Ninth Circuit with which it had been consolidated. IPC and IE also filed a motion to dismiss the Port of Seattle s petition for review. The Port of Seattle filed their answers in opposition to the motion to sever and the motion to dismiss on February 1 , 2007, and IPC and IE replied on February 12 , 2007. IDACORP and IPC are not able to predict when or how the Ninth Circuitmight rule on the motions. Prior to December of 2005, IE had accrued a reserve of $42 million. This reserve was calculated taking into account the uncertainty of collection from the CalPX and CaIISO. In the fourth quarter of 2005, following the tentative agreement with the California Parties, IE reduced this reserve by $9.5 million to $32 million. Following payment of the $10.25 million to IE and IPC in June 2006 , IE further reduced the reserve by $24. million to $7.1 million. This reserve was calculated taking into account several unresolved issues in the California refund proceeding. Market Manipulation: In a November 20,2002 order, the FERC permitted discovery and the submission of evidence respecting market manipulation by various sellers during the western power crises of 2000 and 2001. On March 3, 2003, the California Parties (certain investor owned utilities, the California Attorney General, the California Electricity Oversight Board and the CPUC) filed voluminous documentation asserting that a number of wholesale power suppliers, including IE and IPC, had engaged in a variety of forms of conduct that the California Parties contended were impermissible. Although the contentions of the California Parties were contained in more than 11 compact discs of data and testimony, approximately 12 000 pages, IE and IPC were mentioned only in limited contexts with the overwhelming majority of the claims of the California Parties relating to the conduct of other parties. The California Parties urged the FERC to apply the precepts of its earlier decision, to replace actual prices charged in every hour starting January 1 , 2000 through the beginning of the existing refund period (October , 2000) with a Mitigated Market Clearing Price, seeking approximately $8 billion in refunds to the CallSO and the CaIPX. On March 20,2003 , numerous parties , including IE and IPC, submitted briefs and responsive testimony. In its March 26, 2003 order, discussed above in "California Refund " the FERC declined to generically apply its refund determinations to sales by all market participants , although it stated that it reserved the right to provide remedies for the market against parties shown to have engaged in proscribed conduct. On June 25, 2003, the FERC ordered over 50 entities that participated in the western wholesale power markets between January 1 2000 and June 20,2001 , including IPC, to show cause why certain trading practices did not constitute gaming or anomalous market behavior in violation of the CallSO and the CalPX Tariffs. The CallSO was ordered to provide data on each entity s trading practices within 21 days of the order, and each entity was to respond explaining their trading practices within 45 days of receipt of the Cal ISO data. IPC submitted its responses to the show cause orders on September 2 and 4, 2003. On October 16, 2003 , IPC reached agreement with the FERC Staff on the two orders commonly referred to as the gaming" and "partnership" show cause orders. Regarding the gaming order, the FERC Staff determined it had no basis to proceed with allegations of false imports and paper trading and IPC agreed to pay $83,373 to settle allegations of circular scheduling. IPC believed that it had defenses to the circular scheduling allegation but determined that the cost of settlement was less than the cost of litigation. In the settlement IPC did not admit any wrongdoing or violation of any law. With respect to the "partnership" order, the FERC Staff submitted a motion to the FERC to dismiss the proceeding because materials submitted by IPC demonstrated that IPC did not use its "parking" and "lending" arrangement with Public Service Company of New Mexico to engage in "gaming" or anomalous market behavior ("partnership ). The "gaming" settlement was approved by the FERC on March 3, 2004. Originally, eight parties requested rehearing of the FERC' March 3, 2004 order. The motion to dismiss the "partnership" proceeding was approved by the FERC in an order issued on January 23, 2004 and rehearing of that order was not sought within the time allowed by statute. Some of the California Parties and other parties have petitioned the U.S. Court of Appeals for the Ninth Circuit and the District of Columbia Circuit for review of the FERC's orders initiating the show cause proceedings. Some of the parties contend that the scope of the proceedings initiated by the FERC was too narrow. Other parties contend that the orders initiating the show cause proceedings were impermissible. Under the rules for multidistrict litigation , a lottery was held and although these cases were to be considered in the District of Columbia Circuit by order of February 10, 2005, the District of Columbia Circuit transferred the proceedings to the Ninth Circuit. The FERC had moved the District of Columbia Circuit to dismiss these petitions on the grounds of prematurity and lack of ripeness and finality. The transfer order was issued before a ruling from the District of Columbia Circuit and the motions , if renewed, will be considered by the Ninth Circuit. The Ninth Circuit has consolidated this case with other matters and are holding them in abeyance. IPC is not able to predict the outcome of the judicial determination of these issues. The settlement between the California Parties and IE and IPC discussed above in the California Refund proceeding approved by the FERC on May 22, 2006, results in the California Parties and other settling parties withdrawing their requests for rehearing of IPC's and IE's settlement with the FERC Staff regarding allegations of "gaming . On October 11 , 2006, the FERC issued an Order denying rehearing of its earlier approval of the "gaming" allegations, thereby effectively terminating the FERC investigations as to IPC and IE regarding bidding behavior, physical withholding of power and "gaming" without finding of wrongdoing. On October 24, 2006 , the Port of Seattle appealed the FERC order to the U.S. Court of Appeals for the Ninth Circuit. On June 25, 2003, the FERC also issued an order instituting an investigation of anomalous bidding behavior and practices in the western wholesale power markets. In this investigation , the FERC was to review evidence of alleged economic withholding of generation. The FERC determined that all bids into the CalPX and the CallSO markets for more than $250 per MWh for the time period May 1 , 2000, through October 1 2000, would be considered prima facie evidence of economic withholding. The FERC Staff issued data requests in this investigation to over 60 market participants including IPC. IPC responded to the FERC' data requests. In a letter dated May 12, 2004, the FERC's Office of Market Oversight and Investigations advised that it was terminating the investigation as to IPC. In March 2005, the California Attorney General the CPUC, the California Electricity Oversight Board and Pacific Gas and Electric Company sought judicial review in the Ninth Circuit of the FERC's termination of this investigation as to IPC and approximately 30 other market participants. IPC has moved to intervene in these proceedings. On April 25, 2005, Pacific Gas and Electric Company sought review in the Ninth Circuit of another FERC order in the same docketed proceeding confirming the agency s earlier decision not to allow the participation of the California Parties in what the FERC characterized as its non-public investigative proceeding. Pacific Northwest Refund: On July 25 2001 , the FERC issued an order establishing another proceeding to explore whether there may have been unjust and unreasonable charges for spot market sales in the Pacific Northwest during the period December 25, 2000 through June 20, 2001. The FERC Administrative Law Judge submitted recommendations and findings to the FERC on September 24 2001. The Administrative Law Judge found that prices should be governed by the Mobile-Sierra standard of the public interest rather than the just and reasonable standard, that the Pacific Northwest spot markets were competitive and that no refunds should be allowed. Procedurally, the Administrative Law Judge s decision is a recommendation to the commissioners of the FERC. Multiple parties submitted comments to the FERC with respect to the Administrative Law Judge s recommendations. The Administrative Law Judge s recommended findings had been pending before the FERC, when at the request of the City of Tacoma and the Port of Seattle on December 19, 2002 the FERC reopened the proceedings to allow the submission of additional evidence related to alleged manipulation of the power market by Enron and others. As was the case in the California refund proceeding, at the conclusion of the discovery period , parties alleging market manipulation were to submit their claims to the FERC and responses were due on March 20, 2003. Grays Harbor intervened in this FERC proceeding, asserting on March 3, 2003 that its six-month forward contract, for which performance had been completed, should be treated as a spot market contract for purposes of the FERC's consideration of refunds and requested refunds from IPC of $5 million. Grays Harbor did not suggest that there was any misconduct by IPC or IE. The companies submitted responsive testimony defending vigorously against Grays Harbor refund claims. In addition, the Port of Seattle, the City of Tacoma and the City of Seattle made filings with the FERC on March 3, 2003, claiming that because some market participants drove prices up throughout the west through acts of manipulation, prices for contracts throughout the Pacific Northwest market should be re-set starting in May 2000 using the same factors the FERC would use for California markets. Although the majority of these claims are generic, they named a number of power market suppliers, including IPC and IE, as having used parking services provided by other parties under FERC-approved tariffs and thus as being candidates for claims of improperly having received congestion revenues from the CaIISO. On June 25, 2003, after having considered oral argument held earlier in the month , the FERC issued its Order Granting Rehearing, Denying Request to Withdraw Complaint and Terminating Proceeding, in which it terminated the proceeding and denied claims that refunds should be paid. The FERC denied rehearing on November 10, 2003, triggering the right to file for review. The Port of Seattle, the City of Tacoma, the City of Seattle, the California Attorney General, the CPUC and Puget Sound Energy, Inc. filed petitions for review in the Ninth Circuit. These petitions have been consolidated. Grays Harbor did not file a petition for review, although it sought to intervene in the proceedings initiated by the petitions of others. On July 21 , 2004 , the City of Seattle submitted a motion requesting leave to offer additional evidence before the FERC in order to try to secure another opportunity for reconsideration by the FERC of its earlier rulings. The evidence that the City of Seattle sought to introduce before the FERC consisted of audio tapes of what purports to be Enron trader conversations containing inflammatory language. Under Section 313(b) of the Federal Power Act, a court is empowered to direct the introduction of additional evidence if it is material and could not have been introduced during the underlying proceeding. On September 29 2004, the Ninth Circuit denied the City of Seattle s motion for leave to adduce evidence, without prejudice to renewing the request for remand in the briefing in the Pacific Northwest refund case. Briefing was completed on May 25, 2005, and oral argumentwas held on January 8 2007. The Settlement approved by the FERC on May 22 2006, resolves all claims the California Parties have against IE and IPC in the Pacific Northwest refund proceeding. The settlement with Grays Harbor resolves all claims Grays Harbor has against IE and IPC in this proceeding. IE and IPC are unable to predict the outcome as to all other parties in this proceeding. In separate western energy proceedings , the Ninth Circuit issued two decisions on December 19, 2006 reviewing the FERC's decisions not to require repricing of certain long term contracts. Those cases originated with individual complaints against specified sellers which did not include IE or IPC. The Ninth Circuit remanded to the FERC for additional consideration the agency s use of restrictive standards of contract review. In its decisions, the Ninth Circuit also questioned the validity of the FERC's administration of its market-based rate regime. IDACORP and IPC are unable to predict whether parties to that case will seek a writ of certiorari or how or when the FERC might respond to these decisions. Shareholder Lawsuit: On May 26, 2004 and June 22 , 2004, respectively, two shareholder lawsuits were filed against IDACORP and certain of its directors and officers. The lawsuits, captioned Powell , et al. v. IDACORP, Inc., et al. and Shorthouse, et al. v. IDACORP, Inc., et aI., raise largely similar allegations. The lawsuits are putative class actions brought on behalf of purchasers of IDACORP stock between February 1 2002, and June 4 , 2002 , and were filed in the U.S. District Court for the District of Idaho. The named defendants in each suit, in addition to IDACORP, are Jon H. Miller, Jan B. Packwood, J. LaMont Keen and Darrel T. Anderson. The complaints alleged that, during the purported class period, IDACORP and/or certain of its officers and/or directors made materially false and misleading statements or omissions about the company s financial outlook in violation of Sections 10(b) and 20(a) of the Securities Exchange Act of 1934, as amended, and Rule 10b-, thereby causing investors to purchase IDACORP's common stock at artificially inflated prices. More specifically, the complaints alleged that IDACORP failed to disclose and misrepresented the following material adverse facts which were known to defendants or recklessly disregarded by them: (1) IDACORP failed to appreciate the negative impact that lower volatility and reduced pricing spreads in the western wholesale energy market would have on its marketing subsidiary, IE; (2) IDACORP would be forced to limit its origination activities to shorter-term transactions due to increasing regulatory uncertainty and continued deterioration of creditworthy counterparties; (3) IDACORP failed to account for the fact that IPC may not recover from the lingering effects of the prior year s regional drought and (4) as a result of the foregoing, defendants lacked a reasonable basis for their positive statements about IDACORP and their earnings projections. The Powell complaint also alleged that the defendants' conduct artificially inflated the price of IDACORP's common stock. The actions seek an unspecified amount of damages, as well as other forms of relief. By order dated August 31 2004 , the court consolidated the Powell and Shorthouse cases for pretrial purposes, and ordered the plaintiffs to file a consolidated complaint within 60 days. On November 1 , 2004 IDACORP and the directors and officers named above were served with a purported consolidated complaint captioned Powell , et al. v. IDACORP, Inc., et aI., which was filed in the U.S. District Court for the District of Idaho. The new complaint alleged that during the class period IDACORP and/or certain of its officers and/or directors made materially false and misleading statements or omissions about its business operations, and specifically the I E financial outlook, in violation of Rule 10b-5, thereby causing investors to purchase IDACORP's common stock at artificially inflated prices. The new complaint alleged that IDACORP failed to disclose and misrepresented the following material adverse facts which were known to it or recklessly disregarded by it: (1) IDACORP falsely inflated the value of energy contracts held by IE in order to report higher revenues and profits; (2) IDACORP permitted IPC to inappropriately grant native load priority for certain energy transactions to IE; (3) IDACORP failed to file 13 ancillary service agreements involving the sale of power for resale in interstate commerce that it was required to file under Section 205 of the Federal Power Act; (4) IDACORP failed to file 1 182 contracts that IPC assigned to IE for the sale of power for resale in interstate commerce that IPC was required lo file under Section 203 of the Federal Power Act; (5) IDACORP failed to ensure that IE provided appropriate compensation from IE to IPC for certain affiliated energy transactions; and (6) IDACORP permitted inappropriate sharing of certain energy pricing and transmission information between IPC and IE. These activities allegedly allowed IE to maintain a false perception of continued growth that inflated its earnings. In addition , the new complaint alleges that those earnings press releases , earnings release conference calls, analyst reports and revised earnings guidance releases issued during the class period were false and misleading. The action seeks an unspecified amount of damages , as well as other forms of relief. IDACORP and the other defendants filed a consolidated motionto dismiss on February 9, 2005, and the plaintiffs filed their opposition to the consolidated motion to dismiss on March 28, 2005. IDACORP and the other defendants filed their response to the plaintiff's opposition on April 29, 2005 and oral argument on the motion was held on May 19 , 2005. On September 14, 2005, Magistrate Judge Mikel H. Williams of the U.S. District Court for the District of Idaho issued a Report and Recommendation that the defendants' motion to dismiss be granted and that the case be dismissed. The Magistrate Judge determined that the plaintiffs did not satisfactorily plead loss causation (i.e., a causal connection between the alleged material misrepresentation and the loss) in conformance with the standards set forth in the recent United States Supreme Court decision of Dura Pharmaceuticals, Inc. v. Broudo, 544 U.336, 125 S. Ct. 1627 (2005). The Magistrate Judge also concluded that it would be futile to afford the plaintiffs an opportunity to file an amended complaint because it did not appear that they could cure the deficiencies in their pleadings. Each party filed objections to different parts of the Magistrate Judge Report and Recommendation. On March 29, 2006, the U.S. District Court for the District of Idaho (Judge Edward J. Lodge) issued an Order in this case (Powell v. IDACORP) adopting the Report and Recommendation of Magistrate Judge Williams issued on September 14, 2005, granting the defendants' (IDACORP and certain of its officers and directors) motion to dismiss because plaintiffs failed to satisfy the pleading requirements for loss causation. However Judge Lodge modified the Report and Recommendation and ruled that plaintiffs had until May 1 , 2006, to file an amended complaint only as to the loss causation element. On May 1 , 2006, the plaintiffs filed an amended complaint. The defendants filed a motion to dismiss the amended complaint on June 16, 2006, asserting that the amended complaint still failed to satisfy the pleading requirements for loss causation. Briefing on this most recent motion to dismiss was completed on August 28, 2006, and oral argument was held on February 26, 2007. IDACORP and the other defendants intend to defend themselves vigorously against the allegations. IDACORP cannot, however, predict the outcome of these matters. Western Shoshone National Council: On April 10, 2006 , the Western Shoshone National Council (which purports to be the governing body of the Western Shoshone Nation) and certain of its individual tribal members filed a First Amended Complaint and Demand for Jury Trial in the U.S. District Court for the District of Nevada, naming IPC and other unrelated entities as defendants. Plaintiffs allege that IPC's ownership interest in certain land, minerals, water or other resources was converted and fraudulently conveyed from lands in which the plaintiffs had historical ownership rights and Indian title dating back to the 1860's or before. Although it is unclear from the complaint, it appears plaintiffs claims relate primarily to lands within the state of Nevada. Plaintiffs seek a judgment declaring their title to land and other resources, disgorgement of profits from the sale or use of the land and resources, a decree declaring a constructive trust in favor of the plaintiffs of IPC's assets connected to the lands or resources, an accounting of money or things of value received from the sale or use of the lands or resources, monetary damages in an unspecified amount for waste and trespass and a judgment declaring that IPC has no right to possess or use the lands or resources. On May 1 2006, IPC filed an Answer to plaintiffs' First Amended Complaint denying all liability to the plaintiffs and asserting certain affirmative defenses including collateral estoppel and res judicata, preemption impossibility and impracticability, failure to join all real and necessary parties, and various defenses based on untimeliness. On June 19 , 2006, IPC filed a motion to dismiss plaintiffs' First Amended Complaint, asserting, among other things, that the Court lacks subject matter jurisdiction and that plaintiffs failed to join an indispensable party (namely, the United States government). Briefing on the motion to dismiss was completed on September 28, 2006. Newly decided authority from the United States Court of Federal Claims in further support of IPC's motion to dismiss was filed on January 3, 2007. The Court has yet to act on the IPC motion to dismiss. IPC intends to vigorously defend its position in this proceeding, but is unable to predict the outcome of this matter. Sierra Club Lawsuit - Bridger: In February 2007, the Sierra Club and the Wyoming Outdoor Council filed a complaint against PacifiCorp in federal district court in Cheyenne, Wyoming for alleged violations of the Clean Air Act's opacity standards (alleged violations of air pollution permit emission limits) at the Jim Bridger coal fired plant Plant") in Sweetwater County, Wyoming. IPC has a one-third ownership interest in the Plant. PacifiCorp owns a two-thirds interest and is the operator of the Plant. The complaint alleges thousands of violations and seeks declaratory and injunctive relief and civil penalties of $32 500 per day per violation as well as the costs of litigation including reasonable attorney fees. IPC believes there are a number of defenses to the claims and intends to vigorously defend its interest in this matter, but is unable to predict its outcome and is unable to estimate the impact this may have on its consolidated financial positions , results of operations or cash flows. TT A CHMENT I(D) IDAHO POWER COMPANY STATEMENT OF RETAINED EARNINGS AND UNDISTRIBUTED SUBSIDIARY EARNINGS For the Twelve Months Ended December 31 2006 Retained Earninqs Retained earnings (at the beginning of period) ,..............................361 256 133 Balance transferred from income,....,.................,......,.....................929 189 Dividends received from subsidiary....,........,....,......,....................... TotaL.,.,.,....,......",.,.".....,....""""",...",...,.."""",.455 185 323 Dividends: Common Stock ,......'............,..'..'......,......,....,..'.........,......",'.109 346 Total.,."""",.,...,.."""."".,...."".""",,,'........,...,.,.,109 346 Retained earnings (at end of period)............,..,...............................404 075 976 Undistributed Subsidiary Earninqs Balance (at beginning of period)................,..,..,..,............,....,..,......802 850 Equity in earnings for the period....................,..,......,........,......,......648 252 Dividends paid (Debit).,...""""""",.,..,.."""""""...,.,"..""'.."....,,., Balance (at end of period),..................,........,........,.......,................49,451 103 c:\documents and settings\pah2878\local settings\temporary internet files\olk52f1retained earnings.xls TT A CHMENT I(E) IDAHO POWER COMPANY STATEMENT OF INCOME For the Twelve Months Ended December 31 , 2006 Operating Revenues............................................................................................ Operating Expenses: Purchased power...................................................................................... FueL......................................................................................................... Power cost adjustment........................................................................... Other operation and maintenance expense.............................................. Depreciation expense............................................................................... Amortization of limited-term electric plant................................................. Taxes other than income taxes................................................................. Income taxes - FederaL............................................................................ Income taxes - Other................................................................................ Provision for deferred income taxes......................................................... Provision for deferred income taxes - Credit............................................. Investment tax credit adjustment............................................................. Total operating expenses.................................................................... Operating Income............................................................................................. Other Income and Deductions: Allowance for equity funds used during construction................................ Income taxes......................................... .................................................... Other - Net............................................................................................... Net other income and deductions............................................................. Income Before Interest Charges....................................................................... Interest Charges: Interest on first mortgage bonds............................................................... Interest on other long-term debt............................................................... Interest on short-term debt....................................................................... Amortization of debt premium, discount and expense - Net..................................................................................... Other interest expense.............................................................................. Total interest charges............................................................. Allowance for borrowed funds used during construction - Credit.............. Net interest charges................................................................ Net Income....................................................................................................... Actual 920,473,490 283,439 877 115 018 156 (29 526 278) 254 505 775 803,410 020 794 661,413 572 378 194 257 231 898) 646 675) 326 869 791 138 077 129 335,413 092 152 836 001 677 809 605 962 149 941 375 320 250 7,424 203 232 870 208,435 852 887 038 645 026,460 012 185 929 190 The accompanying Notes to Financial Statements are an integral part of this statement c:\documents and settings\pah2878\local settings\temporary internet files\olk52f\income statement xis TT A CHMENT STATE OF IDAHO COUNTY OF ADA ) ss. CITY OF BOISE , PATRICK A. HARRINGTON, the undersigned, Secretary of Idaho Power Company, do hereby certify that the following constitutes a full, true and correct copy of the resolutions adopted at the regular meeting of the Board of Directors on March 15 2007 , relating to authority to enter into short-term borrowings and issue promissory notes, and that said resolutions have not been amended or rescinded and are in full force and effect on the date hereof. March, 2007. IN WITNESS WHEREOF, I have hereunto set my hand this ) (P'fh day of f;t r-J/1 #11 rJ /J. . Isl Patrick A. Harrin to Secretary (COI~ORATE SEAL) RESOLVED, That for the purpose of providing in part for the Company ongoing financial requirements during the calendar years 2007 through 2014 unsecured short-term borrowings by the Company are hereby authorized in an aggregate principal amount of not to exceed $450 000 000 at anyone time outstanding, including authorization to renew notes or other evidence of indebtedness with a final maturity no later than April 31 , 2014, such borrowings (including renewals thereof), subject to the authority of, or in compliance with procedures of, all governmental agencies having jurisdiction in respect thereof, to be made (1) at such time or times, in such amount or amounts (within the above specified aggregate maximum), for such period or periods, at such rate or rates of interest, upon such other terms and conditions, and to be evidenced by notes or such other evidence of indebtedness in such form or forms as shall be determined by, and (2) under such agreement or agreements or pursuant to such arrangements as shall have been approved by, the Chief Executive Officer, the Chief Financial Officer, or the Treasurer or any Assistant Treasurer, as necessary or appropriate in view of the Company s financial requirements; and that the Chief Executive Officer, the Chief Financial Officer, the Treasurer or Assistant Treasurer, are, and each of them hereby is authorized to execute and deliver in the name and on behalf of the Company, all such agreements and arrangement documents, or instruments, and to do or cause to be done all such other things, as may be required or expedient for the purpose of such borrowing, including the determination of a bank or banks to act as issuing and paying agent for any promissory notes or other evidence of indebtedness of the Company; and that the Chief Executive Officer, the Chief Financial Officer, the Treasurer or Assistant Treasurer be, and they hereby are authorized and empowered from time to time to make, execute and deliver in the name and on behalf of the Company, promissory notes or other evidence of indebtedness, not to exceed an aggregate principal amount of $450 000 000 at any one time outstanding as herein authorized; and be it FURTHER RESOLVED, That the proper officers of the Company be, and they hereby are, authorized and directed to file applications with the Idaho Public Utilities Commission, the Oregon Public Utility Commission and the Public Service Commission of Wyoming, and such other commissions or regulatory agencies identified by such officers for any necessary or appropriate authorization in connection with the short-term borrowings in an aggregate principal amount not to exceed $450 000 000 as determined by the proper officers of the Company to be in the best interest of the Company, and to execute on behalf of the Company and in its name and to cause to be filed with said Commissions such amendments, supplements and reports, if any, as they deem necessary or proper in connection with such applications and with any orders issued by the Commissions; and be it FURTHER RESOLVED , That all acts heretofore done and all documents heretofore executed, filed or delivered by the officers of the Company in connection with the proposed short-term borrowings are hereby approved, ratified and confirmed; and that the officers of the Company are hereby authorized and directed to do or cause to be done any and all other acts and things in their judgment that may be necessary or proper or as counsel may advise in order to carry out the purpose of the foregoing resolutions. RESOLVED, That effective upon receipt of all necessary regulatory approvals, authorizations or consents and the entry into such agreements as the proper officers of the Company deem necessary or appropriate, Idaho Power Company may issue and sell its promissory notes (commercial paper or similar notes), from time to time (either in physical or electronic book-entry form or otherwise) to such lenders, brokers, dealers or placement agents in commercial paper as the officers of the Company may determine, in principal amounts not to exceed an aggregate of $450 000 000 at any time outstanding, each such note to be signed by one officer of the Company as hereinafter provided, at such prices and containing such dates, rates, maturities or other terms as the officer or officers executing said notes shall deem appropriate; provided, that no such note shall be for a term of more than 270 days; and be it FURTHER RESOLVED , That the signature or signatures on said promissory notes may be either the manual or facsimile signature of the Chief Executive Officer, the Chief Financial Officer or the Treasurer or any Assistant Treasurer of the Company, or any other officer of the Company designated in writing by any of the foregoing; and be it FURTHER RESOLVED, That anyone of the following officers of the Company, the Chief Executive Officer, the Chief Financial Officer, the Treasurer or any Assistant Treasurer be, and each hereby is authorized to execute and deliver on behalf of the Company an agreement, or an amendment to an existing agreement, with Wells Fargo Bank, Minneapolis, MN, or other financial institution, providing for the safekeeping, completion, countersignature, issuance and payment of the promissory notes of the Company; and be it FURTHER RESOLVED , That any of the above officers be and each one hereby is authorized to terminate such agreement or execute and deliver, from time to time, such amendments to said agreement as any such officer may deem to be desirable. TT A CHMENT III BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION IN THE MATTER OF THE APPLICATION OF IDAHO POWER COMPANY FOR AN ORDER AUTHORIZING UP TO $450 000 000 AGGREGATE PRINCIPAL AMOUNT AT ANY ONE TIME OUTSTANDING OF SHORT -TERM BORROWINGS CASE NO. IPC-07- PROPOSED ORDER , 2007 Idaho Power Company ("Idaho Power" or "Company ), an electrical utility headquartered in Boise, Idaho , providing retail electric service in southern Idaho and eastern Oregon, filed with this Commission its Application pursuant to Chapter 9, Title 61 of the Idaho Code and Rules 141 through 150 of the Commission s Rules of Procedure, requesting an Order authorizing Idaho Power to make up to $450 000 000 aggregate principal amount of short-term borrowings at anyone time outstanding. The Commission hereby adopts its Findings of Fact Conclusions of Law and Order approving the Application. FINDINGS OF FACT Idaho Power was incorporated on May 6, 1915 and migrated its state of incorporation to the state ofIdaho on June 30 , 1989 and is duly qualified to do business in the state ofIdaho. Idaho Power s principal office is located in Boise, Idaho. Idaho Power requests authorization to make short-term borrowings of up to $450 000 000 aggregate principal amount at anyone time outstanding for a period from April 1 2007 through April 1 , 2014. Idaho Power states that its short-term borrowings will consist of (1) PROPOSED ORDER - loans issued by financial and other institutions and evidenced by unsecured notes or other evidence of indebtedness of the Company and (2) unsecured promissory notes and commercial paper of the Company to be issued for public or pri v ate placement through one or more commercial paper dealers or agents, or directly by the Company. III Idaho Power intends to secure commitments for new unsecured lines of credit, or extensions of existing unsecured lines of credit, for its short-term borrowings. The unsecured lines of credit may be obtained with several financial or other institutions , directly by the Company or through an agent, when and if required by the Company s then current financial requirements. Each individual line of credit commitment will provide that up to a specific amount at anyone time outstanding will be available to the Company to draw upon for a fee to be determined by a percentage of the credit line available, credit line utilization, compensating balance or combination thereof. Idaho Power may also make arrangements for uncommitted credit facilities under which unsecured lines of credit would be offered to the Company on an "as available" basis and at negotiated interest rates. Such committed and uncommitted borrowings will be evidenced by the Company s unsecured promissory notes or other evidence of indebtedness. Unsecured promissory notes will be issued and sold by Idaho Power through one or more commercial paper dealers or agents, or directly by the Company, up to the limits imposed by applicable statutes, rules or regulations. Each note issued as commercial paper will be either discounted at the rate prevailing at the time of issuance for commercial paper of comparable quality and maturity or will be interest bearing to be paid at maturity. Each note will have a fixed maturity and will contain no provision for automatic "roll over PROPOSED ORDER - 2 Idaho Power plans to enter into a new credit agreement in April of 2007, which will provide a committed line of credit for short-term borrowings from participating banks. The Company expects that the credit agreement will initially authorize short-term borrowings of up to $300 million aggregate principal amount at anyone time outstanding, with the option of the Company to increase the borrowing limit to $450 million during the term of the credit agreement. Idaho Power further expects that the credit agreement will have an initial term of five years, from April 2007 to April 2012, with the option of the Company to extend the term for two one-year extensions , up to April 2014. Idaho Power will provide written notice to the Commission in the event that the Company elects to increase the short-term borrowing limit under the credit agreement above $300 000 000 , or extend the term of the credit agreement beyond April, 2012. Idaho Power states that its short-term borrowings will have maturities of one year or less. All short-term borrowings under the Company s application will mature no later than April 1 2014. VII Idaho Power s line of credit arrangements are expected to include one or more lead agents, and a number of additional banks as participating agents. The Company s proposed new credit agreement would likely include the following fees for the lead agent(s) and participating agents: an up-front arrangement fee payable to the lead agent(s) totaling approximately $225 000; up-front agent participation fees payable to all participating agents totaling approximately $87 500; annual commitment facility fees payable to all participating agents totaling approximately $210 000 per year; and annual administrative fees payable to the lead agent(s) of approximately $15 000 per PROPOSED ORDER - 3 year. Other expenses relating to the credit agreement are estimated to include: Idaho Power outside legal fees of approximately $30 000, agent legal fees of approximately $30 000, and miscellaneous expenses of approximately $5 000. Idaho Power states that such fees are customary in the market and will offset the agents ' costs , including personnel time, travel and administrative costs associated with negotiating and administering the credit agreement. Idaho Power further states that it expects to recei ve a reduction in the annual fees payable under the proposed new credit agreement, as compared with its current credit agreement fees. With respect to commercial paper issuances , Idaho Power expects that the commercial paper dealers or agents will sell such notes at a profit to them of not to exceed 1/8 of 1 percent of the principal amount of each note. VIII Idaho Power states the purpose for which the proposed short -term borrowings will be made and promissory notes , commercial paper or other evidence of indebtedness issued, is to obtain temporary short-term capital for the acquisition of property; the construction , completion, extension or improvement of its facilities; the improvement or maintenance of its service; the discharge or lawful refunding of its obligations; and for general corporate purposes. Idaho Power requests authorization to make the short-term borrowings as described in its application during said seven-year period, so long as the Company maintains at least a BBB- or higher senior secured debt rating, as indicated by Standard & Poor s Ratings Services , and a Baa3 or higher rating as indicated by Moody s Investors' Service , Inc. Idaho Power requests that if its senior secured debt rating falls below either such rating ("Downgrade ), its short-term borrowing authority would continue for a period of 364 days from the date of the Downgrade ("Continued Authorization Period"), provided that the Company: PROPOSED ORDER - 4 (1)Promptly notifies the Commission in writing of the Downgrade; and (2)Files a supplemental application with the Commission within seven (7) days after the Downgrade, requesting a supplemental order ("Supplemental Order ) authorizing Idaho Power to continue to make short-term borrowings and issue commercial paper as provided in the Order, notwithstanding the Downgrade. Until Idaho Power receives the Supplemental Order, any short-term borrowings made or commercial paper issued by the Company during the Continued Authorization Period would become due or mature no later than the final date of the Continued Authorization Period. CONCLUSIONS OF LAW Idaho Power is an electrical corporation within the definition of Idaho Code ~ 61-119 and is a public utility within the definition of Idaho Code ~ 61-129. The Idaho Public Utilities Commission has jurisdiction over this matter pursuant to the provisions of Idaho Code ~ 61-901 et seq.and the Application reasonably conforms to Rules 141 through 150 of the Commission s Rules of Procedures, IDAPA 31.01.01.141-150. The method of issuance is proper. The general purposes to which the proceeds will be put are lawful purposes under the Public Utility Law of the state of Idaho and are compatible with the public interest. However, this general approval of the general purposes to which the proceeds will be put is neither a finding of fact nor a conclusion of law that any particular construction program of the Company which may be benefited by the approval of this Application has been considered or approved by this Order, and this Order shall not be construed to that effect. The issuance of an Order authorizing the proposed financing does not constitute agency determination/approval of the type of financing or the related costs for ratemaking purposes PROPOSED ORDER - 5 which determination the Commission expressly reserves until the appropriate proceeding. All fees have been paid by Idaho Power in accordance with Idaho Code 9 61-905. ORDER IT IS THEREFORE ORDERED that Idaho Power Company is granted authority to make up to $450 000 000 aggregate principal amount at anyone time outstanding of short-term borrowings, for the period of April 1 , 2007 through April 1 , 2014, under the terms and conditions and for the purposes set forth in the Company s application and this Order. IT IS FURTHER ORDERED that this authorization will remain in place from April 2007 to April 2014, provided that the Company maintains at least a BBB- or higher senior secured debt rating, as indicated by Standard & Poor s Ratings Services, and a Baa3 or higher rating as indicated by Moody s Investors' Service, Inc. If Idaho Power s senior secured debt rating falls below either such rating ("Downgrade ), the Company s authority to incur short-term borrowings and issue commercial paper as provided in this Order will not terminate, but instead such authority will continue for a period of 364 days from the date of the 'Downgrade ("Continued Authorization Period"), provided that Idaho Power: (1) Promptly notifies the Commission in writing of the Downgrade; and (2) Files a supplemental application with the Commission within seven (7) days after the Downgrade, requesting a supplemental order ("Supplemental Order authorizing the Company to continue to make short-term borrowings and issue commercial paper as provided in the Order, notwithstanding the Downgrade. Until the Company receives the Supplemental Order, any short-term borrowings made or commercial paper issued by Idaho Power during the Continued Authorization Period will become due or mature no later than the final date of the Continued Authorization Period. Subject to the foregoing ordering paragraph regarding a Downgrade , no additional authorization is ~equired to carry out this transaction and no Supplemental Order will be issued. PROPOSED ORDER - 6 IT IS FURTHER ORDERED that Idaho Power file, as soon as available, final exhibits as set forth in its Application. IT IS FURTHER ORDERED that the foregoing authorization is without prejudice to the regulatory authority of this Commission with respect to rates , utility capital structure, service accounts, evaluation , estimates for determination of cost or any other matter which may come before this Commission pursuant to its jurisdiction and authority as provided by law. IT IS FURTHER ORDERED that nothing in this Order and no provisions of Title 61 Chapter 9, Idaho Code or any act or deed done or performed in connection therewith shall be construed to obligate the state of Idaho to payor guarantee in any manner whatsoever any security authorized, issued, assumed or guaranteed under the provisions of said Title 61 , Chapter 9 Idaho Code. DONE BY ORDER of the Idaho Public Utilities Commission at Boise , Idaho this day of 2007. PAUL KJELLANDER, President MACK A. REDFORD , Commissioner MARSHA H. SMITH, Commissioner ATTEST: Jean D. Jewell Commission Secretary PROPOSED ORDER - 7