UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D. C. 20549 FORM 10-Q X QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended September 30, 2001 OR TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from ______ to ______ Exact name of registrants as specified in their charters, state of I.R.S. Commission incorporation, address of Employer File principal executive offices, Identification Number and telephone number Number 1-14465 IDACORP, Inc. 82-0505802 1-3198 Idaho Power Company 82-0130980 1221 W. Idaho Street Boise, ID 83702-5627 Telephone: (208) 388-2200 State of Incorporation: Idaho Web site: www.idacorpinc.com None Former name, former address and former fiscal year, if changed since last report. Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No Number of shares of Common Stock outstanding as of September 30, 2001: IDACORP, Inc.: 37,468,712 Idaho Power Company: 37,612,351 shares, all of which are held by IDACORP, Inc. This combined Form 10-Q represents separate filings by IDACORP, Inc. and Idaho Power Company. Information contained herein relating to an individual registrant is filed by that registrant on its own behalf. Idaho Power Company makes no representations as to the information relating to IDACORP, Inc.'s other operations. INDEX Page Definitions 2 Part I. Financial Information: Item 1. Financial Statements IDACORP, Inc.: Consolidated Statements of Income 3-4 Consolidated Balance Sheets 5-6 Consolidated Statements of Capitalization 7 Consolidated Statements of Cash Flows 8 Consolidated Statements of Comprehensive Income 9 Notes to Consolidated Financial Statements 10-19 Independent Accountants' Report 20 Idaho Power Company: Consolidated Statements of Income 21-22 Consolidated Balance Sheets 23-24 Consolidated Statements of Capitalization 25 Consolidated Statements of Cash Flows 26 Consolidated Statements of Comprehensive Income 27 Notes to Consolidated Financial Statements 28-29 Independent Accountants' Report 30 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations 31-44 Item 3. Quantitative and Qualitative Disclosures about Market Risk 44 Part II. Other Information: Item 6. Exhibits and Reports on Form 8-K 45-50 Signatures 51-52 DEFINITIONS BPA - Bonneville Power MAF - Million Acre-Feet Administration Cal - California Independent MMbtu- Million British ISO System Operator Thermal Units MW - Megawatt CalPX- California Power MWH - Megawatt-hour Exchange DIG - Derivatives OPUC - Oregon Public Implementation Group Utility Commission FASB - Financial Accounting PCA - Power Cost Standards Board Adjustment FERC - Federal Energy PUCN - Public Utility Regulatory Commission Commission of IE - IDACORP Energy Nevada IPC - Idaho Power Company REA - Rural Electrification Administration IPUC - Idaho Public Utilities SFAS - Statement of Commission Financial Accounting kWh - kilowatt-hour Standards FORWARD LOOKING INFORMATION This Form 10-Q contains "forward-looking statements" intended to qualify for the safe harbor from liability established by the Private Securities Litigation Reform Act of 1995. Forward-looking statements should be read with the cautionary statements and important factors included in this Form 10-Q at Part I, Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations- Forward-Looking Information. Forward-looking statements are all statements other than statements of historical fact, including without limitation those that are identified by the use of the words "anticipates," "estimates," "expects," "intends," "plans," "predicts," and similar expressions. PART I - FINANCIAL INFORMATION Item 1. Financial Statements IDACORP, Inc. Consolidated Statements of Income Three Months Ended September 30, 2001 2000 (Thousands of Dollars Except Per Share Amounts) OPERATING REVENUES: Electric utility: General business $185,830 $158,611 Off system sales 91,654 61,179 Equity in earnings of partnerships 2,475 2,529 Other revenues 9,322 12,145 Total electric utility revenues 289,281 234,464 Energy marketing 104,985 72,881 Other 3,735 9,038 Total operating revenues 398,001 316,383 OPERATING EXPENSES: Electric Utility: Purchased power 228,460 139,243 Fuel expense 25,947 23,811 Power cost adjustment (57,770) (45,612) Other operations and maintenance 50,004 49,629 Depreciation 21,894 19,933 Taxes other than income taxes 4,947 5,024 Total electric utility expenses 273,482 192,028 Energy marketing 48,216 30,878 Other 7,305 10,909 Total operating expenses 329,003 233,815 OPERATING INCOME: Electric utility 15,799 42,436 Energy marketing 56,769 42,003 Other (3,570) (1,871) Total operating income 68,998 82,568 OTHER INCOME: Allowance for equity funds used during construction 173 696 Other - net 894 (3,357) Total other income 1,067 (2,661) INTEREST EXPENSE AND OTHER: Interest on long-term debt 13,788 13,239 Other interest 4,804 2,366 Allowance for borrowed funds used during construction (879) (609) Preferred dividends of Idaho Power Company 1,374 1,511 Total interest expense and other 19,087 16,507 INCOME BEFORE INCOME TAXES 50,978 63,400 INCOME TAXES 17,055 21,839 NET INCOME $ 33,923 $ 41,561 AVERAGE COMMON SHARES OUTSTANDING (000's) 37,410 37,524 EARNINGS PER SHARE OF COMMON STOCK $ 0.91 $ 1.11 (basic and diluted) The accompanying notes are an integral part of these statements. IDACORP, Inc. Consolidated Statements of Income Nine Months Ended September 30, 2001 2000 (Thousands of Dollars Except Per Share Amounts) OPERATING REVENUES: Electric utility: General business $475,158 $420,993 Off system sales 205,552 161,158 Equity in earnings of partnerships 7,522 9,240 Other revenues 34,763 29,820 Total electric utility revenues 722,995 621,211 Energy marketing 306,568 124,019 Other 10,189 19,940 Total operating revenues 1,039,752 765,170 OPERATING EXPENSES: Electric utility: Purchased power 523,165 253,762 Fuel expense 73,545 68,526 Power cost adjustment (184,102) (64,297) Other operations and maintenance 149,383 146,317 Depreciation 64,293 59,769 Taxes other than income taxes 15,591 15,914 Total electric utility expenses 641,875 479,991 Energy marketing 159,969 45,406 Other 24,089 26,261 Total operating expenses 825,933 551,658 OPERATING INCOME: Electric utility 81,120 141,220 Energy marketing 146,599 78,613 Other (13,900) (6,321) Total operating income 213,819 213,512 OTHER INCOME: Allowance for equity funds used during construction 758 1,787 Gains on sales of assets 1,605 14,000 Other - net 1,098 (2,082) Total other income 3,461 13,705 INTEREST EXPENSE AND OTHER: Interest on long-term debt 42,003 39,654 Other interest 13,464 7,051 Allowance for borrowed funds used during construction (3,295) (1,620) Preferred dividends of Idaho Power Company 4,128 4,423 Total interest expense and other 56,300 49,508 INCOME BEFORE INCOME TAXES 160,980 177,709 INCOME TAXES 56,198 61,546 NET INCOME $104,782 $116,163 AVERAGE COMMON SHARES OUTSTANDING (000's) 37,413 37,581 EARNINGS PER SHARE OF COMMON STOCK (basic and diluted) $ 2.80 $ 3.09 The accompanying notes are an integral part of these statements. IDACORP, Inc. Consolidated Balance Sheets Assets September 30, December 31, 2001 2000 (Thousands of Dollars) CURRENT ASSETS: Cash and cash equivalents $ 62,415 $ 106,795 Receivables: Customer 330,549 243,647 Allowance for uncollectible accounts (42,426) (23,079) Employee notes 5,170 4,742 Other 10,849 15,611 Energy marketing assets 294,825 1,060,128 Derivative assets 1,133 - Taxes receivable 19,621 - Accrued unbilled revenues 32,427 44,825 Materials and supplies (at average cost) 26,486 29,731 Fuel stock (at average cost) 6,797 5,105 Prepayments 26,845 24,575 Regulatory assets associated with income taxes 13,054 8,672 Regulatory assets - derivatives 55,136 - Total current assets 842,881 1,520,752 INVESTMENTS AND OTHER ASSETS 187,750 157,068 PROPERTY, PLANT AND EQUIPMENT: Utility plant in service 2,941,236 2,799,874 Accumulated provision for depreciation (1,201,079) (1,142,572) Utility plant in service - net 1,740,157 1,657,302 Construction work in progress 112,266 136,388 Utility plant held for future use 2,232 2,167 Other property, net of accumulated depreciation 18,893 9,179 Property, plant and equipment - net 1,873,548 1,805,036 DEFERRED DEBITS: American Falls and Milner water rights 31,585 31,585 Company-owned life insurance 39,627 39,554 Energy marketing assets - long-term 345,466 43,556 Regulatory assets associated with income taxes 198,240 204,880 Regulatory assets - PCA 308,107 119,905 Regulatory assets - long-term derivatives 15,229 - Regulatory assets - other 38,816 45,750 Other 67,952 71,620 Total deferred debits 1,045,022 556,850 TOTAL $3,949,201 $4,039,706 The accompanying notes are an integral part of these statements. IDACORP, Inc. Consolidated Balance Sheets Liabilities and Capitalization September 30, December 31, 2001 2000 (Thousands of Dollars) CURRENT LIABILITIES: Current maturities of long-term debt $ 9,110 $ 39,774 Notes payable 325,500 120,600 Accounts payable 353,466 272,376 Energy marketing liabilities 356,690 1,060,180 Derivative liabilities 56,270 - Taxes accrued - 15,631 Interest accrued 20,576 16,985 Deferred income taxes 13,054 8,672 Other 48,777 28,104 Total current liabilities 1,183,443 1,562,322 DEFERRED CREDITS: Deferred income taxes 567,733 460,464 Energy marketing liabilities - long- term 170,711 46,769 Derivative liabilities - long-term 15,229 - Regulatory liabilities associated with deferred investment tax credits 65,856 66,050 Regulatory liabilities associated with income taxes 39,979 40,230 Regulatory liabilities - other 4,178 4,621 Other 62,395 69,259 Total deferred credits 926,081 687,393 LONG-TERM DEBT 870,140 864,114 COMMITMENTS AND CONTINGENT LIABILITIES PREFERRED STOCK OF IDAHO POWER COMPANY 104,524 105,066 COMMON STOCK EQUITY: Common stock, no par value (shares authorized 120,000,000; 37,614,798 shares issued) 451,530 453,102 Retained earnings 422,565 370,126 Accumulated other comprehensive income (loss) (3,536) (921) Treasury stock (146,086 and 44,425 shares at cost, respectively) (5,546) (1,496) Total common stock equity 865,013 820,811 TOTAL $3,949,201 $4,039,706 The accompanying notes are an integral part of these statements. IDACORP, Inc. Consolidated Statements of Capitalization September 30, December 31, 2001 % 2000 % (Thousands of Dollars) COMMON STOCK EQUITY: Common stock $ 451,530 $ 453,102 Retained earnings 422,565 370,126 Accumulated other comprehensive income (loss) (3,536) (921) Treasury stock (5,546) (1,496) Total common stock equity 865,013 47 820,811 46 PREFERRED STOCK OF IDAHO POWER COMPANY: 4% preferred stock 14,524 15,066 7.68% Series, serial preferred stock 15,000 15,000 7.07% Series, serial preferred stock 25,000 25,000 Auction rate preferred stock 50,000 50,000 Total preferred stock 104,524 6 105,066 6 LONG-TERM DEBT: First mortgage bonds: 6.93% Series due 2001 - 30,000 6.85% Series due 2002 27,000 27,000 6.40% Series due 2003 80,000 80,000 8 % Series due 2004 50,000 50,000 5.83% Series due 2005 60,000 60,000 7.38% Series due 2007 80,000 80,000 7.20% Series due 2009 80,000 80,000 6.60% Series due 2011 120,000 - Maturing 2021 through 2031 with rates ranging from 7.5% to 9.52% 130,000 230,000 Total first mortgage bonds 627,000 637,000 Amount due within one year - (30,000) Net first mortgage bonds 627,000 607,000 Pollution control revenue bonds: 8.30% Series 1984 due 2014 49,800 49,800 6.05% Series 1996A due 2026 68,100 68,100 Variable Rate Series 1996B due 2026 24,200 24,200 Variable Rate Series 1996C due 2026 24,000 24,000 Variable Rate Series 2000 due 2027 4,360 4,360 Total pollution control revenue bonds 170,460 170,460 REA notes 1,282 1,339 Amount due within one year (77) (77) Net REA notes 1,205 1,262 American Falls bond guarantee 19,885 19,885 Milner Dam note guarantee 11,700 11,700 Unamortized premium/discount - net (1,048) (1,330) Debt related to investments in affordable housing with rates ranging from 6.03% to 8.59% due 2001 to 2011 49,673 64,063 Amount due within one year (9,033) (9,697) Net affordable housing debt 40,640 54,366 Other subsidiary debt 298 771 Total long-term debt 870,140 47 864,114 48 TOTAL CAPITALIZATION $1,839,677 100 $1,789,991 100 The accompanying notes are an integral part of these statements. IDACORP, Inc. Consolidated Statements of Cash Flows Nine Months Ended September 30, 2001 2000 (Thousands of Dollars) OPERATING ACTIVITIES: Net income $104,782 $116,163 Adjustments to reconcile net income to net cash provided by (used in) operating activities: Allowance for uncollectible accounts 19,347 - Unrealized gains from energy marketing activities (116,299) (11,904) Gains on sales of assets (1,605) (14,000) Depreciation and amortization 82,324 73,996 Deferred taxes and investment tax credits 115,045 29,741 Accrued PCA costs (188,202) (65,190) Undistributed earnings (losses) of affiliates 2,314 (558) Change in: Accounts receivable and prepayments (85,804) (98,296) Accrued unbilled revenue 12,398 (2,175) Materials and supplies and fuel stock (510) 3,021 Accounts payable 64,569 80,613 Taxes accrued (35,252) 2,711 Other current assets and liabilities 3,591 (5,823) Other - net (5,821) (4,608) Net cash provided by (used in) operating activities (29,123) 103,691 INVESTING ACTIVITIES: Additions to property, plant and equipment (138,260) (88,944) Investments in affordable housing projects - (15,813) Proceeds from sales of assets 11,126 17,500 Other - net (3,266) (8,012) Net cash used in investing activities (130,400) (95,269) FINANCING ACTIVITIES: Proceeds from issuance of: First mortgage bonds 120,000 - Pollution control revenue bonds - 4,360 Long-term debt related to affordable housing projects - 6,995 Retirement of: First mortgage bonds (130,000) (80,000) Long-term debt related to affordable housing projects (14,390) (15,173) Pollution control revenue bonds - (4,360) Reacquisition of common shares (7,969) (8,014) Dividends on common stock (52,343) (52,386) Increase in short-term borrowings 204,900 47,418 Other - net (5,055) (109) Net cash provided by (used in) financing activities 115,143 (101,269) Net decrease in cash and cash equivalents (44,380) (92,847) Cash and cash equivalents at beginning of period 106,795 111,338 Cash and cash equivalents at end of period $ 62,415 $ 18,491 SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: Cash (received) paid during the period for: Income taxes $(17,241) $ 30,928 Interest (net of amount capitalized) $ 46,772 $ 45,960 Distribution of treasury stock to affiliates $ 8,249 $ - The accompanying notes are an integral part of these statements. IDACORP, Inc. Consolidated Statements of Comprehensive Income Three Months Ended September 30, 2001 2000 (Thousands of Dollars) NET INCOME $33,923 $41,561 OTHER COMPREHENSIVE INCOME (LOSS): Unrealized gains (losses) on (1,008) 249 securities (net of tax of ($655) and $162) TOTAL COMPREHENSIVE INCOME $32,915 $41,810 The accompanying notes are an integral part of these statements. Nine Months Ended September 30, 2001 2000 (Thousands of Dollars) NET INCOME $104,782 $116,163 OTHER COMPREHENSIVE INCOME (LOSS): Unrealized gains (losses) on (2,615) 992 securities (net of tax of ($1,580) and $67) TOTAL COMPREHENSIVE INCOME $102,167 $117,155 The accompanying notes are an integral part of these statements. IDACORP, Inc. Notes to Consolidated Financial Statements 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: Nature of Business IDACORP, Inc. (IDACORP or the Company) is a holding company whose principal operating subsidiaries are Idaho Power Company (IPC) and IDACORP Energy (IE). IPC is regulated by the FERC and the state regulatory commissions of Idaho, Oregon, Nevada and Wyoming, and is engaged in the generation, transmission, distribution, sale and purchase of electric energy. IPC is the parent of Idaho Energy Resources Co., a joint venturer in Bridger Coal Company, which supplies coal to IPC's Jim Bridger generating plant. IE is a marketer of electricity and natural gas, trading in 31 states and two Canadian provinces. IDACORP's other subsidiaries include: Ida-West Energy - independent power projects development and management; IdaTech - developer of integrated fuel cell systems; IDACORP Financial Services - affordable housing and other real estate investments; Rocky Mountain Communications (RMC) - commercial and residential Internet service provider; IDACOMM - provider of telecommunications services; IDACORP Services - products and services for homes and businesses. Financial Statements In the opinion of the Company, the accompanying unaudited consolidated financial statements contain all adjustments necessary to present fairly its consolidated financial position as of September 30, 2001, and its consolidated results of operations for the three and nine months ended September 30, 2001 and 2000 and consolidated cash flows for the nine months ended September 30, 2001 and 2000. These financial statements do not contain the complete detail or footnote disclosure concerning accounting policies and other matters that would be included in full year financial statements and therefore they should be read in conjunction with the Company's audited consolidated financial statements included in the Company's Annual Report on Form 10-K for the year ended December 31, 2000. The results of operations for the interim periods are not necessarily indicative of the results to be expected for the full year. Planned Major Maintenance The Company records repair and maintenance costs associated with planned major maintenance activities as these costs are incurred. Regulatory Assets IPC has $4.5 million of regulatory assets that are not earning a return. These assets are predominately related to reorganization costs and post-employment benefits, and have remaining amortization periods of less than five years. Principles of Consolidation The consolidated financial statements include the accounts of the Company and its wholly-owned or controlled subsidiaries. All significant intercompany transactions and balances have been eliminated in consolidation. Investments in business entities in which the Company and its subsidiaries do not have control, but have the ability to exercise significant influence over operating and financial policies, are accounted for using the equity method. Reclassifications Certain items previously reported for periods prior to September 30, 2001 have been reclassified to conform with the current period's presentation. Net income and common stock equity were not affected by these reclassifications. New Accounting Pronouncements In July 2001 the FASB issued SFAS 141, "Business Combinations," which addresses accounting and reporting for business combinations. SFAS 141 requires that all business combinations initiated after June 30, 2001 be accounted for using one method, the purchase method. The Company does not believe the adoption will have a significant effect on its financial statements. Also in July 2001 the FASB issued SFAS 142 "Goodwill and Other Intangible Assets," which is effective January 1, 2002. SFAS 142 requires, among other things, that goodwill can no longer be amortized. In addition, the standard includes provisions for the reclassification of certain existing recognized intangibles as goodwill, reassessment of the useful lives of existing recognized intangibles, reclassification of certain intangibles out of previously reported goodwill and the identification of reporting units for purposes of assessing potential future impairments of goodwill. SFAS 142 also requires the Company to complete a transitional goodwill impairment test six months from the date of adoption. The Company is currently assessing but has not yet determined the impact of SFAS 142 on its financial position and results of operations. In August 2001 the FASB issued SFAS 143 "Accounting for Asset Retirement Obligations" which is effective for fiscal years beginning after June 15, 2002. This Statement addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. An obligation may result from the acquisition, construction, development and the normal operation of a long-lived asset. The Company is currently assessing but has not yet determined the impact of SFAS 143 on its financial position and results of operations. Also in August 2001 the FASB issued SFAS 144 "Accounting for the Impairment or Disposal of Long-Lived Assets" which is effective for fiscal years beginning after December 15, 2001. SFAS 144 addresses financial accounting and reporting for the impairment or disposal of long-lived assets superseding SFAS 121 "Accounting for the Impairment of Long- Lived Assets and for Long-Lived Assets to be Disposed of." The Company is currently assessing but has not yet determined the impact of SFAS 144 on its financial position and results of operations. 2. INCOME TAXES The Company's effective tax rate for the first nine months increased from 34.6 percent in 2000 to 34.9 percent in 2001. Reconciliations between the statutory income tax rate and the effective rates are as follows (in thousands of dollars): Nine Months Ended September 30, 2001 2000 Amount Rate Amount Rate Computed income taxes based on statutory federal income tax rate $ 56,343 35.0% $ 62,198 35.0% Changes in taxes resulting from: Investment tax credits (2,329) (1.4) (2,313) (1.3) Repair allowance (2,100) (1.3) (2,100) (1.2) Pension expense (1,368) (0.9) (1,420) (0.8) State income taxes 8,734 5.4 8,841 4.9 Depreciation 6,325 3.9 5,154 2.9 Affordable housing tax credits (10,034) (6.2) (10,257) (5.8) Preferred dividends of IPC 1,444 0.9 1,548 0.9 Other (817) (0.5) (105) 0.0 Total provision for federal and state income taxes $ 56,198 34.9% $ 61,546 34.6% 3. PREFERRED STOCK OF IDAHO POWER COMPANY: The number of shares of IPC preferred stock outstanding were as follows: September 30, December 31, 2001 2000 Cumulative, $100 par value: 4% preferred stock (authorized 215,000 shares) 145,244 150,656 Serial preferred stock, 7.68% Series (authorized 150,000 shares) 150,000 150,000 Serial preferred stock, cumulative, without par value; total of 3,000,000 shares authorized: 7.07% Series, $100 stated value, (authorized 250,000 shares) 250,000 250,000 Auction rate preferred stock, $100,000 stated value, (authorized 500 shares) 500 500 4. FINANCING: At September 30, 2001, IPC had regulatory authority to incur up to $500 million of short-term indebtedness. On September 12, 2001, IPC issued $100 million Floating Rate Notes, Due September 1, 2002. Proceeds from this issuance were used to retire other short-term borrowings. At September 30, 2001, IPC's short-term borrowing totaled $244 million. The Company has bank line of credit facilities established at both IPC and IDACORP. IPC has a $120 million multi-year revolving credit facility that expires in December 2001 under which it pays a facility fee on the commitment, quarterly in arrears, based on IPC's First Mortgage Bond rating. IPC also established on April 27, 2001 a 364-day credit facility for up to $165 million in support of its ongoing operations. IPC commercial paper may be issued subject to the regulatory maximum. IDACORP has separately established a $50 million three-year credit facility that expires in December 2001, and a $375 million 364-day credit facility that expires in March 2002. Under these facilities IDACORP pays a facility fee on the commitment, quarterly in arrears, based on IPC's First Mortgage Bond rating. At September 30, 2001, short-term borrowing on these facilities totaled $81.5 million. IDACORP currently has a $300 million shelf registration statement that can be used for the issuance of unsecured debt and preferred or common stock. At September 30, 2001, none had been issued. On March 23, 2000, IPC filed a $200 million shelf registration statement that could be used for First Mortgage Bonds (including medium term notes), unsecured debt, or preferred stock. On December 1, 2000, IPC issued $80 million principal amount of Secured Medium Term Notes, Series C, 7.38% Series due 2007. Proceeds were used for the early redemption in January 2001 of the $75 million First Mortgage Bonds 9.50% Series due 2021. On March 2, 2001, IPC issued $120 million principal amount of Secured Medium Term Notes, Series C, 6.60% Series due 2011 with the proceeds used to reduce short-term borrowing incurred in support of ongoing long-term construction requirements. At September 30, 2001, no amount remained to be issued on this shelf registration statement. On August 16, 2001, IPC filed a $200 million shelf registration statement that can be used for First Mortgage Bonds (including medium-term notes), unsecured debt or preferred stock. At September 30, 2001, no amounts had been issued. 5. COMMITMENTS AND CONTINGENT LIABILITIES: Commitments under contracts and purchase orders relating to IPC's program for construction and operation of facilities amounted to approximately $6.5 million at September 30, 2001. Additionally, Ida-West Energy has commitments totaling $30.5 million. The commitments are generally revocable by the Company subject to reimbursement of manufacturers' expenditures incurred and/or other termination charges. From time to time the Company is party to various legal claims, actions, and complaints, certain of which may involve material amounts. Although the Company is unable to predict with certainty whether or not it will ultimately be successful in these legal proceedings, or, if not, what the impact might be, based upon the advice of legal counsel, management presently believes that disposition of these matters will not have a material adverse effect on the Company's financial position, results of operation, or cash flows. IE also has approximately $0.4 million in receivables from less-than-investment grade entities at September 30, 2001. California Energy Situation 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 (CalPX), a California non-profit public benefit corporation. The CalPX, at this 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 exchange defaults on a payment to the exchange, the other participants are required to pay their allocated share of the default amount to the exchange. The allocated shares are based upon the level of trading activity, which includes 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 $2.2 million - a "default share invoice" - as a result of an alleged Southern California Edison (SCE) payment default of $214.5 million for power purchases. IPC made this payment. On January 24, 2001, IPC terminated the participation agreement. On February 8, 2001, the CalPX sent a further invoice for $5.2 million, due February 20, 2001, as a result of alleged payment defaults by SCE, Pacific Gas and Electric Company (PG&E), and others. However, because the CalPX owed IPC $11.3 million for power sold to the CalPX in November and December 2000, IPC did not pay the February 8th invoice. IPC essentially discontinued energy trading with California entities in December 2000. IPC believes that the default invoices were not proper and that IPC owes no further amounts to the CalPX. IPC has pursued all available remedies in its efforts to collect amounts owed to it by the CalPX. On February 20, 2001, IPC filed a petition with FERC to intervene in a proceeding which requested the FERC to suspend the use of the CalPX charge back methodology and provides for further oversight in the CalPX's implementation of its default mitigation procedures. A preliminary injunction was granted by a Federal Judge in the Federal 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, PG&E filed for bankruptcy. The CalPX and the California Independent System Operator (Cal ISO) were also creditors of PG&E. To the extent that PG&E's bankruptcy filing affects the collectibility of our receivables from the CalPX and Cal ISO our receivables from these entities are at greater risk. Also 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 its 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 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 Cal ISO 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 Chief Judge submitted a Report and Recommendation to the FERC recommending that the FERC adopt his methodology set forth in his report and set for evidentiary hearing an analysis of the Cal ISO's and the CalPX's spot markets to determine what refunds may be due upon application of that methodology. The Judge recommended that his methodology should be applied to all sellers except those who at the evidentiary hearing are able to demonstrate that their costs exceed the results of the recommended 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 Cal ISO and the CalPX during the period October 2, 2000 through June 20, 2001. As to potential refunds, if any, the Company believes that its exposure will be more than offset by amounts due it from California entities. In addition, the July 25, 2001 FERC order established 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 (ALJ) submitted her recommendations and findings to the FERC on September 24, 2001. The ALJ found that the prices were just and reasonable and therefore no refunds should be allowed. Procedurally, the ALJ's decision is a recommendation to the commissioners of the FERC. The FERC is not bound to accept any or all of it. The next step is for the FERC to issue an order in response to the ALJ's recommendation. The FERC has issued a notice soliciting comments on this case. Although there is no binding timeframe for the FERC to issue its order, it may issue an order in the next 30 to 60 days. Actions of the FERC are appealable to the United States Court of Appeals. The Company will continue to monitor all proceedings to determine the impact on the Company. Counsel has been retained in connection with the CalPX and PG&E bankruptcies and FERC proceedings. Effective June 11, 2001, IPC transferred its wholesale electricity marketing operations to IE. IE is a Delaware limited partnership with IDACORP, Inc. as its sole general partner and IDACORP Energy Services Co., a wholly-owned subsidiary of IDACORP, Inc., as its sole limited partner (see Note 9 to the Idaho Power Company financial statements and the MD&A, "Other Matters - Energy Marketing"). Effective with the June 11 transfer, the outstanding receivables and payables with the CalPX and Cal ISO were assigned from IPC to IE. At September 30, 2001, the CalPX and Cal ISO owed $13 million and $31 million respectively for energy sales made to them by IPC in November and December 2000. In addition, at September 30, 2001, IE had accrued but not paid $35.1 million due to the Cal ISO as an offset to the outstanding receivable. IE has accrued a reserve of $4 million against these receivables. These reserves were calculated taking into account the deterioration of the California energy markets and, for the less-than-investment-grade receivables, by using a model that estimates the probability of default and the estimated recovery amounts of such receivables. Based on the reserves recorded as of September 30, 2001, the Company believes that the future collectibility of these receivables or any potential refunds ordered by the FERC would not have a significant impact on operations or liquidity. 6. REGULATORY ISSUES: Idaho Power Cost Adjustment (PCA) IPC has a PCA mechanism that provides for annual adjustments to the rates IPC charges to Idaho retail customers. These adjustments, which take effect annually in May, are based on forecasts of net power supply expenses. During the year, the difference between actual and forecasted costs is deferred with interest. The balance of this deferral, called a true-up, is then included in the calculation of the next year's PCA adjustment. In its 2001 PCA filing, IPC requested recovery of $227.4 million of power supply costs. In May, the IPUC authorized recovery of $168.3 million, but deferred recovery of $59.1 million pending further review. The approved amount resulted in an average rate increase of 31.6 percent. After conducting hearings on the remaining $59.1 million, the IPUC authorized recovery of $47.7 million plus $1.2 million of accrued interest, beginning in October 2001. The remaining $11.4 million not recovered in rates from the PCA filing was written off in September 2001. Of the $227 million requested by IPC, $185 million related to the true-up of power supply costs incurred in the 2000- 2001 PCA year and $42 million was for recovery of excess power supply costs forecasted in the 2001-2002 PCA year. The forecast amount, however, underestimates expected power supply costs. Reservoir water is significantly lower than forecast, necessitating the use of higher cost alternatives to hydro generation. As part of the May 2001 PCA, the IPUC required IPC to implement a three-tiered rate structure for Idaho residential customers. The IPUC determined that the approved rates for residential customers should increase as a customer's electricity consumption increases. The residential rate increases are 14.4 percent for the first 800 kWh of usage, 28.8 percent for the next 1,200 kWh, and 62 percent for usage over 2,000 kWh. On August 31, IPC filed a request with the IPUC to implement a rate credit to qualifying residential and small farm customers. The credit is the result of a settlement agreement between IPC and the Bonneville Power Administration (BPA), which will pass on the benefits of the Federal Columbia River Power System. IPC estimates the credit could be as much as $3.60 per month for residential customers who use 1,200 kWh per month and $300 per month for farm customers that use 100,000 kWh. The IPUC, by Order No. 28868, approved the credit to be passed to the qualified customers effective October 1, 2001. In its May 2001 rate authorization the IPUC also directed IPC to reinstate a comprehensive conservation program given the current volatility of market prices and the opportunity to incorporate long-term conservation. In response to that directive, IPC filed a report of present energy efficiency activities, a list of conservation measures, an examination of funding options and a detailed program structure that could be implemented should the Commission determine that additional conservation programs, including the funding of these programs, is in the public interest. On October 18, 2001 IPC filed an application with the IPUC for an order approving the costs to be included in the 2002- 2003 PCA for the Irrigation Load Reduction Program and Astaris Load Reduction Agreement. These two programs were implemented in 2001 to reduce demand and were approved by the IPUC and OPUC. The costs included in the application were $58.6 million for the Irrigation Load Reduction Program and $42.2 million for the Astaris Load Reduction Agreement, representing total costs through September 2001. IPC will file a second application requesting approval for subsequently incurred costs. Oregon Excess Power Costs IPC filed an application with the OPUC to begin recovering extraordinary 2001 power supply costs in its Oregon jurisdiction. On June 18, 2001, the OPUC approved new rates that will recover $0.8 million over the next year. Under the provisions of the deferred accounting statute, ORS757.259(6), annual rate recovery of deferred amounts is limited to $0.8 million or 3% of IPC's 2000 gross revenues in Oregon. IPC filed on October 5, 2001 to recover an additional 3% of extraordinary power supply costs deferred for 2001. The OPUC will hear the request November 20, 2001 and a decision could be made as early as November 28, 2001. The Oregon deferral balance is $12.2 as of September 30, 2001, net of the June 18th recovery. IPC filed with the OPUC a request to implement the same BPA program as in Idaho. The OPUC held a public meeting on October 22, 2001. The OPUC approved the Company's request to implement the BPA residential and small farm energy credit (BPA Credit) for the benefits derived during the period October 1, 2001 though September 30, 2006. IPC is also planning to file for a comprehensive conservation program in its Oregon jurisdiction. 7. DERIVATIVE FINANCIAL INSTRUMENTS: The Company uses financial instruments such as commodity futures, forwards, options and swaps to manage exposure to commodity price risk in the electricity and natural gas markets. The objective of the Company's risk management program is to mitigate the risk associated with the purchase and sale of electricity and natural gas as well as to optimize its energy marketing portfolio. The accounting for derivative financial instruments that are used to manage risk is in accordance with the concepts established in Emerging Issues Task Force (EITF) 98-10, "Accounting for Contracts Involved in Energy Trading Activities," and SFAS 133, "Accounting for Derivative Instruments and Hedging Activities" as amended by SFAS 138 "Accounting for Certain Derivative Instruments and Certain Hedging Activities." Energy Trading Contracts All contracts classified as energy trading contracts, under the guidance provided by EITF 98-10, including forward transmission contracts, are marked to market and the resulting change in fair value from the previous period is presented on IDACORP'S Statement of Income in "Energy marketing revenues." The same accounting treatment is applied for all energy trading contracts regardless of whether they are anticipated to be physically scheduled for delivery or net settled for cash. In the settlement month of these energy contracts, the gains and losses from settlement are recorded and the previously recognized mark- to-market values are reversed in the same financial statement line item. Transmission costs associated with the physical delivery of energy are reported as "Energy marketing expenses" in the month of settlement. The fair value of positions recorded on the balance sheet is dependent on the price, volatility, and other uncertainties of the energy markets. As such, these items on the balance sheet can fluctuate greatly without large changes in volumes or positions. Cash flows from energy trading contracts are recognized in the statement of cash flows as an operating activity. Derivative Assets and Liabilities The Company adopted SFAS 133, as amended, effective January 1, 2001. Contracts company-wide were evaluated based upon the SFAS 133 derivative definitions and requirements. Most of the Company's contracts that meet the derivative definition are the energy trading contracts that were already recorded at fair value under EITF 98-10 as discussed above. Most of the remaining energy contracts meet the definition of a normal purchase or sale as described in SFAS 138 and therefore are not considered derivatives. However, IPC has certain electricity contracts that are periodically net settled with the counterparty (booked out). Booking out of electricity contracts is a normal business transaction within the electric utility industry; however the FASB and the Derivative Implementation Group (DIG) initially interpreted that book outs did not qualify for the normal purchase and sales exception. The Company has recorded the fair market value of the booked out system electricity contracts within the financial statements as "Derivative assets" and "Derivative liabilities". Such assets and liabilities at January 1 and September 30, 2001 are as follows: January 1, 2001 September 30, 2001 (Thousands of Dollars) Assets $ 108,909 $ 1,133 Liabilities (207,407) (71,499) Net $ (98,498) $ (70,366) The electricity contracts identified above are subject to IPC regulatory processes. Accordingly, SFAS 71, "Accounting for the Effects of Certain Types of Regulation" allows the net amount of these Derivative assets and liabilities to be offset by regulatory assets or liabilities. The IPUC granted approval of this use of SFAS 71 regulatory assets or liabilities in its Order 28661 issued March 12, 2001. In June 2001 the DIG issued Interpretation C-15 that tentatively concludes that certain booked out contracts now qualify for the normal purchase and sales exception. IPC is evaluating the effect of this new conclusion on its treatment of booked out contracts but expects that some contracts previously classified as derivatives will be exempt when C-15 becomes final. The effect of this change will not have a material effect on IPC's financial position, results of operations, or cash flows. As a result of the items discussed above, the Company's adoption of SFAS 133, as amended, did not have a material effect on its financial position, results of operations, or cash flows. 8. INDUSTRY SEGMENT INFORMATION: The Company has identified two reportable operating segments, Utility Operations and Energy Marketing. The following table summarizes the segment information for the Company's utility operations and energy marketing segments and the total of all other segments, and reconciles this information to total enterprise amounts. Utility Energy Consolidated Operations Marketing Other Eliminations Total (Thousands of Dollars) Three months ended September 30, 2001: Revenues $ 289,281 $ 105,886 $ 3,735 $ (901) $ 398,001 Net income (loss) (100) 34,798 (775) - 33,923 Total assets at September 30, 2001 $2,913,304 $1,014,331 $319,974 $(298,408) $3,949,201 Three months ended September 30, 2000: Revenues $ 234,464 $ 72,881 $ 9,038 $ - $ 316,383 Net income (loss) 16,281 25,869 (589) - 41,561 Total assets at $2,530,312 $1,312,045 $197,349 $ - $4,039,706 December 31, 2000 Nine months ended September 30, 2001: Revenues $ 722,995 $ 307,469 $ 10,189 $ (901) $1,039,752 Net income (loss) 19,598 88,869 (3,685) - 104,782 Nine months ended September 30, 2000: Revenues $ 621,211 $ 124,019 $ 19,940 $ - $ 765,170 Net income (loss) 58,932 48,423 8,808 - 116,163 INDEPENDENT ACCOUNTANTS' REPORT IDACORP, Inc. Boise, Idaho We have reviewed the accompanying consolidated balance sheet and statement of capitalization of IDACORP, Inc. and subsidiaries as of September 30, 2001, and the related consolidated statements of income and comprehensive income for the three and nine month periods ended September 30, 2001 and 2000 and consolidated statements of cash flows for the nine month periods ended September 30, 2001 and 2000. These financial statements are the responsibility of the Company's management. We conducted our review in accordance with standards established by the American Institute of Certified Public Accountants. A review of interim financial information consists principally of applying analytical procedures to financial data and of making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with auditing standards generally accepted in the United States of America, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion. Based on our review, we are not aware of any material modifications that should be made to such consolidated financial statements for them to be in conformity with accounting principles generally accepted in the United States of America. We have previously audited, in accordance with auditing standards generally accepted in the United States of America, the consolidated balance sheet and statement of capitalization of IDACORP, Inc. and subsidiaries as of December 31, 2000, and the related consolidated statements of income, comprehensive income, retained earnings, and cash flows for the year then ended (not presented herein); and in our report dated February 1, 2001, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet and statement of capitalization as of December 31, 2000 is fairly stated, in all material respects, in relation to the consolidated balance sheet and statement of capitalization from which it has been derived. DELOITTE & TOUCHE LLP Boise, Idaho October 24, 2001 Idaho Power Company Consolidated Statements of Income Three Months Ended September 30, 2001 2000 (Thousands of Dollars) REVENUES: General business $185,830 $158,611 Off system sales 91,654 61,179 Other revenues 8,808 11,749 Total revenues 286,292 231,539 EXPENSES: Operation: Purchased power 228,460 139,243 Fuel expense 25,947 23,811 Power cost adjustment (57,770) (45,612) Other 36,515 35,505 Maintenance 13,829 13,676 Depreciation 21,894 19,933 Taxes other than income taxes 4,947 5,024 Total expenses 273,822 191,580 INCOME FROM OPERATIONS 12,470 39,959 OTHER INCOME: Allowance for equity funds used during construction 173 696 Other - Net 4,930 2,206 Total other income 5,103 2,902 INTEREST CHARGES: Interest on long-term debt 13,770 13,217 Other interest 2,450 1,042 Allowance for borrowed funds used during construction (879) (609) Total interest charges 15,341 13,650 INCOME BEFORE INCOME TAXES 2,232 29,211 INCOME TAXES 958 11,419 INCOME FROM CONTINUING OPERATIONS 1,274 17,792 DISCONTINUED OPERATIONS: Income from operations of energy marketing transferred to parent (net of income taxes of $17,010) - 25,303 NET INCOME 1,274 43,095 Dividends on preferred stock 1,374 1,511 EARNINGS (LOSS) ON COMMON STOCK $ (100) $ 41,584 The accompanying notes are an integral part of these statements. Idaho Power Company Consolidated Statements of Income Nine Months Ended September 30, 2001 2000 (Thousands of Dollars) REVENUES: General business $475,158 $420,993 Off system sales 205,552 161,158 Other revenues 33,828 28,803 Total revenues 714,538 610,954 EXPENSES: Operation: Purchased power 523,165 253,762 Fuel expense 73,545 68,526 Power cost adjustment (184,102) (64,297) Other 108,055 108,626 Maintenance 41,046 36,589 Depreciation 64,293 59,769 Taxes other than income taxes 15,591 15,914 Total expenses 641,593 478,889 INCOME FROM OPERATIONS 72,945 132,065 OTHER INCOME: Allowance for equity funds used during construction 758 1,787 Other - Net 12,108 9,018 Total other income 12,866 10,805 INTEREST CHARGES: Interest on long-term debt 41,943 39,575 Other interest 7,270 3,433 Allowance for borrowed funds used during construction (3,295) (1,620) Total interest charges 45,918 41,388 INCOME BEFORE INCOME TAXES 39,893 101,482 INCOME TAXES 15,549 38,127 INCOME FROM CONTINUING OPERATIONS 24,344 63,355 DISCONTINUED OPERATIONS: Income from operations of energy marketing transferred to parent (net of income taxes of $33,574 in 2001 and $30,668 in 2000) 49,943 45,620 NET INCOME 74,287 108,975 Dividends on preferred stock 4,128 4,423 EARNINGS ON COMMON STOCK $ 70,159 $104,552 The accompanying notes are an integral part of these statements. Idaho Power Company Consolidated Balance Sheets Assets September 30, December 31, 2001 2000 (Thousands of Dollars) ELECTRIC PLANT: In service (at original cost) $2,941,236 $2,799,590 Accumulated provision for depreciation (1,201,079) (1,142,572) In service - Net 1,740,157 1,657,018 Construction work in progress 102,852 130,477 Held for future use 2,232 2,167 Electric plant - Net 1,845,241 1,789,662 INVESTMENTS AND OTHER PROPERTY 18,368 21,502 CURRENT ASSETS: Cash and cash equivalents 26,918 83,494 Receivables: Customer 93,786 74,225 Allowance for uncollectible accounts (1,397) (1,397) Notes 2,895 2,945 Employee notes 5,170 4,742 Related parties 62,058 311 Other 2,306 4,943 Derivative assets 1,133 - Taxes receivable 16,566 - Accrued unbilled revenues 32,427 44,825 Materials and supplies (at average cost) 22,599 24,685 Fuel stock (at average cost) 6,797 5,105 Prepayments 26,611 24,145 Regulatory assets associated with income taxes 13,054 8,672 Regulatory assets - derivatives 55,136 - Net assets of discontinued operations - 37,702 Total current assets 366,059 314,397 DEFERRED DEBITS: American Falls and Milner water rights 31,585 31,585 Company-owned life insurance 39,627 39,554 Regulatory assets associated with income taxes 198,240 204,880 Regulatory assets - PCA 308,107 119,905 Regulatory assets - long-term derivatives 15,229 - Regulatory assets - other 38,816 45,750 Other 52,032 49,857 Total deferred debits 683,636 491,531 TOTAL $2,913,304 $2,617,092 The accompanying notes are an integral part of these statements. Idaho Power Company Consolidated Balance Sheets Liabilities and Capitalization September 30, December 31, 2001 2000 (Thousands of Dollars) CAPITALIZATION: Common stock equity: Common stock, $2.50 par value (50,000,000 shares authorized; 37,612,351 shares outstanding) $ 94,031 $ 94,031 Premium on capital stock 362,570 362,430 Capital stock expense (4,113) (4,024) Retained earnings 331,615 313,800 Accumulated other comprehensive income (loss) (3,536) (921) Total common stock equity 780,567 765,316 Preferred stock 104,524 105,066 Long-term debt 829,202 808,977 Total capitalization 1,714,293 1,679,359 CURRENT LIABILITIES: Long-term debt due within one year 77 30,077 Notes payable 244,000 59,700 Accounts payable 123,354 164,237 Notes and accounts payable to related parties 4,516 4,212 Derivative liabilities 56,270 - Taxes accrued - 12,983 Interest accrued 19,793 15,002 Deferred income taxes 13,054 8,672 Other 11,688 18,460 Total current liabilities 472,752 313,343 DEFERRED CREDITS: Regulatory liabilities associated with deferred investment tax credits 65,856 66,050 Deferred income taxes 544,020 452,404 Derivative liabilities - long-term 15,229 - Regulatory liabilities associated with income taxes 39,979 40,230 Regulatory liabilities - other 4,178 4,621 Other 56,997 61,085 Total deferred credits 726,259 624,390 COMMITMENTS AND CONTINGENT LIABILITIES TOTAL $2,913,304 $2,617,092 The accompanying notes are an integral part of these statements. Idaho Power Company Consolidated Statements of Capitalization September 30, December 31, 2001 % 2000 % (Thousands of Dollars) COMMON STOCK EQUITY: Common stock $ 94,031 $ 94,031 Premium on capital stock 362,570 362,430 Capital stock expense (4,113) (4,024) Retained earnings 331,615 313,800 Accumulated other comprehensive income (loss) (3,536) (921) Total common stock equity 780,567 46 765,316 46 PREFERRED STOCK: 4% preferred stock 14,524 15,066 7.68% Series, serial preferred stock 15,000 15,000 7.07% Series, serial preferred stock 25,000 25,000 Auction rate preferred stock 50,000 50,000 Total preferred stock 104,524 6 105,066 6 LONG-TERM DEBT: First mortgage bonds: 6.93% Series due 2001 - 30,000 6.85% Series due 2002 27,000 27,000 6.40% Series due 2003 80,000 80,000 8 % Series due 2004 50,000 50,000 5.83% Series due 2005 60,000 60,000 7.38% Series due 2007 80,000 80,000 7.20% Series due 2009 80,000 80,000 6.60% Series due 2011 120,000 - Maturing 2021 through 2031 with rates ranging from 7.5% to 9.52% 130,000 230,000 Total first mortgage bonds 627,000 637,000 Amount due within one year - (30,000) Net first mortgage bonds 627,000 607,000 Pollution control revenue bonds: 8.30% Series 1984 due 2014 49,800 49,800 6.05% Series 1996A due 2026 68,100 68,100 Variable Rate Series 1996B due 2026 24,200 24,200 Variable Rate Series 1996C due 2026 24,000 24,000 Variable Rate Series 2000 due 2007 4,360 4,360 Total pollution control revenue bonds 170,460 170,460 REA notes 1,282 1,339 Amount due within one year (77) (77) Net REA notes 1,205 1,262 American Falls bond guarantee 19,885 19,885 Milner Dam note guarantee 11,700 11,700 Unamortized premium/discount - (1,048) (1,330) Net Total long-term debt 829,202 48 808,977 48 TOTAL CAPITALIZATION $1,714,293 100 $1,679,359 100 The accompanying notes are an integral part of these statements. Idaho Power Company Consolidated Statements of Cash Flows Nine Months Ended September 30, 2001 2000 (Thousands of Dollars) OPERATING ACTIVITIES: Net income $ 74,287 $108,975 Adjustments to reconcile net income to net cash provided by (used in) operating activities: Allowance for uncollectible accounts 20,174 - Unrealized gains from energy marketing activities (101,461) (4,022) Depreciation and amortization 73,740 67,750 Deferred taxes and investment tax credits 99,391 28,355 Undistributed earnings of affiliates 1,897 (1,490) Accrued PCA costs (188,202) (65,190) Changes in (net of effects of transfers to parent): Accounts receivable and prepayments (13,047) (97,311) Accrued unbilled revenue 12,398 (2,175) Materials and supplies and fuel stock 394 2,621 Accounts payable 8,276 102,452 Taxes accrued (29,549) 1,288 Other current assets and liabilities 167 (7,117) Other - net (4,892) (6,341) Net cash provided by (used in) operating activities (46,427) 127,795 INVESTING ACTIVITIES: Additions to utility plant (120,871) (88,944) Net cash of affiliates transferred to parent - (4,737) Other - net (3,182) 1,722 Net cash used in investing activities (124,053) (91,959) FINANCING ACTIVITIES: Proceeds from issuance of: First mortgage bonds 120,000 - Pollution control revenue bonds - 4,360 Retirement of: First mortgage bonds (130,000) (80,000) Pollution control revenue bonds - (4,360) Dividends on common stock (52,343) (52,386) Dividends on preferred stock (4,128) (4,423) Increase (decrease) in short-term borrowings 184,300 13,277 Other - net (3,925) (504) Net cash provided by (used in) financing activities 113,904 (124,036) Net decrease in cash and cash equivalents (56,576) (88,200) Cash and cash equivalents at beginning of period 83,494 95,038 Cash and cash equivalents at end of period $ 26,918 $ 6,838 SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: Cash (received) paid during the period for: Income taxes $(15,059) $ 43,483 Interest (net of amount capitalized) 39,058 41,263 Net assets of affiliates transferred to parent as dividend - 22,090 Net assets transferred to parent for notes receivable 76,250 - The accompanying notes are an integral part of these statements. Idaho Power Company Consolidated Statements of Comprehensive Income Three Months Ended September 30, 2001 2000 (Thousands of Dollars) NET INCOME $ 1,274 $43,095 OTHER COMPREHENSIVE INCOME (LOSS): Unrealized gains (losses) on (1,008) 249 securities (net of tax of ($655) and $162) TOTAL COMPREHENSIVE INCOME $ 266 $43,344 The accompanying notes are an integral part of these statements. Nine Months Ended September 30, 2001 2000 (Thousands of Dollars) NET INCOME $74,287 $108,975 OTHER COMPREHENSIVE INCOME (LOSS): Unrealized gains (losses) on (2,615) 992 securities (net of tax of ($1,580) and $67) TOTAL COMPREHENSIVE INCOME $71,672 $109,967 The accompanying notes are an integral part of these statements. Idaho Power Company Notes to the Consolidated Financial Statements On January 1, 2000 IPC's ownership interests in two subsidiaries were transferred to IDACORP at book value, total assets of $108 million and net assets of $22 million. Except as modified below, the Notes to the Consolidated Financial Statements of IDACORP also contained in this Form 10-Q are incorporated herein by reference insofar as they relate to IPC. Note 1 - Summary of Significant Accounting Policies Note 3 - Preferred Stock of Idaho Power Company Note 4 - Financing Note 5 - Commitments and Contingent Liabilities Note 6 - Regulatory Issues Note 7 - Derivative Financial Instruments 2. INCOME TAXES: IPC's effective tax rate for the first nine months increased from 38.7 percent in 2000 to 39.8 percent in 2001. Reconciliations between the statutory income tax rate and the effective rates are as follows (in thousands of dollars): Nine Months Ended September 30, 2001 2000 Amount Rate Amount Rate Computed income taxes based on statutory federal income tax rate $ 43,193 35.0% $ 62,220 35.0% Changes in taxes resulting from: Investment tax credits (2,329) (1.9) (2,313) (1.3) Repair allowance (2,100) (1.7) (2,100) (1.2) Pension expense (1,368) (1.1) (1,420) (0.8) State income taxes 6,604 5.4 9,154 5.1 Depreciation 6,325 5.1 5,154 2.9 Other (1,202) (1.0) (1,900) (1.0) Total provision for federal and state income taxes $ 49,123 39.8% $ 68,795 38.7% 8. INDUSTRY SEGMENT INFORMATION: Based on the transfer of Energy Marketing discussed in Note 9, substantially all of IPC consists of one operating segment, Utility Operations. The Utility Operations segment has two primary sources of income, the regulated operation of IPC and income from Bridger Coal Company, an unconsolidated joint venture also subject to regulation. IPC's regulated operations include the generation, transmission, distribution, purchase and sale of electricity. 9. DISCONTINUED OPERATIONS Effective June 11, 2001, IPC transferred its wholesale electricity marketing operations ("Energy Marketing") to IDACORP Energy L.P. (IE). IE is a Delaware limited partnership with IDACORP, Inc. as its sole general partner and IDACORP Energy Services Co., a wholly owned subsidiary of IDACORP, Inc. as its sole limited partner. Energy Marketing net assets transferred consist primarily of energy trading contracts and trading accounts receivable and accounts payable. The results of operations of Energy Marketing were previously reported on IPC's Statements of Income as "Energy marketing activities - net." For all periods presented, Energy Marketing is reported as a discontinued operation. The Consolidated Financial Statements have been restated to conform to the discontinued operations presentation. In exchange for the transfer of Energy Marketing to IE, IPC received a partnership interest in IE, which was transferred to IDACORP in exchange for notes receivable from IDACORP totaling approximately $76 million. This amount approximates the historical book value of the transferred Energy Marketing net assets on May 31, 2001 of $21 million and retained intercompany tax liabilities of $55 million. The notes receivable are due over periods of one to ten years and bear interest at IDACORP's overall variable short- term borrowing rate which was 4.56% at September 30, 2001. The net assets identified as part of the disposition of Energy Marketing are reported as "Net assets of discontinued operations" on IPC's consolidated balance sheet and consisted of the following at: May 31, December 31, 2001 2000 (Thousands of Dollars) Property, plant and equipment $ 551 $ 1,021 - net Investments and other property 864 382 Current assets 489,526 1,070,645 Current liabilities (481,762) (1,031,686) Other net noncurrent assets 67,071 (2,660) and liabilities Net assets of discontinued $ 76,250 $ 37,702 operations INDEPENDENT ACCOUNTANTS' REPORT Idaho Power Company Boise, Idaho We have reviewed the accompanying consolidated balance sheet and statement of capitalization of Idaho Power Company and subsidiaries as of September 30, 2001, and the related consolidated statements of income and comprehensive income for the three and nine month periods ended September 30, 2001 and 2000 and consolidated statements of cash flows for the nine month periods ended September 30, 2001 and 2000. These financial statements are the responsibility of the Company's management. We conducted our review in accordance with standards established by the American Institute of Certified Public Accountants. A review of interim financial information consists principally of applying analytical procedures to financial data and of making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with auditing standards generally accepted in the United States of America, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion. Based on our review, we are not aware of any material modifications that should be made to such consolidated financial statements for them to be in conformity with accounting principles generally accepted in the United States of America. We have previously audited, in accordance with auditing standards generally accepted in the United States of America, the consolidated balance sheet and statement of capitalization of Idaho Power Company and subsidiaries as of December 31, 2000, and the related consolidated statements of income, comprehensive income, retained earnings, and cash flows for the year then ended (not presented herein); and in our report dated February 1, 2001, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet and statement of capitalization as of December 31, 2000 is fairly stated, in all material respects, in relation to the consolidated balance sheet and statement of capitalization from which it has been derived. DELOITTE & TOUCHE LLP Boise, Idaho October 24, 2001 Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERTIONS In Management's Discussion and Analysis (MD&A) we explain the general financial condition and results of operations for IDACORP, Inc. and subsidiaries (IDACORP or the Company) and for Idaho Power Company and subsidiaries (IPC). IDACORP is a holding company formed in 1998 as the parent of IPC and several other entities. IPC is an electric utility with a service territory covering over 20,000 square miles in southern Idaho and eastern Oregon, and is the parent of Idaho Energy Resources, Co., a joint venturer in Bridger Coal Company, which supplies coal to IPC's Jim Bridger generating plant. Until June 2001, IPC also conducted electricity marketing operations. In that month, those operations were transferred to IDACORP's subsidiary IDACORP Energy. IPC's financial statements show these transferred operations as Discontinued Operations. IDACORP's other significant operating subsidiaries are: IDACORP Energy - marketer of electricity and natural gas in 31 states and two Canadian provinces; Ida-West Energy - independent power projects development and management; IdaTech - developer of integrated fuel cell systems; IDACORP Financial Services - affordable housing and other real estate investments; Rocky Mountain Communications (RMC) - commercial and residential Internet service provider; IDACOMM - provider of telecommunications services; IDACORP Services - products and services for homes and businesses. Except where we indicate otherwise, this discussion explains the material changes in results of operations and the financial condition of both IDACORP and IPC. This MD&A should be read in conjunction with the accompanying consolidated financial statements of both IDACORP and IPC. This discussion updates our MD&A included in our Annual Report on Form 10-K for the year ended December 31, 2000. This discussion should be read in conjunction with the discussion in the annual report. FORWARD-LOOKING INFORMATION: In connection with the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 (Reform Act), we are hereby filing cautionary statements identifying important factors that could cause our actual results to differ materially from those projected in forward-looking statements (as such term is defined in the Reform Act) made by or on behalf of the Company and IPC in this quarterly report on Form 10-Q, in presentations, in response to questions or otherwise. Any statements that express, or involve discussions as to expectations, beliefs, plans, objectives, assumptions or future events or performance (often, but not always, through the use of words or phrases such as "anticipates", "believes", "estimates", "expects", "intends", "plans", "predicts", projects", "will likely result", "will continue", or similar expressions) are not statements of historical facts and may be forward-looking. Forward-looking statements involve estimates, assumptions, and uncertainties and are qualified in their entirety by reference to, and are accompanied by, the following important factors, which are difficult to predict, contain uncertainties, are beyond our control and may cause actual results to differ materially from those contained in forward- looking statements: prevailing governmental policies and regulatory actions, including those of the FERC, the IPUC, the OPUC, and the PUCN, with respect to allowed rates of return, industry and rate structure, acquisition and disposal of assets and facilities, operations and construction of plant facilities, recovery of purchased power and other capital investments, and present or prospective wholesale and retail competition (including but not limited to retail wheeling and transmission costs); the current energy situation in the western United States; economic and geographic factors including political and economic risks; the occurrence of significant disasters, such as the attack on September 11, 2001; changes in and compliance with environmental and safety laws and policies; weather conditions; population growth rates and demographic patterns; competition for retail and wholesale customers; pricing and transportation of commodities; market demand, including structural market changes; changes in tax rates or policies or in rates of inflation; changes in project costs; unanticipated changes in operating expenses and capital expenditures; capital market conditions; competition for new energy development opportunities;and legal and administrative proceedings (whether civil or criminal) and settlements that influence the business and profitability of the Company. Any forward-looking statement speaks only as of the date on which such statement is made. New factors emerge from time to time and it is not possible for management to predict all such factors, nor can it assess the impact of any such factor on the business, or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement. RESULTS OF OPERATIONS In this section we discuss the factors that affected our earnings, beginning with a general overview, then discussing results for each of our operating segments. Earnings per share 3rd Quarter Year-to-date (EPS) 2001 2000 2001 2000 Utility operations $0.00 $0.43 $0.52 $1.57 Energy marketing 0.93 0.69 2.38 1.29 Other (0.02) (0.01) (0.10) 0.23 Total $0.91 $1.11 $2.80 $3.09 EPS from utility operations decreased due to increased power supply costs resulting from a decline in hydroelectric generating conditions and increased prices paid for purchased power. These increased costs are partially offset by increased general business revenues resulting from rate increases and customer growth, and the deferral of expenses related to our power cost adjustment mechanism. In the third quarter IPC's earnings per share were reduced $0.18 by an $11.4 million write-off of amounts disallowed in IPC's PCA rate case. Our net income from energy marketing activities increased 34 percent, or $9 million, for the quarter and 83 percent, or $40 million, year-to-date, reflecting the expansion of marketing activities in terms of volume, services and geographic area. EPS from IDACORP's other businesses decreased year-to-date due to the sale of our Hermiston project in 2000, which contributed approximately $0.22 per share in 2000 and due to increased losses at IdaTech and RMC in 2001. Utility Operations This section discusses IPC's utility operations, which are subject to regulation by, among others, the state regulatory commissions of Idaho and Oregon and the FERC. General Business Revenue The following table presents IPC's general business revenue and sales for the quarters and nine months ended September 30, 2001 and 2000 (in thousands): 3rd Quarter Year-to-date Revenue MWH Revenue MWH 2001 2000 2001 2000 2001 2000 2001 2000 Residential $ 60,593 $ 52,187 934 996 $180,739 $156,939 3,111 3,081 Commercial 45,339 34,928 883 894 117,046 95,088 2,526 2,475 Industrial 40,921 31,199 939 1,099 109,491 96,085 3,001 3,596 Irrigation 38,977 40,297 769 1,074 67,882 72,881 1,342 1,926 Total $185,830 $158,611 3,525 4,063 $475,158 $420,993 9,980 11,078 Our general business revenue is dependent on many factors, including the number of customers we serve, the rates we charge, and economic and weather conditions. The increases in revenues in 2001 are due primarily to the following: our annual power cost adjustment increased average rates from Idaho customers subject to the PCA, resulting in increased revenues of $39 million for the quarter and $72 million year-to-date. We discuss the PCA in more detail below in "Regulatory Issues - PCA." population growth in our service territory increased our customer count by 2.6 percent. This increase resulted in a $6 million increase in revenues for the quarter and $14 million year-to-date. we implemented programs to reduce system load. Our load-reduction program with irrigators was the main factor in the reductions in sales to irrigation customers of 28 percent for the quarter and 30 percent year-to-date. These reductions decreased revenues approximately $14 million for the quarter and $26 million year-to-date. conservation and other usage factors affected sales to residential, commercial and small industrial customers, decreasing revenue by $6 million for the quarter and $3 million year-to-date. changes in contract provisions and sales volumes to certain large industrial customers resulted in increased revenues from these customers of $3 million for the quarter. Year-to-date revenues from these customers did not change significantly from last year. Off-system sales Off-system sales consist primarily of long-term sales contracts and opportunity sales of surplus system energy. The changes in 2001 are the result of two factors, substantial increases in electricity prices in the IPC region, and changes in availability of excess energy due to hydroelectric generating conditions and system requirements. The following table presents IPC's off-system sales for the quarters and nine-month periods ended September 30, 2001 and 2000 (in thousands): 3rd Quarter Year-to-date Revenues MWHs Revenues MWHs 2001 2000 2001 2000 2001 2000 2001 2000 $91,654 $61,179 744 670 $205,552 $161,158 1,674 3,910 Power Supply Power supply components of income from operations include off-system sales (described above) and purchased power, fuel, and PCA expenses (analyzed below). Net power supply costs increased $79 million for the quarter and $155 million year-to-date. The portion of net power supply costs not recoverable through the PCA and Oregon excess power cost mechanisms increased by $14 million for the quarter and $51 million year-to-date. Purchased power Purchased power expenses increased $89 million for the quarter and $269 million year-to-date. The increase for the quarter is due primarily to a 64 percent increase in the average cost per MWH purchased, and the year-to-date increase is due primarily to a 126 percent increase in the average cost per MWH, offset by a nine percent decrease in MWH purchased. The price increases are the result of the volatile western United States electricity markets. The following table presents IPC's purchased power expense for the quarters and nine-month periods ended September 30, 2001 and 2000 (in thousands): 3rd Quarter Year-to-date Expense MWHs Expense MWHs 2001 2000 2001 2000 2001 2000 2001 2000 $228,460 $139,243 1,762 1,762 $523,165 $253,762 3,424 3,753 Fuel expense Fuel expenses increased moderately in 2001, due to increases in the average price of coal used. The following table presents IPC's fuel expense and thermal generation for the quarters and nine-month periods ended September 30, 2001 and 2000 (in thousands): 3rd Quarter Year-to-date Expense MWHs generated Expense MWHs generated 2001 2000 2001 2000 2001 2000 2001 2000 $25,947 $23,811 1,993 1,933 $73,545 $68,526 5,640 5,562 PCA The PCA decreased $12 million for the quarter and $120 million year-to-date. The PCA expense component is related to our PCA regulatory mechanism. Under this mechanism, we record an expense when actual power supply costs are below the costs forecasted in the annual PCA filing, and record a reduction of expense when actual power supply costs are above the forecast. In 2001, actual power supply costs have been significantly greater than forecasted, resulting in a large PCA credit. Our PCA credits would have been larger, except that in September 2001 we wrote off $11 million of accrued PCA costs that have not been authorized for recovery by the IPUC. We discuss the PCA in more detail below in "Regulatory Issues." Other expenses Other operating and maintenance expenses were substantially unchanged for the quarter and increased $3 million year-to- date. Quarterly increases of $3 million for both transmission costs and generator rent were offset by smaller decreases in administrative and general, thermal plant and distribution expenses. The year-to-date increase results from increases of $4 million for generator rent and $3 million for customer expenses, primarily for our new customer information system. These increases were partially offset by decreases in administrative and general and distribution expenses. Energy Marketing Energy marketing revenues increased $32 million for the quarter and $183 million year-to-date. This increase reflects the increase in volumes traded and the market price for power. Physical electricity transactions that settled during the quarter totaled 11.4 million MWH in 2001 compared to 7 million MWH in 2000. Year-to-date, volumes increased from 16.3 million MWH to 24.5 million MWH. Average transaction prices in 2001 were approximately 50 percent higher for the quarter and nearly three times higher year-to- date. IE transacts business in 31 states and two Canadian provinces. Products offered include physical energy commodities, risk management services, asset optimization services and structured products designed specific to customer preferences. Energy marketing expenses increased $17 million for the quarter and $115 million year-to-date. The increase for the quarter is due primarily to increased transmission costs of $19 million. The year-to-date increase is due to increased transmission costs of $80 million, $22 million in reserves recorded in 2001 related to trading activities conducted with California entities in 2000 and a $13 million increase in general and administrative costs. We discuss the ongoing California energy situation, including its effect on operations and liquidity, below in "California Energy Situation." Other Operations Other operations include the results of operations of IDACORP's diversified subsidiaries, including Ida-West Energy, IdaTech, IDACORP Financial Services, RMC, IDACOMM and IDACORP Services. Revenues Revenues from other diversified operations decreased $5 million for the quarter and $10 million year-to-date. Applied Power Company (APC), sold in January 2001, had contributed $5 million for the quarter and $13 million year- to-date in 2000. Loss of this revenue was partially offset by revenues from RMC, which we acquired in August 2000. RMC revenue increased $1 million in the quarter, and $5 million year-to-date. Expenses Other operating expenses decreased $4 million for the quarter, and $2 million year-to-date. For the quarter, a $5 million decrease in expenses due to the sale of APC was offset by $1 million of expenses at RMC, which was acquired in August 2000, and $1 million from increased product development activities at IdaTech, our fuel cell technology subsidiary. Year-to-date, expense decreases of $13 million related to APC were offset by a $7 million increase from RMC and $5 million increase from IdaTech. Other Income IDACORP's other income decreased $10 million year-to-date. In March 2000 we recorded a pre-tax gain of $14 million on the sale of our interest in the Hermiston Power Project, a 536-MW, gas-fired cogeneration project located near Hermiston, Oregon. Income Taxes Income taxes decreased for the quarter and year-to-date due primarily to the decrease in net income before taxes. LIQUIDITY AND CAPITAL RESOURCES: Cash Flow IDACORP's net cash used by operations totaled $29 million for the nine months ended September 30, 2001. The most significant factor affecting operating cash flows was increased power supply costs in excess of amounts recovered through the PCA rate adjustments. The balance in our PCA regulatory asset has increased $188 million year-to-date. In addition, power supply costs not recoverable through the PCA or Oregon excess power cost mechanism were $68 million year-to-date. Though cash flows from operations were positively affected when we begin realizing increased revenues from the May 2001 PCA adjustment (see "PCA" below), we also expect that continuing poor water conditions and high purchased power costs will result in power supply costs that continue to exceed the amounts we are recovering in rates in the 2001- 2002 PCA rate year. These conditions have had an adverse effect on our operating cash flows and have required additional short-term borrowing and may require other financing options. Working Capital The changes in IDACORP's customer receivables and accounts payable are attributed primarily to trading volumes and prices on settled energy trading contracts. The increase in IDACORP's allowance for uncollectible accounts of $19 million is due to additional reserves against settled energy trading contracts related to trading activities in the California markets. The remaining changes in working capital are attributed to timing and normal business activity. Cash Expenditures We forecast that internal cash generation after dividends will provide approximately 154 percent of total capital requirements for the remainder of 2001 and 77 percent during the three-year period 2002-2004. We expect to finance our utility construction programs and other capital requirements with both internally generated funds and, to the extent necessary, externally financed capital. Financing Program At September 30, 2001, IPC had regulatory authority to incur up to $500 million of short-term indebtedness. In September 2001 IPC issued $100 million of floating-rate notes due in September 2002. At September 30, 2001, IPC's short term borrowing totaled $244 million. We have bank line of credit facilities established at both IPC and IDACORP. IPC has a $120 million multi-year revolving credit facility that expires in December 2001 under which we pay a facility fee on the commitment, quarterly in arrears, based on IPC's First Mortgage Bond rating. We also established on April 27, 2001, a 364-day credit facility for up to $165 million in support of IPC's ongoing operations. IPC's commercial paper may be issued subject to the regulatory maximum. IDACORP has separately established a $50 million three-year credit facility that expires in December 2001, and a $375 million 364-day credit facility that expires in March 2002. Under these facilities we pay a facility fee on the commitment, quarterly in arrears, based on IPC's First Mortgage Bond rating. At September 30, 2001, short-term borrowing on these facilities totaled $81.5 million. IDACORP currently has a $300 million shelf registration statement that can be used for the issuance of unsecured debt (including medium-term notes) and preferred or common stock. At September 30, 2001 none had been issued. In March 2000 IPC filed a $200 million shelf registration statement that could be used for both first mortgage bonds (including medium-term notes), unsecured debt or preferred stock. In December 2000, IPC issued $80 million of Secured Medium Term Notes. Proceeds were used in January 2001 for the early redemption of $75 million of First Mortgage Bonds originally due in 2021. In March 2001, IPC issued $120 million of Secured Medium Term Notes, with the proceeds used to reduce short-term borrowing incurred in support of ongoing long-term construction requirements. At September 30, 2001, no amounts remain to be issued on this shelf registration. In August 2001 IPC filed a $200 million shelf registration that can be used for both first mortgage bonds (including medium-term notes), unsecured debt or preferred stock. At September 30, 2001, no amounts had been issued. OTHER MATTERS: Regulatory Issues: Idaho Power Cost Adjustment (PCA) IPC has a PCA mechanism that provides for annual adjustments to the rates we charge to our Idaho retail customers. These adjustments, which take effect annually in May, are based on forecasts of net power supply expenses. During the year, the difference between actual and forecasted costs is deferred with interest. The balance of this deferral, called a true-up, is then included in the calculation of the next year's PCA adjustment. In its 2001 PCA filing, IPC requested recovery of $227.4 million of power supply costs. In May, the IPUC authorized recovery of $168.3 million, but deferred recovery of $59.1 million pending further review. The approved amount resulted in an average rate increase of 31.6 percent. After conducting hearings on the remaining $59.1 million, the IPUC authorized recovery of $47.7 million plus $1.2 million of accrued interest, beginning in October 2001. The remaining $11.4 million not recovered in rates from the PCA filing was written off in September 2001. Of the $227 million requested by IPC, $185 million related to the true-up of power supply costs incurred in the 2000- 2001 PCA year and $42 million was for recovery of excess power supply costs forecasted in the 2001-2002 PCA year. The forecast amount, however, underestimates expected power supply costs. Reservoir water is significantly lower than forecast, necessitating the use of higher cost alternatives to hydro generations. As part of the May 2001 PCA, the IPUC required IPC to implement a three-tiered rate structure for Idaho residential customers. The IPUC determined that the approved rates for residential customers should increase as a customer's electricity consumption increases. The residential rate increases are 14.4 percent for the first 800 kWh of usage, 28.8 percent for the next 1,200 kWh, and 62 percent for usage over 2,000 kWh. On August 31, IPC filed a request with the IPUC to implement a rate credit to qualifying residential and small farm customers. The credit is the result of a settlement agreement between IPC and the Bonneville Power Administration (BPA), which will pass on the benefits of the Federal Columbia River Power System. IPC estimates the credit could be as much as $3.60 per month for residential customers who use 1,200 kWh per month and $300 per month for farm customers that use 100,000 kWh. The IPUC, by Order No. 28868, approved the credit to be passed to the qualified customers effective October 1, 2001. In its May 2001 rate authorization the IPUC also directed IPC to reinstate a comprehensive conservation program given the current volatility of market prices and the opportunity to incorporate long-term conservation. In response to that directive, IPC filed a report of present energy efficiency activities, a list of conservation measures, an examination of funding options and a detailed program structure that could be implemented should the Commission determine that additional conservation programs, including the funding of these programs, is in the public interest. On October 18, 2001 IPC filed an application with the IPUC for an order approving the costs to be included in the 2002- 2003 PCA for the Irrigation Load Reduction Program and Astaris Load Reduction Agreement. These two programs were implemented in 2001 to reduce demand and approved by the IPUC and OPUC. The costs included in the application were $58.6 million for the Irrigation Load Reduction Program and $42.2 million for the Astaris Load Reduction Agreement, representing total costs through September 2001. IPC will file a second application requesting approval for subsequently incurred costs. Oregon Excess Power Costs IPC filed an application with the OPUC to begin recovering extraordinary 2001power supply costs in its Oregon jurisdiction. On June 18, 2001, the OPUC approved new rates that will recover $0.8 million over the next year. Under the provisions of the deferred accounting statute, ORS757.259(6), annual rate recovery of deferred amounts is limited to $0.8 million or 3% of IPC's 2000 gross revenues in Oregon. IPC filed on October 5, 2001 to recovery an additional 3% of extraordinary supply costs deferred for 2001. The OPUC will hear the request November 20, 2001 and a decision could be made as early as November 28, 2001. The Oregon deferral balance is $12.2 million as of September 30, 2001 net of the June 18th recovery. IPC filed with the OPUC a request to implement the same BPA program as in Idaho. The OPUC held a public meeting on October 22, 2001. The OPUC approved the Company's request to implement the BPA residential and small farm energy credit (BPA Credit) for the benefits derived during the period October 1, 2001 though September 30, 2006. IPC is also planning to file for a comprehensive conservation program in its Oregon jurisdiction. New Idaho Legislation Idaho Senate Bill No. 1255, chapter 15, title 61, Idaho Code (the Act), was signed into law on April 10, 2001. It authorizes the IPUC to allow public utilities or their assignees to issue energy cost recovery bonds to finance, among other things, significant increases in the cost of electricity resulting from shortfalls in available hydroelectric power for which higher-cost replacement power must be substituted. The legislative intent of the Act is to provide utilities with a mechanism for recovery of these increased costs while leveling the rate impact of such increases on the utilities' customers. Energy cost recovery bonds must have an expected maturity date no later than five years after issuance and a legal maturity date no later than seven years after issuance. Under the Act, the IPUC may issue an energy cost financing order in favor of the utility, pursuant to which a charge, known as an energy cost bond charge, would be included on the bills of the utility's Idaho customers. The Act requires the energy cost bond charge to remain in effect until the energy cost recovery bonds are paid in full. In addition, the charge is subject to periodic adjustment to ensure the timely payment of principal and interest on the energy cost recovery bonds and the recovery of certain related expenses. An energy cost financing order creates energy cost property, which includes the right to receive revenues arising from the energy cost bond charge. Energy cost property may be sold or otherwise transferred to, among others, the assignee of the public utility that issues energy cost recovery bonds, and it may be pledged as security for such bonds. The Act requires that, before it issues an energy cost financing order, the IPUC must find that the public interest would be better served if increased costs reflected in a fuel or power cost adjustment and related expenses were recovered through the issuance of energy cost recovery bonds than if these amounts were recovered over a one-year period assuming a conventional financing. Before seeking to recover costs through the issuance of energy bonds, IPC must file with the IPUC a proposal to establish a threshold energy cost amount, or trigger. In June 2001, the IPUC approved IPC's application, establishing a one cent per kWh trigger amount. California Energy Situation 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 (CalPX), a California non-profit public benefit corporation. The CalPX, 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 defaults on a payment to the exchange, the other participants are required to pay their allocated share of the default amount to the exchange. The allocated shares are based upon the level of trading activity, which includes 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 $2.2 million - a "default share invoice" - as a result of an alleged Southern California Edison (SCE) payment default of $214.5 million for power purchases. We made this payment. On January 24, 2001, IPC terminated the participation agreement. On February 8, 2001, the CalPX sent a further invoice for $5.2 million, due February 20, 2001, as a result of alleged payment defaults by SCE, Pacific Gas and Electric Company (PG&E), and others. However, because the CalPX owed IPC $11.3 million for power sold to the CalPX in November and December 2000, IPC did not pay the February 8th invoice. IPC essentially discontinued energy trading with California entities in December 2000. IPC believes that the default invoices were not proper and that it owes no further amounts to the CalPX. IPC has pursued all available remedies in its efforts to collect amounts owed to it by the CalPX. On February 20, 2001, IPC filed a petition with FERC to intervene in a proceeding which requested the FERC to suspend the use of the CalPX charge back methodology and provides for further oversight in the CalPX's implementation of its default mitigation procedures. A preliminary injunction was granted by a Federal Judge in the Federal 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, PG&E filed for bankruptcy. The CalPX and the California Independent System Operator (Cal ISO) were also creditors of PG&E. To the extent that PG&E's bankruptcy filing affects the collectibility of our receivables from the CalPX and Cal ISO our receivables from these entities are at greater risk. Also 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 its 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 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 Cal ISO 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 Chief Judge submitted a Report and Recommendation to the FERC recommending that the FERC adopt his methodology set forth in his report and set for evidentiary hearing an analysis of the Cal ISO's and the CalPX's spot markets to determine what refunds may be due upon application of that methodology. The Judge recommended that his methodology should be applied to all sellers except those who at the evidentiary hearing are able to demonstrate that their costs exceed the results of the recommended 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 Cal ISO and the CalPX during the period October 2, 2000 through June 20, 2001. As to potential refunds, if any, the Company believes that its exposure will be more than offset by amounts due it from California entities. In addition, the July 25, 2001 FERC order established 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 (ALJ) submitted her recommendations and findings to the FERC on September 24, 2001. The ALJ found that the prices were just and reasonable and therefore no refunds should be allowed. Procedurally, the ALJ's decision is a recommendation to the commissioners of the FERC. The FERC is not bound to accept any or all of it. The next step is for the FERC to issue an order in response to the ALJ's recommendation. The FERC has issued a notice soliciting comments on this case. Although there is no binding timeframe for the FERC to issue its order, it may issue an order in the next 30 to 60 days. Actions of the FERC are appealable to the United States Court of Appeals. The Company will continue to monitor all proceedings to determine the impact on the Company. Counsel has been retained in connection with the CalPX and PG&E bankruptcies and FERC proceedings. Effective June 11, 2001, IPC transferred its wholesale electricity marketing operations to IE. IE is a Delaware limited partnership with IDACORP, Inc. as its sole general partner and IDACORP Energy Services Co., a wholly-owned subsidiary of IDACORP, Inc., as its sole limited partner. (See Note 9 to the Idaho Power Company financial statements.) Effective with the June 11 transfer, the outstanding receivables and payables with the CalPX and Cal ISO were assigned from IPC to IE. At September 30, 2001, the CalPX and Cal ISO owed $13 million and $31 million respectively for energy sales made to them by IPC in November and December 2000. In addition, at September 30, 2001, IE had accrued but not paid $35.1 million due to the Cal ISO as an offset to the outstanding receivable. IE has accrued a reserve of $41 million against these receivables. These reserves were calculated taking into account the continued deterioration of the California energy markets and, for the less-than-investment-grade receivables, by using a model that estimates the probability of default and the estimated recovery amounts of such receivables. Based on the reserves recorded as of September 30, 2001, the Company believes that the future collectibility of these receivables or any potential refunds ordered by the FERC would not have a significant impact on operations or liquidity. Energy Marketing Effective June 11, 2001, IPC transferred its wholesale electricity marketing operations to IDACORP Energy, L.P. (IE). Prior to June 11, all wholesale electric trading operations were conducted by IPC. IE is a Delaware limited partnership with IDACORP, Inc. as its sole general partner and IDACORP Energy Services Co., a wholly owned subsidiary of IDACORP, Inc. as its sole limited partner. Concurrent with the transfer, IE and IPC have entered into an Electricity Supply Management Services Agreement (Agreement). IPC has received approval of the Agreement from the IPUC, the OPUC and the FERC. Under the Agreement, IPC will continue to own, operate and maintain its electric generating equipment and transmission facilities (System Resources) and be responsible for system reliability. IE will manage and dispatch the System Resources to balance generation and load within the IPC operating area. When buying and selling energy, the high volatility of energy prices can have a significant impact on profitability. Also, counterparty creditworthiness is key to ensuring that transactions entered into withstand dramatic market fluctuations. To manage these risks while implementing our business strategy, the Company has risk management committees, comprised of Company officers, to oversee the risk management program as defined in the risk management policy. The program is intended to manage, within approved limits, commodity price risk, credit risk, and other risks related to the energy trading business. As of September 30, 2001, the aggregate potential daily loss from our energy trading activity due to adverse market price movements is estimated to be $0.8 million at a 95 percent confidence interval and for a holding period of one business day (common industry parameters). This potential loss in earnings was estimated using an analytic value-at-risk methodology. This methodology computes value-at-risk based upon forward market prices and historical volatilities as of September 30, 2001. Value-at-risk is a statistical calculation of potential loss and not a forecast of expected loss and as such, is not guaranteed to occur. The confidence level and holding period imply that there is a five percent chance that the daily loss could exceed $0.8 million. The daily value-at-risk estimate is managed within approved limits and is reported daily to the Risk Management Committee. Power supply and demand management Our utility operations are being affected by the electricity market and generation conditions in the western United States. The tremendous unpredictability of prices for purchased power, along with increasing demand and reduced hydroelectric generation, have combined to produce substantial increases in our costs to supply power. We monitor the effect of streamflow conditions on Brownlee Reservoir, the water source for our three Hells Canyon hydroelectric facilities. In a typical year, these three projects combine to produce about half of our generated electricity. Inflows into Brownlee result from a combination of precipitation, storage and ground water conditions. Inflows into Brownlee during the April-July 2001 runoff period was 2.4 MAF. This compares to the 73- year median of 5.1 MAF and last year's 4.4 MAF. Hydro generation on IPC's system decreased 28 percent or 0.5 million MWH for the quarter and 39 percent or 2.7 million MWH year-to-date compared to 2000 because of these poor generating conditions. These conditions are expected to continue through this water year. These conditions set in motion a number of programs to decrease our reliance on potentially volatile wholesale power markets. These programs are designed to reduce overall energy use, decrease peak demand levels, and increase generation within our service territory. Significant programs include the following: IPC placed its Danskin Power Plant in service in September 2001. Danskin is a 90-MW natural gas-fired combustion turbine located near Mountain Home, Idaho. The fuel expense associated with the operation of this plant is included in the PCA. IPC has also sited mobile generators at various locations in Boise. These generators can supply up to 40 MW of additional generating capacity if the need arises. The fuel costs are included in the PCA. The IPUC approved a two-year agreement through which IPC will compensate its largest industrial customer, Astaris, for reducing its load by 50 MW. The load reduction, effective in April 2001, should provide IPC an additional 300,000 MWHs in 2001. Astaris gave IPC notice it will cease production at the end of 2001. Astaris, formerly FMC, said it is shifting away from elemental phosphorus production, which relies on the use of high-energy furnaces, to a process relying on wet, purified phosphoric acid. It is unclear at this time what impact the plant closure will have on IPC. In March 2001, the IPUC and OPUC approved a program that compensates large customers who voluntarily reduce load by at least one MW when requested to do so by IPC. There have been no participants in this program to date. The IPUC and OPUC have also approved a program that compensates irrigation customers capable of reducing usage by at least 100 MWH. The program is projected to reduce usage by 500,000 MWH, more than 25 percent of normal irrigation load. As part of the May 2001 PCA discussed above, the IPUC required IPC to implement a tiered rate structure for Idaho residential customers. This rate structure increases rates as a customer's usage increases. IPC is also studying residential and commercial conservation programs, e.g. fluorescent light bulbs, AC heat pump servicing, and methods of funding such programs. New accounting pronouncements In July 2001 the FASB issued SFAS 141, "Business Combinations," which addresses accounting and reporting for business combinations. SFAS 141 requires that all business combinations initiated after June 30, 2001 be accounted for using one method, the purchase method. The Company does not believe the adoption will have a significant affect on its financial statements. Also in July 2001 the FASB issued SFAS 142 "Goodwill and Other Intangible Assets," which is effective January 1, 2002. SFAS 142 requires, among other things, the discontinuance of goodwill amortization. In addition, the standard includes provisions for the reclassification of certain existing recognized intangibles as goodwill, reassessment of the useful lives of existing recognized intangibles, reclassification of certain intangibles out of previously reported goodwill and the identification of reporting units for purposes of assessing potential future impairments of goodwill. SFAS 142 also requires the Company to complete a transitional goodwill impairment test six months from the date of adoption. The Company is currently assessing but has not yet determined the impact of SFAS 142 on its financial position and results of operations. In August 2001 the FASB issued SFAS 143 "Accounting for Asset Retirement Obligations" which is effective for fiscal years beginning after June 15, 2002. This Statement addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. An obligation may result from the acquisition, construction, development and the normal operation of a long-lived asset. The Company is currently assessing but has not yet determined the impact of SFAS 143 on its financial position and results of operations. Also in August 2001 the FASB issued SFAS 144 "Accounting for the Impairment or Disposal of Long-Lived Assets" which is effective for fiscal years beginning after December 15, 2001. SFAS 144 addresses financial accounting and reporting for the impairment or disposal of long-lived assets superseding SFAS 121 "Accounting for the Impairment of Long- Lived Assets and for Long-Lived Assets to be Disposed of." The Company is currently assessing but has not yet determined the impact of SFAS 144 on its financial position and results of operations. Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK The information required by this item is included in Item 2 "Management's Discussion and Analysis of Financial Condition and Results of Operations" under "Other Matters - Energy Marketing." PART II - OTHER INFORMATION Item 6. Exhibits and Reports on Form 8-K (a) Exhibits: Exhibit File As Number Exhibit *2 333-48031 2 Agreement and Plan of Exchange between IDACORP, Inc., and IPC dated as of February 2, 1998. *3(a) 33-00440 4(a)(xiii) Restated Articles of Incorporation of IPC as filed with the Secretary of State of Idaho on June 30, 1989. *3(a)(i) 33-65720 4(a)(ii) Statement of Resolution Establishing Terms of Flexible Auction Series A, Serial Preferred Stock, Without Par Value (cumulative stated value of $100,000 per share) of IPC, as filed with the Secretary of State of Idaho on November 5, 1991. *3(a)(ii) 33-65720 4(a)(iii) Statement of Resolution Establishing Terms of 7.07% Serial Preferred Stock, Without Par Value (cumulative stated value of $100 per share) of IPC, as filed with the Secretary of State of Idaho on June 30, 1993. *3(a)(iii) 1-3198 3(a)(iii) Articles of Amendment to Restated Form 10-Q Articles of Incorporation of IPC for as filed with the Secretary of 6/30/00 State of Idaho on June 15, 2000. *3(b) 1-3198 3(c) By-laws of IPC amended on Form 10-Q September 9, 1999, and presently for in effect. 9/30/99 *3(c) 33-56071 3(d) Articles of Share Exchange, as filed with the Secretary of State of Idaho on September 29, 1998. *3(d) 333-64737 3.1 Articles of Incorporation of IDACORP, Inc. *3(e) 333-64737 3.2 Articles of Amendment to Articles of Incorporation of IDACORP, Inc. as filed with the Secretary of State of Idaho on March 9, 1998. *3(f) 333-00139 3(b) Articles of Amendment to Articles of Incorporation of IDACORP, Inc. creating A Series Preferred Stock, without par value, as filed with the Secretary of State of Idaho on September 17, 1998. *3(g) 1-14465 3(c) Amended Bylaws of IDACORP, Inc. Form 10-Q as of July 8, 1999. for 6/30/99 *4(a)(i) 2-3413 B-2 Mortgage and Deed of Trust, dated as of October 1, 1937, between IPC and Bankers Trust Company and R. G. Page, as Trustees. *4(a)(ii) IPC Supplemental Indentures to Mortgage and Deed of Trust: Number Dated 1-MD B-2-a First July 1, 1939 2-5395 7-a-3 Second November 15, 1943 2-7237 7-a-4 Third February 1, 1947 2-7502 7-a-5 Fourth May 1, 1948 2-8398 7-a-6 Fifth November 1, 1949 2-8973 7-a-7 Sixth October 1, 1951 2-12941 2-C-8 Seventh January 1, 1957 2-13688 4-J Eighth July 15, 1957 2-13689 4-K Ninth November 15, 1957 2-14245 4-L Tenth April 1, 1958 2-14366 2-L Eleventh October 15, 1958 2-14935 4-N Twelfth May 15, 1959 2-18976 4-O Thirteenth November 15, 1960 2-18977 4-Q Fourteenth November 1, 1961 2-22988 4-B-16 Fifteenth September 15, 1964 2-24578 4-B-17 Sixteenth April 1, 1966 2-25479 4-B-18 Seventeenth October 1, 1966 2-45260 2(c) Eighteenth September 1, 1972 2-49854 2(c) Nineteenth January 15, 1974 2-51722 2(c)(i) Twentieth August 1, 1974 2-51722 2(c)(ii) Twenty-first October 15, 1974 2-57374 2(c) Twenty-second November 15, 1976 2-62035 2(c) Twenty-third August 15, 1978 33-34222 4(d)(iii) Twenty-fourth September 1, 1979 33-34222 4(d)(iv) Twenty-fifth November 1, 1981 33-34222 4(d)(v) Twenty-sixth May 1, 1982 33-34222 4(d)(vi) Twenty-seventh May 1, 1986 33-00440 4(c)(iv) Twenty-eighth June 30, 1989 33-34222 4(d)(vii) Twenty-ninth January 1, 1990 33-65720 4(d)(iii) Thirtieth January 1, 1991 33-65720 4(d)(iv) Thirty-first August 15, 1991 33-65720 4(d)(v) Thirty-second March 15, 1992 33-65720 4(d)(vi) Thirty-third April 1, 1993 1-3198 4 Thirty-fourth December 1, 1993 Form 8-K Dated 12/17/93 1-3198 4 Thirty-fifth November 1, 2000 Form 8-K Dated 11/21/00 1-3198 4 Thirty-sixth September 27, 2001 Form 8-K Dated 9/27/01 *4(b) 33-65720 10(c) Instruments relating to IPC American Falls bond guarantee. (see Exhibit 10(c)). *4(c) 33-65720 4(f) Agreement of IPC to furnish certain debt instruments. *4(d) 33-00440 2(a)(iii) Agreement and Plan of Merger dated March 10, 1989, between Idaho Power Company, a Maine Corporation, and Idaho Power Migrating Corporation. *4(e) 1-14465 4 Rights Agreement, dated as of Form 8-K September 10, 1998, between dated IDACORP, Inc. and the Bank of New September York as Rights Agent. 15, 1998 *10(a) 2-49584 5(b) Agreements, dated September 22, 1969, between IPC and Pacific Power & Light Company relating to the operation, construction and ownership of the Jim Bridger Project. *10(a)(i) 2-51762 5(c) Amendment, dated February 1, 1974, relating to operation agreement filed as Exhibit 10(a). *10(b) 2-49584 5(c) Agreement, dated as of October 11, 1973, between IPC and Pacific Power & Light Company. *10(c) 33-65720 10(c) Guaranty Agreement, dated March 1, 1990, between IPC and West One Bank, as Trustee, relating to $21,425,000 American Falls Replacement Dam Bonds of the American Falls Reservoir District, Idaho. *10(d) 2-62034 5(r) Guaranty Agreement, dated as of August 30, 1974, between IPC and Pacific Power & Light Company. *10(e) 2-56513 5(i) Letter Agreement, dated January 23, 1976, between IPC and Portland General Electric Company. *10(e)(i) 2-62034 5(s) Agreement for Construction, Ownership and Operation of the Number One Boardman Station on Carty Reservoir, dated as of October 15, 1976, between Portland General Electric Company and IPC. *10(e)(ii) 2-62034 5(t) Amendment, dated September 30, 1977, relating to agreement filed as Exhibit 10(e). *10(e)(iii) 2-62034 5(u) Amendment, dated October 31, 1977, relating to agreement filed as Exhibit 10(e). *10(e)(iv) 2-62034 5(v) Amendment, dated January 23, 1978, relating to agreement filed as Exhibit 10(e). *10(e)(v) 2-62034 5(w) Amendment, dated February 15, 1978, relating to agreement filed as Exhibit 10(e). *10(e)(vi) 2-68574 5(x) Amendment, dated September 1, 1979, relating to agreement filed as Exhibit 10(e). *10(f) 2-68574 5(z) Participation Agreement, dated September 1, 1979, relating to the sale and leaseback of coal handling facilities at the Number One Boardman Station on Carty Reservoir. *10(g) 2-64910 5(y) Agreements for the Operation, Construction and Ownership of the North Valmy Power Plant Project, dated December 12, 1978, between Sierra Pacific Power Company and IPC. *10(h)(i)1 1-3198 10(n)(i) The Revised Security Plan for Form 10-K Senior Management Employees - a for 1994 non-qualified, deferred compensation plan effective August 1, 1996. *10(h)(ii)1 1-3198 10(n)(ii) The Executive Annual Incentive Form 10-K Plan for senior management for 1994 employees of IPC effective January 1, 1995. *10(h)(iii)1 1-3198 10(n)(iii) The 1994 Restricted Stock Plan Form 10-K for officers and key executives for 1994 of IDACORP, Inc. and IPC effective July 1, 1994. *10(h)(iv)1 1-14465 10(h)(iv) The Revised Security Plan for 1-3198 Board of Directors - a non- Form 10-K qualified, deferred compensation for 1998 plan effective August 1, 1996, revised March 2, 1999. *10(h)(v)1 14465 10(e) IDACORP, Inc. Non-Employee Form 10-Q Directors Stock Compensation Plan for as of May 17, 1999. 6/30/99 *10(h)(vi) 1-3198 10(y) Executive Employment Agreement Form 10-K dated November 20, 1996 between for 1997 IPC and Richard R. Riazzi. *10(h)(vii) 1-3198 10(g) Executive Employment Agreement Form 10-Q dated April 12, 1999 between IPC for and Marlene Williams. 6/30/99 *10(h)(viii) 1-14465 10(h) Agreement between IDACORP, Inc. Form 10-Q and Jan B. Packwood, J. LaMont for Keen, James C. Miller, Richard 9/30/99 Riazzi, Darrel T. Anderson, Bryan Kearney, Cliff N. Olson, Robert W. Stahman and Marlene K. Williams. 10(h)(ix)1 IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan. *10(i) 33-65720 10(h) Framework Agreement, dated October 1, 1984, between the State of Idaho and IPC relating to IPC's Swan Falls and Snake River water rights. *10(i)(i) 33-65720 10(h)(i) Agreement, dated October 25, 1984, between the State of Idaho and IPC relating to the agreement filed as Exhibit 10(i). *10(i)(ii) 33-65720 10(h)(ii) Contract to Implement, dated October 25, 1984, between the State of Idaho and IPC relating to the agreement filed as Exhibit 10(i). *10(j) 33-65720 10(m) Agreement Regarding the Ownership, Construction, Operation and Maintenance of the Milner Hydroelectric Project (FERC No. 2899), dated January 22, 1990, between IPC and the Twin Falls Canal Company and the Northside Canal Company Limited. *10(j)(i) 33-65720 10(m)(i) Guaranty Agreement, dated February 10, 1992, between IPC and New York Life Insurance Company, as Note Purchaser, relating to $11,700,000 Guaranteed Notes due 2017 of Milner Dam Inc. 12 Statement Re: Computation of Ratio of Earnings to Fixed Charges. (IDACORP, Inc.) 12(a) Statement Re: Computation of Supplemental Ratio of Earnings to Fixed Charges. (IDACORP, Inc.) 12(b) Statement Re: Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Dividend Requirements. (IDACORP, Inc.) 12(c) Statement Re: Computation of Supplemental Ratio of Earnings to Combined Fixed Charges and Preferred Dividend Requirements. (IDACORP, Inc.) 12(d) Statement Re: Computation of Ratio of Earnings to Fixed Charges. (IPC) 12(e) Statement Re: Computation of Supplemental Ratio of Earnings to Fixed Charges. (IPC) 12(f) Statement Re: Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Dividend Requirements. (IPC) 12(g) Statement Re: Computation of Supplemental Ratio of Earnings to Combined Fixed Charges and Preferred Dividend Requirements. (IPC) 15 Letter Re: Unaudited Interim Financial Information. 21 Subsidiaries of IDACORP, Inc. and IPC. 1 Compensatory plan (b)Reports on Form 8-K. The following reports on Form 8-K were filed for the three months ended September 30, 2001. Items Reported Date of Filed By Report Item 5 - Other Events August 10, 2001 IDACORP, Inc. Item 5 - Other Events September 27,2001 IPC Item 7 - Financial Statements and Exhibits * Previously filed and Incorporated herein by Reference. SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. IDACORP, Inc. (Registrant) Date November 8, 2001 By: /s/ J LaMont Keen J LaMont Keen Senior Vice President Administration and Chief Financial Officer (Principal Financial Officer) Date November 8, 2001 By: /s/ Darrel T Anderson Darrel T Anderson Vice President-Finance and Treasurer (Principal Accounting Officer) SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. IDAHO POWER COMPANY (Registrant) Date November 8, 2001 By: /s/ J LaMont Keen J LaMont Keen Senior Vice President Administration and Chief Financial Officer (Principal Financial Officer) Date November 8, 2001 By: /s/ Darrel T Anderson Darrel T Anderson Vice President-Finance and Treasurer (Principal Accounting Officer)