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 March 31, 2002 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 registrant as specified in its charter, state of incorporation, address of I.R.S.Employer Commission principal executive offices, Identification File Number and telephone number Number 1-14465 IDACORP, Inc. 82-0505802 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 March 31, 2002: 37,593,770 GLOSSARY AFDC - Allowance for Funds used During Construction APB - Accounting Principles Board APC - Applied Power Company BPA - Bonneville Power Administration Cal ISO - California Independent System Operator CalPX - California Power Exchange CSPP - Cogeneration and Small Power Production DIG - Derivatives Implementation Group DSM - Demand-Side Management EITF - Emerging Issues Task Force EPA - Environmental Protection Agency EPS - Earning per share FASB - Financial Accounting Standards Board FERC - Federal Energy Regulatory Commission FPA - Federal Power Act Ida-West - Ida-West Energy IE - IDACORP Energy IFS - IDACORP Financial Services IPC - Idaho Power Company IPUC - Idaho Public Utilities Commission IRP - Integrated Resource Plan kW - kilowatt kWh - kilowatt-hour LTICP - Long-Term Incentive and Compensation Plan MD&A - Management's Discussion and Analysis MMbtu - Million British Thermal Units MW - Megawatt MWh - Megawatt-hour OPUC - Oregon Public Utility Commission Overton - Overton Power District No. 5 PCA - Power Cost Adjustment PG&E - Pacific Gas and Electric Company PURPA - Public Utilities Regulatory Policy Act REA - Rural Electrification Administration RFP - Request for proposals RMC - Risk Management Committee RTOs - Regional Transmission Organizations SCE - Southern California Edison SFAS - Statement of Financial Accounting Standards SPPCo - Sierra Pacific Power Company Valmy - North Valmy Steam Electric Generating Plant WSCC - Western Systems Coordinating Council INDEX Page Part I. Financial Information: Item 1. Financial Statements Consolidated Statements of Income 5 Consolidated Balance Sheets 6-7 Consolidated Statements of Cash Flows 8 Consolidated Statements of Comprehensive Income 9 Notes to Consolidated Financial Statements 10-18 Independent Accountants' Report 19 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations 20-31 Item 3. Quantitative and Qualitative Disclosures about Market Risk 31 Part II. Other Information: Item 1. Legal Proceedings 32 Item 6. Exhibits and Reports on Form 8-K 32-34 Signatures 35 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. (This page intentionally left blank.) PART I - FINANCIAL INFORMATION Item 1. Financial Statements IDACORP, Inc. Consolidated Statements of Income Three months ended March 31, 2002 2001 (millions of dollars) OPERATING REVENUES: Electric utility: General business $ 186 $ 133 Off system sales 20 55 Other revenues 9 12 Total electric utility revenues 215 200 Energy marketing commodities and services 434 929 Other 4 3 Total operating revenues 653 1,132 OPERATING EXPENSES: Electric utility: Purchased power 30 125 Fuel expense 28 25 Power cost adjustment 34 (58) Other operations and maintenance 50 49 Depreciation 23 21 Taxes other than income taxes 5 5 Total electric utility expenses 170 167 Energy marketing: Cost of energy commodities and services 425 858 Selling, general and administrative 3 33 Other 8 9 Total operating expenses 606 1,067 OPERATING INCOME: Electric utility 45 33 Energy marketing 6 38 Other (4) (6) Total operating income 47 65 OTHER INCOME 5 5 INTEREST EXPENSE AND OTHER: Interest on long-term debt 13 13 Other interest 4 3 Preferred dividends of Idaho Power Company 1 2 Total interest expense and other 18 18 INCOME BEFORE INCOME TAXES 34 52 INCOME TAXES 9 17 NET INCOME $ 25 $ 35 AVERAGE COMMON SHARES OUTSTANDING (000'S) 37,560 37,359 EARNINGS PER SHARE OF COMMON STOCK (basic and diluted) $ 0.66 $ 0.93 The accompanying notes are an integral part of these statements. IDACORP, Inc. Consolidated Balance Sheets Assets March 31, December 31, 2002 2001 (millions of dollars) CURRENT ASSETS: Cash and cash equivalents $ 59 $ 67 Receivables: Customer 177 207 Allowance for uncollectible accounts (43) (43) Employee notes 7 6 Other 16 11 Energy marketing assets 102 194 Taxes receivable - 51 Accrued unbilled revenues 27 37 Materials and supplies (at average cost) 27 26 Fuel stock (at average cost) 8 9 Prepayments 35 32 Regulatory assets 43 56 Total current assets 458 653 INVESTMENTS 207 159 PROPERTY, PLANT AND EQUIPMENT: Utility plant in service 3,002 2,990 Accumulated provision for depreciation (1,239) (1,220) Utility plant in service - net 1,763 1,770 Construction work in progress 103 96 Utility plant held for future use 2 2 Other property, net of accumulated depreciation 21 18 Property, plant and equipment - net 1,889 1,886 OTHER ASSETS: American Falls and Milner water rights 31 31 Company-owned life insurance 39 40 Energy marketing assets - long-term 138 204 Regulatory assets 509 544 Long-term receivables 74 74 Other 54 51 Total other assets 845 944 TOTAL $ 3,399 $ 3,642 The accompanying notes are an integral part of these statements. IDACORP, Inc. Consolidated Balance Sheets Liabilities and Capitalization March 31, December 31, 2002 2001 (millions of dollars) CURRENT LIABILITIES: Current maturities of long-term debt $ 36 $ 36 Notes payable 386 363 Accounts payable 160 248 Energy marketing liabilities 104 125 Derivative liabilities 29 41 Taxes accrued 15 - Interest accrued 23 15 Deferred income taxes 14 24 Other 20 55 Total current liabilities 787 907 OTHER LIABILITIES: Deferred income taxes 584 590 Energy marketing liabilities - long-term 54 135 Derivative liabilities - long-term 3 7 Regulatory liabilities 116 114 Other 78 71 Total other liabilities 835 917 LONG-TERM DEBT 791 843 COMMITMENTS AND CONTINGENT LIABILITIES PREFERRED STOCK OF IDAHO POWER COMPANY 104 104 SHAREHOLDERS' EQUITY: Common stock, no par value (shares authorized 120,000,000; 37,735,082 and 37,628,919 shares issued, respectively) 458 454 Retained earnings 432 424 Accumulated other comprehensive income (loss) (4) (4) Treasury stock (141,312 and 66,188 shares at cost, respectively) (4) (3) Total shareholders' equity 882 871 TOTAL $ 3,399 $ 3,642 The accompanying notes are an integral part of these statements. IDACORP, Inc. Consolidated Statements of Cash Flows Three Months Ended March 31, 2002 2001 (millions of dollars) OPERATING ACTIVITIES: Net income $ 25 $ 35 Adjustments to reconcile net income to net cash provided by (used in) operating activities: Allowance for uncollectible accounts - 20 Unrealized (gains) losses from energy marketing activities 20 (75) Depreciation and amortization 27 26 Deferred taxes and investment tax credits (14) 62 Accrued PCA costs 30 (60) Change in: Receivables and prepayments 22 (23) Accrued unbilled revenues 10 15 Materials and supplies and fuel stock - (4) Accounts payable (88) (48) Taxes receivable/accrued 66 (32) Other current assets and liabilities 9 (47) Other - net 2 4 Net cash provided by (used in) operating activities 109 (127) INVESTING ACTIVITIES: Additions to property, plant and equipment (27) (52) Investments in affordable housing projects (44) - Other - net (1) (5) Net cash used in investing activities (72) (57) FINANCING ACTIVITIES: Proceeds from issuance of: First mortgage bonds - 120 Retirement of: First mortgage bonds (50) (75) Other long-term debt (2) (5) Dividends on common stock (17) (17) Increase in short-term borrowings 23 96 Common stock issued 4 - Acquisition of treasury stock (1) (8) Other - net (2) (4) Net cash provided by (used in) financing activities (45) 107 Net increase (decrease) in cash and cash equivalents (8) (77) Cash and cash equivalents beginning 67 107 of period Cash and cash equivalents at end of $ 59 $ 30 period SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: Cash paid (received) during the year for: Income taxes $ (41) $ (7) Interest (net of amount capitalized) $ 9 $ 13 The accompanying notes are an integral part of these statements IDACORP, Inc. Consolidated Statements of Comprehensive Income Three Months Ended March 31, 2002 2001 (millions of dollars) NET INCOME $ 25 $ 35 OTHER COMPREHENSIVE INCOME (LOSS): Unrealized gains (losses) on securities (net of tax of ($1)) - (2) TOTAL COMPREHENSIVE INCOME $ 25 $ 33 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 Federal Energy Regulatory Commission (FERC) and the state regulatory commissions of Idaho, Oregon 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 markets electricity and natural gas, and offers risk management and asset optimization services, to wholesale customers 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 (IFS) - affordable housing and other real estate investments; Velocitus - commercial and residential Internet service provider; IDACOMM - provider of telecommunications services. 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 March 31, 2002, and its consolidated results of operations for the three months ended March 31, 2002 and 2001 and consolidated cash flows for the three months ended March 31, 2002 and 2001. 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, 2001. The results of operations for the interim periods are not necessarily indicative of the results to be expected for the full year. 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. Adopted Accounting Standards On January 1, 2002, the Company adopted SFAS 142, "Goodwill and Other Intangible Assets." SFAS 142 changes the accounting for goodwill from an amortization method to an impairment-only method. Thus, amortization of goodwill, including goodwill recorded in past transactions, has ceased. The Company is currently performing transitional goodwill impairment tests for recorded goodwill of $13 million, which will be completed by June 30, 2002. If an impairment loss is identified, the Company will then be required to measure and record such loss before the end of 2002. The Company will be required to perform goodwill impairment tests at least annually. The following table presents the Company's net income and earnings per share, adjusted to exclude amortization expense recognized in those periods related to goodwill for the quarters ending March 31. 2002 2001 (in millions of dollars) Reported net income $ 25 $ 35 Add back goodwill amortization - 1 Adjusted net income $ 25 $ 36 Basic and diluted earnings per share: Reported net income $ 0.66 $ 0.93 Goodwill amortization - 0.01 Adjusted net income $ 0.66 $ 0.94 SFAS 142 also includes provisions related to reclassification of intangible assets and reassessment of useful lives of intangible assets. The Company had no intangible assets affected by these provisions. In January 2002, the Company adopted SFAS 144 "Accounting for the Impairment or Disposal of Long-Lived Assets." 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 Long-Lived Assets to be Disposed of." The adoption of SFAS 144 did not have a significant effect on the Company's financial statements. New Accounting Pronouncement 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. Reclassifications Certain items previously reported for periods prior to March 31, 2002 have been reclassified to conform with the current period's presentation. Net income and shareholders' equity were not affected by these reclassifications. 2. INCOME TAXES The Company's effective tax rate for the first three months decreased from 33.2 percent in 2001 to 27.4 percent in 2002. Reconciliations between the statutory income tax rate and the effective rates are as follows (in millions of dollars): Three Months Ended March 31, 2002 2001 Amount Rate Amount Rate Computed income taxes based on statutory federal income tax rate $ 12 35.0% $ 18 35.0% Changes in taxes resulting from: Investment tax credits (1) (2.4) (1) (1.5) Repair allowance (1) (2.1) (1) (1.3) Pension expense - - - (0.9) State income taxes 2 5.6 2 4.4 Depreciation 2 6.2 2 3.5 Affordable housing tax credits (4) (11.4) (3) (5.9) Preferred dividends of IPC 1 1.4 1 1.0 Other (2) (4.9) (1) (1.1) Total provision for federal and state income taxes $ 9 27.4% $ 17 33.2% 3. PREFERRED STOCK OF IDAHO POWER COMPANY: The number of shares of IPC preferred stock outstanding were as follows: March 31, December 31, 2002 2001 Cumulative, $100 par value: 4% preferred stock (authorized 215,000 shares) 142,745 143,872 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: The following table summarizes long-term debt at: March 31, December 31, 2002 2001 (millions of dollars) First mortgage bonds: 6.85% Series due 2002 $ 27 $ 27 6.40% Series due 2003 80 80 8 % Series due 2004 50 50 5.83% Series due 2005 60 60 7.38% Series due 2007 80 80 7.20% Series due 2009 80 80 6.60% Series due 2011 120 120 7.50% Series due 2023 80 80 8.75% Series due 2027 - 50 Total first mortgage bonds 577 627 Pollution control revenue bonds: 8.30% Series 1984 due 2014 50 50 6.05% Series 1996A due 2026 68 68 Variable Rate Series 1996B due 2026 24 24 Variable Rate Series 1996C due 2026 24 24 Variable Rate Series 2000 due 2027 4 4 Total pollution control revenue bonds 170 170 REA notes 1 1 American Falls bond guarantee 20 20 Milner Dam note guarantee 12 12 Unamortized premium/discount - net (1) (1) Debt related to investments in affordable housing 48 50 Total 827 879 Current maturities of long-term debt (36) (36) Total long-term debt $ 791 $ 843 In March 2002, $50 million First Mortgage Bonds 8.75% Series due 2027 were redeemed early using short-term borrowings. The Company has credit facilities established at both IPC and IDACORP. IDACORP has a $140 million three-year credit facility that expires in March 2005, and a $350 million 364- day credit facility that expires in March 2003. Under these facilities, IDACORP pays a facility fee on the commitment, quarterly in arrears, based on IDACORP's corporate credit rating. Commercial paper may be issued up to the amounts supported by the credit facilities. At March 31, 2002, short-term borrowing on these facilities totaled $96 million. IPC has regulatory authority to incur up to $350 million of short-term indebtedness. IPC has a $200 million 364-day revolving credit facility that expires in March 2003, under which IPC pays a facility fee on the commitment quarterly in arrears, based on IPC's corporate credit rating. Commercial paper may be issued up to amounts supported by the credit facilities. At March 31, 2002, IPC's short-term borrowing under this facility totaled $190 million. IPC also has $100 million of floating rate notes outstanding, payable on September 1, 2002. IDACORP currently has shelf registration statements totaling $800 million that can be used for the issuance of unsecured debt securities, including medium-term notes, and preferred or common stock. At March 31, 2002 none had been issued. IPC currently has a $200 million shelf registration that can be used for first mortgage bonds, including medium-term notes, unsecured debt or preferred stock. At March 31, 2002, none had been issued. 5. COMMITMENTS AND CONTINGENT LIABILITIES: Commitments under contracts and purchase orders relating to IPC's and Ida-West's program for construction and operation of facilities amounted to approximately $5 million and $30 million, respectively, at March 31, 2002. The commitments are generally revocable by the companies 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. Overton Power District No. 5: IE filed a lawsuit on November 30, 2001 in Idaho State District Court in and for the County of Ada against Overton Power District No. 5, a Nevada electric improvement district, for failure to meet payment obligations under a power contract. The contract provided for Overton to purchase 40 megawatts of electrical energy per hour from IE at $88.50 per megawatt hour, from July 1, 2001 through June 30, 2011. In the contract, Overton agreed to raise its rates to its customers to the extent necessary to make its payment obligations to IE under the contract. IE has asked the Idaho District Court for damages pursuant to the contract, for a declaration that Overton is not entitled to renegotiate or terminate the contract and for injunctive relief requiring Overton to raise rates as stipulated in the contract. Overton filed an Answer and Counterclaim on April 23, 2002, claiming IE breached the agreement by failing to perform in accordance with its contractual obligations and asking for damages in an amount to be proved at trial. IE believes Overton's assertions are without merit. IE believes that Overton's actions constitute a breach of the contract and intends to vigorously prosecute this lawsuit. While the outcome of litigation is never certain, IE believes it should prevail on the merits of this case. At March 31, 2002, the Company had a $74 million long-term asset related to the Overton claim. IE will review the recoverability of the asset on an ongoing basis. 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 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 among the creditors of PG&E. To the extent that PG&E's bankruptcy filing affects the collectibility of the receivables from the CalPX and Cal ISO the 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 19th 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 the methodology set forth in the 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 the 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 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. Multiple parties have filed requests for rehearing and petitions for review. The ALJ has re-established a procedural schedule which would result in findings of fact and recommended conclusions during August 2002; such schedule is subject to Commission review. On May 8, 2002 the FERC issued a data request to all Sellers of Wholesale Electricity and/or Ancillary Services to the Cal ISO and/or the CalPX during the years 2000-2001. The request requires the Company to respond in the form of an affadavit to various trading practices that the FERC has identified in its fact finding investigation of Potential Manipulation of Electric and Natural Gas Prices in Docket No. PA02-2-000. The response is due on or before May 22, 2002. In response to the FERC's request, the Company has initiated a comprehensive internal analysis of its trading policies and actions in order to respond. The Company's policy has at all times been to operate in compliance with the Cal ISO's and CalPX's rules for participation in the California markets. Effective June 11, 2001, IPC transferred its non-utility wholesale electricity marketing operations to IE. Effective with the June 11 transfer, the outstanding receivables and payables with the CalPX and Cal ISO were assigned from IPC to IE. At March 31, 2002, 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. IE has accrued a reserve of $41 million against these receivables. These reserves were calculated taking into account the uncertaintity of collection, given the current California energy situation. Based on the reserves recorded as of March 31, 2002, 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 the Company's financial position, results of operations or cash flows. 6. REGULATORY ISSUES: Deferred Power Supply Costs Idaho: IPC has a Power Cost Adjustment (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 May 2002 the IPUC issued an order related to our 2002-2003 PCA rate filing. The order granted recovery of $256 million of excess power supply costs, consisting of: $209 million of voluntary load reduction and power supply costs incurred between March 1, 2001 and March 31, 2002. $28 million of excess power supply costs forecasted for the April 2002-March 2003. $18 million of unamortized costs previously approved for recovery beginning October 1, 2001. The order also: Denied recovery of $12 million of lost revenues resulting from the irrigation load reduction program, and $2 million of other costs IPC was seeking to recover. Authorized recovery over a one-year period for all but $11.5 million of the $256 million of deferred costs. The remaining amount will be recovered during the 2003-2004 PCA rate year, and IPC will earn a six percent carrying charge on the balance. Denied IPC's request to issue $172 million in Energy Cost Recovery Bonds, which would have spread the recovery of that amount over three years. Discontinued the Commission-required three-tiered rate structure for residential customers. Authorized a separate surcharge to collect approximately $2.6 million to fund future conservation programs. The IPUC had previously filed an order disallowing the lost revenue portion of the irrigation load reduction program. IPC believes that the Commission's order is inconsistent with an earlier order that allowed recovery of such costs and IPC filed a Petition for Reconsideration on May 2, 2002. It is a long- standing legal position in Idaho that an IPUC order is not administratively final until the reconsideration process is completed. The process we have embarked upon has a number of steps involved and could extend into the early fall. If IPC is unsuccessful in its efforts to overturn the denial, this amount would be written off. Oregon: 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 would recover $1 million over the next year. Under the provisions of the deferred accounting statute, annual rate recovery amounts were limited to three percent of IPC's 2000 gross revenues in Oregon. During the 2001 session, the Oregon Legislature amended the statute giving the OPUC authority to increase the maximum annual rate of recovery of deferred amounts to six percent for electric utilities. IPC subsequently filed on October 5, 2001 to recover an additional three percent extraordinary deferred power supply costs. As a result of this filing, the OPUC issued Order No. 01-994 allowing IPC to increase its rate of recovery to six percent effective November 28, 2001. IPC's deferred power supply costs consists of the following (in millions of dollars): March 31, December 31, 2002 2001 Oregon deferral $ 15 $ 15 Idaho PCA current deferral: Deferral for 2001-2002 rate year 76 78 Irrigation load reduction program 71 70 Astaris load reduction agreement 76 62 Idaho PCA true-up: Remaining true-up authorized October 2001 23 36 Remaining true-up authorized May 2001 13 43 Total deferral $ 274 $ 304 7. DERIVATIVE FINANCIAL INSTRUMENTS: The following table details the gross margin for the energy marketing operations for the three months ended March 31 (in millions of dollars): 2002 2001 Gross Margin: Realized or otherwise settled $ 29 $ (4) Unrealized (loss) gain (20) 75 Total $ 9 $ 71 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 and energy marketing segments and the total of all other segments, and reconciles this information to total enterprise amounts. Utility Energy Consolidated Operations Markeking Other Eliminations Total (millions of dollars) Three months ended March 31, 2002 Revenues $ 203 $ 434 $ 4 $ - $ 641 Intersegment revenues 12 3 - (3) 12 Net income 22 4 (1) - 25 Total assets at March 31, 2002 $ 2,780 $ 519 $ 370 $ (270) $ 3,399 Three months ended March 31, 2001 Revenues $ 177 $ 929 $ 3 $ - $ 1,109 Intersegment revenues 23 109 - (109) 23 Net income 14 23 (2) - 35 Total assets at $ 2,860 $ 718 $ 205 $ (141) $ 3,642 December 31, 2001 The intersegment revenues from Utility Operations to Energy Marketing are not eliminated because they are included in the regulatory cost mechanism for IPC. INDEPENDENT ACCOUNTANTS' REPORT IDACORP, Inc. Boise, Idaho We have reviewed the accompanying consolidated balance sheet of IDACORP, Inc. and subsidiaries as of March 31, 2002, and the related consolidated statements of income, comprehensive income and cash flows for the three month periods ended March 31, 2002 and 2001. 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 of IDACORP, Inc. and subsidiaries as of December 31, 2001, and the related consolidated statements of income, comprehensive income, shareholders' equity, and cash flows for the year then ended (not presented herein); and in our report dated January 31, 2002, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2001 is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived. DELOITTE & TOUCHE LLP Boise, Idaho April 24, 2002 Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERTIONS INTRODUCTION 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). IDACORP is a holding company formed in 1998 as the parent of Idaho Power Company (IPC), IDACORP Energy (IE), 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. 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 markets electricity and natural gas, and offers risk management and asset optimization services, to wholesale customers in 31 states and two Canadian provinces. In June 2001, IPC transferred its non-utility energy marketing operations to IE. IDACORP's other significant operating subsidiaries are: Ida-West Energy (Ida-West) - independent power projects development and management; IdaTech - developer of integrated fuel cell systems; IDACORP Financial Services (IFS) - affordable housing and other real estate investments; Velocitus - commercial and residential Internet service provider; IDACOMM - provider of telecommunications services. This MD&A should be read in conjunction with the accompanying consolidated financial statements. This discussion updates our MD&A included in our Annual Report on Form 10-K for the year ended December 31, 2001, and 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 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 and the OPUC, 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; 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 for the three months ended March 31: 2002 2001 Earnings per share of common stock Electric utility $ 0.57 $ 0.37 Energy marketing 0.11 0.62 Other (0.02) (0.06) Total $ 0.66 $ 0.93 Earnings per share (EPS) from utility operations increased $0.20 due to decreased power supply costs resulting from lower market prices for purchased power and improved hydroelectric generation. Increases in general business revenues of approximately $53 million, resulting primarily from annual power cost adjustment (PCA) rate increases, were substantially offset by the related $44 million amortization of our PCA regulatory asset balances. EPS from energy marketing activities decreased $0.51 in the first quarter of 2002. Last year's results were driven by high prices, extreme volatility and wide regional price spreads. The decline in regional price spreads and volatility, combined with the decreasing number of creditworthy counterparties, has limited our ability to match the results of past quarters. EPS from IDACORP's other businesses improved due primarily to improved results at Velocitus and IFS, offset by a decline at Ida-West. 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 for the three months ended March 31: $ (in millions) MWH (in thousands) 2002 2001 2002 2001 Residential $ 94 $ 70 1,356 1,349 Commercial 49 33 878 834 Industrial 43 30 773 1,064 Irrigation - - 3 2 Total $ 186 $ 133 3,010 3,249 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 change in revenues in 2002 is due primarily to the following: Our annual power cost adjustment resulted in increased revenues of approximately $49 million. We discuss the PCA in more detail below in "Regulatory Issues - PCA." Population growth in our service territory increased our customer count by 1.8 percent, resulting in a $2 million increase in revenues. Weather and other usage factors increased revenues approximately $1 million. Heating degree-days, a common measure used in the utility industry to analyze demand, were above 2001 levels by only 1.0 percent. Astaris, previously our largest volume customer, closed its manufacturing plants late in 2001. They have a take-or-pay contract that requires them to pay us for generation capacity regardless of delivery. As a result, our revenues from Astaris increased slightly, while our volumes sold decreased 97 percent. Off-system sales Off-system sales consist primarily of sales of surplus system energy when available, and long-term sales contracts. The decrease in 2002 is due to lower electricity prices in the IPC region, offset by the increased availability of excess energy. The following table presents IPC's off- system sales for the three months ended March 31: $(in millions) MWHs (in thousands) Revenue per MWH 2002 2001 2002 2001 2002 2001 $ 20 $ 55 822 495 $ 24.52 $111.61 Purchased power The decrease in purchased power is also due to the reduced volatility in wholesale electricity markets, reduced demand, and increased production. Load reduction program costs of $17 million are also included in purchased power for the first quarter of 2002. The following table presents IPC's purchased power expenses for the three months ended March 31: $ (in millions) MWHs (in thousands) Cost per MWH 2002 2001 2002 2001 2002 2001 Purchases $13 $ 125 475 573 $ 27.72 $218.55 Program 17 - - - - - costs Fuel expense Fuel expenses increased 11 percent, due primarily to increased coal prices and the use of our new Danskin natural gas-fired plant. Generation at our coal-fired and natural gas-fired plants was down slightly. The following table presents IPC's fuel expense for the three months ended March 31: Thermal MWHs generated $ (in millions) (in thousands) 2002 2001 2002 2001 $ 28 $ 25 1,921 1,951 PCA The PCA expense component is related to our PCA regulatory mechanism. In 2001, actual power supply costs were significantly greater than forecasted, resulting in a large PCA credit, which is now being recovered in rates (as revenues) and amortized in this line item. Astaris program cost deferrals also affected this year's expense. We discuss the PCA in more detail below in "Regulatory Issues." The following table presents the components of PCA expense for the three months ended March 31: $ (in millions) 2002 2001 Current year power supply costs accrual (deferral) $ 3 $ (57) Astaris and irrigation program costs (deferral) (13) - Amortization of prior year balance 44 (1) Total power cost adjustment $ 34 $ (58) Energy Marketing The following table presents our energy marketing operations (including intersegment transactions) for the three months ended March 31: $ (in millions) 2002 2001 Operating revenues: Electricity $ 401 $ 929 Gas 36 109 Total $ 437 $ 1,038 Settled volumes: Electricity (MWh's) 12,997,815 6,308,614 Gas (mmbtu's) 12,173,707 17,383,287 Operating expenses: Electricity $ 398 $ 891 Gas 32 109 Total $ 430 $ 1,000 The decreases in operating revenues, operating expenses and earnings are due to the dramatic decline in regional pricing spreads and volatility. Despite this decrease in revenue, our settled physical power sales have increased 106 percent over the first quarter of 2001. Our average price per settled MWH decreased from $136 in the first quarter of 2001 to $32 in the first quarter of 2002. Basis spreads between regions have dropped from around $85 to about $2, with volatility of prices being half what it was a year ago. Our trading and marketing portfolio is impacted primarily by regional price spreads and volatility and, with the reduction in both, we have seen a corresponding drop in earnings. The decreasing number of creditworthy counterparties also has had an affect on our origination activities. We continue to adhere to our credit policies, as we believe that the long-term health of our company depends on prudently managing our exposure to credit risk. We measure our sensitivity to commodity price risk using a value-at-risk measure. This methodology computes value-at- risk based upon market prices for futures and option-implied volatilities as of March 31, 2002. Our average value at risk, or VaR, for the quarter was $1.4 million, peaking at $2.4 million. As of March 31, 2002 it was $1.7 million. Our VaR measure is calculated by application of a variance/covariance methodology - assuming a 95 percent confidence level and a one-day holding period. Daily backtesting ensures that VaR measures produced by the model are in line with actual historical results. The value-at-risk is understood to be 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, at March 31, 2002, there is a five percent chance that the daily loss could exceed $1.7 million. Contracts Accounted for at Fair Value When determining the fair value of our marketing and trading contracts, we use actively quoted prices for contracts with similar terms as the quoted price, including specific delivery points and maturities. To determine fair value of contracts with terms that are not consistent with actively quoted prices, we use (when available) prices provided by other external sources. When prices from external sources are not available, we determine prices by using internal pricing models that incorporate available current and historical pricing information. Finally, we adjust the fair market value of our contracts for the impact of market depth and liquidity, potential model error, and expected credit losses at the counterparty level. The following table details the gross margin for the energy marketing operations for the three months ended March 31: $ (in millions) 2002 2001 Gross Margin: Realized or otherwise settled $ 29 $ (4) Unrealized (loss)gain (20) 75 Total $ 9 $ 71 At March 31, 2002, 63 percent of the credit exposure related to our unrealized position is with investment grade counterparties. Less than three percent is with non- investment grade counterparties. The remaining 34 percent of credit exposure is with non-rated counterparties. The majority of the non-rated entities are municipalities, public utility districts and electric cooperatives. The change in net fair value (energy marketing assets less energy marketing liabilities) between year-end 2001 and March 31, 2002 is explained as follows (in million of dollars): Net fair value of contracts outstanding as of 12/31/2001 $ 138 Contracts realized or otherwise settled during the period (29) Net fair value of new contracts when entered into during the period 2 Changes in net fair value attributable to market prices and other market changes (29) Net fair value of contracts outstanding as of 3/31/2002 $ 82 Changes in net fair value attributable to market prices and other market changes include: Changes in value due to changes in actively quoted prices Changes in value due to changes in prices provided by other external sources Changes in value due to changes in prices derived by models or other methods Changes in price basis between liquid and illiquid points. Some price bases between points are easily determined in the market, some are derived by analyzing other market data Changes in implied volatility and price correlations Changes in liquidity at various delivery points that are driven by changes in market conditions Changes in discounts related to counterparty creditworthiness Net fair value at March 31, 2002 disaggregated by source of fair value and maturity of contracts: Maturity Maturity less than Maturity Maturity in excess Grand 1 year 1-3 years 4-5 years of 5 years Total Source of Fair Value (in millions of dollars) Prices actively quoted $ 6 $ 46 $ 10 $ 1 $ 63 Prices provided by other external sources (9) 30 (3) 13 31 Prices based on models and other valuation methods (3) (9) 1 (1) (12) Total $ (6) $ 67 $ 8 $ 13 $ 82 Prices actively quoted are quoted daily by brokers and trading exchanges such as NYMEX, TFS, Intercontinental, and Bloomberg. The time horizon is April 2002 through December 2006. Products include physical, financial, swap, interest rate, index, and basis for both natural gas and heavy load power. Prices provided by other external sources are quoted periodically by brokers and trading exchanges such as TFS, APB, Prebon, Intercontinental, and Bloomberg. The time horizon is April 2002 through December 2010. Products include physical, financial, swap, index, and basis for both natural gas and heavy and light load power. Prices derived from models and other valuation methods incorporate available current and historical pricing information. The time horizon is April 2002 through December 2009. Products include transmission, options, and ancillary services related to heavy and light load power. Other Segment Operations Our other operations include the results of operations of IDACORP's diversified subsidiaries, including Ida-West, IdaTech, IFS, Velocitus and IDACOMM. Other operating revenues and expenses for the quarter did not differ materially from the first quarter of 2001. Income Taxes Income taxes decreased for the quarter, due primarily to the decreases in net income before taxes and by an increase in tax credits from affordable housing projects. LIQUIDITY AND CAPITAL RESOURCES: Cash Flow Our net cash provided by operations totaled $109 million for the quarter ended March 31, 2002. Significant factors affecting cash flows in 2002 include: the receipt of a $41 million income tax refund related to net operating loss carrybacks associated with 2001 power supply costs; the recovery through the PCA of power supply costs incurred in 2000 and 2001; payments of accounts payable at December 31, 2001. We anticipate that our cash flows from operations will continue to be positively affected as we recover the remaining balance of the 2001 PCA, and begin recovery of the May 2002 PCA. We discuss the PCA in the section "Power Cost Adjustment" below. Working Capital The changes in customer receivables and accounts payable are attributed primarily to lower prices on settled energy trading contracts. Accounts payable also decreased due to timing and normal business activity. Energy marketing assets and liabilities represent the fair value of energy marketing contracts. The fair value of these contracts is unrealized and therefore does not necessarily indicate a current source or use of funds. The decreases in energy marketing assets and liabilities from December 31, 2001 to March 31, 2002 is primarily a reflection of lower market prices at March 31, 2002. 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 100 percent of total capital requirements in 2002 and 82 percent during the two-year period 2003-2004. 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 We have credit facilities established at both IPC and IDACORP. IDACORP has a $140 million three-year credit facility that expires in March 2005, and a $350 million 364- day credit facility that expires in March 2003. Under these facilities, IDACORP pays a facility fee on the commitment, quarterly in arrears, based on IDACORP's corporate credit rating. Commercial paper may be issued up to the amounts supported by the credit facilities. At March 31, 2002, short-term borrowing on these facilities totaled $96 million. IPC has regulatory authority to incur up to $350 million of short-term indebtedness. IPC has a $200 million 364-day revolving credit facility that expires in March 2003, under which IPC pays a facility fee on the commitment quarterly in arrears, based on IPC's corporate credit rating. Commercial paper may be issued subject to the regulatory maximum, up to the amount supported by the credit facilities. At March 31, 2002, IPC's short term borrowing under this facility totaled $190 million. IPC also has $100 million of floating rate notes outstanding, payable on September 1, 2002. IDACORP currently has shelf registration statements totaling $800 million that can be used for the issuance of unsecured debt securities, including medium-term notes, and preferred or common stock. At March 31, 2002 none had been issued. IPC currently has a $200 million shelf registration that can be used for first mortgage bonds, including medium-term notes, unsecured debt or preferred stock. At March 31, 2002, none had been issued. In March 2002 IPC redeemed $50 million of first mortgage bonds originally due in 2027 using short-term borrowings. IDACORP plans to issue equity and debt securities this year. The equity could take the form of common equity, mandatorily convertible securities, or a combination of the two. The equity or equity-like securities are being issued to strengthen the Company's balance sheet and to provide for additional funding of the Company's businesses. This could include infusing equity capital at IPC, providing additional liquidity for IE's ongoing operations, paying down short- term balances and funding of the capital needs of our growth subsidiaries. Credit Rating On March 25, 2002, Standard & Poor's lowered its Corporate Credit Rating on IDACORP and Idaho Power Company from "A+" (negative outlook) to "A-" (negative outlook). S&P cited increasing business risk combined with a financial profile that is weak for the rating. The increased business risk at IDACORP is the result of the rapid growth of non-regulated trading and marketing activities. The financial profile has been considerable weakened by the accumulation of deferred power costs incurred during 2001. S&P also stated that more stringent financial benchmarks are now expected at any given rating level to compensate for the increased business risk of the trading and marketing operation. These downgrades are expected to increase our future cost of debt and other securities. The following outlines the former and current S&P rating of IDACORP's and Idaho Power's securities: From To IDACORP Corporate Credit Rating A+ A- Senior Unsecured A BBB+ Commerical Paper A-1 A-2 Idaho Power Company Corporate Credit Rating A+ A- Senior Unsecured A BBB+ Senior Secured AA- A Preferred Stock A- BBB Commercial Paper A-1 A-2 Some collateral agreements in place between IE and its counter parties include provisions requiring additional margining in the event of a credit rating downgrade. IDACORP's most recent downgrade did not impact the liquidity required at IE. In general, credit rating changes within the investment grade category should not materially impact the liquidity or financial condition of IDACORP. A credit downgrade below an investment grade rating could result in additional margin calls that could have a material negative impact to the liquidity of IDACORP. The Company believes its existing credit facilities are adequate to fund these potential liquidity requirements. OTHER MATTERS: Regulatory Issues: 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 May 2002 the IPUC issued an order related to our 2002-2003 PCA rate filing. The order granted recovery of $256 million of excess power supply costs, consisting of: $209 million of voluntary load reduction and power supply costs incurred between March 1, 2001 and March 31, 2002. $28 million of excess power supply costs forecasted for the April 2002-March 2003. $18 million of unamortized costs previously approved for recovery beginning October 1, 2001. The order also: Denied recovery of $12 million of lost revenues resulting from the irrigation load reduction program, and $2 million of other costs IPC was seeking to recover. Authorized recovery over a one-year period for all but $11.5 million of the $256 million of deferred costs. The remaining amount will be recovered during the 2003-2004 PCA rate year, and IPC will earn a six percent carrying charge on the balance. Denied IPC's request to issue $172 million in Energy Cost Recovery Bonds, which would have spread the recovery of that amount over three years. Discontinued the Commission-required three-tiered rate structure for residential customers. Authorized a separate surcharge to collect approximately $2.6 million to fund future conservation programs. The IPUC had previously filed an order disallowing the lost revenue portion of the irrigation load reduction program. IPC believes that the Commission's order is inconsistent with an earlier order that allowed recovery of such costs and IPC filed a Petition for Reconsideration on May 2, 2002. It is a long- standing legal position in Idaho that an IPUC order is not administratively final until the reconsideration process is completed. The process we have embarked upon has a number of steps involved and could extend into the early fall. If IPC is unsuccessful in its efforts to overturn the denial, this amount would be written off. Overton Power District No. 5: IE filed a lawsuit on November 30, 2001 in Idaho State District Court in and for the County of Ada against Overton Power District No. 5, a Nevada electric improvement district, for failure to meet payment obligations under a power contract. The contract provided for Overton to purchase 40 megawatts of electrical energy per hour from IE at $88.50 per megawatt hour, from July 1, 2001 through June 30, 2011. In the contract, Overton agreed to raise its rates to its customers to the extent necessary to make its payment obligations to IE under the contract. IE has asked the Idaho District Court for damages pursuant to the contract, for a declaration that Overton is not entitled to renegotiate or terminate the contract and for injunctive relief requiring Overton to raise rates as stipulated in the contract. Overton filed an Answer and Counterclaim on April 23, 2002 claiming IE breached the agreement by failing to perform in accordance with its contractual obligation and asking for damages in an amount to be proved at trial. IE believes Overton's assertions are without merit. IE believes that Overton's actions constitute a breach of the contract and intends to vigorously prosecute this lawsuit. While the outcome of litigation is never certain, IE believes it should prevail on the merits of this case. At March 31, 2002, the Company had a $74 million long-term asset related to the Overton claim. IE will review the recoverability of the asset on an ongoing basis. Truckee-Donner Public Utility District: IE has received notice from Truckee-Donner Public Utility District ("Truckee") asserting they have the right to renegotiate certain terms of the Agreement for the Sale and Purchase of Firm Capacity and Energy in place between the two entities. Generally, the terms of the contract provide for IE to sell to Truckee 10 MW light load energy and 20 MW heavy load energy for the term January 1, 2002 through December 31, 2002 at $72 per MWh and 25 MW flat energy for the term January 1, 2003 through December 31, 2009 at $72 per MWh. IE believes there are no grounds for dispute or renegotiation under the terms of the contract, however IE has agreed to informally negotiate with Truckee on the issues in an effort to resolve the matter. 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 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 among the creditors of PG&E. To the extent that PG&E's bankruptcy filing affects the collectibility of the receivables from the CalPX and Cal ISO the 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 19th 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 the methodology set forth in the 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 the 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 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. Multiple parties have filed requests for rehearing and petitions for review. The ALJ has re-established a procedural schedule which would result in findings of fact and recommended conclusions during August 2002; such schedule is subject to Commission review. On May 8, 2002 the FERC issued a data request to all Sellers of Wholesale Electricity and/or Ancillary Services to the Cal ISO and/or the CalPX during the years 2000-2001. The request requires the Company to respond in the form of an affidavit to various trading practices that the FERC has identified in its fact finding investigation of Potential Manipulation of Electric and Natural Gas Prices in Docket No. PA02-2-000. The response is due on or before May 22, 2002. In response to the FERC's request, the Company has initiated a comprehensive internal analysis of its trading policies and actions in order to respond. The Company's policy has at all times been to operate in compliance with the Cal ISO's and CalPX's rules for participation in the California markets. Effective June 11, 2001, IPC transferred its non-utility wholesale electricity marketing operations to IE. Effective with the June 11 transfer, the outstanding receivables and payables with the CalPX and Cal ISO were assigned from IPC to IE. At March 31, 2002, 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. IE has accrued a reserve of $41 million against these receivables. These reserves were calculated taking into account the uncertaintity of collection, given the current California energy situation. Based on the reserves recorded as of March 31, 2002, 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 the Company's financial position, results of operations or cash flows. Power supply: 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 The National Weather Service River Forecast Center is projecting that April-July 2002 inflow into Brownlee Reservoir, IPC's key water storage facility, is expected to be 3.63 million acre-feet (maf). Average inflow into the reservoir is 6.3 maf. Inflow into Brownlee Reservoir dictates IPC's ability to produce low-cost hydropower. The three-dam Hells Canyon complex generates approximately two-thirds of IPC's total hydroelectric output. As of May 13, 2002, the snow pack above Brownlee Reservoir was 81 percent of normal for this time of year. This is a dramatic improvement from last year, when the snow pack for the Snake River above Brownlee was about 23 percent of normal on May 14, 2001. Through the first quarter of 2002, hydro generation was 26 percent above the same period in 2001, but below normal. Based on these conditions, we expect 2002 hydro generation to be improved over last year, but remain below normal. Such conditions necessitate the use of higher-cost power from coal-fired plants and wholesale purchases. Delay of Garnet Energy Facility: In April 2002, IPC notified Garnet Energy, a subsidiary of Ida-West, requesting delay of the guaranteed commercial operation date of the Garnet Energy Facility for one year to June 1, 2005, instead of June 1, 2004, as originally planned. This decision was necessary because the permitting process and regulatory approval has extended beyond original projections. The regional energy situation has changed somewhat and this delay is expected to better match customer electricity needs with related resource availability. Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK The Company's market risks related to commodity prices is included in Item 2 "Management's Discussion and Analysis of Financial Condition and Results of Operations" under "Energy Marketing". The Company's market risks related to interest rates and foreign currency have not changed materially from those reported in the Company's Annual Report on Form 10-K for the year ended December 31, 2001. PART II - OTHER INFORMATION Item 1. Legal Proceedings IDACORP Energy (IE) filed a lawsuit on November 30, 2001 in Idaho State District Court in and for the County of Ada against Overton Power District No. 5, a Nevada electric improvement district, for failure to meet payment obligations under a power contract. The contract provided for Overton to purchase 40 megawatts of electrical energy per hour from IE at $88.50 per megawatt hour, from July 1, 2001 through June 30, 2011. In the contract, Overton agreed to raise its rates to its customers to the extent necessary to make its payment obligations to IE under the contract. IE has asked the Idaho District Court for damages pursuant to the contract, for a declaration that Overton is not entitled to renegotiate or terminate the contract and for injunctive relief requiring Overton to raise rates as stipulated in the contract. Overton filed an Answer and Counterclaim on April 23, 2002, claiming IE breached the agreement by failing to perform in accordance with its contractual obligations and asking for damages in an amount to be proved at trial. IE believes Overton's assertions are without merit. IE believes that Overton's actions constitute a breach of the contract and intends to vigorously prosecute this lawsuit. While the outcome of litigation is never certain, IE believes it should prevail on the merits of this case. At March 31, 2002, the Company had a $74 million long-term asset related to the Overton claim. IE will review the recoverability of the asset on an ongoing basis. This matter has been previously discussed in IDACORP's Annual Report on Form 10-K for the year ended December 31, 2001. Item 6. Exhibits and Reports on Form 8-K (a) Exhibits: Exhibit File Number As Exhibit *2 333-48031 2 Agreement and Plan of Exchange between IDACORP, Inc., and IPC dated as of February 2, 1998. *3(a) 33-56071 3(d) Articles of Share Exchange, as filed with the Secretary of State of Idaho on September 29, 1998. *3(b) 333-64737 3.1 Articles of Incorporation of IDACORP, Inc. *3(b)(i) 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(b)(ii) 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(c) 1-14465 3(c) Amended Bylaws of IDACORP, Inc. as Form 10-Q of July 8, 1999. for 6/30/99 *4(a) 1-14465 4 Rights Agreement, dated as of Form 8-K September 10, 1998, between dated IDACORP, Inc. and Wells Fargo Bank September 15, Minnesota, N.A. as Successor 1998 Rights Agent. *4(b) 1-14465 4.1 Indenture for Senior Debt Form 8-K Securities dated as of February 1, dated 2001, between IDACORP, Inc. and February 28, Bankers Trust Company (now Deutsche 2001 Bank Trust Company Americas), as Trustee. *4(c) 1-14465 4.2 First Supplemental Indenture dated Form 8-K as of February 1, 2001, to dated Indenture for Senior Debt February 28, Securities dated as of February 1, 2001 2001 between IDACORP, Inc. and Bankers Trust Company (now Deutsche Bank Trust Company Americas), as Trustee. *10(a)1 1-3198 10(n)(i) The Revised Security Plan for Form 10-K Senior Management Employees - a non- for 1994 qualified, deferred compensation plan effective August 1, 1996. *10(b)1 1-14465 10(n)(ii) The Executive Annual Incentive Plan Form 10-K for senior management employees of for 2001 IPC effective January 1, 2001. *10(c)1 1-3198 10(n)(iii) The 1994 Restricted Stock Plan for Form 10-K officers and key executives of for 1994 IDACORP, Inc. and IPC effective July 1, 1994. *10(d)1 1-14465 10(h)(iv) The Revised Security Plan for Board Form 10-K of Directors - a non-qualified, for 1998 deferred compensation plan effective August 1, 1996, revised March 2, 1999. 10(e)1 IDACORP, Inc. Non-Employee Directors Stock Compensation Plan as of May 17, 1999, as amended. *10(f) 1-3198 10(y) Executive Employment Agreement Form 10-K dated November 20, 1996 between IPC for 1997 and Richard R. Riazzi. *10(g) 1-3198 10(g) Executive Employment Agreement Form 10-Q dated April 12, 1999 between IPC for 6/30/99 and Marlene Williams. *10(h) 1-14465 10(h) Agreement between IDACORP, Inc. and Form 10-Q Jan B. Packwood, J. LaMont Keen, for 9/30/99 James C. Miller, Richard Riazzi, Darrel T. Anderson, Bryan Kearney, Cliff N. Olson, Robert W. Stahman and Marlene K. Williams. 10(i)1 IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan, as amended. 12 Statement Re: Computation of Ratio of Earnings to Fixed Charges. 12(a) Statement Re: Computation of Supplemental Ratio of Earnings to Fixed Charges. 12(b) Statement Re: Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Dividend Requirements. 12(c) Statement Re: Computation of Supplemental Ratio of Earnings to Combined Fixed Charges and Preferred Dividend Requirements. 15 Letter Re: Unaudited Interim Financial Information. *21 1-14465 21 Subsidiaries of IDACORP, Inc. Form 10-K for 2001 1 Compensatory Plan Reports on Form 8-K. The following reports on Form 8-K were filed for the three months ended March 31, 2002. Items Reported Date of Report Item 5 - Other events March 26, 2002 * 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 May 15, 2002 By: /s/ Jan B. Packwood Jan B. Packwood President and Chief Executive Officer and Director Date May 15, 2002 By: /s/ Darrel T Anderson Darrel T Anderson Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer) (Principal Accounting Officer)