-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, W2KOBCZ9wbkEqJVJxJeILRda0OnjXC266MC/tC2/gaq69hR6M56RnosRbuyCiHAZ Ntsz6UlliF/xxrP1P4cZdw== 0000049648-98-000024.txt : 19981109 0000049648-98-000024.hdr.sgml : 19981109 ACCESSION NUMBER: 0000049648-98-000024 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 7 CONFORMED PERIOD OF REPORT: 19980930 FILED AS OF DATE: 19981106 FILER: COMPANY DATA: COMPANY CONFORMED NAME: IDAHO POWER CO CENTRAL INDEX KEY: 0000049648 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 820130980 STATE OF INCORPORATION: ID FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: SEC FILE NUMBER: 001-03198 FILM NUMBER: 98738978 BUSINESS ADDRESS: STREET 1: 1221 W IDAHO ST STREET 2: PO BOX 70 CITY: BOISE STATE: ID ZIP: 83707 BUSINESS PHONE: 2083882200 10-Q 1 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, 1998 OR TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from to Commission file number 1-3198 IDAHO POWER COMPANY (Exact name of registrant as specified in its charter) Idaho 82-0130980 (State or other jurisdiction (I.R.S. Employer of incorporation or organization) Identification No.) 1221 W. Idaho Street, Boise, Idaho 83702-5627 (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code (208) 388-2200 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 Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date. Number of shares of Common Stock, $2.50 par value, outstanding as of September 30, 1998 is 37,612,351. IDAHO POWER COMPANY Index Page Definitions 2 Part I. Financial Information: Item 1. Financial Statements Consolidated Statements of Income 3-4 Consolidated Balance Sheets 5-6 Consolidated Statements of Cash Flows 7 Consolidated Statements of Capitalization 8 Notes to Consolidated Financial Statements 9-12 Independent Accountants' Report 13 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations 14-20 Part II. Other Information: Item 1. Legal Proceedings 21 Item 6. Exhibits and Reports on Form 8-K 22-25 Signatures 26 DEFINITIONS AFDC Allowance For Funds Used During Construction BPA Bonneville Power Administration CSPP Cogeneration and Small Power Production DSM Demand Side Management FASB Financial Accounting Standards Board FERC Federal Energy Regulatory Commission IPUC Idaho Public Utilities Commission OPUC Oregon Public Utilities Commission kWh kilowatt-hour MAF Million Acre-Feet MMbtu Million British Thermal Units MOU Memorandum of Understanding MWH Megawatt-Hour PCA Power Cost Adjustment REA Rural Electrification Administration SFAS Statement of Financial Accounting 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 and includes but are not limited to statements under the heading "Other Matters" concerning the outcome of the Company's Year 2000 efforts. PART I - FINANCIAL INFORMATION Item 1. Financial Statements IDAHO POWER COMPANY Consolidated Statements of Income Three Months Ended September 30, 1998 1997 (Thousands of Dollars) REVENUES: Total general business $149,411 $125,407 Off system sales 236,738 84,776 Other 6,229 6,991 Total revenues 392,378 217,174 EXPENSES: Operation: Purchased power 251,641 88,392 Fuel expense 25,054 22,756 Power cost adjustment (1,338) (6,893) Other 34,455 33,652 Maintenance 10,709 11,958 Depreciation 19,140 18,099 Taxes other than income taxes 5,258 5,333 Total expenses 344,919 173,297 INCOME FROM OPERATIONS 47,459 43,877 OTHER INCOME: Allowance for equity funds used during construction 46 4 Gas trading - net (1,380) (523) Other - net 5,037 2,646 Total other income 3,703 2,127 INTEREST CHARGES: Interest on long-term debt 13,106 13,147 Other 2,223 1,120 Total interest charges 15,329 14,267 Allowance for borrowed funds used during construction (274) (119) Net interest charges 15,055 14,148 INCOME BEFORE INCOME TAXES 36,107 31,856 INCOME TAXES 12,392 10,715 NET INCOME 23,715 21,141 Dividends on preferred stock 1,410 1,422 EARNINGS ON COMMON STOCK $ 22,305 $ 19,719 AVERAGE COMMON SHARES OUTSTANDING (000) 37,612 37,612 Earnings per share of common stock (basic and diluted) 0.59 0.52 Dividends paid per share of common stock $ 0.465 $ 0.465 The accompanying notes are an integral part of these statements. IDAHO POWER COMPANY Consolidated Statements of Income Nine Months Ended September 30, 1998 1997 (Thousands of Dollars) REVENUES: Total general business $382,631 $363,497 Off system sales 446,129 155,053 Other 23,411 21,045 Total revenues 852,171 539,595 EXPENSES: Operation: Purchased power 421,893 145,019 Fuel expense 60,077 48,030 Power cost adjustment 12,951 (5,961) Other 106,008 101,567 Maintenance 31,262 35,830 Depreciation 57,080 53,664 Taxes other than income taxes 16,103 16,721 Total expenses 705,374 394,870 INCOME FROM OPERATIONS 146,797 144,725 OTHER INCOME: Allowance for equity funds used during construction 71 2 Gas trading - net (3,005) (662) Other - net 10,665 8,430 Total other income 7,731 7,770 INTEREST CHARGES: Interest on long-term debt 39,204 40,110 Other 6,368 5,001 Total interest charges 45,572 45,111 Allowance for borrowed funds used during construction (714) (379) Net interest charges 44,858 44,732 INCOME BEFORE INCOME TAXES 109,670 107,763 INCOME TAXES 34,730 36,202 NET INCOME 74,940 71,561 Dividends on preferred stock 4,232 3,481 EARNINGS ON COMMON STOCK $ 70,708 $68,080 AVERAGE COMMON SHARES OUTSTANDING (000) 37,612 37,612 Earnings per share of common stock (basic and diluted) 1.88 1.81 Dividends paid per share of common stock $ 1.395 $ 1.395 The accompanying notes are an integral part of these statements. IDAHO POWER COMPANY Consolidated Balance Sheets ASSETS September 30, December 31, 1998 1997 (Thousands of Dollars) ELECTRIC PLANT: In service (at original cost) $2,627,264 $2,605,697 Accumulated provision for depreciation (1,000,692) (942,400) In service - net 1,626,572 1,663,297 Construction work in progress 72,080 51,892 Held for future use 1,738 1,738 Electric plant - net 1,700,390 1,716,927 INVESTMENTS AND OTHER PROPERTY 128,504 97,065 CURRENT ASSETS: Cash and cash equivalents 4,916 6,905 Receivables: Customer 142,228 63,076 Allowance for uncollectible accounts (1,397) (1,397) Gas trading 22,493 42,128 Notes 5,059 4,613 Employee notes 4,551 4,757 Other 5,351 8,854 Accrued unbilled revenue 26,465 33,312 Materials and supplies (at average cost) 29,776 29,156 Fuel stock (at average cost) 6,268 7,172 Prepayments 15,186 15,381 Regulatory assets associated with income taxes 3,063 3,164 Total current assets 263,959 217,121 DEFERRED DEBITS: American Falls and Milner water rights 31,830 32,055 Company-owned life insurance 35,323 51,915 Regulatory assets associated with income taxes 200,813 198,521 Regulatory assets - other 73,970 90,239 Other 65,630 47,973 Total deferred debits 407,566 420,703 TOTAL $2,500,419 $2,451,816 The accompanying notes are an integral part of these statements. IDAHO POWER COMPANY Consolidated Balance Sheets CAPITALIZATION & LIABILITIES September 30, December 31, 1998 1997 (Thousands of Dollars) CAPITALIZATION: Common stock equity - $2.50 par value (shares authorized 50,000,000; shares outstanding - 37,612,351) $ 730,045 $ 711,818 Preferred stock 106,208 106,697 Long-term debt 816,035 746,142 Total capitalization 1,652,288 1,564,657 CURRENT LIABILITIES: Long-term debt due within one year 6,285 33,998 Notes payable 22,439 57,516 Accounts payable 130,037 69,064 Accounts payable gas trading 27,642 42,874 Taxes accrued 27,482 24,295 Interest accrued 14,719 17,918 Deferred income taxes 3,063 3,164 Other 11,450 13,703 Total current liabilities 243,117 262,532 DEFERRED CREDITS: Regulatory liabilities associated with deferred investment tax credits 69,706 70,196 Deferred income taxes 432,369 423,736 Regulatory liabilities associated with income taxes 27,635 34,072 Regulatory liabilities - other 5,050 509 Other 70,254 96,114 Total deferred credits 605,014 624,627 COMMITMENTS AND CONTINGENT LIABILITIES TOTAL $2,500,419 $2,451,816 The accompanying notes are an integral part of these statements. IDAHO POWER COMPANY Consolidated Statements Of Cash Flows Nine Months Ended September 30, 1998 1997 (Thousands of Dollars) OPERATING ACTIVITIES: Net income $ 74,940 $ 71,561 Adjustments to reconcile net income to net cash: Depreciation & amortization 62,895 60,141 Deferred taxes and investment tax credits (656) 7,497 Accrued PCA costs 12,743 (5,995) Change in: Accounts receivable and prepayments (56,060) (42,339) Accrued unbilled revenue 6,847 2,258 Increase in margin accounts at brokers (7,157) (106) Materials and supplies and fuel stock 284 (1,242) Accounts payable 45,741 24,663 Taxes Accrued 3,187 13,167 Other current assets and liabilities (5,327) 4,669 Other - net (2,594) (4,030) Net cash provided by operating activities 134,843 130,244 INVESTING ACTIVITIES: Additions to utility plant (60,136) (69,855) Investments in affordable housing projects (19,139) (17,021) Other - net (7,486) 598 Net cash used in investing activities (86,761) (86,278) FINANCING ACTIVITIES: Proceeds from issuance of: Long-term debt related to affordable housing projects 15,088 12,984 First mortgage bonds 60,000 - Retirement of subsidiary long-term debt (3,316) (2,250) Retirement of first mortgage bonds (30,000) - Dividends on common stock (52,399) (52,415) Dividends on preferred stock (4,232) (4,086) Increase (decrease) in short-term borrowings (35,077) 4,254 Other - net (135) (126) Net cash used in financing activities (50,071) (41,639) Net increase (decrease) in cash and cash equivalents (1,989) 2,327 Cash and cash equivalents at beginning of period 6,905 7,928 Cash and cash equivalents at end of period $ 4,916 $ 10,255 SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: Cash paid during the period for: Income taxes $ 44,773 $ 27,429 Interest (net of amount capitalized) 40,712 42,304 The accompanying notes are an integral part of these statements. IDAHO POWER COMPANY Consolidated Statements Of Capitalization September 30,December 31, 1998 1997 (Thousands of Dollars) COMMON STOCK EQUITY: Common stock $94,031 $94,031 Premium on capital stock 362,126 362,328 Capital stock expense (3,828) (3,840) Retained earnings 277,607 259,299 Other comprehensive income 109 - Total common stock equity 730,045 44.2% 711,818 45.5% PREFERRED STOCK: 4% preferred stock 16,208 16,697 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 106,208 6.4 106,697 6.8 LONG-TERM DEBT: Utility: First mortgage bonds: 5.33 % Series due 1998 - 30,000 8.65 % Series due 2000 80,000 80,000 6.93 % Series due 2001 30,000 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 - Maturing 2021 through 2031 with rates from 7.5% to 9.52% 230,000 230,000 Total first mortgage bonds 557,000 527,000 Amount due within one year - (30,000) Net first mortgage bonds 557,000 497,000 Pollution control revenue bonds: 7 1/4% Series due 2008 4,360 4,360 8.30 % Series 1984 due 2014 49,800 49,800 6.05 % Series 1996A due 2026 68,100 68,100 Variable Rate Series 1996 B and C due 2026 48,200 48,200 Total pollution control revenue bonds 170,460 170,460 REA Notes 1,507 1,561 Amount due within one year (74) (72) Net REA Notes 1,433 1,489 American Falls bond guarantee 20,130 20,355 Milner Dam note guarantee 11,700 11,700 Unamortized premium/discount - Net (1,563) (1,637) Net utility debt 759,160 699,367 Subsidiaries: Debt related to investments in affordable housing with rates ranging from 6.97% to 8.59% due 1998 to 2009 61,473 46,385 Other subsidiary debt 1,613 4,316 Total subsidiary debt 63,086 50,701 Amount due within one year (6,211) (3,926) Net subsidiary debt 56,875 46,775 Total long-term debt 816,035 49.4 746,142 47.7 TOTAL CAPITALIZATION $1,652,288 100.0% $1,564,657 100.0% The accompanying notes are an integral part of these statements. IDAHO POWER COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. SUMMARY OF ACCOUNTING POLICIES: 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, 1998 and its consolidated results of operations for the three and nine months ended September 30, 1998 and 1997 and its consolidated cash flows for the nine months ended September 30, 1998 and 1997. These financial statements do not contain the complete detail or footnote disclosure concerning accounting policies and other matters which would be included in full year financial statements and, therefore, they should be read in conjunction with the Company's audited financial statements included in the Company's Annual Report on Form 10-K for the year ended December 31, 1997. 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. Revenues In order to match revenues with associated expenses, the Company accrues unbilled revenues for electric services delivered to customers but not yet billed at month-end. Comprehensive Income The Company adopted SFAS 130, Reporting Comprehensive Income, on January 1, 1998. The statement establishes standards for the reporting and displaying of comprehensive income and its components in the Company's financial statements. For the three and nine months ended September 30, 1998, the Company's comprehensive income was not materially different from net income. The components of comprehensive income include net income, the Company's proportionate share of unrealized holding gains on marketable securities held by an equity investee, and the changes in additional minimum liability under a deferred compensation plan for certain senior management employees and directors. Cash and Cash Equivalents For purposes of reporting cash flows, cash and cash equivalents include cash on hand and highly liquid temporary investments with original maturity dates of three months or less. The Company has changed the presentation of operating activities in its statement of cash flows from the direct to the indirect method effective for all periods reported in 1998. Previous year's presentation has been reclassified to conform with the new presentation. Management Estimates The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Gas Trading The Company intends to be a competitive energy provider, including both electricity and gas. In April 1997 the Company opened a gas trading office in Houston, Texas to serve the southern and eastern United States gas markets and a Boise, Idaho office that serves the Northwest and Canadian markets. The following table shows gas trading activities for the three and nine month periods ended September 30, 1998 and 1997 (thousands of dollars): Three Months Ended Nine Months Ended September 30, September 30, 1998 1997 1998 1997 Gas revenues $77,544 $29,736 $258,022 $39,197 Cost of gas and other - net (78,924) (30,259) (261,027) (39,859) Gas trading activities - Net $(1,380) $ (523) $ (3,005) $ (662) Reclassifications Certain items previously reported for periods prior to September 30, 1998 have been reclassified to conform with the current period's presentation. Net income was not affected by these reclassifications. 2. COMMITMENTS AND CONTINGENT LIABILITIES: Commitments under contracts and purchase orders relating to the Company's program for construction and operation of facilities amounted to approximately $2.4 million at September 30, 1998. The commitments are generally revocable by the Company subject to reimbursement of manufacturers' expenditures incurred and/or other termination charges. The Company is party to various legal claims, actions, and complaints, certain of which 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 flow. 3. REGULATORY ISSUES: The Company has a PCA mechanism that provides for annual adjustments to the electric rates charged to Idaho retail customers. These adjustments are based on forecasts of net power supply costs, and take effect annually on May 16. The difference between the actual costs incurred and the forecasted costs are deferred, with interest, and trued-up in the next annual rate adjustment. The May 16, 1998 adjustment increased electric rates $34.0 million over the 1997 rates and $17.3 million over base rates. The increase was due primarily to the forecasted return to more normal streamflow conditions from the near- record conditions experienced in 1997, and rising costs associated with mandatory purchases from CSPP projects. Good water conditions and mild weather since the forecast date have resulted in the Company currently recording a true- up credit of $5.2 million at September 30, 1998. The credit reflects power supply costs below those projected for the 1998 PCA forecast. Any additional variance that exists at the end of the current rate period will be trued-up in the next annual PCA adjustment. Under IPUC Order No. 26216, when the Company's actual earnings in the Idaho jurisdiction in a given year exceed an 11.75 percent return on year-end common equity through 1999, the Company will refund 50 percent of the excess. In 1997, $7.6 million of revenue accrued for the benefit of its Idaho customers based on actual data. The IPUC ordered that approximately $5.0 million be applied against the balance of demand-side conservation expenditures in order to defer any rate increase associated with conservation recovery until May 16, 1999, the same time as the next PCA adjustment to rates. The Company has applied to the IPUC to use approximately $2.4 million of the remaining $2.6 million as reimbursement of deferred expenses related to its participation in the Northwest Energy Efficiency Alliance during 1997 and 1998. The Company has sought changes to the regulatory treatment of previously deferred DSM (conservation) expenses in both Idaho and Oregon. In Idaho the Company requested in Case No. IPC-E-97-12 that the IPUC authorize recovery of post- 1993 DSM expenses and an acceleration of the recovery of DSM expenditures authorized in the last general rate case. The Company requested a five-year amortization instead of the 24-year period previously adopted. In its Order No. 27660 issued on July 31, 1998, the IPUC set a new amortization period of 12 years. The IPUC order reflects an increase in annual revenue requirement of $3.1 million for twelve years. As noted above, the Company is funding the annual revenue requirement with revenue sharing amounts until May 16, 1999. A notice of appeal has been filed with the IPUC by a group of the Company's industrial customers notifying the IPUC that its order has been appealed to the Idaho Supreme Court. In Oregon, the OPUC, in case No. UE 107, authorized the amortization of the Oregon allocated share of the DSM expenditures over five years. The OPUC allowed a rate surcharge for extraordinary purchases to be replaced by an identical charge to recover the amortization of the DSM expenditures. This charge will recover approximately $540,000 per year. 4. FINANCING: The Company currently has a $200,000,000 shelf registration statement that can be used for both First Mortgage Bonds (including Medium Term Notes) and Preferred Stock. In September 1998, the Company issued $60,000,000 principal amount of Secured Medium Term Notes 5.83% Series due September 9, 2005. The proceeds from this issuance was used to redeem at maturity, the $30,000,000 First Mortgage Bonds 5.33% Series due September 1998, with the balance used for repayment of commercial paper issued in connection with the Company's ongoing business. This issuance, combined with two issuances in 1996, has reduced the remaining balance of the shelf registration to $83,000,000 at September 30, 1998. 5. INCOME TAXES: The effective tax rate for the first nine months decreased from 33.6 percent in 1997 to 31.7 percent in 1998. A reconciliation between the statutory income tax rate and the effective rate for the nine months ended September 30 is as follows: 1998 1997 Amount Rate Amount Rate Computed income taxes based on statutory federal income tax rate $38,385 35.0% $37,717 35.0% Changes in taxes resulting from: Current state income taxes 5,106 4.7 3,945 3.7 Settlement of prior year tax returns (1,500) (1.4) 0 0.0 Net depreciation 4,005 3.6 4,268 4.0 Investment tax credits restored (2,197) (2.0) (2,161) (2.0) Removal costs (1,037) (0.9) (1,025) (0.9) Repair allowance (2,346) (2.1) (2,346) (2.2) Affordable housing credit (5,160) (4.7) (3,444) (3.2) Other (526) (0.5) (752) (0.8) $34,730 31.7% $36,202 33.6% 6. PREFERRED STOCK: The number of shares of preferred stock outstanding were as follows: September 30, December 31, 1998 1997 Cumulative, $100 par value: 4% preferred stock (authorized 215,000 shares) 162,080 166,972 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 7. NEW ACCOUNTING PRONOUNCEMENTS: In June 1998 the FASB issued SFAS No. 133 Accounting for Derivative Instruments and Hedging Transactions. This statement establishes accounting and reporting standards for derivative financial instruments and other similar financial instruments and for hedging activities. It is effective for fiscal years beginning after June 15, 1999. The Company is reviewing this statement to determine its effects on the Company's accounting and reporting requirements. 8. SUBSEQUENT EVENTS: On October 1, 1998, the Company officially adopted a holding company structure with the completion of a statutory share exchange under which the outstanding common stock of Idaho Power was exchanged on a share-for- share basis for the common stock of IDACORP, Inc. (IDACORP), and Idaho Power became a subsidiary of IDACORP. The share exchange was effected pursuant to the terms of an Agreement and Plan of Exchange dated February 2, 1998 and was approved by Idaho Power shareholders, the FERC, and the regulatory commissions of Idaho, Oregon, Wyoming and Nevada. Following the share exchange, in October 1998 Idaho Power transferred ownership of its subsidiaries Ida-West Energy Company, IDACORP Energy Solutions Co. and IDACORP Retail Enterprises Co. to IDACORP. As has been the case with Idaho Power Company, a "Shareholders Rights" plan is also in effect for IDACORP. This plan, authorized by the Board of Directors of IDACORP on September 10, 1998 and effective at the close of business on October 1, 1998, is designed to ensure that all shareholders receive fair and equal treatment in the event of any proposal to acquire control of the Company. This plan is substantially similar to the plan already in effect for Idaho Power Company. On September 30, 1998, IDACORP filed a $300,000,000 shelf registration statement that can be used to issue Debt Securities, Common Stock or Preferred Stock. 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, 1998, and the related consolidated statements of income for the three and nine month periods ended September 30, 1998 and 1997 and consolidated statements of cash flows for the nine month periods ended September 30, 1998 and 1997. 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 making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with generally accepted auditing standards, 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 generally accepted accounting principles. We have previously audited, in accordance with generally accepted auditing standards, the consolidated balance sheet and statement of capitalization of Idaho Power Company and subsidiaries as of December 31, 1997, and the related consolidated statements of income, retained earnings, and cash flows for the year then ended (not presented herein); and in our report dated January 30, 1998, 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, 1997 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 November 2, 1998 Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS In Management's Discussion and Analysis we explain the general financial condition and results of operations for Idaho Power and its diversified business subsidiaries. As you read the Management's Discussion and Analysis, it may be helpful to refer to our Consolidated Statements of Income which present the results of our operations for the three-month and nine-month periods ended September 30, 1998 and 1997. In our discussion we explain the significant quarterly and year-to-date changes in the specific line items in the Consolidated Statements of Income. This discussion updates the discussion which was included in our 1997 Annual Report on Form 10-K for the year ended December 31, 1997, and should be read in conjunction with it. FORWARD-LOOKING INFORMATION Certain matters that we discuss in this report are "forward- looking statements" intended to qualify for the safe harbor from liability established by the Private Securities Litigation Reform Act of 1995. Such statements address future plans, objectives, expectations, and events or conditions concerning various matters such as capital expenditures, earnings, litigation, rate and other regulatory matters, liquidity and capital resources, accounting matters and includes statements under the heading "Other Matters" concerning the outcome of the Company's Year 2000 efforts. Actual results could differ materially from the results anticipated in such statements, for reasons including without limitations, electric utility restructuring, including ongoing state and federal legislative and regulatory activities; future economic conditions; competition; and other circumstances affecting anticipated rates, revenues and costs. With respect to the Company's Year 2000 efforts results could differ due to unanticipated developments while implementing the modifications necessary to mitigate Year 2000 compliance problems, including the ability to locate and correct all relevant computer codes in computer and embedded systems, the indirect impacts of third parties with whom the Company does business and who do not mitigate their Year 2000 compliance problems, and similar uncertainties. Any forward- looking statement speaks only as of the date on which such statement is made, and we undertake no obligation to update any forward-looking statement. RESULTS OF OPERATIONS Earnings Per Share and Book Value Earnings per share of common stock (basic and diluted) was $0.59 for the quarter ended September 30, 1998, an increase of $0.07 (13.5 percent) from the same quarter last year. Earnings per share (basic and diluted) was $1.88 for the nine months ended September 30, 1998, an increase of $0.07 (3.9 percent) over last year. At September 30, 1998, the book value per share of common stock was $19.41, compared to $18.40 at the same date in 1997. General Business Revenue Our general business revenue is dependent on many factors, including the number of customers we serve, the rates we charge, and weather conditions (temperature and precipitation) in our service territory. Compared to 1997, the number of general business customers we served increased 3.0 percent for the quarter and 2.9 percent for the nine months ended September 30, 1998. This increase was due primarily to economic growth in our service territory. Hotter than normal summer temperatures contributed to an increase in our energy sales during the quarter. Cooling degree days, a common measure used in the utility industry to analyze demand, were 35.4 percent above the same period in 1997 and 63.4 percent above normal. Compared to the same quarter last year, MWH's sold per general business customer increased 4.8 percent. For the year, warmer winter temperatures and increased rainfall during the growing season more than offset the hotter summer temperatures, resulting in a 1.7 percent decrease in sales per general business customer. Our revenue per MWH increased 10.4 percent for the quarter ended and 4.1 percent for the nine months ended September 30, 1998, compared to 1997. Revenue per MWH changes as a result of the annual rate adjustments discussed below in "Power Cost Adjustment." The combination of the factors just discussed resulted in a $24.0 million (19.1 percent) increase in general business revenue for the quarter and a $19.1 million (5.3 percent) increase year-to- date, compared to 1997. Off System Sales Off-system sales are comprised of trading in the wholesale electricity markets, long-term sales contracts, and opportunity sales made when we have surplus energy available. The increases in off-system revenue are due primarily to 83.9 percent and 110.8 percent increases in MWH sold in the third quarter and year-to- date, and to increased prices. The sales volume and price increases were primarily from trading in the wholesale electricity markets. We discuss our energy trading activity in more detail below in "Other Matters." Expenses Purchased power expenses increased $163.2 million (184.7 percent) for the quarter and $276.9 million (190.9 percent) year-to-date. These increases are due primarily to129.8 percent and 146.4 percent increases in MWHs purchased for the third quarter and year-to-date, and to increased prices. These purchases were primarily from trading in the wholesale electricity markets. Fuel expenses increased $2.3 million (10.1 percent) for the quarter and $12.0 million (25.1 percent) year-to-date, due primarily to 22.2 percent and 24.2 percent increases in MWHs generated by our coal-fired power plants for the quarter and year- to-date. Generation by these plants was increased to meet retail loads and take advantage of off-system sales opportunities. The PCA (power cost adjustment) component of expenses increased $5.6 million for the quarter and $18.9 million year-to-date. The PCA increases expenses when actual power supply costs are below the costs forecasted in the annual PCA filing and decreases expenses when actual power supply costs are above the forecast. In the third quarter of 1998, actual power supply costs were slightly above what had been forecast; in 1997 actual power supply costs were above the forecast to a greater degree. Year-to- date, power supply costs have been significantly below forecast in 1998, while they were somewhat above forecast in 1997. Our 1998 forecast anticipated near-normal streamflow conditions. Actual conditions have been better than forecasted. We discuss the PCA and streamflow conditions in more detail below in "Other Matters." Other operation expenses increased $4.4 million (4.4 percent) year-to-date. These increases were due primarily to increased administrative and labor expenses and a $1.2 million increase in transmission charges from other utilities. Maintenance expenses decreased $1.2 million (10.4 percent) for the quarter and $4.6 million (12.7 percent) year-to-date. These decreases are due primarily to decreased expenses at the Jim Bridger plant and reduced maintenance on overhead lines. During the first half of 1997 extensive maintenance was performed at the Bridger plant and on transmission lines. Other Other income increased $1.6 million (74.1 percent) for the three month period ended September 30 compared to the prior year. This increase is due primarily to $2.3 million of carrying charges on 1994-7 demand-side management (DSM) charges, offset by a $0.9 million increase in losses on gas trading activities. We began trading natural gas in the third quarter of 1997. Since then, trading volumes and related administrative costs have increased significantly. We discuss our energy trading activities in more detail below in "Other Matters." Income taxes increased $1.7 million (15.7 percent) for the quarter, due primarily to increased net income before taxes. Year-to-date income taxes decreased $1.5 million primarily from increased affordable housing tax credits and from adjustments associated with the settlement of prior year tax returns, offset by increased net income. LIQUIDITY AND CAPITAL RESOURCES Cash Flow For the nine months ended September 30, 1998, we generated $134.8 million in net cash from operations. After deducting for both common and preferred dividends, net cash generation from operations provided approximately $78.2 million for our construction program and other capital requirements. Cash Expenditures We estimate that our cash construction program for 1998 will require approximately $100.0 million. This estimate is subject to revision in light of changing economic, regulatory, environmental, and conservation factors. During the first nine months of 1998, we spent approximately $60.1 million for construction. Our primary financial commitments and obligations are related to contracts and purchase orders associated with ongoing construction programs. To the extent required, we expect to finance these commitments and obligations by using both internally generated funds and externally financed capital. At September 30, 1998, our short-term borrowings totaled $22.4 million. Financing Program We currently have a $200 million shelf registration statement that can be used for both First Mortgage Bonds (including Medium Term Notes) and Preferred Stock of which $83 million remains available at September 30, 1998. In September, 1998 we issued $60 million principal amount of Secured Medium Term Notes, 5.83% series, due September 9, 2005. The proceeds from this issuance were used to redeem $30 million of First Mortgage Bonds which matured in September 1998, and to reduce the balance of commercial paper issued in connection with ongoing business. Our objective is to maintain capitalization ratios of approximately 45 percent common equity, 5 to 10 percent preferred stock, and the balance in long-term debt. For the twelve-month period ended September 30, our consolidated pre-tax interest coverage was 3.30 times. OTHER MATTERS Holding Company On October 1, 1998, Idaho Power Company officially adopted a holding company structure with the completion of a statutory share exchange under which the outstanding common stock of Idaho Power was exchanged on a share-for-share basis for the common stock of IDACORP, Inc. (IDACORP) , and Idaho Power became a subsidiary of IDACORP. We had previously received approval to form the holding company from our shareholders, the state regulatory commissions in Idaho, Oregon, Nevada and Wyoming and the FERC. Following the share exchange, Idaho Power transferred ownership of three subsidiaries, Ida-West Energy Company (Ida-West), IDACORP Energy Solutions Co. (IES), and IDACORP Retail Enterprises Co. (IREC) to IDACORP. Shareholders of Idaho Power Company common stock will retain their current certificates and any new common stock issued on or after October 1, 1998 will be issued as IDACORP stock. Common shares will trade on the New York and Pacific Stock Exchanges under the existing symbol "IDA". Idaho Power Chairman and Chief Executive Officer (CEO) Joseph W. Marshall will serve as Chairman and CEO of IDACORP. Jan B. Packwood, Idaho Power President and Chief Operating Officer and J. LaMont Keen, Vice President, Chief Financial Officer and Treasurer will assume similar positions in IDACORP. Ida-West holds investments in 13 operating hydroelectric plants with a total generating capacity of 72 MW. IES, currently a shell, will conduct non-regulated marketing functions under the new holding company. IREC owns a 25% interest in Allied Utility Network, a Georgia-based limited liability company which develops and assists with the marketing of non-utility goods and services to retail customers. Our purpose in forming the holding company is to create a structure under which Idaho Power will continue as a regulated entity while allowing our unregulated operations to compete for business in the non-regulated environment. We anticipate that we will be transferring other Idaho Power subsidiaries and other non- utility operations to IDACORP in the near future. The formation of the holding company is discussed in more detail in the notes to the consolidated financial statements. Power Cost Adjustment We have 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 on May 16, are based on forecasts of net power supply costs. The difference between the actual costs incurred and the forecasted costs is deferred, with interest, and trued-up in the next annual rate adjustment. The May 16, 1998 adjustment increased rates $34.0 million over the 1997 rates and $17.3 million over base rates. The increase is due primarily to the forecasted return to more normal streamflow conditions from the near-record conditions experienced in 1997, and rising costs associated with mandatory purchases from CSPP projects The IPUC has requested that the treatment of mandatory purchases from certain CSPP projects be reviewed to determine if there is a way to avoid a large true-up which was a major factor in the 1998 increase. Regulatory Settlement Under the terms of an IPUC Settlement in effect though 1999, when earnings in our Idaho jurisdiction exceed an 11.75 percent return on year-end common equity, we refund 50 percent of the excess to our Idaho retail ratepayers. For 1997, we set aside $7.6 million of revenue for the benefit of these customers. The IPUC has ordered that approximately $5.0 million be applied against the balance of demand-side conservation expenditures in order to defer any rate increase associated with conservation recovery until May 16, 1999, the same time as the next PCA adjustment to rates. In October 1998 we filed an application requesting reimbursement for $2.4 in payments made in 1997 and 1998 to the Northwest Energy Efficiency Alliance. In this filing we asked that the reimbursement come out of the remaining revenue sharing funds. Demand-Side Management Expenses We are seeking changes to the regulatory treatment of previously deferred demand-side management (DSM) expenses in both Idaho and Oregon. In Idaho, we requested that the IPUC authorize recovery of post- 1993 DSM expenses and acceleration of the recovery of DSM expenditures authorized in the last general rate case. We requested a five-year amortization instead of the 24-year period previously adopted. In its Order No. 27660 issued on July 31, 1998, the IPUC set a new amortization period of 12 years. The IPUC order reflects an increase in annual revenue requirements of $3.1 million for 12 years. As noted above, we are funding the annual revenue requirement with revenue sharing amounts until May 16, 1999. A group of our industrial customers have filed a notice of appeal with the IPUC indicating that the companies are appealing the IPUC order to the Idaho Supreme Court. In Oregon, the OPUC authorized the amortization of the Oregon- allocated share of the DSM expenditures over five years. The OPUC allowed a rate surcharge for extraordinary purchases to be replaced by an identical charge to recover the amortization of the DSM expenditures. We anticipate that the charge will recover approximately $540,000 per year. Energy Trading We intend to be a competitive energy provider, including both electricity and natural gas. In 1997, we opened gas trading offices in Houston, Texas, to serve the southern and eastern United States and in Boise, Idaho to serve the Northwest and Canadian markets. We also actively participate in the western wholesale electricity markets, the results of which are included in off-system revenue and purchased power expense. (see "Off- system sales" and "Expenses"). Results of our gas trading activity are included in other income (see "Other"). Inherent in the energy trading business are risks related to market movements and the creditworthiness of counterparties. When buying and selling energy, the high volatility of energy prices can have a significant impact on profitability if not managed. Also, counterparty creditworthiness is key to ensuring that transactions entered into withstand dramatic market fluctuations. To mitigate these risks while implementing our business strategy, the Board of Directors gave approval for executive management to form a Risk Management Committee, comprised of company officers, to oversee a risk management program. The program is intended to minimize fluctuations in earnings while managing the volatility of energy prices. Embedded within the Risk Management policy and procedures is a credit policy requiring a credit evaluation of all counterparties before doing business with them. The objective of our risk management program is to mitigate commodity price risk, credit risk, and other risks related to the energy trading business. Streamflow Conditions We monitor the effect of streamflow conditions on Brownlee Reservoir, the water source for our three Hells Canyon hydroelectric projects. 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. During the April-July 1998 runoff period, inflows into Brownlee was 8.8 million acre-feet (MAF), compared to the 70-year median of 4.9 MAF and 1997's 9.8 MAF. Year 2000 Costs Many existing computer systems use only two digits to identify a year in the date field. These programs were designed and developed without considering the impact of the upcoming change in the century. Unless proper modifications are made, the program logic in many of these systems will start to produce erroneous results because, among other things, the systems will read the date "01/01/00" as being January 1 of the year 1900 or another incorrect date. In addition, the systems may fail to detect that the year 2000 is a leap year. Similar problems could arise prior to the year 2000 as dates in the next millennium are entered into systems which are not Year 2000 compliant. We recognize the Year 2000 problem as a serious threat to the Company and our customers. Our Year 2000 effort has been underway for over two years and is being addressed at the highest levels within the Company. The Vice President of Corporate Services is responsible for coordinating the corporate effort. Each vice president is responsible for addressing the problem within their respective business units and each has assigned a Year 2000 Project Leader to execute the project plan. In addition, we have appointed a full-time Year 2000 Project Manager to direct the project. Additional staff has been committed to complete the conversion and implementation needed to bring non- compliant items into compliance. This staff consists of a mix of end users, Information Services staff and contract programmers. Currently, there are over 20 full-time employees devoted to the project with dozens of others involved to varying degrees. We have retained third parties to conduct technical and legal audits of our plan to verify its adequacy. Our Year 2000 efforts include our subsidiaries. We have targeted July 1999 as the date by which we expect to be ready for the Year 2000. This means that all critical systems are expected to be capable of handling the century rollover and that we will be able to continue servicing our customers without interruption. It also means that all of the less critical systems are expected to have been identified and that contingency and/or repair plans are expected to be in place for dealing with the change of century. We are following a detailed project plan. The methodology is modeled after those used by some of the top companies in the world and has been adapted to meet our unique requirements. This process includes all the phases and steps commonly found in such plans, including the (i) identification and analysis of critical systems, key manufacturers, service providers, embedded systems, generation plants, (part of which is owned by the Company but is operated by another electric utility), (ii) remediation and testing, (iii) education and awareness and (iv) contingency planning. With respect to that key component of the methodology related to the identification of critical systems, we have identified those critical systems which must be Year 2000 compliant in order to continue operations. Many are already compliant or are in the process of vendor upgrades to become compliant. The largest of these critical systems and their status regarding compliance are set forth below: System Description Status Business The business systems include the PeopleSoft Systems financial and administrative and PassPort functions common to most companies. are both Business systems include accounts compliant payable, general ledger, accounts vendor receivable, labor entry, inventory, packages. purchasing, cash management, Testing is budgeting, asset management, underway to payroll, and financial reporting. verify compliance. Customer This system is used to bill In-house Information customers, log calls from customers system is System and create service or work requests currently and track them through completion, being among other things. At this time, repaired the Company uses an in-house with testing developed, mainframe-based Customer planned to Information System to accomplish start in these tasks. November 1998. Energy The most critical function the The packages Management Company offers is the delivery of comprising System electricity from the source to the the EMS are consumer. This must be done with largely compliant minimal interruption in the midst of and will be fully high demand, weather anomalies and compliant with a equipment failures. To accomplish release scheduled this, the Company relies on a server- for Fall of 1998 based energy management system and with operating provided by Landis & Gyr. This system and database system monitors and directs the upgrades already delivery of electricity throughout available. Testing the Company's service area. currently underway. Metering The Company relies on several In-house code is Systems processes for metering electricity currently being usage, including some hand-held repaired. Vendor devices with embedded chips. It is packages are critical for metering systems to being upgraded. operate without interruption so as Test plans have not to jeopardize the Company's been developed revenue stream. and are underway. Embedded There is a category of systems on Test bench Systems which the Company is highly reliant has been called embedded systems. These are established. typically computer chips that Testing is provide for automated operations about 20% within some device other than a complete. computer such as a relay or a security system. The Company is highly reliant on these systems throughout its generation and delivery systems to monitor and allow manual or automatic adjustments to the desired devices. Those devices with chips which are not Year 2000 compliant which affect the application of the device we replaced. Other The Company also relies on a number In various Systems of other important systems to stages of support engineering, human repair and resources, safety and regulatory testing. compliance, etc. Regarding third parties, the plan methodology has required us to identify those third parties with which we have a material relationship. We have identified as material (1) our ownership interest in thermal generating facilities which are operated and maintained by third party electric utilities; (2) our fuel suppliers for those thermal generating facilities; and (3) our telecommunication providers. In addition, we have identified ninety-three (93) key manufacturers which provide materials and supplies to us. With respect to the thermal plants, fuel suppliers and telecommunication providers, the plan methodology includes a process wherein some members of the Year 2000 team meet periodically with the third parties to assess the status of their efforts. This is an ongoing process and will continue until such time as the third party has completed compliance testing and certified to us that they are compliant. Regarding the 93 key manufacturers we have contacted all via mail and requested they complete a survey indicating the extent and status of their Year 2000 efforts. The survey is followed up with contact by telephone to further document their Year 2000 status. Finally, we are connected to an electric grid that connects utilities throughout the western portion of North America. This interconnection is essential to the reliability and operational integrity of each connected utility. This also means that failure of one electric utility in the interconnected grid could cause the failure of others. In the context of the Year 2000 problem, this interconnectivity compounds the challenge faced by the electric utility industry. Our Company could do a very thorough and effective job of becoming Year 2000 compliant and yet encounter difficulties supplying services and energy because another utility in the interconnected grid failed to achieve Year 2000 compliance. In this regard, we are working closely with other electric industry organizations concerned with reliability issues and technical collaboration. Our estimate of the cost of its Year 2000 plan remains at approximately $5.3 million. This includes costs incurred to date (approximately $700,000) and estimated costs through the year 2000. This level of expenditure is not expected to have any material effect on our operations or our financial position. Funds to cover Year 2000 costs in 1999 have been budgeted by business unit and within the Information Services Department with approximately 10 percent of the Information Services budget used for remediation. No information services department projects have been deferred due to the Company's year 2000 efforts. The Year 2000 issue poses risks to our internal operations due to the potential inability to carry on our business activities and from external sources due to the potential impact on the ability of our customers to continue their business activities. The major applications which pose the greatest risks internally are those systems, embedded or otherwise, which impact the generation, transmission and distribution of energy and the metering and billing systems. The potential risks related to these systems are electric service interruptions to customers and associated reduction in loads and revenue and interrupted data gathering and billing and the resultant delay in receipt of revenues. All of this would negatively impact our relationship with our customers which may enhance the likelihood of losing customers in a restructured industry. Externally, those customers which inadequately prepare for the Year 2000 issue may be unable to continue their business activities. This would affect us in a number of ways. Our loads and revenue would be reduced because of the lost load from discontinued business activities, and customers which lose jobs because of discontinued business activities may face difficulties in paying their power bills. The impact of this on us is dependent upon the number and the size of those businesses which are forced to discontinue business activities because of the Year 2000 issue. As part of its Year 2000 plan, we are in the process of developing a contingency plan and expect to complete this process on or before July 1999. New Accounting Pronouncements In June 1998 the FASB issued SFAS No. 133 Accounting for Derivative Instruments and Hedging Transactions. This statement establishes accounting and reporting standards for derivative financial instruments and other similar financial instruments and for hedging activities. It is effective for fiscal years beginning after June 15, 1999. We are reviewing this statement to determine its effects on our accounting and reporting requirements. PART II - OTHER INFORMATION Item 1. Legal Proceedings On November 30, 1995, a complaint entitled Idaho Power Company vs. Cogeneration, Inc.,Case No. 98467, was filed by the Company in the District Court of the Fourth Judicial District of the State of Idaho. The proceeding involves an effort by the Company to terminate a Firm Energy Sales Agreement (FESA) for a small hydroelectric generating plant. As required by PURPA and the orders of the Idaho Public Utilities Commission (IPUC), on January 7, 1992, the Company entered into a 35-year FESA with Cogeneration, Inc., to purchase the output of a 43-megawatt hydroelectric generating project known as the Auger Falls Project. The FESA for the Auger Falls Project was approved by the IPUC on January 27, 1992. The FESA required that on or before January 1, 1994, Cogeneration, Inc., post cash or cash equivalent security in the amount of approximately $1.9 million to assure performance of the FESA. Cogeneration, Inc., failed to provide the security amount. Consistent with the FESA, the Company filed a petition for declaratory order with the IPUC requesting that the FESA be terminated as a result of Cogeneration, Inc.'s breach. Cogeneration, Inc., cross petitioned claiming that its failure to perform was excused by the occurrence of an event of force majeure. On April 17, 1995, the IPUC issued its order finding that Cogeneration, Inc.'s failure to post the cash security on January 1, 1994, was a default under the FESA and further finding that the posting of the liquid security was required by the public interest. Based upon those findings, the IPUC ordered Cogeneration, Inc., to post the cash security prior to May 1, 1995. Cogeneration, Inc., failed to comply with the Commission's order and has never posted the $1.9 million amount required by the FESA. After the IPUC's order became final and non-appealable, the Company filed a complaint for declaratory relief in the District Court of the Fourth Judicial District. The Complaint sought a determination by the district court that Cogeneration, Inc.'s failure to provide the cash security and its violation of the IPUC's orders requiring that it expeditiously provide the cash security constituted material breaches of the FESA. The Company asked the district court to find that as a matter of law Idaho Power was entitled to either terminate or rescind the FESA. In response to the Company's complaint, Cogeneration, Inc., filed counterclaims alleging that the Company, by seeking to terminate the FESA, had breached the FESA and was attempting to monopolize the electric generation market and drive Cogeneration, Inc., out of business. Cogeneration, Inc., alleged damages for breach in excess of $50 million and requested that any damages be trebled under the anti-trust laws. On November 30, 1995, the district judge, by memorandum decision found that Cogeneration, Inc., had materially breached the FESA and the Company was entitled to either rescind or terminate the FESA. On February 16, 1996, Cogeneration, Inc., dismissed its anti- trust claims against the Company with prejudice, and on February 23, 1996, the Idaho Supreme Court granted Cogeneration, Inc.'s request for an expedited appeal of the district court's decision establishing an accelerated briefing schedule and scheduling oral argument for May 10, 1996. On August 12, 1996, the Idaho Supreme Court determined that the District Court's decision that Cogeneration, Inc., had breached the FESA was premature. On February 10, 1997, Cogeneration, Inc. filed an amended Complaint restating its previous claims, requesting a jury trial rather than the court trial it had previously requested and raising several new allegations and claims. Following a court trial, on June 24, 1998 the District Court issued a memorandum decision finding that Cogeneration, Inc. had materially breached the FESA and as a result Idaho Power had properly terminated the FESA. On July 27, 1998, Cogeneration, Inc., filed a Notice of Appeal with the Idaho Supreme Court. This matter has been previously reported in Form 10-K dated March 12, 1998 and other reports filed with the Commission. Item 6. Exhibits and Reports on Form 8-K (a) Exhibits: Exhibit File Number As Exhibit *2 1-3198 4(f) Agreement and Plan of Exchange, Form 10-K dated as of February 2, 1998. for 1997 *3(a) 33-00440 4(a)(xiii) Restated Articles of Incorporation of the Company 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), 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), as filed with the Secretary of State of Idaho on June 30, 1993. *3(b) 33-41166 4(b) Waiver resolution to Restated Articles of Incorporation adopted by Shareholders on May 1, 1991. *3(c) 33-00440 4(a)(xiv) By-laws of the Company amended on June 30, 1989, and presently in effect. *3(d) 33-56071 3(d) Articles of share exchange as filed with the Secretary of State of Idaho on September 29, 1998. *4(a)(i) 2-3413 B-2 Mortgage and Deed of Trust, dated as of October 1, 1937, between the Company and Bankers Trust Company and R. G. Page, as Trustees. *4(a)(ii) 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 16, 1993 1-3198 4 Thirty-fourth December 1, 1993 Form 8-K Dated 12/17/93 *4(b) Instruments relating to American Falls bond guarantee. (see Exhibit 10(c)). *4(c) 33-65720 4(f) Agreement 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) 33-65720 4(e) Rights Agreement dated January 11, 1990, between the Company and First Chicago Trust Company of New York, as Rights Agent (The Bank of New York, successor Rights Agent). *4(e)(i) 1-3198 4(e)(i) Amendment, dated as of January 30, Form 10-K 1998, related to agreement filed for 1997 as Exhibit 4(e). *10(a) 2-49584 5(b) Agreements, dated September 22, 1969, between the Company 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 the Company and Pacific Power & Light Company. *10(c)(i) 33-65720 10(c) Guaranty Agreement, dated March 1, 1990, between the Company 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, with Pacific Power & Light Company. *10(e) 2-56513 5(i) Letter Agreement, dated January 23, 1976, between the Company 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 the Company. *10(e)(ii) 2-62034 5(t) Amendment, dated September 30, 1977, relating to agreement filed as Exhibit 10(e). *10e)(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 the Company. *10(h)(i) 1 1-3198 10(n)(i) The Revised Security Plans for Form 10-K Senior Management Employees and for for 1994 Directors - a non-qualified, deferred compensation plan effective November 30, 1994. *10(h)(ii) 1 1-3198 10(n)(ii) The Executive Annual Incentive Plan Form 10-K for senior management employees for 1994 effective January 1, 1995. *10(h)(iii)1 1-3198 10(n)(iii) The 1994 Restricted Stock Plan for Form 10-K officers and key executives for 1994 effective July 1, 1994. *10(h)(iv) 1 1-3198 10(n)(iv) The Revised Security Plans for Form 10-K Senior Management Employees and for for 1996 Directors - a non-qualified, deferred compensation plan effective August 1, 1996. *10(i) 33-65720 10(h) Framework Agreement, dated October 1, 1984, between the State of Idaho and the Company relating to the Company'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 the Company 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 the Company 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 the Company 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 the Company 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. 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. 27 Financial Data Schedule (b) Reports on Form 8-K. No reports on Form 8-K were filed during the three month period ended September 30, 1998. *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. IDAHO POWER COMPANY (Registrant) Date November 6, 1998 By: /s/ J LaMont Keen J LaMont Keen Vice President, Chief Financial Officer and Treasurer Treasurer (Principal Financial Officer and Principal Accounting Officer) _______________________________ 1 Compensatory plan EX-12 2
Ex-12 Idaho Power Company Consolidated Financial Information Ratio of Earnings to Fixed Charges Twelve Months Twelve Months Ended December 31, Ended (Thousands of Dollars) September 30, 1993 1994 1995 1996 1997 1998 Computation of Ratio of Earnings to Fixed Charges: Consolidated net income..................... $84,464 $74,930 $86,921 $90,618 $92,274 $95,654 Income taxes: Income taxes (incl amounts charged to other income and deductions)............ 38,057 35,307 49,498 51,316 47,559 45,376 Investment tax credit adjustment............ (1,583) (1,064) (1,086) 776 (1,087) (376) Total income taxes.................... 36,474 34,243 48,412 52,092 46,472 45,000 Income before income taxes...................... 120,938 109,173 135,333 142,710 138,746 140,654 Fixed Charges: Interest on long-term debt................. 53,706 51,172 51,147 52,165 53,215 52,309 expense and premium - net.................. 507 567 567 594 653 652 Interest on short-term bank loans........... 220 1,157 3,144 2,269 2,902 2,939 Other interest.............................. 2,023 1,538 1,598 2,319 3,990 5,321 Interest portion of rentals................. 1,077 794 925 991 982 947 Total fixed charges................... 57,533 55,228 57,381 58,338 61,742 62,168 Earnings - as defined.......................... $178,471 $164,401 $192,714 $201,048 $200,488 $202,822 Ratio of earnings to fixed charges.............. 3.10x 2.98x 3.36x 3.45x 3.25x 3.26x Exhibit 12
EX-12 3
Ex-12a Idaho Power Company Consolidated Financial Information Supplemental Ratio of Earnings to Fixed Charges Twelve Months Twelve Months Ended December 31, Ended (Thousands of Dollars) September 30, 1993 1994 1995 1996 1997 1998 Computation of Ratio of Earnings to Fixed Charges: Consolidated net income..................... $84,464 $74,930 $86,921 $90,618 $92,274 $95,654 Income taxes: Income taxes (incl amounts charged to other income and deductions)............ 38,057 35,307 49,498 51,316 47,559 45,376 Investment tax credit adjustment............ (1,583) (1,064) (1,086) 776 (1,087) (376) Total income taxes.................... 36,474 34,243 48,412 52,092 46,472 45,000 Income before income taxes...................... 120,938 109,173 135,333 142,710 138,746 140,654 Fixed Charges: Interest on long-term debt................. 53,706 51,172 51,147 52,165 53,215 52,309 expense and premium - net.................. 507 567 567 594 653 652 Interest on short-term bank loans........... 220 1,157 3,144 2,269 2,902 2,939 Other interest.............................. 2,023 1,538 1,598 2,319 3,990 5,321 Interest portion of rentals................. 1,077 794 925 991 982 947 Total fixed charges................... 57,533 55,228 57,381 58,338 61,742 62,168 Supplemental increment to fixed charges* .. 2,631 2,622 2,611 2,600 2,574 2,576 Total supplemental fixed charges...... 60,164 57,850 59,992 60,938 64,316 64,744 Supplemental Earnings - as defined............. $181,102 $167,023 $195,325 $203,648 $203,062 $205,398 Supplemental Ratio of earnings to fixed charges 3.01x 2.89x 3.26x 3.34x 3.16x 3.17x * Explanation of increment: Interest on the guaranty of American Falls Reservoir District bonds and Milner Dam Inc. notes which are already included in operating expense. Exhibit 12-A
EX-12 4
Ex-12b Idaho Power Company Consolidated Financial Information Ratio of Earnings to Combined Fixed Charges and Preferred Dividends Requirements Twelve Months Twelve Months Ended December 31, Ended (Thousands of Dollars) September 30, 1993 1994 1995 1996 1997 1998 Computation of Ratio of Earnings to Fixed Charges: Consolidated net income..................... $84,464 $74,930 $86,921 $90,618 $92,274 $95,654 Income taxes: Income taxes (incl amounts charged to other income and deductions)............ 38,057 35,307 49,498 51,316 47,559 45,376 Investment tax credit adjustment............ (1,583) (1,064) (1,086) 776 (1,087) (376) Total income taxes.................... 36,474 34,243 48,412 52,092 46,472 45,000 Income before income taxes...................... 120,938 109,173 135,333 142,710 138,746 140,654 Fixed Charges: Interest on long-term debt................. 53,706 51,172 51,147 52,165 53,215 52,309 expense and premium - net.................. 507 567 567 594 653 652 Interest on short-term bank loans........... 220 1,157 3,144 2,269 2,902 2,939 Other interest.............................. 2,023 1,538 1,598 2,319 3,990 5,321 Interest portion of rentals................. 1,077 794 925 991 982 947 Total fixed charges................... 57,533 55,228 57,381 58,338 61,742 62,168 Preferred dividends requirements............ 8,547 10,682 12,392 12,146 7,803 8,675 Total fixed charges and preferred dividends............................ 66,080 65,910 69,773 70,484 69,545 70,843 Earnings - as defined.......................... $178,471 $164,401 $192,714 $201,048 $200,488 $202,822 Ratio of earnings to fixed charges and preferred dividends.......................... 2.70x 2.49x 2.76x 2.85x 2.88x 2.86x Exhibit 12-B
EX-12 5
Ex-12c Idaho Power Company Consolidated Financial Information Supplemental Ratio of Earnings to Combined Fixed Charges and Preferred Dividends Requirements Twelve Months Twelve Months Ended December 31, Ended (Thousands of Dollars) September 30, 1993 1994 1995 1996 1997 1998 Computation of Ratio of Earnings to Fixed Charges: Consolidated net income..................... $84,464 $74,930 $86,921 $90,618 $92,274 $95,654 Income taxes: Income taxes (incl amounts charged to other income and deductions)............ 38,057 35,307 49,498 51,316 47,559 45,376 Investment tax credit adjustment............ (1,583) (1,064) (1,086) 776 (1,087) (376) Total income taxes.................... 36,474 34,243 48,412 52,092 46,472 45,000 Income before income taxes...................... 120,938 109,173 135,333 142,710 138,746 140,654 Fixed Charges: Interest on long-term debt................. 53,706 51,172 51,147 52,165 53,215 52,309 expense and premium - net.................. 507 567 567 594 653 652 Interest on short-term bank loans........... 220 1,157 3,144 2,269 2,902 2,939 Other interest.............................. 2,023 1,538 1,598 2,319 3,990 5,321 Interest portion of rentals................. 1,077 794 925 991 982 947 Total fixed charges................... 57,533 55,228 57,381 58,338 61,742 62,168 Supplemental increment to fixed charges* .. 2,631 2,622 2,611 2,600 2,574 2,576 Supplemental fixed charges............ 60,164 57,850 59,992 60,938 64,316 64,744 Preferred dividends requirements............ 8,547 10,682 12,392 12,146 7,803 8,675 Total supplemental fixed charges and preferred dividends.............. 68,711 68,532 72,384 73,084 72,119 73,419 Supplemental Earnings - as defined............. $181,102 $167,023 $195,325 $203,648 $203,062 $205,398 Supplemental Ratio of earnings to fixed charges and preferred dividends.............. 2.64x 2.44x 2.70x 2.79x 2.82x 2.80x * Explanation of increment: Exhibit 12-C interest on the guaranty of American Falls District bonds and Milner Dam Inc. notes which are already included in operating expense.
EX-15 6 Exhibit 15 November 2, 1998 Idaho Power Company Boise, Idaho We have made a review, in accordance with standards established by the American Institute of Certified Public Accountants, of the unaudited interim financial information of Idaho Power Company and subsidiaries for the periods ended September 30, 1998 and 1997, as indicated in our report dated November 2, 1998; because we did not perform an audit, we expressed no opinion on that information. We are aware that our report referred to above, which is included in your Quarterly Report on Form 10-Q for the quarter ended September 30, 1998, is incorporated by reference in Idaho Power Company's Registration Statement No. 33-51215 on Form S-3, and IDACORP, Inc.'s Registration Statement Nos. 33-56071 and 333-65157 on Form S-8, Registration Statement No. 333-48031 on Form S-4, and Registration Statement Nos. 333-00139 and 333-64737 on Form S-3. We also are aware that the aforementioned report, pursuant to Rule 436(c) under the Securities Act of 1933, is not considered a part of the aforementioned registration statements prepared or certified by an accountant or a report prepared or certified by an accountant within the meaning of Sections 7 and 11 of that Act. DELOITTE & TOUCHE LLP Boise, Idaho EX-27 7
UT This schedule contains summary financial information extracted from (Balance sheets, income statements and cash flow statements) and is qualified in its entirety by reference to such financial statements. 1,000 9-MOS DEC-31-1997 SEP-30-1998 PER-BOOK 1,700,390 127,411 265,052 407,566 0 2,500,419 94,031 358,298 277,716 730,045 0 106,208 746,027 0 70,008 22,439 6,285 0 0 0 819,407 2,500,419 852,171 34,730 705,374 740,104 112,067 7,731 119,798 44,858 74,940 4,232 70,708 52,399 0 134,843 1.88 1.88
-----END PRIVACY-ENHANCED MESSAGE-----