-----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, TKDAvHCxC6tMBZavAv/mRHwKQUKkwaDQtFWCTGwk3PL+594sWSr8FOIltWm8lSBK 6Q2KPBpAEvoniF1DwyQbrw== 0000071932-98-000033.txt : 19980601 0000071932-98-000033.hdr.sgml : 19980601 ACCESSION NUMBER: 0000071932-98-000033 CONFORMED SUBMISSION TYPE: 10-Q/A PUBLIC DOCUMENT COUNT: 2 CONFORMED PERIOD OF REPORT: 19980331 FILED AS OF DATE: 19980529 SROS: NYSE FILER: COMPANY DATA: COMPANY CONFORMED NAME: NIAGARA MOHAWK POWER CORP /NY/ CENTRAL INDEX KEY: 0000071932 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC & OTHER SERVICES COMBINED [4931] IRS NUMBER: 150265555 STATE OF INCORPORATION: NY FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q/A SEC ACT: SEC FILE NUMBER: 001-02987 FILM NUMBER: 98634144 BUSINESS ADDRESS: STREET 1: 300 ERIE BLVD W CITY: SYRACUSE STATE: NY ZIP: 13202 BUSINESS PHONE: 3154741511 MAIL ADDRESS: STREET 1: 300 ERIE BLVD W CITY: SYRACUSE STATE: NY ZIP: 13202 FORMER COMPANY: FORMER CONFORMED NAME: CENTRAL NEW YORK POWER CORP DATE OF NAME CHANGE: 19710419 10-Q/A 1 SECURITIES AND EXCHANGE COMMISSION Washington, D. C. 20549 FORM 10-Q/A [ X ] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED MARCH 31, 1998 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 COMMISSION FILE NUMBER: 1-2987 NIAGARA MOHAWK POWER CORPORATION (Exact name of registrant as specified in its charter) STATE OF NEW YORK 15-0265555 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 300 ERIE BOULEVARD WEST SYRACUSE, NEW YORK 13202 (Address of principal executive offices) (Zip Code) (315) 474-1511 Registrant's telephone number, including area code 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. COMMON STOCK, $1 PAR VALUE, OUTSTANDING AT APRIL 30, 1998 - 144,419,351 NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES FORM 10-Q/A - For the Quarter Ended March 31, 1998 INDEX PART I. FINANCIAL INFORMATION ---------------------------------- Glossary of Terms Item 1. Financial Statements. a) Consolidated Statements of Income - Three Months Ended March 31, 1998 and 1997 b) Consolidated Balance Sheets - March 31, 1998 and December 31, 1997 c) Consolidated Statements of Cash Flows - Three Months Ended March 31, 1998 and 1997 d) Notes to Consolidated Financial Statements e) Review by Independent Accountants f) Independent Accountants' Report on the Limited Review of the Interim Financial Information Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations PART II. OTHER INFORMATION ------------------------------- Item 6. Exhibits and Reports on Form 8-K Signature Exhibit Index NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES - --------------------------------------------------------- GLOSSARY OF TERMS - ----------------- TERM DEFINITION - ---- ---------- Dth Dekatherm: one thousand cubic feet of gas with a heat content of 1,000 British Thermal Units per cubic foot EBITDA Earnings before interest charges, interest income, income taxes, depreciation and amortization, amortization of nuclear fuel, allowance for funds used during construction, non-cash regulatory deferrals and other amortizations, and extraordinary items. FAC Fuel Adjustment Clause: a clause in a rate schedule that provides for an adjustment to the customer's bill if the cost of fuel varies from a specified unit cost GAAP Generally Accepted Accounting Principles GWh Gigawatt-hours: one gigawatt equals one billion watt-hours IPP Independent Power Producer: any person that owns or operates, in whole or part, one or more Independent Power Facilities IPP Party Independent Power Producers that are a party to the MRA KWh Kilowatt-hour: a unit of electrical energy equal to one kilowatt of power supplied or taken from and electric circuit steadily for one hour MRA Master Restructuring Agreement - an agreement to terminate, restate or amend IPP Party power purchase agreements, including amendments thereto MRA Recoverable costs to terminate, restate or amend IPP Party Regulatory contracts, which will be deferred and amortized under Asset POWERCHOICE POWERCHOICE Company's five-year electric rate agreement, which incorporates agreement the MRA, approved by the PSC in an order dated March 20, 1998 PPA Power Purchase Agreement: long-term contracts under which a utility is obligated to purchase electricity from an IPP at specified rates NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES - --------------------------------------------------------- GLOSSARY OF TERMS - ----------------- TERM DEFINITION - ---- ---------- PRP Potentially Responsible Party PSC New York State Public Service Commission SFAS Statement of Financial Accounting Standards No. 71 No. 71 "Accounting for the Effects of Certain Types of Regulation" SFAS Statement of Financial Accounting Standards No. 121 No. 121 "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of" Unit 1 Nine Mile Point Nuclear Station Unit No. 1 Unit 2 Nine Mile Point Nuclear Station Unit No. 2 PART I - FINANCIAL INFORMATION - ------------------------------ ITEM 1. FINANCIAL STATEMENTS NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES CONSOLIDATED STATEMENT OF INCOME (UNAUDITED)
Three Months Ended March 31, 1998 1997 ---- ---- (In thousands of dollars) OPERATING REVENUES: Electric. . . . . . . . . . . . . . . . . . . . . . . . . . $ 863,169 $ 877,369 Gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . 235,235 286,463 ---------- ---------- 1,098,404 1,163,832 ---------- ---------- OPERATING EXPENSES: Fuel for electric generation. . . . . . . . . . . . . . . . 47,198 37,465 Electricity purchased . . . . . . . . . . . . . . . . . . . 324,350 328,803 Gas purchased . . . . . . . . . . . . . . . . . . . . . . . 115,452 148,631 Other operation and maintenance expenses. . . . . . . . . . 262,362 206,665 Depreciation and amortization . . . . . . . . . . . . . . . 87,950 84,222 Other taxes . . . . . . . . . . . . . . . . . . . . . . . . 126,795 126,109 ---------- ---------- 964,107 931,895 ---------- ---------- OPERATING INCOME. . . . . . . . . . . . . . . . . . . . . . . 134,297 231,937 Other income. . . . . . . . . . . . . . . . . . . . . . . . . 4,225 7,100 ---------- ---------- INCOME BEFORE INTEREST CHARGES. . . . . . . . . . . . . . . . 138,522 239,037 Interest charges. . . . . . . . . . . . . . . . . . . . . . . 65,590 67,538 ---------- ---------- INCOME BEFORE FEDERAL AND FOREIGN INCOME TAXES. . . . . . . . 72,932 171,499 Federal and foreign income taxes. . . . . . . . . . . . . . . 52,569 68,477 ---------- ---------- NET INCOME (Note 1) . . . . . . . . . . . . . . . . . . . . . 20,363 103,022 Dividends on preferred stock. . . . . . . . . . . . . . . . . 9,223 9,399 ---------- ---------- BALANCE AVAILABLE FOR COMMON STOCK. . . . . . . . . . . . . . $ 11,140 $ 93,623 ========== ========== Average number of shares of common stock outstanding (in thousands). . . . . . . . . . . . . . . . . . . . . . . . 144,419 144,389 BASIC AND DILUTED EARNINGS PER AVERAGE SHARE OF COMMON STOCK. $ 0.08 $ 0.65 The accompanying notes are an integral part of these financial statements
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES CONSOLIDATED BALANCE SHEETS
MARCH 31, 1998 December 31, (UNAUDITED) 1997 ----------- ----------- (In thousands of dollars) UTILITY PLANT: Electric plant. . . . . . . . . . . . . . . . . . $ 8,751,846 $ 8,752,865 Nuclear fuel. . . . . . . . . . . . . . . . . . . 583,639 577,409 Gas plant . . . . . . . . . . . . . . . . . . . . 1,131,482 1,131,541 Common plant. . . . . . . . . . . . . . . . . . . 319,146 319,409 Construction work in progress . . . . . . . . . . 420,299 294,650 ----------- ----------- Total utility plant. . . . . . . . . . . . . 11,206,412 11,075,874 Less - Accumulated depreciation and amortization. 4,308,748 4,207,830 ----------- ----------- Net utility plant. . . . . . . . . . . . . . 6,897,664 6,868,044 ----------- ----------- OTHER PROPERTY AND INVESTMENTS. . . . . . . . . . . 296,976 371,709 ----------- ----------- CURRENT ASSETS: Cash, including temporary cash investments of $379,920 and $315,708, respectively. . . . 436,256 378,232 Accounts Receivable (less allowance for doubtful accounts of $64,500 and $62,500 respectively) 578,488 492,244 Materials and supplies, at average cost: Coal and oil for production of electricity. . 22,440 27,642 Gas storage . . . . . . . . . . . . . . . . . 14,367 39,447 Other . . . . . . . . . . . . . . . . . . . . 124,923 118,308 Prepaid taxes . . . . . . . . . . . . . . . . . . 78,921 15,518 Other . . . . . . . . . . . . . . . . . . . . . . 10,733 20,309 ----------- ----------- 1,266,128 1,091,700 ----------- ----------- REGULATORY ASSETS (NOTE 3): Regulatory tax asset. . . . . . . . . . . . . . . 405,624 399,119 Deferred finance charges. . . . . . . . . . . . . 239,880 239,880 Deferred environmental restoration costs (Note 2) 220,000 220,000 Unamortized debt expense. . . . . . . . . . . . . 55,314 57,312 Postretirement benefits other than pensions . . . 55,524 56,464 Other . . . . . . . . . . . . . . . . . . . . . . 198,228 204,049 ----------- ----------- 1,174,570 1,176,824 ----------- ----------- OTHER ASSETS. . . . . . . . . . . . . . . . . . . . 72,245 75,864 ----------- ----------- $ 9,707,583 $ 9,584,141 =========== =========== The accompanying notes are an integral part of these financial statements
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES CONSOLIDATED BALANCE SHEETS
MARCH 31, 1998 December 31, (UNAUDITED) 1997 ----------- ---------- (In thousands of dollars) CAPITALIZATION: COMMON STOCKHOLDERS' EQUITY: Common stock - $1 par value; authorized 185,000,000 shares; issued 144,419,351 $ 144,419 $ 144,419 Capital stock premium and expense. . . . . . . . . . . . . . . . . . . . . . . 1,780,978 1,779,688 Retained earnings. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 814,560 803,420 ---------- ---------- 2,739,957 2,727,527 ---------- ---------- CUMULATIVE PREFERRED STOCK, AUTHORIZED 3,400,000 SHARES, $100 PAR VALUE: Non-redeemable (optionally redeemable), issued 2,100,000 shares. . . . . . . . 210,000 210,000 Redeemable (mandatorily redeemable), issued 222,000 shares . . . . . . . . . . 20,400 20,400 CUMULATIVE PREFERRED STOCK, AUTHORIZED 19,600,000 SHARES, $25 PAR VALUE: Non-redeemable (optionally redeemable), issued 9,200,000 shares. . . . . . . . 230,000 230,000 Redeemable (mandatorily redeemable), issued 2,581,204 shares . . . . . . . . . 56,210 56,210 ---------- ---------- 516,610 516,610 Long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,418,299 3,417,381 ---------- ---------- TOTAL CAPITALIZATION. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6,674,866 6,661,518 ---------- ---------- CURRENT LIABILITIES: Long-term debt due within one year . . . . . . . . . . . . . . . . . . . . . . . . 67,065 67,095 Sinking fund requirements on redeemable perferred stock. . . . . . . . . . . . . . 10,120 10,120 Accounts payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 227,564 263,095 Payable on outstanding bank checks . . . . . . . . . . . . . . . . . . . . . . . . 17,380 23,720 Customers' deposits. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18,689 18,372 Accrued taxes. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39,055 9,005 Accrued interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 76,573 62,643 Accrued vacation pay . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37,081 36,532 Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 119,997 64,756 ---------- ---------- 613,524 555,338 ---------- ---------- REGULATORY LIABILITIES (NOTE 3): Deferred finance charges . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 239,880 239,880 ---------- ---------- OTHER LIABILITIES: Accumulated deferred income taxes. . . . . . . . . . . . . . . . . . . . . . . . . 1,448,400 1,387,032 Employee pension and other benefits. . . . . . . . . . . . . . . . . . . . . . . . 240,526 240,211 Deferred pension settlement gain . . . . . . . . . . . . . . . . . . . . . . . . . 10,142 12,438 Unbilled revenues. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28,881 43,281 Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 231,364 224,443 ---------- ---------- 1,959,313 1,907,405 ---------- ---------- COMMITMENTS AND CONTINGENCIES (NOTES 2 AND 3): Liability for environmental restoration. . . . . . . . . . . . . . . . . . . . . . 220,000 220,000 ---------- ---------- $9,707,583 $9,584,141 ========== ========== The accompanying notes are an integral part of these financial statements
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES CONSOLIDATED STATEMENTS OF CASH FLOWS INCREASE (DECREASE) IN CASH (UNAUDITED)
THREE MONTHS ENDED MARCH 31, 1998 1997 ---- ---- (In thousands of dollars) CASH FLOWS FROM OPERATING ACTIVITIES: Net Income. . . . . . . . . . . . . . . . . . . . . . . . . . $ 20,363 $103,022 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization . . . . . . . . . . . . . . . 87,950 84,222 Amortization of nuclear fuel. . . . . . . . . . . . . . . . 8,461 7,526 Provision for deferred income taxes . . . . . . . . . . . . 54,863 21,288 Net accounts receivable . . . . . . . . . . . . . . . . . . (100,644) (30,895) Materials and supplies. . . . . . . . . . . . . . . . . . . 26,313 37,626 Accounts payable and accrued expenses . . . . . . . . . . . (31,949) (58,066) Accrued interest and taxes. . . . . . . . . . . . . . . . . 43,980 86,568 Changes in other assets and liabilities . . . . . . . . . . 17,886 (20,173) ---------- --------- NET CASH PROVIDED BY OPERATING ACTIVITIES. . . . . . . . . 127,223 231,118 ---------- --------- CASH FLOWS FROM INVESTING ACTIVITIES: Construction additions. . . . . . . . . . . . . . . . . . . . (123,518) (49,668) Nuclear fuel. . . . . . . . . . . . . . . . . . . . . . . . . (6,230) (2,445) ---------- --------- Acquisition of utility plant. . . . . . . . . . . . . . . . . (129,748) (52,113) Materials and supplies related to construction. . . . . . . . (2,646) 68 Accounts payable and accrued expenses related to construction (7,987) (14,517) Other investments . . . . . . . . . . . . . . . . . . . . . . 75,124 (6,258) Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6,070 (3,290) ---------- --------- NET CASH USED IN INVESTING ACTIVITIES. . . . . . . . . . . (59,187) (76,110) ---------- --------- CASH FLOWS FROM FINANCING ACTIVITIES: Reductions in long-term debt. . . . . . . . . . . . . . . . . - (3,300) Dividends paid. . . . . . . . . . . . . . . . . . . . . . . . (9,223) (9,399) Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . (789) (203) ---------- --------- NET CASH USED IN FINANCING ACTIVITIES. . . . . . . . . . . (10,012) (12,902) ---------- --------- NET INCREASE IN CASH. . . . . . . . . . . . . . . . . . . . . . 58,024 142,106 Cash at beginning of period . . . . . . . . . . . . . . . . . . 378,232 325,398 ---------- --------- CASH AT END OF PERIOD . . . . . . . . . . . . . . . . . . . . . $ 436,256 $467,504 ========== ========= SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION: Interest paid . . . . . . . . . . . . . . . . . . . . . . . . $ 54,774 $ 59,074 Income taxes paid . . . . . . . . . . . . . . . . . . . . . . $ 304 $ 11,470 The accompanying notes are an integral part of these financial statements
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS NOTE 1. UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS. Niagara Mohawk Power Corporation and subsidiary companies (the "Company"), in the opinion of management, has included all adjustments (which include normal recurring adjustments) necessary for a fair statement of the results of operations for the interim periods presented. The consolidated financial statements for 1998 are subject to adjustment at the end of the year when they will be audited by independent accountants. The consolidated financial statements and notes thereto should be read in conjunction with the financial statements and notes for the years ended December 31, 1997, 1996 and 1995 included in the Company's 1997 Annual Report on Form 10-K/A. The Company's electric sales tend to be substantially higher in summer and winter months as related to weather patterns in its service territory; gas sales tend to peak in the winter. Notwithstanding other factors, the Company's quarterly net income will generally fluctuate accordingly. Therefore, the earnings for the three-month period ended March 31, 1998, should not be taken as an indication of earnings for all or any part of the balance of the year. It is expected that the closing of the MRA and implementation of POWERCHOICE will result in substantially depressed earnings during its five-year term, but will substantially improve operating cash flows. Effective January 1, 1998, the Company adopted Statement of Financial Accounting Standards No. 130 "Reporting Comprehensive Income", which establishes standards for reporting comprehensive income. Comprehensive income is the change in the equity of a company, not including those changes that result from shareholder transactions. The Company's components of other comprehensive income relate to foreign currency translation adjustments and unrealized gains and losses associated with certain investments held as available for sale. Total comprehensive income for the three months ended March 31, 1998 and 1997 was $21.4 million and $100.5 million, respectively. Certain amounts have been reclassified on the accompanying Consolidated Financial Statements to conform with the 1998 presentation. NOTE 2. CONTINGENCIES ENVIRONMENTAL ISSUES: The public utility industry typically utilizes and/or generates in its operations a broad range of hazardous and potentially hazardous wastes and by-products. The Company believes it is handling identified wastes and by-products in a manner consistent with federal, state and local requirements and has implemented an environmental audit program to identify any potential areas of concern and aid in compliance with such requirements. The Company is also currently conducting a program to investigate and restore, as necessary to meet current environmental standards, certain properties associated with its former gas manufacturing process and other properties which the Company has learned may be contaminated with industrial waste, as well as investigating identified industrial waste sites as to which it may be determined that the Company contributed. The Company has also been advised that various federal, state or local agencies believe certain properties require investigation and has prioritized the sites based on available information in order to enhance the management of investigation and remediation, if necessary. The Company is currently aware of 126 sites with which it has been or may be associated, including 78 which are Company-owned. The number of owned sites increased as the Company has established a program to identify and actively manage potential areas of concern at its electric substations. This effort resulted in identifying an additional 32 sites. With respect to non-owned sites, the Company may be required to contribute some proportionate share of remedial costs. Although one party can, as a matter of law, be held liable for all of the remedial costs at a site, regardless of fault, in practice costs are usually allocated among PRPs. Investigations at each of the Company-owned sites are designed to (1) determine if environmental contamination problems exist, (2) if necessary, determine the appropriate remedial actions and (3) where appropriate, identify other parties who should bear some or all of the cost of remediation. Legal action against such other parties will be initiated where appropriate. After site investigations are completed, the Company expects to determine site-specific remedial actions and to estimate the attendant costs for restoration. However, since investigations are ongoing for most sites, the estimated cost of remedial action is subject to change. Estimates of the cost of remediation and post-remedial monitoring are based upon a variety of factors, including identified or potential contaminants; location, size and use of the site; proximity to sensitive resources; status of regulatory investigation and knowledge of activities at similarly situated sites. Additionally, the Company's estimating process includes an initiative where these factors are developed and reviewed using direct input and support obtained from the New York State Department of Environmental Conservation ("DEC"). Actual Company expenditures are dependent upon the total cost of investigation and remediation and the ultimate determination of the Company's share of responsibility for such costs, as well as the financial viability of other identified responsible parties since clean-up obligations are joint and several. The Company has denied any responsibility at certain of these PRP sites and is contesting liability accordingly. As a consequence of site characterizations and assessments completed to date and negotiations with PRPs, the Company has accrued a liability in the amount of $220 million, which is reflected in the Company's Consolidated Balance Sheets at March 31, 1998 and December 31, 1997. The potential high end of the range is presently estimated at approximately $650 million, including approximately $285 million in the unlikely event the Company is required to assume 100% responsibility at non-owned sites. The amount accrued at March 31, 1998 and December 31, 1997 incorporates the additional electric substations, previously mentioned, and a change in the method used to estimate the liability for 27 of the Company's largest sites to rely upon a decision analysis approach. This method includes developing several remediation approaches for each of the 27 sites, using the factors previously described, and then assigning a probability to each approach. The probability represents the Company's best estimate of the likelihood of the approach occurring using input received directly from the DEC. The probable costs for each approach are then calculated to arrive at an expected value. While this approach calculates a range of outcomes for each site, the Company has accrued the sum of the expected values for these sites. The amount accrued for the Company's remaining sites is determined through feasibility studies or engineering estimates, the Company's estimated share of a PRP allocation or where no better estimate is available, the low end of a range of possible outcomes. In addition, the Company has recorded a regulatory asset representing the remediation obligations to be recovered from ratepayers. POWERCHOICE provides for the continued application of deferral accounting for cost differences resulting from this effort. In October 1997, the Company submitted a draft feasibility study to the DEC, which included the Company's Harbor Point site and five surrounding non-owned sites. The study indicates a range of viable remedial approaches, however, a final determination has not been made concerning the remedial approach to be taken. This range consists of a low end of $22 million and a high end of $230 million, with an expected value calculation of $51 million, which is included in the amounts accrued at March 31, 1998 and December 31, 1997. The range represents the total costs to remediate the properties and does not consider contributions from other PRPs. The Company anticipates receiving comments from the DEC on the draft feasibility study by the summer of 1999. At this time, the Company cannot definitively predict the nature of the DEC proposed remedial action plan or the range of remediation costs it will require. While the Company does not expect to be responsible for the entire cost to remediate these properties, it is not possible at this time to determine its share of the cost of remediation. In May 1995, the Company filed a complaint, pursuant to applicable Federal and New York State law, in the U.S. District Court for the Northern District of New York against several defendants seeking recovery of past and future costs associated with the investigation and remediation of the Harbor Point and surrounding sites. The New York State Attorney General moved to dismiss the Company's claims against the State of New York, the New York State Department of Transportation and the Thruway Authority and Canal Corporation under the Comprehensive Environmental Response, Compensation and Liability Act. The Company opposed this motion. On April 3, 1998, the Court denied the New York State Attorney General's motion as it pertains to the Thruway Authority and Canal Corporation, and granted the motion relative to the State of New York and the Department of Transportation. The case management order presently calls for the close of discovery on December 31, 1998. As a result, the Company cannot predict the outcome of the pending litigation against other PRPs or the allocation of the Company's share of the costs to remediate the Harbor Point and surrounding sites. Where appropriate, the Company has provided notices of insurance claims to carriers with respect to the investigation and remediation costs for manufactured gas plant, industrial waste sites and sites for which the Company has been identified as a PRP. To date, the Company has reached settlements with a number of insurance carriers, resulting in payments to the Company of approximately $36 million, net of costs incurred in pursuing recoveries. Under POWERCHOICE the electric portion or approximately $32 million will be amortized over 10 years. The remaining portion relates to the gas business and is being amortized over the three year settlement period. TAX ASSESSMENTS: The Internal Revenue Service ("IRS") has conducted an examination of the Company's federal income tax returns for the years 1989 and 1990 and issued a Revenue Agents' Report. The IRS has raised an issue concerning the deductibility of payments made to IPPs in accordance with certain contracts that include a provision for a tracking account. A tracking account represents amounts that these mandated contracts required the Company to pay IPPs in excess of the Company's avoided costs, including a carrying charge. The IRS proposes to disallow a current deduction for amounts paid in excess of the avoided costs of the Company. Although the Company believes that any such disallowances for the years 1989 and 1990 will not have a material impact on its financial position or results of operations, it believes that a disallowance for these above-market payments for the years subsequent to 1990 could have a material adverse affect on its cash flows. To the extent that contracts involving tracking accounts are terminated or restated or amended under the MRA with IPP Parties as described in Note 3, the effects of any proposed disallowance would be mitigated with respect to the IPP Parties covered under the MRA. The Company is vigorously defending its position on this issue. The IRS is currently conducting its examination of the Company's federal income tax returns for the years 1991 through 1993. NOTE 3. RATE AND REGULATORY ISSUES AND CONTINGENCIES The Company's financial statements conform to GAAP, including the accounting principles for rate-regulated entities with respect to its regulated operations. As discussed below, the Company discontinued application of regulatory accounting principles to the Company's fossil and hydro generation business. Substantively, SFAS No. 71 permits a public utility, regulated on a cost-of-service basis, to defer certain costs which would otherwise be charged to expense, when authorized to do so by the regulator. These deferred costs are known as regulatory assets, which in the case of the Company are approximately $935 million, net of approximately $240 million of regulatory liabilities at March 31, 1998. These regulatory assets are probable of recovery. The portion of the $935 million which has been allocated to the nuclear generation and electric transmission and distribution business is approximately $811 million, which is net of approximately $240 million of regulatory liabilities. Regulatory assets allocated to the rate-regulated gas distribution business are $124 million. Generally, regulatory assets and liabilities were allocated to the portion of the business that incurred the underlying transaction that resulted in the recognition of the regulatory asset or liability. The allocation methods used between electric and gas are consistent with those used in prior regulatory proceedings. The Company concluded as of December 31, 1996, that the termination, restatement or amendment of IPP contracts and implementation of POWERCHOICE was the probable outcome of negotiations that had taken place since the POWERCHOICE announcement. Under POWERCHOICE, the separated non-nuclear generation business would no longer be rate-regulated on a cost-of-service basis and, accordingly, regulatory assets related to the non-nuclear power generation business, amounting to approximately $103.6 million ($67.4 million after tax or 47 cents per share) were charged against 1996 income as an extraordinary non-cash charge. The PSC, in its written order issued March 20, 1998 approving POWERCHOICE, determined to limit the estimated value of the MRA Regulatory Asset that can be recovered from customers to approximately $4 billion. The ultimate amount of the MRA Regulatory Asset to be established may vary based on certain events related to the closing of the MRA. The estimated value of the MRA Regulatory Asset includes the issuance of 42.9 million shares of common stock, which the PSC, in determining the recoverable amount of such asset, valued at $8 per share. Because the value of the consideration to be paid to the IPP Parties can only be determined at the MRA closing, the value of the limitation on the recoverability of the MRA Regulatory Asset is expected to be recorded as a charge to expense in the second quarter of 1998 with the closing of the MRA. The charge to expense will be determined by the difference between $8 per share and the Company's closing common stock price on the date the MRA closes, multiplied by 42.9 million shares. Using the Company's common stock price on March 26, 1998 of $12 7/16 per share, the charge to expense would be approximately $190 million (85 cents per share). As a result of amendments to the MRA dated April 22 and May 7, 1998, the amount of cash compensation to be paid to the IPP Parties was increased a net amount of approximately $15 million to $3.631 billion. The net increase in cash compensation was partly in exchange for net reductions in future payment obligations. The Company proposes , subject to PSC approval, to adjust the MRA Regulatory Asset as a consequence of the amendments. The amortization periods related to components of changes to the cash compensation will generally correspond to the changes in cash flow resulting from the amendments. The Company expects that the net amount of annual MRA Regulatory Asset amortization to be slightly higher in the period beyond POWERCHOICE. Under POWERCHOICE, the Company's remaining electric business (nuclear generation and electric transmission and distribution business) will continue to be rate-regulated on a cost-of-service basis and, accordingly, the Company continues to apply SFAS No. 71 to these businesses. Also, the Company's IPP contracts, including those restructured under the MRA, will continue to be the obligations of the regulated business. The EITF of the FASB reached a consensus on Issue No. 97-4 "Deregulation of the Pricing of Electricity - Issues Related to the Application of SFAS No. 71 and SFAS No. 101" in July 1997. As discussed previously, the Company discontinued the application of SFAS No. 71 and applied SFAS No. 101 with respect to the fossil and hydro generation business at December 31, 1996, in a manner consistent with EITF 97-4. EITF 97-4 does not require the Company to earn a return on regulatory assets that arise from a deregulating transition plan in assessing the applicability of SFAS No. 71. The Company believes that the regulated cash flows to be derived from prices it will charge for electric service over the next 10 years, including the Competitive Transition Charge ("CTC") assuming no unforeseen reduction in demand or bypass of the CTC or exit fees, will be sufficient to recover the MRA Regulatory Asset and to provide recovery of and a return on the remainder of its assets, as appropriate. In the event the Company could no longer apply SFAS No. 71 in the future, it would be required to record an after-tax non-cash charge against income for any remaining unamortized regulatory assets and liabilities. Depending on when SFAS No. 71 was required to be discontinued, such charge would likely be material to the Company's reported financial condition and results of operations and adversely effect the Company's ability to pay dividends. It is expected that the POWERCHOICE agreement, while having the effect of substantially depressing earnings during its five-year term, will substantially improve operating cash flows. With the implementation of POWERCHOICE, specifically the separation of non-nuclear generation as an entity that would no longer be cost-of-service regulated, the Company is required to assess the carrying amounts of its long-lived assets in accordance with SFAS No. 121. SFAS No. 121 requires long-lived assets and certain identifiable intangibles held and used by an entity to be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable or when assets are to be disposed of. In performing the review for recoverability, the Company is required to estimate future undiscounted cash flows expected to result from the use of the asset and/or its disposition. The Company has determined that there is no impairment of its fossil and hydro generating assets. To the extent the proceeds resulting from the sale of the fossil and hydro assets are not sufficient to avoid a loss, the Company would be able to recover such loss through the CTC. The POWERCHOICE agreement provides for deferral and future recovery of losses, if any, resulting from the sale of the non-nuclear generating assets. The Company believes that it will be permitted to record a regulatory asset for any such loss in accordance with EITF 97-4. The Company's fossil and hydro generation plant assets had a net book value of approximately $1.1 billion at March 31, 1998. As described in Form 10-K/A for fiscal year ended December 31, 1997, Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - "Master Restructuring Agreement and the POWERCHOICE Agreement," the conclusion of the termination, restatement or amendment of IPP contracts, and closing of the financing necessary to implement such termination, restatement or amendment, as well as implementation of POWERCHOICE, is subject to a number of contingencies. In the event the Company is unable to successfully bring these events to conclusion, it is likely that application of SFAS No. 71 would be discontinued. The resulting non-cash after-tax charges against income, based on regulatory assets and liabilities associated with the nuclear generation and electric transmission and distribution businesses as of March 31, 1998, would be approximately $527 million or $3.65 per share. Various requirements under applicable law and regulations and under corporate instruments, including those with respect to issuance of debt and equity securities, payment of common and preferred dividends and certain types of transfers of assets could be adversely impacted by any such write-downs. NOTE 4. ADJUSTMENT OF FINANCIAL STATEMENTS FOR THE QUARTER ENDED MARCH 31, 1998 On May 29, 1998, after discussion with the Staff of the Securities and Exchange Commission, the Company determined that the $190 million limitation on the recoverability of the MRA regulatory asset, as discussed in Note 3 - Rate and Regulatory Issues and Contingencies, should be charged to expense in the quarter in which the MRA closes. Accordingly, the 1997 financial statements have been restated to eliminate this charge and the Company expects that the second quarter 1998 financial statements will reflect such $190 million charge. NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES REVIEW BY INDEPENDENT ACCOUNTANTS The Company's independent accountants, Price Waterhouse LLP, have made limited reviews (based on procedures adopted by the American Institute of Certified Public Accountants) of the unaudited Consolidated Balance Sheet of Niagara Mohawk Power Corporation and Subsidiary Companies as of March 31, 1998 and the unaudited Consolidated Statements of Income and Cash Flows for the three-month periods ended March 31, 1998 and 1997. The accountants' report regarding their limited reviews of the Form 10-Q of Niagara Mohawk Power Corporation and its subsidiaries appears on the next page. That report does not express an opinion on the interim unaudited consolidated financial information. Price Waterhouse LLP has not carried out any significant or additional audit tests beyond those which would have been necessary if their report had not been included. Accordingly, such report is not a "report" or "part of the Registration Statement" within the meaning of Sections 7 and 11 of the Securities Act of 1933 and the liability provisions of Section 11 of such Act do not apply. REPORT OF INDEPENDENT ACCOUNTANTS To the Stockholders and Board of Directors of Niagara Mohawk Power Corporation 300 Erie Boulevard West Syracuse, NY 13202 We have reviewed the condensed consolidated balance sheet of Niagara Mohawk Power Corporation and its subsidiaries as of March 31, 1998 and the related condensed consolidated statements of income and of cash flows for the three-month periods ended March 31, 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 the condensed consolidated financial statements referred to above for them to be in conformity with generally accepted accounting principles. We previously audited in accordance with generally accepted auditing standards, the consolidated balance sheet as of December 31, 1997, and the related consolidated statements of income, of retained earnings and of cash flows for the year then ended (not presented herein), and in our report dated March 26, 1998, we expressed an unqualified opinion (containing explanatory paragraphs with respect to the Company's application of Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain Types of Regulation" [SFAS No. 71] for its nuclear generation, electric transmission and distribution and gas businesses and discontinuation of SFAS No. 71 for its non-nuclear generation business in 1996). In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 1997, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived. As discussed in Note 4 to the accompanying financial statements, the Company has restated its 1997 financial statements to eliminate the $190 million charge related to the limitation on the recoverability of the regulatory asset described in Note 3. As discussed in Note 3, the Company believes that it continues to meet the requirements for application of SFAS No. 71 for its nuclear generation, electric transmission and distribution and gas businesses. In the event that the Company is unable to complete the termination, restatement or amendment of independent power producer contracts, this conclusion could change in 1998 and beyond, resulting in material adverse effects on the Company's financial condition and results of operations. /s/ Price Waterhouse LLP PRICE WATERHOUSE LLP SYRACUSE NY May 14, 1998, except Note 3 (third paragraph) and Note 4, as to which the date is May 29, 1998 ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Certain statements included in this Quarterly Report on Form 10-Q are forward-looking statements as defined in Section 21E of the Securities Exchange Act of 1934, including the improvement in the Company's financial condition expected as a result of the MRA and the implementation of POWERCHOICE. The Company's actual results and developments may differ materially from the results discussed in or implied by such forward-looking statements, due to risks and uncertainties that exist in the Company's operations and business environment, including, but not limited to, matters described in the context of such forward-looking statements, as well as such other factors as set forth in the Notes to Consolidated Financial Statements contained herein. MASTER RESTRUCTURING AGREEMENT AND POWERCHOICE AGREEMENT (See Form 10-K/A for fiscal year ended December 31, 1997, Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - "Master Restructuring Agreement and the POWERCHOICE Agreement.") MASTER RESTRUCTURING AGREEMENT. The MRA was amended to decrease the cash payable to the IPP Parties by approximately $157 million in exchange for agreed-upon price increases in certain restated IPP contracts. Only one IPP, NorCon Power Partners, L.P. ("NorCon"), has withdrawn from the MRA. The withdrawal of NorCon will reduce the cash payable by the Company at closing by approximately $158 million. The Company is currently assessing its possible actions with respect to Norcon's contract. The Company has also determined to replace the fixed price swap contracts originally contemplated by the MRA with an additional $297 million of cash compensation to the IPP Parties. The MRA currently provides for the termination, restatement or amendment of 27 PPAs with 14 IPPs, which represent approximately three quarters of the Company's over-market purchased power obligations, in exchange for an aggregate of approximately $3.631 billion in cash and 42.9 million shares of the Company's common stock. The closing of the MRA is subject to certain conditions, including the successful financing of the MRA and Company shareholder approval of the issuance of common stock to the IPP Parties. Norcen Energy Resources, Ltd. ("Norcen"), a gas supplier, sued three IPPs that are party to the MRA and the Company, as to which litigation a settlement agreement has been reached (see Form 10-K, Part II, Item 1. Legal Proceedings - "Norcen Litigation"). POWERCHOICE AGREEMENT. The PSC in its written order issued March 20, 1998 limited the estimated value of the MRA regulatory asset that can be recovered from customers to approximately $4,000 million. The ultimate amount of the regulatory asset to be established may vary based on certain events related to the closing of the MRA. The estimated value of the MRA regulatory asset includes the issuance of 42.9 million shares of common stock, which the PSC, in determining the recoverable amount of such asset valued at $8 per share. Because the value of the consideration to be paid to the IPP Parties can only be determined at the MRA closing, the value of the limitation on the recoverability of the MRA regulatory asset is expected to be recorded as a charge to expense in the second quarter of 1998 with the closing of the MRA. The charge to expense will be determined by the difference between $8 per share and the Company's closing common stock price on the date the MRA closes, multiplied by 42.9 million shares. Using the Company's common stock price on March 26, 1998 of $12 7/16 per share, the charge to expense would be approximately $190 million (85 cents per share). In April 1998, the cities of Oswego, Fulton, Cohoes and the New York Conference of Mayors and Municipal Officials sought a temporary restraining order and preliminary injunction in New York State Supreme Court against the PSC to enjoin the implementation of the POWERCHOICE settlement, the MRA and the Company's contemplated auction of its fossil and hydro generation assets on the grounds that the PSC failed to comply with the provisions of the State Environmental Quality Review Act. They were joined in their petition by the chairman of the Buffalo City Council Energy Committee (see Form 10-K, Part II, Item 1. Legal Proceedings - "City of Oswego Litigation"). In addition, the City of Oswego and others petitioned the PSC for rehearing of the March 20, 1998 Order approving POWERCHOICE. The Company is unable to predict the outcome or timing of this matter. In its written order dated May 6, 1998, the PSC approved the Company's plan to divest its fossil and hydroelectric generating plants, which is a key component in the Company's POWERCHOICE plan to lower average electricity prices and provide customer choice. The Company has begun distributing information about the plants to interested bidders and is reviewing potential buyers for appropriate financial qualifications. The Company expects to begin receiving non-binding bids in June 1998. Final bids are expected in September 1998 and definitive agreements will be completed shortly thereafter. Transaction closings are anticipated to occur in mid-1999. JANUARY 1998 ICE STORM In early January 1998, a major ice storm and flooding caused extensive damage in a large area of northern New York. The Company's electric transmission and distribution facilities in an area of approximately 7,000 square miles were damaged, interrupting service to approximately 120,000 of the Company's customers, or approximately 300,000 people. The Company had to rebuild much of its transmission and distribution system to restore power in this area. By the end of January 1998, service to all customers was restored. The total estimated cost of the restoration and rebuild efforts is approximately $131 million. As of March 1998, the Company recorded $70.2 million in expense associated with the January 1998 ice storm (of which $62.9 million was considered incremental) and $61.2 million was capitalized. The Company is continuing to inspect and survey the work completed and these efforts may impact the allocation of costs between capital and expense. The Company continues to pursue federal disaster relief assistance and is working with its insurance carriers to assess what portion of the rebuild costs are covered by insurance policies. The Company is also analyzing potential available options for state financial aid. The Company is unable to determine what recoveries, if any, it may receive from these sources. While these efforts are continuing, the fact that the Company has not recovered any amounts to date required a charge to first-quarter earnings. NUCLEAR MATTERS UNIT 1 OUTAGE. On April 28, 1998, Unit 1 was taken out of service to fix design deficiencies related to the control room emergency ventilation system. Unit 1 is expected to return to service by early June 1998. UNIT 2 OUTAGE. On May 2, 1998, Unit 2 was taken out of service for a planned refueling and maintenance outage. Based on progress to date, Unit 2 is scheduled to return to service, mid-June 1998. DISPOSAL OF NUCLEAR FUEL. (See Form 10-K/A for fiscal year ended December 31, 1997, Part II, Item 8. Financial Statements and Supplementary Data - "Note 3. Nuclear Operations - Nuclear Fuel Disposal Cost.") In April 1998, the U.S. Senate passed legislation to reform the federal government's spent nuclear fuel disposal policy. Such legislation requires the Department of Energy to accept spent nuclear fuel from nuclear power plants beginning no later than June 30, 2003, if all necessary approvals are obtained. In addition, it requires the payment of one-time fees by electric utilities for the disposal of nuclear fuel irradiated prior to 1983 to be paid to the Nuclear Waste Fund no later than September 30, 2001. As of March 31, 1998, the Company has recorded a liability of $115.9 million for the disposal of nuclear fuel irradiated prior to 1983. The Company is unable to predict whether this bill will be enacted into law. PSC STAFF'S TENTATIVE CONCLUSIONS ON THE FUTURE OF NUCLEAR GENERATION. (See Form 10-K/A for fiscal year ended December 31, 1997, Part II, Item 8. Financial Statements and Supplementary Data - "Note 3. Nuclear Operations - PSC Staff's Tentative Conclusions on the Future of Nuclear Generation.") In late March 1998, the PSC issued an Opinion and Order Instituting Further Inquiry. The order concluded that a more extensive examination is required to address all issues regarding the future treatment of nuclear generation brought forth by the PSC staff and other parties. GENERIC GAS RESTRUCTURING PROCEEDING As a result of the generic restructuring proceeding, in which the PSC ordered all New York utilities to implement a service unbundling beginning in May 1996, nearly 3,200 customers have chosen to buy natural gas from other sources, with the Company continuing to provide transportation service for a separate fee. These changes have not had a material impact on the Company's margins since the margin is traditionally derived from the delivery service and not from the commodity sale. The margin for delivery for residential and commercial aggregation services approximately equals the margin on the traditional sales service classes. To date the PSC has allowed the utilities to assign the pipeline capacity to the customers converting from sales to transportation. This assignment is allowed during a three-year period ending March 1999, by which time the PSC will decide on methods for dealing with the remaining unassigned or excess capacity. In a clarifying order in the generic restructuring proceeding, issued September 4, 1997, the PSC indicated that it is unlikely that utilities will be allowed to continue to assign pipeline capacity to departing customers after March, 1999. As a part of the generic restructuring proceeding, all utilities were required to file a report with the PSC in April 1998, describing actions that have been taken to mitigate potential stranded costs as customers migrate to transportation service. The Company filed a report on March 31, 1998, that noted that it has taken numerous actions to reduce its capacity obligations and its potential stranded costs to the maximum extent possible. The Company's actions include the following: 1) The Company has not entered into any new upstream capacity contracts; 2) The Company has provided notice of termination with respect to firm upstream capacity contracts that have reached their notification date (the total capacity under such contracts is 96,101 Dth per day); 3) All opportunities to reduce capacity contracts continue to be exercised by the Company; 4) Active participation in programs to remarket or release its existing capacity, where those programs do not provide full reimbursement of the Company's costs; 5) Active participation in open seasons offered by the interstate pipelines to return capacity prior to the termination date of the contract; and 6) Expansion of the Company's service territory by obtaining new franchises to serve areas not previously served. The Company is unable to determine the timing or outcome of this proceeding. FINANCIAL POSITION The Company's EBITDA for the twelve months ended March 31, 1998, was approximately $859.7 million, and upon implementation of the MRA and POWERCHOICE is expected to increase to approximately $1.2 billion to $1.3 billion per year. EBITDA represents earnings before interest charges, interest income, income taxes, depreciation and amortization, amortization of nuclear fuel, allowance for funds used during construction, non-cash regulatory deferrals and other amortizations, and extraordinary items. EBITDA is a non-GAAP measure of cash flows and is presented to provide additional information about the Company's ability to meet its future requirements for debt service which would increase significantly upon consummation of the MRA. EBITDA should not be considered an alternative to net income as an indicator of operating performance or as an alternative to cash flows, as presented on the Consolidated Statement of Cash Flows, as a measure of liquidity. LIQUIDITY AND CAPITAL RESOURCES Under the MRA, the Company will pay an aggregate of $3.631 billion in cash. The Company now expects to obtain $3.272 billion of this amount through a public market offering of senior unsecured debt and the remainder from cash on hand. The Company is unable to issue incremental first mortgage bonds under the terms of the public debt offering. The Company plans to amend its existing $804 million bank facility to, among other things, extend the term from June 30, 1999 to June 1, 2000 and accommodate the holding company restructuring and permit the auction of fossil/hydro generating assets. NET CASH PROVIDED BY OPERATING ACTIVITIES decreased $103.9 million in the first quarter of 1998 primarily due to a decrease of $98.7 million in the amount of accounts receivable sold under the accounts receivable sales program (which the Company has budgeted to restore in 1998). NET CASH USED IN INVESTING ACTIVITIES decreased $16.5 million in the first quarter of 1998 primarily as a result of a decrease in other investments of $81.4 million offset by an increase in the acquisition of utility plant of $77.6 million, primarily due to the January 1998 ice storm. RESULTS OF OPERATIONS Three Months Ended March 31, 1998 versus Three Months Ended March 31, 1997 - -------------------------------------------------------------------------- The following discussion presents the material changes in results of operations for the first quarter of 1998 in comparison to the same period in 1997. The Company's quarterly results of operations reflect the seasonal nature of its business, with peak electric loads in summer and winter periods. Gas sales peak principally in the winter. The earnings for the three month period should not be taken as an indication of earnings for all or any part of the balance of the year. In addition, this discussion and analysis is not likely to be indicative of future operations or earnings, particularly in view of the probable termination, restatement or amendment of IPP contracts and implementation of POWERCHOICE. It should also be read in conjunction with other financial and statistical information appearing elsewhere in this report. Earnings for the first quarter were $11.1 million or 8 cents per share, as compared with $93.6 million or 65 cents per share for the first quarter of 1997. Earnings for the first quarter of 1998 reflect the write-off of $62.9 million, or 28 cents per share, to reflect the Company's estimate of incremental, non-capitalized costs to restore power and rebuild its electric system in northern New York as a result of the January 1998 ice storm (see "January 1998 Ice Storm"). First quarter 1998 earnings were also lower by approximately 14 cents per share due to a higher allocation of federal income taxes in this period reflecting the expected lower level of earnings over the remainder of the year. In addition, first quarter 1998 earnings were also lower due to warmer weather, higher capacity payments to IPPs and higher industrial customer discounts. ELECTRIC REVENUES Electric revenues decreased $14.2 million or 1.6% from 1997 primarily as a result of a decrease in volume and mix of sales to ultimate customers of $25.5 million, offset by an increase in sales to other electric systems and miscellaneous electric revenues of $11.3 million. ELECTRIC SALES Electric sales to ultimate consumers were approximately 8.7 billion KWh in the first quarter of 1998, a 1.1% decrease from 1997 primarily as a result of warmer weather and the power outages during the January 1998 ice storm (see "January 1998 Ice Storm"). Residential and commercial sales declined 4.9% and 1.1%, respectively. After adjusting for the effects of weather and the farm and food processor retail access pilot program, sales to ultimate consumers would have been expected to increase 0.9%. Sales for resale increased 204 million KWh (17.2%), reflecting sales to energy service companies participating in the Company's farm and food processor retail access pilot program. This resulted in a net increase in total electric sales of 106 million KWh (1.1%).
THREE MONTHS ENDED MARCH 31, Electric Revenue (Thousands) Sales (GWh) ----------------------------- ---------------------- % % 1998 1997 Change 1998 1997 Change --------- --------- ------- ------ ----- ------- Residential. . . . . . $ 336,434 $ 352,919 (4.7) 2,737 2,877 (4.9) Commercial . . . . . . 310,038 314,291 (1.4) 2,956 2,988 (1.1) Industrial . . . . . . 123,470 129,943 (5.0) 1,743 1,738 0.3 Industrial - Special . 15,977 14,922 7.1 1,162 1,099 5.7 Other. . . . . . . . . 14,576 13,888 5.0 70 64 9.4 --------- --------- ------- ------ ----- ------- Total to Ultimate Consumers 800,495 825,963 (3.1) 8,668 8,766 (1.1) Other Electric Systems 32,923 23,949 37.5 1,387 1,183 17.2 Miscellaneous. . . . . 29,751 27,457 8.4 - - - --------- --------- ------- ------ ----- ------- Total. . . . . . . . . $ 863,169 $ 877,369 (1.6) 10,055 9,949 1.1 ========= ========= ======= ====== ===== =======
Electric fuel and purchased power costs increased $5.3 million or 1.4%. This increase is the result of an $8.7 million increase in actual fuel costs, a $0.1 million increase in payments to IPPs and a $2.7 million increase in costs deferred and recovered through the operation of the FAC, partially offset by a decrease in other purchased power costs of $6.2 million. Internal generation increased in 1998, reflecting the full operation of the Company's nuclear power plants in the first quarter of 1998 as compared to 1997. On March 3, 1997, Unit 1 was taken out of service for a planned refueling and maintenance outage and was returned to service on May 8, 1997. GAS REVENUES Gas revenues decreased $51.2 million or 17.9% in 1998 from the comparable period in 1997, primarily as a result of lower purchased gas adjustment clause revenues of $26.9 million and a decrease in sales to ultimate consumers of $24.3 million. GAS SALES Due primarily to warmer weather during the first quarter of 1998, gas sales to ultimate consumers decreased 4.0 million Dth or 10.8% from the first quarter of 1997. After adjusting for the effects of weather, sales to ultimate consumers decreased 6.5% primarily due to the migration of certain large commercial sales customers to the transportation class and lower customer usage. Spot market sales (sales for resale), which are generally from the higher priced gas available to the Company and therefore yield margins that are substantially lower than traditional sales to ultimate consumers, also decreased as the warm weather depressed spot sales opportunities. In addition, changes in purchased gas adjustment clause revenues are generally margin-neutral.
THREE MONTHS ENDED MARCH 31, Gas Revenue (Thousands) Sales (Thousands of Dth) ----------------------------- ----------------------- % % 1998 1997 Change 1998 1997 Change --------- --------- ------- ------ ------ ------- Residential. . . . . . $ 160,664 $ 188,687 (14.9) 23,820 25,764 (7.5) Commercial . . . . . . 55,053 72,500 (24.1) 8,862 10,540 (15.9) Industrial . . . . . . 1,546 3,412 (54.7) 306 678 (54.9) --------- --------- ------- ------ ------ ------- Total to Ultimate Consumers 217,263 264,599 (17.9) 32,988 36,982 (10.8) Transportation of Customer-Owned Gas . . 16,685 15,313 9.0 42,297 41,702 1.4 Spot Market Sales. . . 38 3,082 (98.8) 15 1,088 (98.6) Miscellaneous. . . . . 1,249 3,469 (64.0) - - --------- --------- ------- ------ ------ Total to System Core Customers . $ 235,235 $ 286,463 (17.9) 75,300 79,772 (5.6) ========= ========= ======= ====== ====== =======
The total cost of gas included in expense decreased 22.3% in 1998. This was the result of a 5.8 million decrease in Dth purchased and withdrawn from storage for ultimate consumer sales ($20.1 million), a $3.0 million decrease in Dth purchased for spot market sales, a $0.7 million decrease in purchased gas costs and certain other items recognized and recovered through the purchased gas adjustment clause and an 8.3% decrease in the average cost per Dth purchased ($9.4 million). The Company's net cost per Dth sold, as charged to expense and excluding spot market purchases, decreased to $3.56 in 1998 from $3.82 in 1997. OTHER OPERATION AND MAINTENANCE EXPENSES increased by $55.7 million primarily as a result of the write-off of the costs associated with the January 1998 ice storm (see "January 1998 Ice Storm"). BAD DEBT EXPENSE for the first quarter of 1998 was $16.0 million as compared with $21.3 million in 1997. The decrease in FEDERAL AND FOREIGN INCOME TAXES of approximately $15.9 million was primarily due to a decrease in pre-tax income, partially offset by a higher percentage allocation of federal income taxes to the first quarter of 1998, reflecting the expected lower level of earnings over the remainder of the year. The effective tax rate for the first quarter of 1998 was 72% as compared to 40% for the first quarter of 1997. This increase is caused by the allocation of certain flow through tax adjustments. NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES PART II - OTHER INFORMATION --------------------------- ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K. (a) Exhibits: Exhibit 3(i) - By-laws of the Company, as amended April 23, 1998. Exhibit 10 - Employment Agreement between the Company and John H. Mueller, dated January 19, 1998, incorporated herein by reference to the Company's Annual Report on Form 10-K for fiscal year ended December 31, 1997. Exhibit 10(b) - PSC Opinion and Order regarding approval of the POWERCHOICE settlement agreement with the PSC, issued and effective March 20, 1998, incorporated herein by reference to the Company's Annual Report on Form 10-K for fiscal year ended December 31, 1997. Exhibit 10(c) - Amendments to the Master Restructuring Agreement. Exhibit 11 - Computation of the Average Number of Shares of Common Stock Outstanding for the Three Months Ended March 31, 1998 and 1997. Exhibit 12 - Statement Showing Computations of Ratio of Earnings to Fixed Charges, Ratio of Earnings to Fixed Charges without Allowance for Funds Used During Construction ("AFC") and Ratio of Earnings to Fixed Charges and Preferred Stock Dividends for the Twelve Months Ended March 31, 1998. Exhibit 15 - Accountants' Acknowledgement Letter. Exhibit 27 - Financial Data Schedule. In accordance with Paragraph 4(iii) of Item 601(b) of Regulation S-K, the Company agrees to furnish to the Securities and Exchange Commission, upon request, a copy of the agreements comprising the $804 million senior debt facility that the Company completed with a bank group during March 1996. The total amount of long-term debt authorized under such agreement does not exceed 10 percent of the total consolidated assets of the Company and its subsidiaries. (b) Report on Form 8-K: Form 8-K Reporting Date - February 11, 1998 Item reported - Item 5. Other Events. Registrant filed information concerning the January 1998 ice storm. NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES SIGNATURE 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. NIAGARA MOHAWK POWER CORPORATION (Registrant) Date: May 29, 1998 By /s/ Steven W. Tasker Steven W. Tasker Vice President-Controller and Principal Accounting Officer NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES EXHIBIT INDEX Exhibit Number Description - ------ ----------- 3(i) By-laws of NMPC, as amended April 23, 1998. 10 Employment Agreement between the Company and John H. Mueller, dated January 19, 1998, incorporated herein by reference to the Company's Annual Report on Form 10-K for fiscal year ended December 31, 1997. 10(b) PSC Opinion and Order regarding approval of the POWERCHOICE settlement agreement with the PSC, issued and effective March 20, 1998, incorporated herein by reference to the Company's Annual Report on Form 10-K for fiscal year ended December 31, 1997. 10(c) Amendments to the Master Restructuring Agreement. 11 Computation of the Average Number of Shares of Common Stock Outstanding for the Three Months Ended March 31, 1998 and 1997. 12 Statement Showing Computations of Ratio of Earnings to Fixed Charges, Ratio of Earnings to Fixed Charges without AFC and Ratio of Earnings to Fixed Charges and Preferred Stock Dividends for the Twelve Months Ended March 31, 1998. 15 Accountants' Acknowledgement Letter. 27 Financial Data Schedule.
EXHIBIT 11 NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES Computation of the Average Number of Shares of Common Stock Outstanding For the Three Months Ended March 31, 1998 and 1997 (4) Average Number of Shares Outstanding As Shown on the (1) (2) (3) Consolidated Shares of Number of Share Statement of Income Common Days Days (3 divided by number Stock Outstanding (2 x 1) of Days in Period) ----------- -------------- -------------- ----------- Three Month's Ended March 31: January 1 - March 31, 1998 . . 144,419,351 90 12,997,741,590 144,419,351 =========== ============== =========== January 1 - March 31, 1997 . . 144,365,214 90 12,992,869,260 Shares issued - Acqusition - Syracuse Suburban Gas Company, Inc - January 6 . . . . . . . . . 25,405 85 2,159,425 ----------- -------------- 144,390,619 12,995,028,685 144,389,208 =========== ============== =========== Note: Earnings per share calculated on both a primary and fully diluted basis are the same due to the effects of rounding.
EXHIBIT 12 NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES Statement Showing Computation of Ratio of Earnings to Fixed Charges, Ratio of Earnings to Fixed Charges without AFC and Ratio of Earnings to Fixed Charges and Preferred Stock Dividends for the Twelve Months Ended March 31, 1998 (in thousands of dollars) A. Net Income . . . . . . . . . . . . . . . . . . . . $ 100,676 B. Taxes Based on Income or Profits . . . . . . . . . 110,687 ----------- C. Earnings, Before Income Taxes. . . . . . . . . . . 211,363 D. Fixed Charges (a) . . . . . . . . . . . . . . . . 304,670 ----------- E. Earnings Before Income Taxes and Fixed Charges . . 516,033 F. Allowance for Funds Used During Construction (AFC) 12,844 ----------- G. Earnings Before Income Taxes and Fixed Charges without AFC. . . . . . . . . . . . . . . . . . . . $ 503,189 =========== Preferred Dividend Factor: H. Preferred Dividend Requirements. . . . . . . . . . $ 37,221 I. Ratio of Pre-tax Income to Net Income (C / A). . . 2.10 ----------- J. Preferred Dividend Factor (H x I). . . . . . . . . $ 78,164 K. Fixed Charges as Above (D) . . . . . . . . . . . . 304,670 ----------- L. Fixed Charges and Preferred Dividends Combined . . $ 382,834 =========== M. Ratio of Earnings to Fixed Charges (E / D) . . . . 1.69 =========== N. Ratio of Earnings to Fixed Charges without AFC (G / D). . . . . . . . . . . . . . . . 1.65 =========== O. Ratio of Earnings to Fixed Charges and Preferred Dividends Combined (E / L) . . . . . . . 1.35 ===========
(a) Includes a portion of the rentals deemed representitive of the interest factor ($26,345). EXHIBIT 15 May 29, 1998 Securities and Exchange Commission 450 Fifth Street, N.W. Washington, D.C. 20549 Dear Sirs: We are aware that Niagara Mohawk Power Corporation has included our report dated May 14, 1998, except Note 3 (third paragraph) and Note 4, as to which the date is May 29, 1998, (issued pursuant to the provisions of Statement on Auditing Standards No. 71) in the Registration Statements on Form S-8 (Nos. 33-36189, 33-42771 and 333-13781) in the Prospectus constituting part of the Registration Statements on Form S-3 (Nos. 33-50703, 33-51073, 33-54827, 33-55546 and 333-49541) and in the Prospectus/Proxy Statement constituting part of the Registration Statement on Form S-4 (No. 333-49769). We are also aware of our responsibilities under the Securities Act of 1933. Yours very truly, /s/ Price Waterhouse LLP EX-27 2
OPUR1 THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE CONSOLIDATED BALANCE SHEET, CONSOLIDATED STATEMENT OF INCOME AND CONSOLIDATED STATEMENT OF CASH FLOWS AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS. 1000 3-MOS DEC-31-1998 MAR-31-1998 PER-BOOK 6897664 296976 1266128 1174570 72245 9707583 144419 1780978 814560 2739957 76610 440000 3418299 0 0 0 67065 10120 0 0 2955532 9707583 1098404 52569 964107 964107 134297 4225 138522 65590 20363 9223 11140 0 0 127223 0.08 0
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