-----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, NFkkwnYBaQoc3Zkw+1GQTq38ORFuP03Ijo91g5BJa4vITKPUZdUFCvFwkphyR/U9 HRn0BKbR1bphv4koNpHzPw== 0000071932-98-000032.txt : 19980601 0000071932-98-000032.hdr.sgml : 19980601 ACCESSION NUMBER: 0000071932-98-000032 CONFORMED SUBMISSION TYPE: 10-K/A PUBLIC DOCUMENT COUNT: 2 CONFORMED PERIOD OF REPORT: 19971231 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-K/A SEC ACT: SEC FILE NUMBER: 001-02987 FILM NUMBER: 98634035 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-K/A 1 FORM 10-K/A - ----------- (Mark One) /X/ Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the fiscal year ended December 31, 1997 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 1-2987 - ------------------------------------------------------------------ NIAGARA MOHAWK POWER CORPORATION (Exact name of registrant as specified in its charter) State of New York 15-0265555 - ----------------- ---------- (State or other jurisdiction (I.R.S. Employer of 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 - ----------------------------------------------------------------- Securities registered pursuant to Section 12(b) of the Act: (Each class is registered on the New York Stock Exchange) Title of each class Common Stock ($1 par value) Preferred Stock ($100 par Preferred Stock ($25 par value-cumulative): value-cumulative): 3.40% Series 4.10% Series 6.10% Series 9.50% Series 3.60% Series 4.85% Series 7.72% Series Adjustable Rate 3.90% Series 5.25% Series Series A & Series C Securities registered pursuant to Section 12(g) of the Act: None - ----------------------------------------------------------------- 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 by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K /X/ State the aggregate market value of the voting stock held by non- affiliates of the registrant. Approximately $1,800,000,000 at March 26, 1998. Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of the latest practicable date. Common stock, $1 par value, outstanding at March 26, 1998: 144,419,351. NIAGARA MOHAWK POWER CORPORATION INFORMATION REQUIRED IN FORM 10-K/A Item Number - ----------- Glossary of Terms PART II - ------- Item 6. Selected Consolidated Financial Data. Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations. Item 8. Financial Statements and Supplementary Data. PART IV - ------- Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K. Signatures NIAGARA MOHAWK POWER CORPORATION GLOSSARY OF TERMS - ----------------- TERM DEFINITION - ---- ---------- AFC Allowance for Funds Used During Construction CNP Canadian Niagara Power Company, Limited COPS Competitive Opportunities Proceeding CTC Competitive Transition Charges DEC New York State Department of Environmental Conservation DOE U. S. Department of Energy 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, MRA Regulatory Asset amortization, non-cash regulatory deferrals and other amortizations and extraordinary items (a non-GAAP measure of cash flow) 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 FASB Financial Accounting Standards Board FERC Federal Energy Regulatory Commission GAAP Generally Accepted Accounting Principles GRT Gross Receipts Tax GWh Gigawatt-hour: one gigawatt-hour equals one billion watt-hours IPP Independent Power Producer: any person that owns or operates, in whole or in part, one or more Independent Power Facilities IPP Party Independent Power Producers that are a party to the MRA ISO Independent System Operator KW Kilowatt: one thousand watts KWh Kilowatt-hour: a unit of electrical energy equal to one kilowatt of power supplied or taken from an electric circuit steadily for one hour MERIT Measured Equity Return Incentive Term MRA Master Restructuring Agreement - an agreement to terminate, restate or amend IPP Party power purchase agreements MRA Recoverable costs to terminate, restate or amend regulatory IPP Party contracts, which are deferred asset and amortized under PowerChoice MW Megawatt: one million watts MWh Megawatt-hour: one thousand kilowatt-hours NRC U. S. Nuclear Regulatory Commission NYPA New York Power Authority NYPP New York Power Pool NYPP Member Eight Member Systems are: the seven New York Systems State investor-owned electric utilities and NYPA NYSERDA New York State Energy Research and Development Authority PowerChoice Company's five-year electric rate agreement, agreement which incorporates the MRA, approved in February 1998 PPA Power Purchase Agreement: long-term contracts under which a utility is obligated to purchase electricity from an IPP at specified rates PRP Potentially Responsible Party PSC New York State Public Service Commission PURPA Public Utility Regulatory Policies Act of 1978, as amended. One of five bills signed into law on November 8, 1978, as the National Energy Act. It sets forth procedures and requirements applicable to state utility commissions, electric and natural gas utilities and certain federal regulatory agencies. A major aspect of this law is the mandatory purchase obligation from qualifying facilities. QF Qualifying Facility: an individual (or corporation) that owns and/or operates a generating facility but is not primarily engaged in the generation or sale of electric power. QFs are either power production or cogeneration facilities that qualify under Section 201 of PURPA. ROE Return on Common Stock Equity SFAS Statement of Financial Accounting Standards No. No. 71 71 "Accounting for the Effects of Certain Types of Regulation" SFAS Statement of Financial Accounting Standards No. No. 101 101 "Regulated Enterprises - Accounting for the Discontinuance of Application of FASB Statement No. 71" SFAS Statement of Financial Accounting Standards No. No. 106 106 "Employers' Accounting for Postretirement Benefits Other Than Pensions" SFAS Statement of Financial Accounting Standards No. No. 109 109 "Accounting for Income Taxes" SFAS Statement of Financial Accounting Standards No. No. 121 121 "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of" SFAS Statement of Financial Accounting Standards No. No. 130 130 "Reporting Comprehensive Income" SFAS Statement of Financial Accounting Standards No. No. 131 131 "Disclosures about Segments of an Enterprise and Related Information" SFAS Statement of Financial Accounting Standards No. No. 132 132 "Employers' Disclosure about Pensions and Other Postretirement Benefits" stranded Utility costs that may become unrecoverable due costs to a change in the regulatory environment Unit 1 Nine Mile Point Nuclear Station Unit No. 1 Unit 2 Nine Mile Point Nuclear Station Unit No. 2
NIAGARA MOHAWK POWER CORPORATION ITEM 6. SELECTED CONSOLIDATED FINANCIAL DATA The following table sets forth selected financial information of the Company for each of the five years during the period ended December 31, 1997, which has been derived from the audited financial statements of the Company, and should be read in connection therewith. As discussed in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations and Item 8. Financial Statements and Supplementary Data - "Notes to Consolidated Financial Statements," the following selected financial data is not likely to be indicative of the Company's future financial condition or results of operations. 1997 1996* 1995 1994 1993 - ------------------------------------------------------------------------------------------ Operations: (000's) Operating revenues $ 3,966,404 $ 3,990,653 $ 3,917,338 $ 4,152,178 $ 3,933,431 Net income 183,335 110,390 248,036 176,984 271,831 - ------------------------------------------------------------------------------------------ Common stock data: Book value per share at year end $18.89 $17.91 $17.42 $17.06 $17.25 Market price at year end 10 1/2 9 7/8 9 1/2 14 1/4 20 1/4 Ratio of market price to book value at year end 55.6% 55.1% 54.5% 83.5% 117.4% Dividend yield at year end - - 11.8% 7.9% 4.9% Basic and diluted earnings per average common share $1.01 $ .50 $1.44 $1.00 $1.71 Rate of return on common equity 5.5% 2.8% 8.4% 5.8% 10.2% Dividends paid per common share - - $1.12 $1.09 $ .95 Dividend payout ratio - - 77.8% 109.0% 55.6% - ------------------------------------------------------------------------------------------ Capitalization: (000's) Common equity $ 2,727,527 $ 2,585,572 $ 2,513,952 $ 2,462,398 $ 2,456,465 Non-redeemable preferred stock 440,000 440,000 440,000 440,000 290,000 Mandatorily redeemable preferred stock 76,610 86,730 96,850 106,000 123,200 Long-term debt 3,417,381 3,477,879 3,582,414 3,297,874 3,258,612 - ------------------------------------------------------------------------------------------ TOTAL 6,661,518 6,590,181 6,633,216 6,306,272 6,128,277 Long-term debt maturing within one year 67,095 48,084 65,064 77,971 216,185 - ------------------------------------------------------------------------------------------ TOTAL $ 6,728,613 $ 6,638,265 $ 6,698,280 $ 6,384,243 $ 6,344,462 - ------------------------------------------------------------------------------------------ Capitalization ratios: (including long-term debt maturing within one year) Common stock equity 40.5% 39.0% 37.5% 38.6% 38.7% Preferred stock 7.7 7.9 8.0 8.5 6.5 Long-term debt 51.8 53.1 54.5 52.9 54.8 - ------------------------------------------------------------------------------------------ Financial ratios: Ratio of earnings to fixed charges 2.02 1.57 2.29 1.91 2.31 Ratio of earnings to fixed charges and preferred stock dividends 1.67 1.31 1.90 1.63 2.00 Other ratios - % of operating revenues: Fuel, electricity purchased and gas purchased 44.4% 43.5% 40.3% 39.6% 36.1% Other operation and maintenance expenses 21.1 23.3 20.9 23.1 26.9 Depreciation and amortization 8.6 8.3 8.1 7.4 7.0 Federal and foreign income taxes, and other taxes 15.1 13.6 17.3 14.7 16.2 Operating income 14.1 13.1 17.5 13.3 17.5 Balance available for common stock 3.7 1.8 5.3 3.5 6.1 - ------------------------------------------------------------------------------------------ Miscellaneous: (000's) Gross additions to utility plant $ 290,757 $ 352,049 $ 345,804 $ 490,124 $ 519,612 Total utility plant 11,075,874 10,839,341 10,649,301 10,485,339 10,108,529 Accumulated depreciation and amortization 4,207,830 3,881,726 3,641,448 3,449,696 3,231,237 Total assets 9,584,141 9,427,635 9,477,869 9,649,816 9,471,327 ========================================================================================== * Amounts include extraordinary item, see Note 2. Rate and Regulatory Issues and Contingencies.
NIAGARA MOHAWK POWER CORPORATION Certain statements included in this Annual Report on Form 10-K are forward-looking statements as defined in Section 21E of the Securities Exchange Act of 1934, including the hedge against upward movement in market prices provided by the restructured and amended PPAs, the improvement in operating cash flows as a result of the MRA and PowerChoice, the recoverability of the MRA regulatory asset through the prices charged for electric service, the effect of a PSC natural gas proposal on the Company's results of operations, expected earnings over the five-year term of the PowerChoice agreement, the effect of the elimination of the FAC under PowerChoice on the Company's financial condition, the reduction in net income resulting from the non-cash amortization of the MRA regulatory asset, the effect of the January 1998 ice storm damage restoration costs on the Company's capital requirements, recoverability of environmental compliance costs and nuclear decommissioning costs through rates, and 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. ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS EVENTS AFFECTING 1997 AND THE FUTURE - - On July 9, 1997, the Company announced the MRA to terminate, restate or amend IPP power purchase contracts in exchange for cash, shares of the Company's common stock and certain financial contracts. The terms of the MRA have been and may continue to be modified. - - In February 1998, the PSC approved the PowerChoice settlement agreement, which incorporates the terms of the MRA. Under PowerChoice, a regulatory asset will be established for the costs of the MRA and it will be amortized over a period generally not to exceed ten years. The Company's rates under PowerChoice are designed to permit recovery of the MRA regulatory asset. In approving PowerChoice, the PSC limited the estimated value of the MRA regulatory asset that can be recovered to approximately $4,000 million, which is expected to result in a charge to the second quarter of 1998 earnings of $190.0 million or 85 cents per share upon the closing of the MRA. The PowerChoice agreement, while having the effect of substantially depressing earnings during its five-year term, will substantially improve operating cash flows. - - In December 1997, the preferred shareholders gave the Company approval to increase the amount of unsecured debt that the Company may issue by $5 billion. This authorization enables the issuance of unsecured debt to consummate the MRA. - - The PowerChoice agreement calls for the Company to conduct an auction to sell all of its fossil and hydro generation assets. - - In early January 1998, a major ice storm caused extensive and costly damage to the Company's facilities in northern New York. MASTER RESTRUCTURING AGREEMENT AND THE POWERCHOICE AGREEMENT The Company entered into the PPAs that are subject to the MRA because it was required to do so under PURPA, which was intended to provide incentives for businesses to create alternative energy sources. Under PURPA, the Company was required to purchase electricity generated by qualifying facilities of IPPs at prices that were not expected to exceed the cost that otherwise would have been incurred by the Company in generating its own electricity, or in purchasing it from other sources (known as "avoided costs"). While PURPA was a federal initiative, each state retained certain delegated authority over how PURPA would be implemented within its borders. In its implementation of PURPA, the State of New York passed the "Six-Cent Law," establishing 6 cents per KWh as the floor on avoided costs for projects less than 80 MW in size. The Six-Cent Law remained in place until it was amended in 1992 to deny the benefit of the statute to any future PPAs. The avoided cost determinations under PURPA were periodically increased by the PSC during this period. PURPA and the Six-Cent Law, in combination with other factors, attracted large numbers of IPPs to New York State, and, in particular, to the Company's service territory, due to the area's existing energy infrastructure and availability of cogeneration hosts. The pricing terms of substantially all of the PPAs that the Company entered into in compliance with PURPA and the Six-Cent Law or other New York laws were based, at the option of the IPP, either on administratively determined avoided costs or minimum prices, both of which have consistently been materially higher than the wholesale market prices for electricity. Since PURPA and the Six-Cent Law were passed, the Company has been required to purchase electricity from IPPs in quantities in excess of its own demand and at prices in excess of that available to the Company by internal generation or for purchase in the wholesale market. In fact, by 1991, the Company was facing a potential obligation to purchase power from IPPs substantially in excess of its peak demand of 6,093 MW. As a result, the Company's competitive position and financial performance have deteriorated and the price of electricity paid per KWh by its customers has risen significantly above the national average. Accordingly, in 1991 the Company initiated a parallel strategy of negotiating individual PPA buyouts, cancellations and renegotiations, and of pursuing regulatory and legislative support and litigation to mitigate the Company's obligation under the PPAs. By mid-1996, this strategy had resulted in reducing the capacity of the Company's obligations to purchase power under its PPA portfolio to approximately 2,700 MW. Notwithstanding this reduction in capacity, over the same period the payments made to the IPPs under their PPAs rose from approximately $200 million in 1990 to approximately $1.1 billion in 1997 as independent power facilities from which the Company was obligated to purchase electricity commenced operations. The Company estimates that absent the MRA, payments made to the IPPs pursuant to PPAs would continue to escalate by approximately $50 million per year until 2002. Recognizing the competitive trends in the electric utility industry and the impracticability of remedying the situation through a series of customer rate increases, in mid-1996 the Company began comprehensive negotiations to terminate, amend or restate a substantial portion of above-market PPAs in an effort to mitigate the escalating cost of these PPAs as well as to prepare the Company for a more competitive environment. These negotiations led to the MRA and the PowerChoice agreement. MASTER RESTRUCTURING AGREEMENT. On July 9, 1997, the Company entered into the MRA with 16 IPP Parties who sell electricity to the Company under 29 PPAs. The MRA specifically contemplated that two IPPs, Oxbow Power of North Tonawanda, New York, Inc. ("Oxbow") and NorCon would enter into further negotiations concerning their treatment under the MRA. Following such negotiations, Oxbow has withdrawn from the MRA, but, based on the value of its allocation under the MRA and the terms of its existing PPA, Oxbow's withdrawal does not materially impact the cost reductions associated with the MRA. The Company and NorCon have agreed to replace NorCon's initial allocation under the MRA with an all cash allocation which has, in the Company's estimation, a value approximately $60 million higher than NorCon's initial allocation. A third IPP Party has agreed to take cash in exchange for the shares of common stock allocated to it in the MRA. As a result of these cash allocations, there are 3,054,000 fewer shares of common stock allocated to the IPPs under the MRA. The MRA has been amended to expire on July 15, 1998. The MRA currently provides for the termination, restatement or amendment of 28 PPAs with 15 IPPs, which represent approximately 80% of the Company's over-market purchased power obligations, in exchange for an aggregate of $3,616 million in cash and 42.9 million shares of the Company's common stock and certain financial contracts. The closing of the MRA is subject to a number of conditions, including the Company and the IPP Parties negotiating individual restated and amended contracts, the receipt of all regulatory approvals, the receipt of all consents by third parties necessary for the transactions contemplated by the MRA (including the termination of the existing PPAs and the termination or amendment of all related third party agreements), the IPP Parties entering into new third party arrangements which will enable each IPP Party to restructure its projects on a reasonably satisfactory economic basis, the Company having completed all necessary financing arrangements and the Company and the IPP Parties having received all necessary approvals from their respective boards of directors, shareholders and partners. While one or more of the IPP Parties may under certain circumstances terminate the MRA with respect to itself, the Company's obligation to close the MRA is subject to its determination that as a result of any such terminations the benefits anticipated to be received by the Company pursuant to the MRA have not been materially and adversely affected. The Company expects that prior to the consummation of the MRA, the mix of consideration to be received by the IPP Parties may be renegotiated. The foregoing is qualified in its entirety by the text of the MRA (see Exhibit 10-11). As the Conditions Determination Date (the date by which all IPP Parties must satisfy or waive their third party conditions or withdraw from the MRA) has not occurred, the Company cannot predict whether such conditions will be satisfied, whether some IPP Parties may withdraw, whether the terms of the MRA might be renegotiated, or whether the MRA will be consummated. In the event the Company is unable to successfully complete the MRA and therefore implement PowerChoice, it would pursue all alternatives including a traditional rate request. The principal effects of the MRA are to reduce significantly the Company's existing payment obligations under the PPAs, which currently consist of approximately 2,700 MW of capacity at December 31, 1997. While earnings will be depressed during the five-year term, the savings in annual energy payments, coupled with the rates established in PowerChoice, will yield free cash flow that can be dedicated to the new debt service obligations associated with the payment of cash to the IPP Parties. Under the terms of the MRA, the Company's significant long term and escalating IPP payment obligations will be restructured into a defined and more manageable obligation and a portfolio of restated and amended PPAs with price and duration terms that the Company believes are more favorable than the existing PPAs. Under the MRA, 19 PPAs representing approximately 1,180 MW of capacity will be terminated completely thus allowing this capacity to be replaced through the competitive market at market based prices. The Company has no continuing obligation to purchase energy from the terminating IPP Parties. Also under the MRA, 8 PPAs representing approximately 541 MW of capacity will be restated on economic terms and conditions that are more favorable to the Company than the existing PPAs. The restated contracts have a term of 10 years and are structured as financial swap contracts where the Company receives or makes payments to the IPP Parties based upon the differential between the contract price and a market reference price for electricity. The contract prices are fixed for the first two years changing to an indexed pricing formula thereafter. Contract quantities are fixed for the full 10 year term of the contracts. The indexed pricing structure ensures that the price paid for energy and capacity will fluctuate relative to the underlying market cost of gas and general indices of inflation. Until such time as a competitive energy market structure becomes operational in the State of New York, the restated contracts provide the IPP Parties with a put option for the physical delivery of energy. Additionally, one PPA representing 42 MW of capacity will be amended to reflect a shortened term and a lower stream of fixed unit prices. Finally, the MRA requires the Company to provide the IPP Parties with a number of fixed price swap contracts with a term of seven years beginning in 2003. The fixed price swap contracts will be cash settled monthly based upon a stream of defined quantities and prices. Although against the Company's forecast of market energy prices the restructured and amended PPAs represent an expected above-market payment obligation, the Company's portfolio of these PPAs provides it and its customers with a hedge against significant upward movement in market prices that may be caused by a change in energy supply or demand. This portfolio and market purchases contain terms that are believed to be more responsive to competitive market price changes. (See Item 8. Financial Statements and Supplementary Data - "Note 9. Commitments and Contingencies - Long-term Contracts for the Purchase of Electric Power"). POWERCHOICE AGREEMENT. The PowerChoice agreement establishes a five-year rate plan that will reduce average residential and commercial rates by an aggregate of 3.2% over the first three years. This reduction will include certain savings that will result from partial reductions of the New York State GRT. Industrial customers will see average reductions of 25% relative to 1995 price levels; these decreases will include discounts currently offered to some industrial customers through optional and flexible rate programs. The cumulative rate reductions, net of GRT savings, are estimated to be approximately $112 million, to be experienced on a generally ratable basis over the first three years of the agreement. During the term of the PowerChoice agreement, the Company will be permitted to defer certain costs, associated primarily with environmental remediation, nuclear decommissioning and related costs, and changes in laws, regulations, rules and orders. In years four and five of its rate plan, the Company can request an annual increase in prices subject to a cap of 1% of the all-in price, excluding commodity costs (e.g., transmission, distribution, nuclear, and forecasted CTC). In addition to the price cap, the PowerChoice agreement provides for the recovery of deferrals established in years one through four and cost variations in the MRA financial contracts resulting from indexing provisions of these contracts. The aggregate of the price cap increase and recovery of deferrals is subject to an overall limitation of inflation. Under the terms of the PowerChoice agreement, all of the Company's customers will be able to choose their electricity supplier in a competitive market by December 1999. The Company will continue to distribute electricity through its distribution and transmission facilities and would be obligated to be the so-called provider of last resort for those customers who do not exercise their right to choose a new electricity supplier. The PowerChoice agreement provides that the MRA and the contracts executed pursuant thereto shall be found to be prudent. The PowerChoice agreement further provides that the Company shall have a reasonable opportunity to recover its stranded costs, including those associated with the MRA and the contracts executed thereto, through a CTC and, under certain circumstances, through exit fees or in rates for back up service. Under the PowerChoice agreement, an MRA regulatory asset, aggregating approximately $4,000 million, will be established. In this way, the costs of the MRA would be deferred and amortized over a period generally not to exceed ten years. The Company's rates under PowerChoice are designed to permit recovery of the MRA regulatory asset and to permit recovery of, and a return on, the remainder of its assets, as appropriate. The PowerChoice agreement, while having the effect of substantially depressing earnings during its five-year term, will substantially improve operating cash flows. The PowerChoice agreement calls for the Company to divest all of its fossil and hydro generation assets. Divestiture is intended to be accomplished through an auction. Winning bids would be selected within 11 months of PSC approval of the auction plan, which was filed with the PSC separately from the PowerChoice agreement. The Company will receive a portion of the auction sale proceeds as an incentive to obtain maximum value in the sale. This incentive would be recovered from sale proceeds. The Company agreed that if it does not receive an acceptable bid for an asset, the Company will form a subsidiary to hold any such assets and then legally separate this subsidiary from the Company through a spin- off to shareholders or otherwise. If a bid of zero or below is received for an asset, the Company may keep the asset as part of its regulated business. The auction process will serve to quantify any stranded costs associated with the Company's fossil and hydro generating assets. The Company will have a reasonable opportunity to recover these costs through the CTC and otherwise as described above. After the auction process is complete, the Company has agreed not to own any non-nuclear generating assets in the State of New York, subject to certain exceptions provided in the PowerChoice agreement. Under the terms of the note indenture prepared in connection with the financing of the MRA, the Company will be required to use a majority of the cash portion of net proceeds from the sale of its fossil and hydro generating assets to reduce indebtedness. Such restrictions would not apply in the event that the Company was unable to successfully conclude the consummation of the MRA and therefore of PowerChoice but nonetheless sold such assets. The PowerChoice agreement contemplates that the Company's nuclear plants will remain part of the Company's regulated business. The Company has been supportive of the creation of a statewide New York Nuclear Operating Company that it expects would improve the efficiency of nuclear units throughout the state. The PowerChoice agreement stipulates that absent such a statewide solution, the Company will file a detailed plan for analyzing other proposals regarding its nuclear assets, including the feasibility of an auction, transfer and/or divestiture of such facilities, within 24 months of PowerChoice approval. The PowerChoice agreement also allows the Company to form a holding company at its election. The Company plans to seek its shareholders' approval at its 1998 annual meeting to the formation of a holding company, the implementation of which would only occur following various regulatory approvals. At its public session on February 24, 1998, the PSC voted to approve the PowerChoice agreement, which incorporates the terms of the MRA. Subject to the satisfaction of the conditions to the MRA, the PSC's approval of PowerChoice should allow the Company to consummate the MRA in the first half of 1998. The PowerChoice agreement will only become effective upon the closing of the MRA. In approving PowerChoice, the PSC made the following changes, among others, to the agreement: i) customers who had made a substantial investment in on-site generation as of October 10, 1997 will be grandfathered and not have to pay the CTC; ii) savings from any reduction in the interest rate associated with the debt issued in connection with the MRA financing as compared to assumptions underlying the Company's PowerChoice filing will be deferred for future disposition; and iii) change the generation auction incentive to 15% of proceeds in excess of net book value for non- Oswego assets and 5% of proceeds in excess of $100 million for Oswego assets. In its written order dated March 20, 1998, the PSC made several other changes to the PowerChoice agreement, in addition to those discussed at the February 24 session. The PSC determined to limit the estimated value of the MRA regulatory asset that can be recovered from customers, to approximately $4,000 million. 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. The Company's common stock closed at $12 7/16 per share on March 26, 1998. The accounting implications of the limitation in value are discussed under "Accounting Implications of the PowerChoice Agreement and Master Restructuring Agreement." The PSC also modified the reduction in average residential and commercial rates. The PowerChoice agreement measured the 3.2% reduction against 1995 prices. The PSC determined that the percentage reduction should be applied against the lower of 1995 prices or the most current twelve-month period. To the extent prices for the most current twelve-month period are lower than 1995 prices, the amount of cumulative rate reductions described below will increase. Lastly, the PSC ordered the Company not to proceed to consummate the MRA with respect to one contract held by one developer until a satisfactory resolution of a cogeneration steam host contract is reached. New York law provides parties the right to appeal the Commission's decision approving the PowerChoice agreement within four months of the date of that decision. In addition, parties have the right to petition the Commission for rehearing of the decision within 30 days of the date of the decision. If a petition for rehearing is filed and the Commission issues a decision on rehearing, parties may appeal the decision on rehearing within four months of the date of the decision on rehearing. Such an appeal or petition for rehearing may be based on the failure of the record to show a reasonable basis for the terms of the PowerChoice agreement and may result in an amendment of the record to correct such failure, in renegotiation of such terms or in renegotiation of the PowerChoice agreement as a whole. There can be no assurance that, on appeal or on rehearing, the approval of the PowerChoice agreement will be upheld or that such appeal or rehearing will not result in terms substantially less favorable to the Company than those described herein. All of the foregoing discussion of the PowerChoice agreement is qualified in its entirety by the text of the agreement and PSC Order (see Exhibits 10-12 and 10-13). ACCOUNTING IMPLICATIONS OF THE POWERCHOICE AGREEMENT AND MASTER RESTRUCTURING AGREEMENT 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. As described under "Master Restructuring Agreement and the 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 upon the closing of the MRA. The charge to expense will be determined as 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). 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 and those not so restructured will continue to be the obligations of the regulated business. As described under "Master Restructuring Agreement and the PowerChoice Agreement," the consummation of the MRA, as well as implementation of PowerChoice, is subject to a number of contingencies. The Emerging Issues Task Force ("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. 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 the EITF consensus. In addition, 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. In the event the MRA and PowerChoice are implemented, the Company believes that the regulated cash flows to be derived from prices it would charge for electric service over 10 years, including the 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 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 the Company's ability to pay common and preferred dividends. The PowerChoice agreement while having the effect of substantially depressing earnings during its five- year term, will substantially improve operating cash flows. In the event the Company is unable to successfully complete the MRA and therefore implement PowerChoice, it would pursue all alternatives including a traditional rate request. However, notwithstanding such a rate request, it is likely that application of SFAS No. 71 would be discontinued for the remaining electric business, since the Company's current rate structure would no longer be sufficient to recover its costs. 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 December 31, 1997, would be approximately $526.5 million or $3.65 per share. In addition, the Company would be required to reassess 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 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 would also be required to determine the extent to which adverse purchase commitments, if any, are required to be recorded as obligations. 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. 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. 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 believe 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 December 31, 1997. PSC COMPETITIVE OPPORTUNITIES PROCEEDING - ELECTRIC On May 16, 1996, the PSC issued its Order in the COPS case, which called for a major restructuring of New York State's electric industry. The COPS order called for a competitive wholesale power market and the introduction of retail access for all electric customers. The goals cited in its decision included lowering consumer rates, increasing choice, continuing reliability of service, continuing environmental and public policy programs, mitigating concerns about market power and continuing customer protection and the obligation to serve. The PSC decision in the COPS proceeding states that recovery of utility stranded costs may be accomplished by a non-bypassable "wires charge" to be imposed by distribution companies. The PSC decision also states that a careful balancing of customer and utility interests and expectations is necessary, and that the level of stranded cost recovery will ultimately depend upon the particular circumstances of each utility. On June 10, 1997, the PSC ordered a multi-utility, retail access pilot program that would allow qualified farmers and food processors to shop for electricity and other energy services. The PSC required utilities to adjust the current delivery rates for farmers and food processors, which resulted in rate reductions of about 10 percent for farmers and 3 percent to 6 percent for food processors. Delivery under this program began in late 1997. The Company does not believe that this order will have a material adverse effect on its financial position or results of operations. On August 27, 1997, the PSC requested comments on its staff's tentative conclusions about how nuclear generation and fossil generation should be treated after decisions are made on the individual electric restructuring agreements currently pending before the PSC. The PSC staff concluded that beyond the transition period (the period covered by the individual restructuring agreements including PowerChoice), nuclear generation should operate on a competitive basis. In addition, the PSC staff concluded that a sale of generation plants to third parties is the preferred means of determining the fair market value of generation plants and offers the greatest potential for the mitigation of stranded costs. The PSC staff also concluded that recovery of sunk costs, including post shutdown costs, would be subject to review by the PSC and this process should take into account mitigation measures taken by the utility, including the steps it has taken to encourage competition in its service area. The Company's nuclear generation assets had a net book value of $1.5 billion (excluding the reserve for decommissioning) at December 31, 1997. In October 1997, the majority of utilities with interests in nuclear power plants, including the Company, requested that the PSC reconsider its staff's nuclear proposal. In addition, the utilities raised the following issues: impediments to nuclear plants operating in a competitive mode; impediments to the sale of plants; responsibility for decommissioning and disposal of spent fuel; safety and health concerns; and environmental and fuel diversity benefits. In light of all of these issues, the utilities recommended that a more formal process be developed to address those issues. The three investor-owned utilities, Rochester Gas and Electric Corporation, Consolidated Edison Company of New York, Inc. and the Company, which are currently pursuing formation of a nuclear operating company in New York State, also filed a response with the PSC in October 1997. The response stated that a forced divestiture of the nuclear plants would add uncertainty to developing a statewide approach to operating the plants and requested that such a forced divestiture proposal be rescinded. The response also stated that implementation of a consolidated six-unit operation would contribute to the mitigation of unrecovered nuclear costs. The NYPA, which is also pursuing formation of the nuclear operating company, submitted its own comments which were similar to the comments of the three utilities. In February 1998, the PSC established a formal proceeding to further examine issues related to nuclear plants and the feasibility of applying market-based pricing to these facilities. See "Master Restructuring Agreement and PowerChoice Agreement" above for a discussion of the treatment of nuclear operations during the term of PowerChoice. FERC RULEMAKING ON OPEN ACCESS AND STRANDED COST RECOVERY In April 1996, the FERC issued FERC Order 888. Order 888 promotes competition by requiring that public utilities owning, operating, or controlling interstate transmission facilities file tariffs which offer others the same transmission services they provide for themselves, under comparable terms and conditions. The Company has complied with this requirement by filing its open access transmission tariff with FERC on July 7, 1996. Based upon settlement discussions with various parties, a proposed settlement was submitted to the FERC in the first quarter of 1997. The settlement has not been approved by the FERC at this time. Hearings were conducted in September 1997 with non-settling parties. A March 1998 Administrative Law Judge's recommended decision in this proceeding recommended lower tariffs than those filed by the Company. The Company is unable to determine the ultimate resolution of this issue or when a decision will be issued by FERC. Under FERC Order 888, the NYPP was required to file reformed power pooling agreements that establish open, non-discriminatory membership provisions and modify any provisions that are unduly discriminatory or preferential. On January 31, 1997, the NYPP Member Systems (the "Member Systems") submitted a comprehensive proposal to establish an ISO, a New York State Reliability Council ("NYSRC") and a New York Power Exchange ("NYPE") that will foster a fully competitive wholesale electricity market in New York State. The ISO would provide for the reliable operation of the transmission system in New York State and provide nondiscriminatory open access to transmission services under a single ISO tariff. Through the ISO, the transmission owners, including the Company, would be compensated for the use of their transmission systems on a cost-of-service basis. The NYSRC would establish the reliability rules and standards by which the ISO operates the bulk power system. The ISO would also administer the daily electric energy market and the NYPE would facilitate the electric energy market on a day-ahead basis. On May 2, 1997, the Member Systems made a supplemental filing related to the proposed NYSRC and on August 15, 1997, six of the Member Systems filed an application for market- based rate authority in the new wholesale market structure. On December 19, 1997, the Member Systems submitted a revised filing which reflected the fundamental components of the initial January 31, 1997 filing. However, the December 19, 1997 filing provides for additional explanatory materials, incorporates FERC's guidance set forth in FERC orders involving other power pools and ISOs, and sets forth a revised governance structure of the ISO. The Company is unable to predict when FERC will act on these submittals, or whether it will approve the filings with or without modifications. However, the Company's PowerChoice agreement does not condition retail access on the presence of an ISO. In Order 888, the FERC also stated that it would provide for the recovery of prudent and verifiable wholesale stranded costs where the wholesale customer was able to obtain alternative power supplies as a result of Order 888's open access mandate. Order 888 left to the states the issue of retail stranded cost recovery. Where newly created municipal electric utilities required transmission service from the displaced utility, the FERC stated that it would entertain requests for stranded cost recovery since such municipalization is made possible by open access. The FERC also reserved the right to consider stranded costs on a case-by- case basis if it appeared that open access was being used to circumvent stranded cost review by any regulatory agency. Numerous parties, including the Company, filed requests for rehearing of Order 888. In March 1997, the FERC issued Order 888- A, which generally affirmed Order 888 and granted rehearing on only a handful of issues. One of those issues was whether the FERC would review stranded costs in annexation cases as it committed to do in municipalization cases. In Order 888-A the FERC stated that it would review stranded costs resulting from territorial annexation by an existing municipal electric system, provided that system relied on transmission from the displaced utility. The FERC denied the Company's request for rehearing on how stranded costs would be calculated and other issues. In November 1997, FERC issued Order 888-B. This Order largely affirmed the positions set forth in Order 888-A while clarifying that the FERC recognizes the existence of concurrent state jurisdiction over stranded costs arising from municipalization. The FERC acknowledged in Order 888- B that the states may be first to address the issue of retail- turned-wholesale stranded costs, and stated that it will give the states substantial deference where they have done so. In late January 1997, the Company provided 26 communities in St. Lawrence and Franklin counties with estimates they requested of the stranded costs they might be expected to pay if they withdraw from the Company's system to create government-controlled utilities. The preliminary estimate of the combined potential stranded cost liability for the communities ranges from a low of $225 million to a high of $452 million, depending upon the forecast of electricity market prices that is used. These amounts do not include the costs of creating and operating a municipal utility. At this time, 21 of the original 26 communities are still pursuing the matter. If these 21 communities withdrew from the Company's system, the Company would experience a potential revenue loss of approximately $60 million to $65 million per year. In addition, the Company is aware of other communities that are considering municipalization. However, the Company is unable to predict whether those communities would pursue municipalization. The stranded cost calculations were based on a methodology prescribed by the FERC. Because no municipality has moved forward with condemnation, the value of the Company's facilities has not been deducted from the stranded cost estimates. The stranded costs included in these estimates are the communities' share of obligations that were incurred on behalf of all customers to fulfill the Company's legal obligations to ensure adequate, reliable electricity service. Such legitimate and prudent costs are currently included in electricity rates. Government-mandated payments to IPPs represent the largest single component of these costs. These 21 communities seeking to withdraw from the Company's system also propose to disconnect entirely from the Company's system and to take transmission service from another utility. They believe that, given the provisions of Order 888, FERC would not approve the Company's request for stranded cost recovery under these circumstances. The Company has responded that, regardless of the result at the FERC, opportunities for stranded cost recovery in this matter could also be pursued before the PSC and in a state condemnation proceeding. (See "Master Restructuring Agreement and the PowerChoice Agreement.") The Company is unable to predict the outcome of this matter. OTHER FEDERAL AND STATE REGULATORY INITIATIVES PSC PROPOSAL OF NEW IPP OPERATING AND PPA MANAGEMENT PROCEDURES. In August 1996, the PSC proposed to examine the circumstances under which a utility, including the Company, may legally curtail purchases from IPPs; whether utilities should be permitted to collect data that will assist in monitoring IPPs' compliance with federal QF requirements, upon which the mandated purchases are predicated; and if utilities should be allowed to demand security from IPPs to ensure the repayment of amounts accumulated in tracking accounts made under their purchased power contracts. The PSC noted that some of the current IPP contracts are far above market prices and are causing utilities to seek rate increases. In addition, the PSC stated that its proposal was initiated to protect ratepayers, since it would ensure just and reasonable rates in the event ongoing negotiations between utilities and IPPs fail. MONITORING. In December 1996, the PSC gave the New York State utilities, including the Company, the authority to collect data to assist them in monitoring IPPs' compliance with both federal QF standards and state requirements. The PSC stated that if QFs are not meeting requirements, the obligation to pay the full contract rate, which is funded by utility ratepayers, is generally excused or mitigated. Furthermore, if the data collected through a QF monitoring program indicates a facility is not meeting federal standards, the utility could petition the FERC to decertify the QF, which could result in penalties that could include cancellation of the contract. A similar penalty could be imposed if it is determined a QF has failed to maintain compliance with state law. Under the monitoring program, QFs are required to submit data as of March 1 each year for the previous calendar year. In accordance with the terms of the MRA, the Company will not implement any QF monitoring program for the IPP Parties. However, the Company continues to monitor those IPPs that are not IPP Parties for continued QF compliance under PSC regulation. CURTAILMENT. On May 20, 1997, the PSC addressed the procedures under which a utility, including the Company, may legally curtail purchases from IPPs that are QFs, unless curtailment is specifically prohibited by contract. Curtailment is allowed by a FERC rule, under certain operational circumstances when purchases from the QFs will exceed the costs the utility would incur if it generated the power itself. Advance notice must be provided to the QF along with the reasons for such curtailment, which are subject to verification by the PSC either before or after curtailment. The PSC stated that PURPA, which encouraged generation by IPPs, was supposed to be revenue-neutral. However, they noted that this has not been the situation in New York State and ratepayers have been unduly burdened because of their lack of specific curtailment procedures. The decision to permit curtailment is not likely to affect the PPAs covered by the MRA, which represents approximately 80% of the Company's over-market purchased power obligations, as described previously. However, the decision could affect most of the remaining IPP contracts. The Company is unable to determine the effect of these statements until such a time as there is a final order. The Company cannot predict whether the PSC will take any action on the firm security issue. However, the firm security issue with respect to the IPP Parties covered under the MRA would be settled upon the closing of the MRA. MULTI-YEAR GAS RATE SETTLEMENT AGREEMENT. The Company, Multiple Intervenors (an unincorporated association of approximately 60 large commercial and industrial energy users with manufacturing and other facilities located throughout New York State) and PSC staff reached a three-year settlement that was conditionally approved by the PSC on December 19, 1996. The PSC ordered conditional approval on the three-year settlement agreement until a final, redrafted agreement, which reflects the Commission's order, is submitted for final approval. The settlement results in a $10 million annual reduction in base rates or a $30 million total reduction over the three-year term of the settlement. This reflects a $19 million reduction in the amount of fixed non- commodity costs to be recoverable in base rates, offset by a $9 million increase in annual base rates. The Company estimates that the combination of in-hand supplier refunds and further reductions in upstream pipeline costs will be sufficient to fund the $19 million annual reduction in non-commodity cost recovery. If the non-commodity cost reductions exceed $57 million ($19 million annually) during the three-year settlement period, the excess, up to $40 million will be credited to a Contingency Reserve Account ("CRA") to be utilized for ratepayer benefit in the rate year ending October 31, 2000 or beyond. To the extent the actual non-commodity cost reductions exceed $57 million by more than $40 million, the Company may retain any excess subject to a return on equity sharing provision. In the event the non-commodity reductions fall short of the $57 million estimate, the Company will bear the risk of any shortfall. In the event that the termination or restructuring of IPP contracts results in margin (revenues less fuel costs) or peak shaving losses, the margin losses would be collected currently subject to 80%/20% (ratepayer/shareholder) sharing and the peak shaving losses will be deferred to the CRA, subject to limits specified in the settlement. In return for taking on this risk, the Company has achieved a portion of the revised rate structure that had been proposed to reduce its throughput risk. The Company obtained an ROE cap of 13.5% with 50/50 sharing between ratepayers and shareholders in excess of the cap. The Company also has an opportunity to earn up to $2.25 million annually if its gas commodity costs are lower than a market based target without being subject to the ROE cap. The Company has an equal $2.25 million risk if gas commodity costs exceed the target. An additional major benefit of the revised rate design is that the margin made on each additional new customer will significantly increase to the extent additional throughput does not require additional upstream pipeline capacity for service. This, along with the approval of the Company's Progress Fund, which allows the Company to use utility revenues in an amount not to exceed $11 million in total for the purpose of providing financing for large customers to convert or increase their gas use, will provide new opportunities for growth. GENERIC GAS RATE PROCEEDING. As a result of the generic rate proceeding, in which the PSC ordered all New York utilities to implement a service unbundling beginning in May 1996, nearly 3,000 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 equals the margin on the traditional sales service classes. To date this migration has not resulted in any stranded costs since 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, at which time the PSC will decide on methods for dealing with the remaining unassigned or excess capacity. As a part of the generic rate proceeding, all utilities are 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. In a clarifying order in this proceeding, issued September 4, 1997, the PSC has indicated that it is unlikely that utilities will be allowed to continue to assign pipeline capacity to departing customers after March 1999. On a separate but parallel path, in September 1997, the PSC issued for comment its staff's position paper on the future of the natural gas industry, including recommendations for increasing competition and expanding customer choice in the natural gas marketplace. The staff proposed, among other things, that all regulated natural gas utilities exit the business of purchasing natural gas for customers over the next five years. This would complete the transition of customers from sales to transportation service only. The regulated utilities would only deliver natural gas purchased by customers from competitive suppliers. If this proposal is adopted by the PSC, then it would eliminate the need to regulate natural gas purchasing practices since market forces would establish natural gas prices. The position paper identified a number of issues that would need to be resolved in order for this proposal to be successful. The primary issues are the pipeline capacity and gas supply contracts that the local utilities have with interstate pipelines that extend beyond the proposed five-year transition period, the obligation of the utility to serve as supplier of last resort, and the issue of system reliability. The Company and other parties submitted comments and reply comments to the PSC in late November and December of 1997, respectively. With the exception of the issues to be resolved by the PSC, as mentioned above, the Company does not believe that this proposal will have a material adverse effect on its results of operations or financial condition, since the Company's natural gas margin is derived from the delivery service and not from the commodity sale. The resolution of the issues identified by the PSC could result in unrecovered stranded costs for the Company. The Company is unable to predict how the PSC will resolve those issues. For a discussion of the Company's gas supply, storage and pipeline commitments, see Item 8. Financial Statements and Supplementary Data - "Note 9. Commitments and Contingencies - Gas Supply, Storage and Pipeline Commitments.") NRC AND NUCLEAR OPERATING MATTERS. In October 1996, the NRC required companies with nuclear plants to provide the NRC with added confidence and assurance that their plants are operated and maintained within the design basis, and any deviations are reconciled in a timely manner. Such information, which was filed within the required 120 days, will be used by the NRC to verify that companies are in compliance with the terms and conditions of their license(s) and NRC regulations. In addition, it will allow the NRC to determine if other inspection activities or enforcement actions should be taken on a particular company. In the letter transmitting the requested information to the NRC, the Company concluded that it has reasonable assurance that (i) design basis requirements are being translated into operating, maintenance, and testing procedures; and (ii) system, structure and component configuration and performance are consistent with the design basis. Also, the Company has an effective administrative tool for the identification, documentation, notification, evaluation, correction, and reporting of conditions, events, activities, and concerns that have the potential for adversely affecting the safe and reliable operation of Unit 1 and Unit 2. In April 1997 and December 1997, the Company received notices from the NRC of a $200,000 fine and $50,000 fine, respectively, for violations at Unit 1 and Unit 2. The penalties were for violations related to corrective actions and design control. The Company paid the fines and is implementing corrective action. On January 23, 1998, the Company received notice of a proposed $55,000 fine from the NRC for violations of NRC requirements related to radioactive waste issues. The Company does not plan to contest the proposed NRC fine. In January 1998, the NRC issued its Systematic Assessment of Licensee Performance (the "SALP") report on Unit 1 and Unit 2, which covers the period June 1996 to November 1997. The SALP report, which is an extensive assessment of the plants' performance in the areas of operations, maintenance, engineering and support, stated that the performance of Unit 1 and Unit 2 was generally good, although ratings were lower than the previous assessment. The Company agrees with the NRC's determination that there are areas of its performance that need improvement and is taking several actions to make those needed improvements. The Company believes that NRC safety enforcement is becoming more stringent as indicated by the NRC's request for information, fines that the Company has been assessed and lower SALP ratings and that there may be a direct cost impact on companies with nuclear plants as a result. The Company is unable to predict how such a changed operating environment may affect its results of operations or financial condition. Some owners of older General Electric Company boiling water reactors, including the Company, have experienced cracking in horizontal welds in the plants' core shrouds. In response to industry findings, the Company installed pre-emptive modifications to the Unit 1 core shroud during a 1995 refueling and maintenance outage. The core shroud, a stainless steel cylinder inside the reactor vessel, surrounds the fuel and directs the flow of reactor water through the fuel assemblies. Inspections conducted as part of the March 1997 refueling and maintenance outage detected cracking in vertical welds not reinforced by the 1995 repairs. On April 8, 1997, the Company filed a comprehensive inspection and analysis report with the NRC that concluded that the condition of the Unit 1 core shroud supports the safe operation of the plant. On May 8, 1997, the NRC approved the Company's request to operate Unit 1 until the next scheduled mid-cycle outage, late 1998. The Company agreed to propose an inspection plan for the outage and submit the plan to the NRC at least three months before the outage is scheduled to begin. The Company believes it has a strong technical basis to operate Unit 1 without a mid-cycle outage and is seeking the necessary approval from the NRC to postpone the inspections until the unit's refueling and maintenance outage in spring 1999, but there can be no assurance that such approval will be granted. The Unit 1 refueling and maintenance outage, originally planned to be completed in early April 1997, was completed on May 10, 1997 due to the core shroud issue. On September 15, 1997, Unit 1 was taken out of service due to leaking in one of four back-up condensers. The standby condensers serve as a back-up system for the removal of reactor steam. The condensers are maintained in a ready state during normal plant operations. Tests and inspections were conducted on the remaining condensers and similar conditions were found. On December 10, 1997, Unit 1 was returned to service after the replacement of all four condensers, which cost approximately $6.7 million. OTHER COMPANY EFFORTS TO ADDRESS COMPETITIVE CHALLENGES TAX INITIATIVES. The Company is working with utility, customer and state representatives to explain the negative impact that all utility taxes, including the GRT, are having on rates and the state of the economy. At the same time, the Company is also contesting the high real estate taxes it is assessed by many taxing authorities, particularly those imposed upon generating facilities. The New York State Legislature passed a state budget in August 1997 which includes a reduction of the GRT over three years. For gas and electric utilities, the tax imposed on gross income will be reduced from 3.5% to 3.25% on October 1, 1998, and from 3.25% to 2.5% on January 1, 2000. The state tax imposed on gross earnings will remain unchanged at .75%, bringing the total GRT to 3.25% -- a full percentage point lower than today's level of 4.25%. The savings from the reduction of the GRT will be passed on to the Company's customers. The Company believes that further tax relief is needed to relieve the Company's customers of high energy costs and to improve New York State's competitive position as the industry moves toward a competitive marketplace. The following table sets forth a summary of the components of other taxes (exclusive of income taxes) incurred by the Company in the years 1995 through 1997:
In millions of dollars 1997 1996 1995 - --------------------------------------------------------------- Property tax expense $250.7 $249.4 $264.8 Sales tax 13.4 14.1 13.9 Payroll tax 34.1 36.4 37.3 Gross Receipts Tax 184.6 184.1 190.2 Other taxes 0.1 0.5 5.2 - --------------------------------------------------------------- Total tax expense 482.9 484.5 511.4 Charged to construction, subsidiaries and regulatory recognition (11.4) (8.7) 6.1 - --------------------------------------------------------------- Total other taxes $471.5 $475.8 $517.5 ===============================================================
CUSTOMER DISCOUNTS. In recent years, some industrial customers have found alternative suppliers or are generating their own power. In addition, a weakened economy or attractive energy prices elsewhere have contributed to other industrial customer decisions to relocate or close. In addressing the threat of further loss of industrial load, the PSC established guidelines to govern flexible electric rates offered by utilities to retain qualified industrial customers. Under these guidelines, the Company filed for a new service tariff in August 1994 (SC-11), under which all new contract rates are administered based on demonstrated industrial and commercial competitive pricing alternatives including, but not limited to, on- site generation, fuel switching, facility relocation and partial plant production shifting. Contracts are for terms not to exceed seven years without PSC approval. In addition, the Company has economic development programs which provide tariff based incentives to retain and grow load. As of January 1998, the Company has 152 executed contracts under its flexible tariff offerings. These contracts have been signed to mitigate the lost margin impacts associated with customers executing the competitive alternatives mentioned above. In addition, many of these contracts include an increase in production levels and/or attract new customers to the Company's service territory. In 1997 and 1996, the total amount of customer discounts (economic development programs and flexible pricing) was $90.6 million and $75.5 million, respectively. The Company recovered $46.6 million and $56.7 million in rates, respectively. Pending implementation of PowerChoice, the Company budgeted its discounts to increase to approximately $95.4 million in 1998 as some discounts granted in 1997 are in effect for an entire year and further discounts are granted. The Company is aggressively using SC-11 to increase sales to existing customers and to attract new customers to its service territory. With the reduction in industrial prices provided in PowerChoice, the level of discounts that have been necessary should decline in the future. REGULATORY AGREEMENTS/PROPOSALS (See "Master Restructuring Agreement and the PowerChoice Agreement.") 1995 RATE ORDER. On April 21, 1995, the Company received a rate decision (1995 rate order) from the PSC which approved an approximately $47 million increase in electric revenues and a $4.9 million increase in gas revenues. YEAR 2000 COMPUTER ISSUE As the year 2000 approaches, the Company, along with many other companies, could experience potentially serious operational problems, since many computer programs that were developed will not properly recognize calendar dates beginning with the year 2000. Further, there are embedded chips contained within generation, transmission, distribution and gas equipment that may be date- sensitive. In these circumstances where an embedded chip fails to recognize the correct date, electric or gas operations could be adversely affected. The Company is addressing these issues so that its computer systems and, where necessary, its embedded chips will process dates greater than 1999, thereby preventing any adverse operational or financial impacts. The Company has been addressing the year 2000 information technology issue through the remediation and replacement of existing business applications and parts of its technical infrastructure. In late 1997, the services of a leading computer services and consulting firm were retained to conduct an assessment of the Company's entire year 2000 program. As a result of the assessment, a Company-wide year 2000 project management office has been formed and year 2000 project managers have been appointed within each business group and efforts are underway to evaluate the scope of the problem for embedded technologies/process control systems in all business groups within the Company. A Company-wide program director and an executive level steering committee have been put in place to oversee all aspects of the program. The Company is also evaluating the exposure to year 2000 problems of third parties with whom the Company conducts business. The Company expects to complete an inventory of exposures, including an assessment of priorities, costs and resources, by the third quarter of 1998. Failures of the Company and/or third party computer systems and embedded chips could have a material impact on the Company's ability to conduct its business. Until further progress is made on these efforts, management is unable to estimate the total year 2000 compliance expense, but it is in the process of assessing this expense. RESULTS OF OPERATIONS Earnings for 1997 were $145.9 million, or $1.01 per share, as compared to $72.1 million, or 50 cents per share, in 1996 and $208.4 million, or $1.44 per share, in 1995. In comparing year-to-year results, earnings in 1996 reflect certain significant events that were not repeated in 1997. Earnings in 1996 were reduced by an after-tax write-off of $67.4 million, or 47 cents per share, associated with the discontinued application of regulatory accounting principles to the Company's fossil and hydro generation business. Largely as a result of the Company's 1996 assessment of the increased risk of collecting significantly higher levels of past-due customer bills, bad debt expense in 1996 was higher than in 1997 by $81.1 million, reducing earnings in 1996, compared to 1997, by 37 cents per share. However, earnings in 1996 were aided by a $15 million after-tax gain on the sale of a 50 percent interest in CNP which added 10 cents per share to 1996 earnings. Industrial customer discounts not recovered in rates in 1997 exceeded 1996 levels by $25.2 million, reducing 1997 earnings by 11 cents per share (see Other Company Efforts to Address Competitive Challenges - "Customer Discounts.") In addition, a decline in higher-margin residential sales also adversely impacted 1997 earnings. The lower-margin industrial-special sales (sales by the Company on behalf of NYPA) and industrial sales increased. As a result, total public sales were essentially the same as sales in 1996. Earnings for 1995 were hurt by lower sales quantities of electricity and natural gas, as compared with amounts used to establish 1995 prices. Sales were primarily affected by the continuing weak economic conditions in upstate New York, loss of industrial customers' load to NYPA and discounts granted. These factors similarly impacted 1996 and 1997 results. In addition, 1995 earnings included the recording of a one-time, non-cash adjustment of prior years' demand-side management ("DSM") incentive revenues, revenues earned under the Unit 1 operating incentive sharing mechanism and a gain on the sale of HYDRA-CO that collectively increased 1995 earnings by 17 cents per share. The Company's 1997 earned ROE was 5.5% as compared to 2.8% (5.4% before extraordinary loss) in 1996 and 8.4% in 1995. The Company's ROE authorized in the 1995 or last rate setting process is 11.0% for the electric business and 11.4% for the gas business. Factors contributing to earnings below authorized levels in 1997 included, among other things, sales below those forecasted in determining rates, contractual increases in capacity payments to IPPs and increasing discounts to customers. As discussed under "Master Restructuring Agreement and the PowerChoice Agreement" and "Accounting Implications of the PowerChoice Agreement and Master Restructuring Agreement," the Company forecasts that earnings for the five-year term of the PowerChoice agreement will be substantially depressed. The level of earnings for 1998 will also be impacted, in part, by the date of implementation of PowerChoice, the PowerChoice charge of $190 million expected to be taken in the second quarter of 1998 and may also be negatively impacted by the financial effects of the January 1998 ice storm (see Item 8. Financial Statements and Supplementary Data - "Note 13. Subsequent Event"). The following discussion and analysis highlights items that significantly affected operations during the three-year period ended December 31, 1997. 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 also should be read in conjunction with Item 8. Financial Statements and Supplementary Data and other financial and statistical information appearing elsewhere in this report. ELECTRIC REVENUES were $3,309 million in both 1997 and 1996, a decrease of $26.1 million, or 0.8% from 1995. As shown in the following table, FAC revenues increased $42.8 million in 1997, primarily as a result of the Company's ability in 1997 to recover increased payments to the IPPs through the FAC. However, this increase was offset by a decrease in revenues from sales to other electric systems and lower electric sales due to warmer weather. Under PowerChoice, revenues may decline as customers choose alternative suppliers. However, the Company will recover stranded costs through the CTC. See "Master Restructuring Agreement and the PowerChoice Agreement." Electric operating revenues decreased in 1996, primarily due to a decrease in miscellaneous electric revenues. Miscellaneous electric revenues were lower in 1996 primarily because 1995 electric revenues included the recording of $71.5 million of unbilled, non-cash revenues in accordance with the 1995 rate order, $13.0 million of revenues earned under MERIT (an incentive mechanism related to improvement in key performance areas which ended in 1996) and a one-time, non-cash adjustment of prior year's DSM incentive revenues and a reduction in the DSM rebate cost program. However, higher electric sales due to colder weather, an increase in sales to other electric systems, an increase in FAC revenues and higher electric rates (effective April 26, 1995) partly offset those factors that contributed to lower electric revenues. FAC revenues increased $28.3 million in 1996, which primarily reflects the Company's increased payments to the IPPs recovered through the FAC.
INCREASE (DECREASE) FROM PRIOR YEAR (In millions of dollars) - ----------------------------------------------------------------- ELECTRIC REVENUES 1997 1996 TOTAL - ----------------------------------------------------------------- Amortization of unbilled revenues $ - $ (77.1) $ (77.1) Base rates - 65.3 65.3 Fuel adjustment clause revenues 42.8 28.3 71.1 Changes in volume and mix of sales to ultimate consumers (12.7) (28.1) (40.8) Sales to other electric systems (29.6) 24.5 (5.1) MERIT revenue - (13.0) (13.0) DSM revenue - (26.5) (26.5) ------- ------ ----- $ 0.5 $ (26.6) $ (26.1) ======== ====== ======
The FAC is eliminated under the PowerChoice agreement. Changes in FAC revenues are generally margin-neutral (subject to an incentive mechanism discussed in Item 8. Financial Statements and Supplementary Data - "Note 1. Summary of Significant Accounting Policies"), while sales to other utilities, because of regulatory sharing mechanisms and relatively low prices, generally result in low margin contributions to the Company. Thus, fluctuations in these revenue components do not generally have a significant impact on net operating income. Electric revenues reflect the billing of a separate factor for DSM programs, which provided for the recovery of program related rebate costs. ELECTRIC KILOWATT-HOUR SALES were 37.1 billion in 1997, 39.1 billion in 1996 and 37.7 billion in 1995. The 1997 decrease of 2.0 billion KWh, or 5.1% as compared to 1996, is related primarily to a 31.0% decrease in sales to other electric systems. (See Item 8. Financial Statements and Supplementary Data -"Electric and Gas Statistics - Electric Statistics"). The 1996 increase of 1.4 billion KWh, or 3.8% as compared to 1995, reflects a 26.2% increase in sales to other electric systems and a 1.2% increase in sales to ultimate customers due to the colder weather. Sales to other electric systems were lower primarily due to a reduction in the availability of nuclear generation as a result of the outages at Unit 1. The Company is anticipating little or no growth in 1998 in sales to ultimate consumers, which will be sensitive to the business climate in its service territory.
Details of the changes in electric revenues and KWh sales by customer group are highlighted in the table below: % INCREASE (DECREASE) FROM PRIOR YEAR 1997 % OF ------------------------------------- ELECTRIC 1997 1996 CLASS OF SERVICE REVENUES REVENUES SALES REVENUES SALES - ---------------------------------------------------------------------- Residential 37.1% (2.0)% (2.0)% 3.1% 0.5% Commercial 37.3 (0.3) (0.1) - (0.4) Industrial 16.1 1.2 0.6 0.2 1.2 Industrial-Special 1.9 5.8 4.2 3.9 6.7 Municipal service 1.6 1.4 (4.5) 5.8 7.4 - ---------------------------------------------------------------------- Total to ultimate consumers 94.0 (0.6) - 1.4 1.2 Other electric systems 2.5 (26.1) (31.0) 27.5 26.2 Miscellaneous 3.5 70.4 (100.0) (57.8) (17.7) - ---------------------------------------------------------------------- TOTAL 100.0% -% (5.1)% (0.8)% 3.8%
As indicated in the table below, internal generation decreased 10.1% in 1997, principally due to the outage at Unit 1 and a reduction in hydroelectric power as a result of lower than normal precipitation in the summer months. In 1997, Unit 1 was out of service for 153 days, due to a planned refueling and maintenance outage (which took 68 days) and for the emergency condenser replacement (which took approximately 85 days) while in 1996, Unit 2 was out of service for a 36 day planned refueling and maintenance outage. (See "Other Federal and State Regulatory Initiatives - NRC and Nuclear Operating Matters.") The amount of electricity delivered to the Company by the IPPs decreased by approximately 277 GWh or 2.0%. However, total IPP costs increased by approximately $18.0 million or 1.7%, as discussed below. (See "Master Restructuring Agreement and the PowerChoice Agreement").
1997 1996 1995 --------------- ---------------- ---------------- (In millions of dollars) GWh Cost GWh Cost GWh Cost ------ ------ ------ ------- ------ -------- Fuel for electric generation: Coal 7,459 $ 106.4 7,095 $ 100.6 6,841 $ 97.9 Oil 701 32.2 462 21.1 537 21.3 Natural gas 394 8.6 319 9.2 996 20.2 Nuclear 6,339 33.0 8,243 47.7 7,272 43.3 Hydro 2,905 - 3,679 - 2,971 - ------- ------ ------ ------- ------ -------- 17,798 180.2 19,798 178.6 18,617 182.7 ------- ------ ------ ------- ------ -------- Electricity purchased: IPPs: Capacity - 220.8 - 212.8 - 181.2 Energy and taxes 13,520 885.7 13,797 875.7 14,023 798.7 ------ ----- ------ ------- ------ ------- Total IPP purchases 13,520 1,106.5 13,797 1,088.5 14,023 979.9 Other 9,421 130.2 9,569 130.6 9,463 126.5 ------ ------- ------ ------- ------ ------- 22,941 1,236.7 23,366 1,219.1 23,486 1,106.4 ------ ------- ------ ------- ------ ------- Total generated and purchased 40,739 1,416.9 43,164 1,397.7 42,103 1,289.1 Fuel adjustment clause - (1.3) - (33.3) - 14.8 Losses/Company use 3,603 - 4,037 - 4,419 - ------ ------- ------ -------- ------ -------- 37,136 $1,415.6 39,127 $1,364.4 37,684 $1,303.9 ====== ======= ====== ======== ====== ========
% Change from Prior Year --------------------------------- 1997 to 1996 1996 to 1995 ------------ ------------ (In millions of dollars) GWh Cost GWh Cost ------ ---- ------ ---- Fuel for electric generation: Coal 5.1% 5.8% 3.7% 2.8% Oil 51.7 52.6 (14.0) (0.9) Natural gas 23.5 (6.5) (68.0) (54.5) Nuclear (23.1) (30.8) 13.4 10.2 Hydro (21.0) - 23.8 - ------ ------ ------ ------ (10.1) 0.9 6.3 (2.2) ------ ------ ------ ------ Electricity purchased: IPPs: Capacity - 3.8 - 17.4 Energy and taxes (2.0) 1.1 (1.6) 9.6 ----- ----- ----- ----- Total IPP purchases (2.0) 1.7 (1.6) 11.1 Other (1.5) (0.3) 1.1 3.2 ----- ----- ----- ----- (1.8) 1.4 (0.5) 10.2 ----- ------ ----- ----- Total generated and purchased (5.6) 1.4 2.5 8.4 Fuel adjustment clause - (96.1) - (325.0) Losses/Company use (10.8) - (8.6) - ------- ------- ------ ------- (5.1)% 3.8% 3.8% 4.6% ======= ======= ====== =======
The above table presents the total costs for purchased electricity, while reflecting only fuel costs for Company generation. Other costs of generation, such as taxes, other operating expenses and depreciation are included within other income statement line items. The Company's management of its IPP power supply generally divides the projects into three categories: hydroelectric, "must run" cogeneration and schedulable cogeneration projects. Following a higher than normal spring run off, the precipitation in the summer months was lower than usual. As a result, hydroelectric IPP projects delivered 242 GWh or 13.7% less under PPAs than they did for the same period last year, representing decreased payments to those IPPs of $15.7 million. A substantial portion of the Company's portfolio of IPP projects operate on a "must run" basis. This means that they tend to run at maximum production levels regardless of the need for or economic value of the electricity produced. Output from "must run" cogeneration IPPs was 230 GWh or 2.6% lower than produced last year, in part due to lower energy purchases from the Sithe Independence plant. However, payments to those IPPs were $12.8 million higher. This was due to a combination of output turndown arrangements with individual projects and escalating contract rates. A turndown arrangement is an agreement where the Company compensates an IPP to reduce the output from their facility. Although output is reduced, the net economic impact is favorable to the Company and its customers since the electricity is replaced from the market or other lower cost sources. Quantities purchased from schedulable cogeneration IPPs increased 195 GWh or 6.3% and payments increased $20.9 million. The increased payments are largely due to escalating contract rates for capacity (fixed) and increased volumes of energy. The terms of these PPAs allow the Company to schedule (with certain constraints) energy deliveries and pay for the energy supplied. In addition, the Company is required to make fixed payments if the IPP plants remain available for service. (See Item 8. Financial Statements and Supplementary Data - "Note 9. Commitments and Contingencies - Long-term Contracts for the Purchase of Electric Power"). GAS REVENUES decreased by $24.7 million, or 3.6% in 1997, and increased by $99.9 million, or 17.2%, in 1996. As shown in the table below, gas revenues decreased in 1997 primarily due to decreased sales to ultimate customers as a result of the migration of commercial sales customers to the transportation class, decreased spot market sales and a decrease in base rates of $5.9 million in accordance with the 1996 rate order. This was partially offset by higher gas adjustment clause recoveries and an increase in revenues from the transportation of customer-owned gas (see "Other Federal and State Regulatory Initiatives -Generic Gas Rate Proceeding"). Gas revenues increased in 1996 primarily due to increased sales to ultimate customers due to colder weather, increased spot market sales, higher gas adjustment clause recoveries, an increase in revenues from the transportation of customer-owned gas and an increase in base rates of $3.1 million in accordance with the 1995 rate order. Rates for transported gas (excluding aggregation services) yield lower margins than gas sold directly by the Company. Therefore, increases in the volume of gas transportation services have not had a proportionate impact on earnings, particularly in instances where customers that took direct service from the Company move to a transportation-only class. In addition, changes in purchased gas adjustment clause revenues are generally margin- neutral.
INCREASE (DECREASE) FROM PRIOR YEAR (In millions of dollars) GAS REVENUES 1997 1996 TOTAL - --------------------------------------------------------------- Base rates $ (5.9) $ 3.1 $ (2.8) Transportation of customer-owned gas 5.3 2.1 7.4 Purchased gas adjustment clause revenues 45.3 30.8 76.1 Spot market sales (30.8) 34.0 3.3 Changes in volume and mix of sales to ultimate consumers (38.6) 29.9 (8.8) ------- ------ ------ $(24.7) $ 99.9 $ 75.2 ======= ====== =======
GAS SALES, excluding transportation of customer-owned gas and spot market sales, were 78.7 million Dth in 1997, a 7.3% decrease from 1996, and a 0.3% increase from 1995. (See Item 8. Financial Statements and Supplementary Data - "Electric and Gas Statistics - Gas Statistics"). The decrease in 1997 was in all ultimate consumer classes, in part due to the warmer weather. In addition, 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 customers, decreased 8.0 million Dth. This was partially offset by an increase in transportation volumes of 18.1 million Dth or 13.5% to customers purchasing gas directly from producers. The Company has experienced an increase in customers of approximately 17,800 since 1995, primarily in the residential class, an increase of 3.5%.
Changes in gas revenues and Dth sales by customer group are detailed in the table below: % INCREASE (DECREASE) FROM PRIOR YEAR 1997 % OF ------------------------------------- GAS 1997 1996 CLASS OF SERVICE REVENUES REVENUES SALES REVENUES SALES - --------------------------------------------------------------------- Residential 66.4% 4.5% (2.7)% 13.3% 9.4% Commercial 22.6 (8.7) (13.0) 13.0 6.4 Industrial 1.0 (50.9) (50.1) 15.6 4.1 - --------------------------------------------------------------------- Total to ultimate consumers 90.0 (0.3) (7.3) 13.3 8.3 Other gas systems - (5.8) (6.7) (81.9) (81.4) Transportation of customer-owned gas 8.5 10.5 13.5 4.3 (6.9) Spot market sales 1.0 (82.9) (76.6) 1,099.1 507.0 Miscellaneous 0.5 263.1 - (82.2) - - --------------------------------------------------------------------- TOTAL 100.0% (3.6)% 1.7% 17.2% 2.3%
The total cost of gas purchased decreased 6.6% in 1997 and increased 34.0% in 1996. The cost fluctuations generally correspond to sales volume changes, as spot market sales activity decreased, as well as changes in gas prices. The Company sold 2.5, 10.5 and 1.7 million Dth on the spot market in 1997, 1996 and 1995, respectively. The total cost of gas decreased $24.4 million in 1997. This was the result of a 5.3 million decrease in Dth purchased and withdrawn from storage for ultimate consumer sales ($18.8 million) and a $22.5 million decrease in Dth purchased for spot market sales, partially offset by a 3.3% increase in the average cost per Dth purchased ($10.7 million) and a $6.3 million increase in purchased gas costs and certain other items recognized and recovered through the purchased gas adjustment clause. The total cost of gas purchased increased $93.8 million in 1996. This was the result of a 9.3 million increase in Dth purchased and withdrawn from storage for ultimate consumer sales ($29.6 million), a $25.6 million increase in Dth purchased for spot market sales and a 12.9% increase in the average cost per Dth purchased ($38.7 million). Gas purchased for spot market sales decreased $22.5 million in 1997 and increased $25.6 million in 1996. The Company's net cost per Dth sold, as charged to expense and excluding spot market purchases, increased to $3.82 in 1997 from $3.62 in 1996 and was $3.17 in 1995. Through the electric and purchased gas adjustment clauses, costs of fuel, purchased power and gas purchased, above or below the levels allowed in approved rate schedules, are billed or credited to customers. The Company's electric FAC provides for a partial pass-through of fuel and purchased power cost fluctuations from those forecast in rate proceedings, with the Company absorbing a portion of increases or retaining a portion of decreases to a maximum of $15 million per rate year. The Company absorbed losses of approximately $11.8 million, $1.4 million and $13.1 million in 1995, 1996 and 1997, respectively. Under PowerChoice, the FAC will be terminated. The Company does not believe that the elimination of the FAC will have a material adverse effect on its financial condition, as a result of its management of (1) power supplies provided through: (i) the operation of its own power plants, and future power purchase arrangements as part of the planned auction of its fossil and hydro assets, (ii) fixed power purchases from NYPA and remaining IPPs and (iii) fixed and indexed swap arrangements with IPP Parties and (2) the transfer of the risk associated with electricity commodity prices to the customer through implementation of retail access included in the PowerChoice agreement. OTHER OPERATION AND MAINTENANCE EXPENSE decreased in 1997 by $92.9 million, or 10.0%, as compared to an increase of $110.3 million or 13.5% in 1996. These changes in 1996 and 1997 each result primarily from a change in 1996 in the Company's assessment of uncollectible customer accounts, which gives greater recognition to the increased risk of collecting past due customer bills, resulting in increases in the Company's allowance for doubtful accounts and a significantly higher expense recognition in 1996. Bad debt expense was $31.2 million, $127.6 million and $46.5 million in 1995, 1996 and 1997, respectively. In 1997, write-offs were $39.0 million and the Company incurred a $10.5 million increase in allowance for doubtful accounts. The increase in the allowance for doubtful accounts was attributable to increases in the collection risk associated with residential accounts receivable and arrears. The Company has implemented a number of collection initiatives that are expected to result in lower arrears levels and potentially lower the allowance for doubtful accounts. Other operation and maintenance expense also decreased in 1997 as a result of a reduction in administrative and general expenses of $15.8 million, primarily due to a reduction in legal costs. OTHER INCOME decreased by $10.9 million in 1997 and increased by $32.9 million in 1996. Despite higher interest income ($12.0 million) related to increasing cash balances, "other income" was lower in 1997, since 1996 reflected a gain on the sale of a 50% interest in CNP ($15.0 million). The 1996 increase also reflected higher interest income ($10.9 million) as a result of an increase in temporary cash investments. In addition, "other income" was higher in 1996 since there were customer service penalties and certain other items written off because they were disallowed in rates in 1995. FEDERAL AND FOREIGN INCOME TAXES increased by $24.1 million in 1997 primarily due to an increase in pre-tax income and decreased by $56.9 million in 1996 primarily due to a decrease in pre-tax income. Other taxes decreased by $4.4 million in 1997 and decreased by $41.6 million in 1996. The 1997 decrease was primarily due to lower payroll taxes ($2.3 million) and lower sales taxes ($0.7 million). The 1996 decrease was primarily as a result of lower real estate taxes ($15.4 million), lower GRTs ($6.1 million) primarily due to a reduction in the GRT surcharge during 1996, lower New York State excess dividend tax accrual due to a suspension of the common stock dividend ($4.6 million) and year-to- year differences in the accounting for regulatory deferrals ($15.2 million) associated primarily with a settlement of tax issues with respect to the Company's Dunkirk facility. INTEREST CHARGES remained fairly constant for the years 1995 through 1997. However, dividends on preferred stock decreased by $0.9 million and $1.3 million in 1997 and 1996, respectively. Dividends on preferred stock decreased in 1997 primarily due to a reduction in preferred stock outstanding through sinking fund redemptions and decreased in 1996 primarily due to a decrease in the cost of variable rate issues. The weighted average long-term debt interest rate and preferred dividend rate paid, reflecting the actual cost of variable rate issues, changed to 7.81% and 7.04%, respectively, in 1997 from 7.71% and 7.09%, respectively, in 1996 and from 7.77% and 7.19%, respectively, in 1995. EFFECTS OF CHANGING PRICES The Company is especially sensitive to inflation because of the amount of capital it typically needs and because its prices are regulated using a rate base methodology that reflects the historical cost of utility plant. The Company's consolidated financial statements are based on historical events and transactions when the purchasing power of the dollar was substantially different than now. The effects of inflation on most utilities, including the Company, are most significant in the areas of depreciation and utility plant. The Company could not replace its non-nuclear utility plant and equipment for the historical cost value at which they are recorded on the Company's books. In addition, the Company would not replace these with identical assets due to technological advances and competitive and regulatory changes that have occurred. In light of these considerations, the depreciation charges in operating expenses do not reflect the cost of providing service if new generating facilities were installed. The Company will seek additional revenue or reallocate resources, if possible, to cover the costs of maintaining service as assets are replaced or retired. FINANCIAL POSITION, LIQUIDITY AND CAPITAL RESOURCES FINANCIAL POSITION. The Company's capital structure at December 31, 1997 was 51.8% long-term debt, 7.7% preferred stock and 40.5% common equity, as compared to 53.1%, 7.9% and 39.0% respectively, at December 31, 1996. The culmination of the termination, restatement or amendment of IPP contracts will significantly increase the leverage of the Company to nearly 65% at the time of closing. Through the anticipated increased operating cash flow resulting from the MRA and PowerChoice agreement, the planned rapid repayment of debt should deleverage the Company over time. Book value of the common stock was $18.89 per share at December 31, 1997, as compared to $17.91 per share at December 31, 1996. With the issuance of equity at below book value to the IPP Parties as part of the MRA, book value per share will be diluted. In addition, earnings per share will be diluted by the effect of the issuance to the IPP Parties of approximately 42.9 million shares of the Company's common stock. The Company's EBITDA for 1997 was approximately $962 million, and upon implementation of the MRA and PowerChoice is expected to increase to approximately $1,200 million to $1,300 million 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. The 1997 ratio of earnings to fixed charges was 2.02 times. The ratios of earnings to fixed charges for 1996 and 1995 were 1.57 times and 2.29 times, respectively. The change in the ratio was primarily due to changes in earnings during the period. Assuming the MRA is implemented, the ratio of earnings to fixed charges will substantially decrease in the future, since the MRA and PowerChoice agreement will have the effect of substantially depressing earnings during its five-year term, while at the same time substantially improving operating cash flows. The primary objective of the MRA is to convert a large and growing off-balance sheet payment obligation that threatens the financial viability of the Company into a fixed and manageable capital obligation. COMMON STOCK DIVIDEND. The Board of Directors omitted the common stock dividend beginning the first quarter of 1996. This action was taken to help stabilize the Company's financial condition and provide flexibility as the Company addresses growing pressure from mandated power purchases and weaker sales and is the primary reason for the increase in the cash balance. In making future dividend decisions, the Board of Directors will evaluate, along with standard business considerations, the financial condition of the Company, the closing of the MRA and implementation of PowerChoice, or the failure to implement such actions, contractual restrictions that might be entered into in conjunction with financing the MRA, the degree of competitive pressure on its prices, the level of available cash flow and retained earnings and other strategic considerations. The Company expects to dedicate a substantial portion of its future expected positive cash flow to reduce the leverage created in connection with the implementation of the MRA. The PowerChoice agreement establishes limits to the annual amount of common and preferred stock dividends that can be paid by the regulated business. The limit is based upon the amount of net income each year, plus a specified amount ranging from $50 million in 1998 to $100 million in 2000. The dividend limitation is subject to review after the term of the PowerChoice agreement. Furthermore, the Company forecasts that earnings for the five-year term of the PowerChoice agreement will be substantially depressed, as non-cash amortization of the MRA regulatory asset is occurring and the interest costs on the IPP debt is the greatest. See "Accounting Implications of the PowerChoice Agreement and Master Restructuring Agreement." CONSTRUCTION AND OTHER CAPITAL REQUIREMENTS. The Company's total capital requirements consist of amounts for the Company's construction program (see Item 8. Financial Statements and Supplementary Data - "Note 9. Commitments and Contingencies - Construction Program,"). The January 1998 ice storm damage restoration costs may further add to these requirements (see Item 8. Financial Statements and Supplementary Data - "Note 13. Subsequent Event"), nuclear decommissioning funding requirements (See Item 8. Financial Statements and Supplementary Data - "Note 3. Nuclear Operations - Nuclear Plant Decommissioning" and - "NRC Policy Statement and Proposal"), working capital needs, maturing debt issues and sinking fund provisions on preferred stock, as well as requirements to complete the MRA and accomplish the restructuring contemplated by the PowerChoice agreement. Annual expenditures for the years 1995 to 1997 for construction and nuclear fuel, including related AFC and overheads capitalized, were $345.8 million, $352.1 million and $290.8 million, respectively, and are budgeted to be approximately $358 million for 1998 and to range from $279 - $352 million for each of the subsequent four years. These estimates include construction expenditures for non- nuclear generation of $20 million to $38 million per year. In addition to the assumed cost of the MRA requirements, as described below, mandatory debt and preferred stock retirements are expected to add approximately another $77 million to the 1998 estimate of capital requirements. The estimate of construction additions included in capital requirements for the period 1998 to 2002 will be reviewed by management to give effect to the storm restoration costs and the overall objective of further reducing construction spending where possible. See discussion in "Liquidity and Capital Resources" section below, which describes how management intends to meet its financing needs for this five-year period. Under the MRA, the Company will pay an aggregate of $3,616 million in cash. The Company expects to issue senior unsecured debt to fund this requirement, which is expected to consist of both debt issued through a public market offering and debt issues to banks which would serve to replace its existing $804 million senior debt facility, discussed below. The Company's preferred shareholders gave the Company approval to increase the amount of unsecured debt the Company may issue by $5 billion. Previously, the Company was able to issue $700 million under the restrictions of its amended Certificate of Incorporation. This authorization will enable the issuance of unsecured debt to consummate the MRA. In addition, the Company believes that the ability to use unsecured indebtedness will increase its flexibility in planning and financing its business activities. LIQUIDITY AND CAPITAL RESOURCES. External financing plans are subject to periodic revision as underlying assumptions are changed to reflect developments, market conditions and, most importantly, conclusion of the MRA and implementation of PowerChoice. The ultimate level of financing during the period 1998 through 2002 will be affected by, among other things: the timing and outcome of the MRA and the cash tax benefits anticipated because the MRA is expected to result in a net operating loss for 1998 income tax purposes; the implementation of the PowerChoice agreement, levels of common dividend payments, if any, and preferred dividend payments; the results of the auction of the Company's fossil and hydro assets; the Company's competitive position and the extent to which competition penetrates the Company's markets; uncertain energy demand due to the weather and economic conditions; and the effects of the ice storm that struck a portion of the Company's service territory in early 1998. The proceeds of the sale of the fossil and hydro assets will be subject to the terms of the Company's mortgage indenture and the note indenture that will be entered into in connection with the MRA debt financing. The Company could also be affected by the outcome of the NRC's consideration of new rules for adequate financial assurance of nuclear decommissioning obligations. (See Item 8. Notes to Consolidated Financial Statements - "Note 3. Nuclear Operations - NRC Policy Statement and Proposal" and "Note 13. Subsequent Event"). The Company has an $804 million senior debt facility with a bank group, consisting of a $255 million term loan facility, a $125 million revolving credit facility and $424 million for letters of credit. The letter of credit facility provides credit support for the adjustable rate pollution control revenue bonds issued through the NYSERDA. The interest rate applicable to the senior debt facility is variable based on certain rate options available under the agreement and currently approximates 7.7% (but is capped at 15%). As of December 31, 1997, the amount outstanding under the senior debt facility was $529 million, consisting of $105 million under the term loan facility and a $424 million letter of credit, leaving the Company with $275 million of borrowing capability under the facility. The facility expires on June 30, 1999 (subject to earlier termination if the Company separates its fossil/hydro generation business from its transmission and distribution business, or any other significant restructuring plan). The Company is currently negotiating with the lenders to replace the senior debt facility with a larger facility to finance a portion of the MRA. This facility is collateralized by first mortgage bonds which were issued on the basis of additional property under the earnings test required under the mortgage trust indenture ("First Mortgage Bonds"). As of December 31, 1997, the Company could issue an additional $1,396 million aggregate principal amount of First Mortgage Bonds under the Company's mortgage trust indenture. This amount is based upon retired bonds without regard to an interest coverage test. The Company is presently precluded from issuing First Mortgage Bonds based on additional property. Although no assurance can be provided, the Company believes 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. There is risk throughout the electric industry that credit ratings could decline if the issue of stranded cost recovery is not satisfactorily resolved. In the event the MRA is not closed, and comparable solutions are not available, the Company will undertake other actions necessary to act in the best interests of stockholders and other constituencies. Ordinarily, construction related short-term borrowings are refunded with long-term securities on a periodic basis. This approach generally results in the Company showing a working capital deficit. This has not been the case in the last two years as the Company's cash balance has increased, reflecting suspension of the common stock dividend in 1996. Working capital deficits may also be a result of the seasonal nature of the Company's operations as well as timing differences between the collection of customer receivables and the payment of fuel and purchased power costs. The Company believes it has sufficient borrowing capacity to fund deficits as necessary in the near term. However, the Company's borrowing capacity to fund such deficits may be affected by the factors discussed above relating to the Company's external financial plans. Since 1995, past-due accounts receivable have increased significantly. A number of factors have contributed to the increase, including rising prices (particularly to residential customers). Rising prices have been driven by increased payments to IPPs and high taxes and have been passed on in customers' bills. The stagnant economy in the Company's service territory since the early 1990's has adversely affected collection of past-due accounts. Also, laws, regulations and regulatory policies impose more stringent collection limitations on the Company than those imposed on business in general; for example, the Company faces more stringent requirements to terminate service during the winter heating season. The increase in the allowance for doubtful accounts was attributable to the reassessment of the collection risk associated with residential accounts receivable and arrears. The Company has implemented a number of collection initiatives that are expected to result in lower arrears levels and potentially lower the allowance for doubtful accounts. The Company has and will continue to implement a variety of strategies to improve its collection of past due accounts and reduce its bad debt expense. The information gathered in developing these strategies enabled management to update its risk assessment of the accounts receivable portfolio. Based on this assessment, management determined that the level of risk associated primarily with the older accounts had increased and the historical loss experience no longer applied. Accordingly, the Company determined that a significant portion of the past-due accounts receivable (principally of residential customers) might be uncollectible, and had written-off a substantial number of these accounts as well as increased its allowance for doubtful accounts in 1996. In 1997 and 1996, the Company charged $46.5 million and $127.6 million, respectively to bad debt expense. The allowance for doubtful accounts is based on assumptions and judgments as to the effectiveness of collection efforts. Future results with respect to collecting the past-due receivables may prove to be different from those anticipated. Although the Company has experienced a level of improvement in collection efforts, future results are necessarily dependent upon the following factors, including, among other things, the effectiveness of the strategies discussed above, the support of regulators and legislators to allow utilities to move towards commercial collection practices and improvement in the condition of the economy in the Company's service territory. The Company has been pursuing PowerChoice to address high prices that are the result of traditional price regulation, but the introduction of competition requires that policies and practices that were central to traditional regulation, including those involving collections, be changed so as not to jeopardize the benefits of competition. NET CASH PROVIDED BY OPERATING ACTIVITIES decreased $162.8 million in 1997 primarily due to a decrease of $105.9 million in the amount of accounts receivable sold under the accounts receivable sales program (which the Company has budgeted to restore in 1998) partially offset by an increase in deferred taxes of $53.9 million. NET CASH USED IN INVESTING ACTIVITIES increased $62.4 million in 1997 primarily as a result of an increase in other cash investments of $116.1 million offset by a decrease in the acquisition of utility plant of $62.9 million. NET CASH USED IN FINANCING ACTIVITIES decreased $106.1 million, primarily due to a net reduction of $94.7 million in the payments on long-term debt. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA A. FINANCIAL STATEMENTS Report of Management Report of Independent Accountants Consolidated Statements of Income and Retained Earnings for each of the three years in the period ended December 31, 1997. Consolidated Balance Sheets at December 31, 1997 and 1996. Consolidated Statements of Cash Flows for each of the three years in the period ended December 31, 1997. Notes to Consolidated Financial Statements. REPORT OF MANAGEMENT The consolidated financial statements of the Company and its subsidiaries were prepared by and are the responsibility of management. Financial information contained elsewhere in this Annual Report is consistent with that in the financial statements. To meet its responsibilities with respect to financial information, management maintains and enforces a system of internal accounting controls, which is designed to provide reasonable assurance, on a cost effective basis, as to the integrity, objectivity and reliability of the financial records and protection of assets. This system includes communication through written policies and procedures, an organizational structure that provides for appropriate division of responsibility and the training of personnel. This system is also tested by a comprehensive internal audit program. In addition, the Company has a Corporate Policy Register and a Code of Business Conduct (the "Code") that supply employees with a framework describing and defining the Company's overall approach to business and require all employees to maintain the highest level of ethical standards as well as requiring all management employees to formally affirm their compliance with the Code. The financial statements have been audited by Price Waterhouse LLP, the Company's independent accountants, in accordance with GAAP. In planning and performing its audit, Price Waterhouse LLP considered the Company's internal control structure in order to determine auditing procedures for the purpose of expressing an opinion on the financial statements, and not to provide assurance on the internal control structure. The independent accountants' audit does not limit in any way management's responsibility for the fair presentation of the financial statements and all other information, whether audited or unaudited, in this Annual Report. The Audit Committee of the Board of Directors, consisting of five outside directors who are not employees, meets regularly with management, internal auditors and Price Waterhouse LLP to review and discuss internal accounting controls, audit examinations and financial reporting matters. Price Waterhouse LLP and the Company's internal auditors have free access to meet individually with the Audit Committee at any time, without management being present. /s/ William E. Davis William E. Davis Chairman of the Board and Chief Executive Officer Niagara Mohawk Power Corporation REPORT OF INDEPENDENT ACCOUNTANTS To the Stockholders and Board of Directors of Niagara Mohawk Power Corporation In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income and retained earnings and of cash flows present fairly, in all material respects, the financial position of Niagara Mohawk Power Corporation and its subsidiaries at December 31, 1997 and 1996, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1997, in conformity with generally accepted accounting principles. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with generally accepted auditing standards which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for the opinion expressed above. As discussed in Note 15 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 2. As discussed in Note 2, the Company believes that it continues to meet the requirements for 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. In the event that the Company is unable to complete the termination, restatement or amendment of independent power producer contracts and implement PowerChoice, this conclusion could change in 1998 and beyond, resulting in material adverse effects on the Company's financial condition and results of operations. As discussed in Note 2, the Company discontinued application of SFAS No. 71 for its non-nuclear generation business in 1996. /s/ Price Waterhouse LLP Price Waterhouse LLP Syracuse, New York March 26, 1998, except Note 2 (third paragraph) and Note 15, as to which the date is May 29, 1998
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES - --------------------------------------------------------- CONSOLIDATED STATEMENTS OF INCOME AND RETAINED EARNINGS In thousands of dollars For the year ended December 31, 1997 1996 1995 - ----------------------------------------------------------------- Operating revenues: Electric $3,309,441 $3,308,979 $3,335,548 Gas 656,963 681,674 581,790 - ----------------------------------------------------------------- 3,966,404 3,990,653 3,917,338 - ----------------------------------------------------------------- Operating expenses: Fuel for electric generation 179,455 181,486 165,929 Electricity purchased 1,236,108 1,182,892 1,137,937 Gas purchased 345,610 370,040 276,232 Other operation and maintenance expenses 835,282 928,224 817,897 Depreciation and amortization (Note 1) 339,641 329,827 317,831 Other taxes 471,469 475,846 517,478 - ----------------------------------------------------------------- 3,407,565 3,468,315 3,233,304 - ----------------------------------------------------------------- Operating income 558,839 522,338 684,034 - ----------------------------------------------------------------- Other income (Note 1) 24,997 35,943 3,069 - ----------------------------------------------------------------- Income before interest charges 583,836 558,281 687,103 - ----------------------------------------------------------------- Interest charges (Note 1) 273,906 278,033 279,674 - ----------------------------------------------------------------- Income before federal and foreign income taxes 309,930 280,248 407,429 Federal and foreign income taxes (Note 7) 126,595 102,494 159,393 - ----------------------------------------------------------------- Income before extraordinary item 183,335 177,754 248,036 Extraordinary item for the discontinuance of regulatory accounting principles, net of income taxes of $36,273 in 1996 (Note 2) - (67,364) - - ----------------------------------------------------------------- Net income (Note 15) 183,335 110,390 248,036 Dividends on preferred stock 37,397 38,281 39,596 - ----------------------------------------------------------------- Balance available for common stock 145,938 72,109 208,440 Dividends on common stock - - 161,650 - ----------------------------------------------------------------- 145,938 72,109 46,790 Retained earnings at beginning of year 657,482 585,373 538,583 - ----------------------------------------------------------------- Retained earnings at end of year $ 803,420 $ 657,482 $ 585,373 ================================================================= Average number of shares of common stock outstanding (in thousands) 144,404 144,350 144,329 Basic and diluted earnings per average share of common stock before extraordinary item $ 1.01 $ 0.97 $ 1.44 Extraordinary item $ - $ (0.47) $ - - ----------------------------------------------------------------- Basic and diluted earnings per average share of common stock $ 1.01 $ 0.50 $ 1.44 Dividends on common stock paid per share $ - $ - $ 1.12 ================================================================= () Denotes deduction The accompanying notes are an integral part of these financial statements
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES - --------------------------------------------------------- CONSOLIDATED BALANCE SHEETS In thousands of dollars At December 31, 1997 1996 - --------------------------------------------------------- ASSETS Utility plant (Note 1): Electric plant $ 8,752,865 $ 8,611,419 Nuclear Fuel 577,409 573,041 Gas plant 1,131,541 1,082,298 Common plant 319,409 292,591 Construction work in progress 294,650 279,992 - --------------------------------------------------------- Total utility plant 11,075,874 10,839,341 Less: Accumulated depreciation and amortization 4,207,830 3,881,726 - --------------------------------------------------------- Net utility plant 6,868,044 6,957,615 - --------------------------------------------------------- Other property and investments 371,709 257,145 - --------------------------------------------------------- Current assets: Cash, including temporary cash investments of $315,708 and $223,829, respectively 378,232 325,398 Accounts receivable (less allowance for doubtful accounts of $62,500 and $52,100, respectively) (Notes 1 and 9) 492,244 373,305 Materials and supplies, at average cost: Coal and oil for production of electricity 27,642 20,788 Gas storage 39,447 43,431 Other 118,308 120,914 Prepaid taxes 15,518 11,976 Other 20,309 25,329 - --------------------------------------------------------- 1,091,700 921,141 - --------------------------------------------------------- Regulatory assets (Note 2): Regulatory tax asset 399,119 416,599 Deferred finance charges 239,880 239,880 Deferred environmental restoration costs (Note 9) 220,000 225,000 Unamortized debt expense 57,312 65,993 Postretirement benefits other than pensions 56,464 60,482 Other 204,049 206,352 - --------------------------------------------------------- 1,176,824 1,214,306 - --------------------------------------------------------- Other assets 75,864 77,428 - --------------------------------------------------------- $9,584,141 $9,427,635 ========================================================= The accompanying notes are an integral part of these financial statements
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES - --------------------------------------------------------- CONSOLIDATED BALANCE SHEETS In thousands of dollars At December 31, 1997 1996 - --------------------------------------------------------- CAPITALIZATION AND LIABILITIES Capitalization (Note 5): Common stockholders' equity: Common stock, issued 144,419,351 and 144,365,214 shares, respectively $ 144,419 $ 144,365 Capital stock premium and expense 1,779,688 1,783,725 Retained earnings 803,420 657,482 - --------------------------------------------------------- 2,727,527 2,585,572 Non-redeemable preferred stock 440,000 440,000 Mandatorily redeemable preferred stock 76,610 86,730 Long-term debt 3,417,381 3,477,879 - --------------------------------------------------------- Total capitalization 6,661,518 6,590,181 - --------------------------------------------------------- Current liabilities: Long-term debt due within one year (Note 5) 67,095 48,084 Sinking fund requirements on redeemable preferred stock (Note 5) 10,120 8,870 Accounts payable 263,095 271,830 Payable on outstanding bank checks 23,720 32,008 Customers' deposits 18,372 15,505 Accrued taxes 9,005 4,216 Accrued interest 62,643 63,252 Accrued vacation pay 36,532 36,436 Other 64,756 52,455 - --------------------------------------------------------- 555,338 532,656 - --------------------------------------------------------- Regulatory liabilities (Note 2): Deferred finance charges 239,880 239,880 - --------------------------------------------------------- Other liabilities: Accumulated deferred income taxes (Notes 1 and 7) 1,387,032 1,357,518 Employee pension and other benefits (Note 8) 240,211 238,688 Deferred pension settlement gain 12,438 19,269 Unbilled revenues (Note 1) 43,281 49,881 Other 224,443 174,562 - --------------------------------------------------------- 1,907,405 1,839,918 - --------------------------------------------------------- Commitments and contingencies (Notes 2 and 9): Liability for environmental restoration 220,000 225,000 - --------------------------------------------------------- $9,584,141 $9,427,635 ========================================================= The accompanying notes are an integral part of these financial statements
(CAPTION> NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES - --------------------------------------------------------- CONSOLIDATED STATEMENTS OF CASH FLOWS INCREASE (DECREASE) IN CASH In thousands of dollars For the year ended December 31, 1997 1996 1995 - ----------------------------------------------------------------- Cash flows from operating activities: Net income $ 183,335 $ 110,390 $ 248,036 Adjustments to reconcile net income to net cash provided by operating activities: Extraordinary item for the discontinuance of regulatory accounting principles, net of income taxes - 67,364 - Depreciation and amortization 339,641 329,827 317,831 Electric margin recoverable - - 58,588 Amortization of nuclear fuel 25,241 38,077 34,295 Provision for deferred income taxes 46,994 (6,870) 114,917 Gain on sale of subsidiary - (15,025) (11,257) Unbilled revenues (6,600) 21,471 (71,258) Net accounts receivable (118,939) 121,198 56,748 Materials and supplies (1,306) 2,265 13,663 Accounts payable and accrued expenses (11,175) 8,224 (47,048) Accrued interest and taxes 4,180 (11,750) (35,440) Changes in other assets and liabilities 76,204 35,231 20,930 - ----------------------------------------------------------------- Net cash provided by operating activities 537,575 700,402 700,005 - ----------------------------------------------------------------- Cash flows from investing activities: Construction additions (286,389) (296,689) (332,443) Nuclear fuel (4,368) (55,360) (13,361) Less: Allowance for other funds used during construction 5,310 3,665 1,063 - ----------------------------------------------------------------- Acquisition of utility plant (285,447) (348,384) (344,741) Decrease in materials and Materials and supplies related ton construction 1,042 8,362 3,346 Accounts payable and accrued expenses related to construction (2,794) 2,056 (7,112) Other investments (115,533) 541 (115,818) Proceeds from sale of sub- sidiary (net of cash sold) - 14,600 161,087 Other 8,761 (8,786) 26,234 - ----------------------------------------------------------------- Net cash used in investing activities (393,971) (331,611) (277,004) - ----------------------------------------------------------------- Cash flows from financing activities: Proceeds from long-term debt - 105,000 346,000 Redemption of preferred stock (8,870) (10,400) (10,950) Reductions of long-term debt (44,600) (244,341) (73,415) Net change in short-term debt - - (416,750) Dividends paid (37,397) (38,281) (201,246) Other 97 (8,846) (7,495) - ----------------------------------------------------------------- Net cash used in financing activities (90,770) (196,868) (363,856) - ----------------------------------------------------------------- Net increase in cash 52,834 171,923 59,145 Cash at beginning of year 325,398 153,475 94,330 - ----------------------------------------------------------------- Cash at end of year $ 378,232 $ 325,398 $ 153,475 ================================================================= Supplemental disclosures of cash flow information: Cash paid during the year for: Interest $ 279,957 $ 286,497 $ 290,352 Income taxes $ 82,331 $ 95,632 $ 47,378 ================================================================= The accompanying notes are an integral part of these financial statements
Notes to Consolidated Financial Statements NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES The Company is subject to regulation by the PSC and FERC with respect to its rates for service under a methodology which establishes prices based on the Company's cost. The Company's accounting policies conform to GAAP, including the accounting principles for rate-regulated entities with respect to the Company's nuclear, transmission, distribution and gas operations (regulated business), and are in accordance with the accounting requirements and ratemaking practices of the regulatory authorities. The Company discontinued the application of regulatory accounting principles to its fossil and hydro generation operations in 1996 (see Note 2). In order to be in conformity with GAAP, management is required to use estimates in the preparation of the Company's financial statements. PRINCIPLES OF CONSOLIDATION: The consolidated financial statements include the Company and its wholly-owned subsidiaries. Intercompany balances and transactions have been eliminated. UTILITY PLANT: The cost of additions to utility plant and replacements of retirement units of property are capitalized. Cost includes direct material, labor, overhead and AFC. Replacement of minor items of utility plant and the cost of current repairs and maintenance is charged to expense. Whenever utility plant is retired, its original cost, together with the cost of removal, less salvage, is charged to accumulated depreciation. The discontinuation of SFAS No. 71 did not affect the carrying value of the Company's utility plant. ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION: The Company capitalizes AFC in amounts equivalent to the cost of funds devoted to plant under construction for its regulated business. AFC rates are determined in accordance with FERC and PSC regulations. The AFC rate in effect during 1997 was 9.28%. AFC is segregated into its two components, borrowed funds and other funds, and is reflected in the "Interest charges" and the "Other income" sections, respectively, of the Consolidated Statements of Income. The amount of AFC credits recorded in each of the three years ended December 31, in thousands of dollars, was as follows: 1997 1996 1995 ---- ---- ---- Other income $5,310 $3,665 $1,063 Interest charges 4,396 3,690 7,987 As a result of the discontinued application of SFAS No. 71 to the fossil and hydro operations, the Company capitalizes interest cost associated with the construction of fossil/hydro assets. DEPRECIATION, AMORTIZATION AND NUCLEAR GENERATING PLANT DECOMMISSIONING COSTS: For accounting and regulatory purposes, depreciation is computed on the straight-line basis using the license lives for nuclear and hydro classes of depreciable property and the average service lives for all other classes. The percentage relationship between the total provision for depreciation and average depreciable property was approximately 3% for the years 1995 through 1997. The Company performs depreciation studies to determine service lives of classes of property and adjusts the depreciation rates when necessary. Estimated decommissioning costs (costs to remove a nuclear plant from service in the future) for the Company's Unit 1 and its share of Unit 2 are being accrued over the service lives of the units, recovered in rates through an annual allowance and currently charged to operations through depreciation. The Company expects to commence decommissioning of both units shortly after cessation of operations at Unit 2 (currently planned for 2026), using a method which removes or decontaminates the Units components promptly at that time. See Note 3 - "Nuclear Plant Decommissioning." The FASB issued an exposure draft in February 1996 entitled "Accounting for Certain Liabilities Related to Closure or Removal Costs of Long-Lived Assets." The scope of the project includes certain plant decommissioning costs, including those for fossil, hydro and nuclear plants. If approved, a liability would be recognized, with a corresponding plant asset, whenever a legal or constructive obligation exists to perform dismantlement or removal activities. The Company currently recognizes the liability for nuclear decommissioning over the service life of the plant as an increase to accumulated depreciation and does not recognize the closure or removal obligation associated with its fossil and hydro plants. The Company's PowerChoice agreement provides for the recovery of nuclear decommissioning costs. As discussed in Note 2, the Company intends to sell its fossil and hydro generating assets through an auction process. To the extent the assets are sold, the effect of this exposure draft on the Company should be mitigated. However, the Company cannot predict the results of the auction. The adoption of the proposed standard is not expected to impact the cash flow from these assets. The FASB continues to discuss the issues addressed in the exposure draft, as well as the timing of its implementation. Amortization of the cost of nuclear fuel is determined on the basis of the quantity of heat produced for the generation of electric energy. The cost of disposal of nuclear fuel, which presently is $.001 per KWh of net generation available for sale, is based upon a contract with the DOE. These costs are charged to operating expense and recovered from customers through base rates or through the fuel adjustment clause. REVENUES: Revenues are based on cycle billings rendered to certain customers monthly and others bi-monthly for energy consumed and not billed at the end of the fiscal year. At December 31, 1997 and 1996, approximately $8.6 million and $11.1 million, respectively, of unbilled electric revenues remained unrecognized in results of operations, are included in "Other liabilities." Under the Company's PowerChoice agreement, the amount of unrecognized electric unbilled revenue as of the PowerChoice implementation date will be netted against certain other regulatory assets and liabilities. Thereafter, changes in electric unbilled revenues will no longer be deferred. In 1995, the Company used $71.5 million of electric unbilled revenues to reduce the 1995 revenue requirement. At December 31, 1997 and 1996, $34.7 million and $38.8 million, respectively, of unbilled gas revenues remain unrecognized in results of operations and may be used to reduce future gas revenue requirements. The unbilled revenues included in accounts receivable at December 31, 1997 and 1996, were $211.9 million and $218.5 million, respectively. The Company's tariffs include electric and gas adjustment clauses under which energy and purchased gas costs, respectively, above or below the levels allowed in approved rate schedules, are billed or credited to customers. The Company, as authorized by the PSC, charges operations for energy and purchased gas cost increases in the period of recovery. The PSC has periodically authorized the Company to make changes in the level of allowed energy and purchased gas costs included in approved rate schedules. As a result of such periodic changes, a portion of energy costs deferred at the time of change would not be recovered or may be overrecovered under the normal operation of the electric and gas adjustment clauses. However, the Company has to date been permitted to defer and bill or credit such portions to customers, through the electric and gas adjustment clauses, over a specified period of time from the effective date of each change. The Company's electric FAC provides for partial pass-through of fuel and purchased power cost fluctuations from amounts forecast, with the Company absorbing a portion of increases or retaining a portion of decreases up to a maximum of $15 million per rate year. Thereafter, 100% of the fluctuation is passed on to ratepayers. The Company also shares with ratepayers fluctuations from amounts forecast for net resale margin and transmission benefits, with the Company retaining/absorbing 40% and passing 60% through to ratepayers. The amounts retained or absorbed in 1995 through 1997 were not material. Under the PowerChoice agreement, the FAC will be discontinued. In December 1996, the Company, Multiple Intervenors and the PSC staff reached a three year gas settlement that was conditionally approved by the PSC. The agreement eliminated the gas adjustment clause and established a gas commodity cost adjustment clause ("CCAC"). The Company's gas CCAC provides for the collection or passback of certain increases or decreases from the base commodity cost of gas. The maximum annual risk or benefit to the Company is $2.25 million. All savings and excess costs beyond that amount will flow to ratepayers. For a discussion of the ratemaking associated with non-commodity gas costs, see Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - "Other Federal and State Regulatory Initiatives - Multi-Year Gas Rate Settlement Agreement." FEDERAL INCOME TAXES: As directed by the PSC, the Company defers any amounts payable pursuant to the alternative minimum tax rules. Deferred investment tax credits are amortized over the useful life of the underlying property. STATEMENT OF CASH FLOWS: The Company considers all highly liquid investments, purchased with a remaining maturity of three months or less, to be cash equivalents. EARNINGS PER SHARE: Basic earnings per share ("EPS") is computed based on the weighted average number of common shares outstanding for the period. The number of options outstanding at December 31, 1997, 1996 and 1995 that could potentially dilute basic EPS, (but are considered antidilutive for each period because the options exercise price was greater than the average market price of common shares), is immaterial. Therefore, the calculation of both basic and dilutive EPS are the same for each period. RECLASSIFICATIONS: Certain amounts from prior years have been reclassified on the accompanying Consolidated Financial Statements to conform with the 1997 presentation. COMPREHENSIVE INCOME: In June 1997, FASB issued SFAS No. 130. SFAS No. 130 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. All components of comprehensive income are required to be reported in a new financial statement that is displayed with equal prominence as existing financial statements. The Company will be required to adopt SFAS No. 130 on January 1, 1998. The Company does not expect that adoption of SFAS No. 130 will have a significant impact on its reporting and disclosure requirements. SEGMENT DISCLOSURES: Also in June 1997, FASB issued SFAS No. 131. SFAS No. 131 establishes standards for additional disclosure about operating segments for interim and annual financial statements. More specifically, it requires financial information to be disclosed for segments whose operating results are reviewed by the chief operating officer for decisions on resource allocation. It also requires related disclosures about product and services, geographic areas and major customers. The Company will be required to adopt SFAS No. 131 for the fiscal year ending December 31, 1998. The Company does not expect that the adoption of SFAS No. 131 will have a significant impact on its reporting and disclosure requirements. PENSION AND OTHER POSTRETIREMENT BENEFITS: In February 1998, FASB issued SFAS No. 132. SFAS No. 132 revises employers' disclosures about pension and other postretirement benefit plans. It does not change the measurement or recognition of those plans. It standardizes the disclosure requirements for pensions and other postretirement benefits to the extent practicable and requires additional information on changes in the benefit obligations and fair values of plan assets. The Company will be required to adopt SFAS No. 132 for the fiscal year ending December 31, 1998. The Company does not expect the adoption of SFAS No. 132 will have a significant impact on its reporting and disclosure requirements. NOTE 2. 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. Substantively, these principles permit 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 $937 million, net of approximately $240 million of regulatory liabilities at December 31, 1997. These regulatory assets are probable of recovery. The portion of the $937 million which has been allocated to the nuclear generation and electric transmission and distribution business is approximately $810 million, which is net of approximately $240 million of regulatory liabilities. Regulatory assets allocated to the rate-regulated gas distribution business are $127 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) was 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 $4,000 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 upon the closing of the MRA. The charge to expense will be determined as 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). 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 and those not so restructured 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 the EITF consensus. In addition, 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. In the event the MRA and PowerChoice are implemented, the Company believes that the regulated cash flows to be derived from prices it will charge for electric service over 10 years, including the 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 the Company's ability to pay dividends. 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 December 31, 1997. As described in 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 December 31, 1997, would be approximately $526.5 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. The Company has recorded the following regulatory assets on its Consolidated Balance Sheets reflecting the rate actions of its regulators: REGULATORY TAX ASSET represents the expected future recovery from ratepayers of the tax consequences of temporary differences between the recorded book bases and the tax bases of assets and liabilities. This amount is primarily timing differences related to depreciation. These amounts are amortized and recovered as the related temporary differences reverse. In January 1993, the PSC issued a Statement of Interim Policy on Accounting and Ratemaking Procedures that required adoption of SFAS No. 109 on a revenue- neutral basis. DEFERRED FINANCE CHARGES represent the deferral of the discontinued portion of AFC related to CWIP at Unit 2 which was included in rate base. In 1985, pursuant to PSC authorization, the Company discontinued accruing AFC on CWIP for which a cash return was being allowed. This amount, which was accumulated in deferred debit and credit accounts up to the commercial operation date of Unit 2, awaits future disposition by the PSC. A portion of the deferred credit could be utilized to reduce future revenue requirements over a period shorter than the life of Unit 2, with a like amount of deferred debit amortized and recovered in rates over the remaining life of Unit 2. PowerChoice provides for netting, and thereby elimination of the debit and credit balances of deferred finance charges. DEFERRED ENVIRONMENTAL RESTORATION COSTS represent the Company's share of the estimated costs to investigate and perform certain remediation activities at both Company-owned sites and non- owned sites with which it may be associated. The Company has recorded a regulatory asset representing the remediation obligations to be recovered from ratepayers. PowerChoice and the Company's gas settlement provide for the recovery of these costs over the settlement periods. The Company believes future costs, beyond the settlement periods, will continue to be recovered in rates. See Note 9 - "Environmental Contingencies." UNAMORTIZED DEBT EXPENSE represents the costs to issue and redeem certain long-term debt securities which were retired prior to maturity. These amounts are amortized as interest expense ratably over the lives of the related issues in accordance with PSC directives. POSTRETIREMENT BENEFITS OTHER THAN PENSIONS represent the excess of such costs recognized in accordance with SFAS No. 106 over the amount received in rates. In accordance with the PSC policy statement, postretirement benefit costs other than pensions are being phased-in to rates over a five-year period and amounts deferred will be amortized and recovered over a period not to exceed 20 years. Substantially all of the Company's regulatory assets described above are being amortized to expense and recovered in rates over periods approved in the Company's electric and gas rate cases, respectively. NOTE 3. NUCLEAR OPERATIONS NUCLEAR PLANT DECOMMISSIONING: The Company's site specific cost estimates for decommissioning Unit 1 and its ownership interest in Unit 2 at December 31, 1997 are as follows: Unit 1 Unit 2 ------ ------ Site Study (year) 1995 1995 End of Plant Life (year) 2009 2026 Radioactive Dismantlement to Begin (year) 2026 2028 Method of Decommissioning Delayed Immediate Dismantlement Dismantlement Cost of Decommissioning (in January 1998 dollars) In millions of dollars Radioactive Components $481 $201 Non-radioactive Components 117 48 Fuel Dry Storage/Continuing Care 78 43 ---- ---- $676 $292 ==== ==== The Company estimates that by the time decommissioning is completed, the above costs will ultimately amount to $1.7 billion and $.9 billion for Unit 1 and Unit 2, respectively, using approximately 3.5% as an annual inflation factor. In addition to the costs mentioned above, the Company expects to incur post-shutdown costs for plant rampdown, insurance and property taxes. In 1998 dollars, these costs are expected to amount to $119 million and $63 million for Unit 1 and the Company's share of Unit 2, respectively. The amounts will escalate to $210 million and $190 million for Unit 1 and the Company's share of Unit 2, respectively, by the time decommissioning is completed. In 1997, the Company made adjustments to the cash flow assumptions at Unit 1 for fuel dry storage, radioactive cost components, property tax and insurance, to more accurately reflect the estimated cost of each cost component. The revisions reduced the total cost estimate by approximately $10 million (in 1998 dollars). NRC regulations require owners of nuclear power plants to place funds into an external trust to provide for the cost of decommissioning radioactive portions of nuclear facilities and establish minimum amounts that must be available in such a trust at the time of decommissioning. The annual allowance for Unit 1 and the Company's share of Unit 2 was approximately $23.7 million, for each of the three years ended December 31, 1997. The amount was based upon the 1993 NRC minimum decommissioning cost requirements of $437 million and $198 million (in 1998 dollars) for Unit 1 and the Company's share of Unit 2, respectively. In Opinion No. 95-21, the Company was authorized, until the PSC orders otherwise, to continue to fund to the NRC minimum requirements. PowerChoice permits rate recovery for all radioactive and non-radioactive cost components for both units, including post-shutdown costs, based upon the amounts estimated in the 1995 site specific studies described above, which are higher than the NRC minimum. There is no assurance that the decommissioning allowance recovered in rates will ultimately aggregate a sufficient amount to decommission the units. The Company believes that if decommissioning costs are higher than currently estimated, the costs would ultimately be included in the rate process. Decommissioning costs recovered in rates are reflected in "Accumulated depreciation and amortization" on the balance sheet and amount to $266.8 million and $217.7 million at December 31, 1997 and 1996, respectively for both units. Additionally at December 31, 1997, the fair value of funds accumulated in the Company's external trusts were $164.7 million for Unit 1 and $51.0 million for its share of Unit 2. The trusts are included in "Other property and investments." Earnings on the external trust aggregated $40.3 million through December 31, 1997 and, because the earnings are available to fund decommissioning, have also been included in "Accumulated depreciation and amortization." Amounts recovered for non-radioactive dismantlement are accumulated in an internal reserve fund which has an accumulated balance of $45.2 million at December 31, 1997. NRC POLICY STATEMENT AND PROPOSAL. The NRC issued a policy statement on the Restructuring and Economic Deregulation of the Electric Utility Industry (the "Policy Statement") in 1997. The Policy Statement addresses the NRC's concerns about the adequacy of decommissioning funds and about the potential impact on operational safety. Current NRC regulations allow a utility to set aside decommissioning funds annually over the estimated life of a plant. The Policy Statement declares the NRC will: - - Continue to conduct reviews of financial qualifications, decommissioning funding and antitrust requirements of nuclear power plants; - - Establish and maintain working relationships with state and federal rate regulators; - - Identify all nuclear power plant owners, indirect as well as direct; and - - Re-evaluate the adequacy of current regulations in light of economic and other changes resulting from rate deregulation. In addition to the above Policy Statement, the NRC is proposing to amend its regulations on decommissioning funding to reflect conditions expected from deregulation of the electric power industry. The amended rule would: - - Revise the definition of an "electric utility" to reflect changes caused by restructuring within the industry. - - Define a "Federal licensee" as any licensee which has the full faith and credit backing of the United States government. Only such licensees could use statements of intent to meet decommissioning financial assurance requirements for power reactors. - - Require nuclear power plant licensees to report to the NRC on the status of their decommissioning funds at least once every three years and annually within five years of the planned end of operation. NRC's present rule contains no such requirement because State and Federal rate-regulating bodies actively monitor these funds. A deregulated nuclear utility would have no such monitoring. - - Permit nuclear licensees to take credit on earnings for prepaid decommissioning trust funds and external sinking funds from the time the funds are set aside through the end of the decommissioning period. The present rule does not permit such credit because it assumed that inflation and taxes would erode any investment return. NRC has decided, however, that this position is not borne out by historical performance of inflation-adjusted funds invested in U.S. Treasury instruments. The Company is unable to predict the outcome of this matter. PSC STAFF'S TENTATIVE CONCLUSIONS ON THE FUTURE OF NUCLEAR GENERATION: On August 27, 1997, the PSC requested comments on its staff's tentative conclusions about how nuclear generation and fossil generation should be treated after decisions are made on the individual electric restructuring agreements currently pending before the PSC. The PSC staff concluded that beyond the transition period (the period covered by the various New York utility restructuring agreements, including PowerChoice), nuclear generation should operate on a competitive basis. In addition, the PSC staff concluded that a sale of generation plants to third parties is the preferred means of determining the fair market value of generation plants and offers the greatest potential for the mitigation of stranded costs. The PSC staff also concluded that recovery of sunk costs, including post shutdown costs, would be subject to review by the PSC and this process should take into account mitigation measures taken by the utility, including the steps it has taken to encourage competition in its service area. In October 1997, the majority of utilities with interests in nuclear power plants, including the Company, requested that the PSC reconsider its staff's nuclear proposal. In addition, the utilities raised the following issues: impediments to nuclear plants operating in a competitive mode; impediments to the sale of plants; responsibility for decommissioning and disposal of spent fuel; safety and health concerns; and environmental and fuel diversity benefits. In light of all of these issues, the utilities recommended that a more formal process be developed to address those issues. The three investor-owned utilities, Rochester Gas and Electric Corporation, Consolidated Edison Company of New York, Inc. and the Company, which are currently pursuing formation of a nuclear operating company in New York State, also filed a response with the PSC in October 1997. The response stated that a forced divestiture of the nuclear plants would add uncertainty to developing a statewide approach to operating the plants and requested that such a forced divestiture proposal be rescinded. The response also stated that implementation of a consolidated six-unit operation would contribute to the mitigation of unrecovered nuclear costs. NYPA, which is also pursuing formation of the nuclear operating company, submitted its own comments which were similar to the comments of the three utilities. PowerChoice contemplates that the Company's nuclear plants will remain part of the Company's regulated business and that the Company will continue efforts to pursue a statewide solution such as the New York Nuclear Operating Company. The settlement stipulates that absent a statewide solution, the Company will file a detailed plan for analyzing proposed solutions for its nuclear assets, including the feasibility of an auction, transfer and/or divestiture within 24 months of PowerChoice approval. At December 31, 1997, the net book value of the Company's nuclear assets was approximately $1.5 billion, excluding the reserve for decommissioning. NUCLEAR LIABILITY INSURANCE: The Atomic Energy Act of 1954, as amended, requires the purchase of nuclear liability insurance from the Nuclear Insurance Pools in amounts as determined by the NRC. At the present time, the Company maintains the required $200 million of nuclear liability insurance. With respect to a nuclear incident at a licensed reactor, the statutory limit for the protection of the public under the Price- Anderson Amendments Act of 1988 which is in excess of the $200 million of nuclear liability insurance, is currently $8.2 billion without the 5% surcharge discussed below. This limit would be funded by assessments of up to $75.5 million for each of the 110 presently licensed nuclear reactors in the United States, payable at a rate not to exceed $10 million per reactor per year. Such assessments are subject to periodic inflation indexing and to a 5% surcharge if funds prove insufficient to pay claims. With the 5% surcharge included, the statutory limit is $8.6 billion. The Company's interest in Units 1 and 2 could expose it to a maximum potential loss, for each accident, of $111.8 million (with 5% assessment) through assessments of $14.1 million per year in the event of a serious nuclear accident at its own or another licensed U.S. commercial nuclear reactor. The amendments also provide, among other things, that insurance and indemnity will cover precautionary evacuations, whether or not a nuclear incident actually occurs. NUCLEAR PROPERTY INSURANCE: The Nine Mile Point Nuclear Site has $500 million primary nuclear property insurance with the Nuclear Insurance Pools (ANI/MRP). In addition, there is $2.25 billion in excess of the $500 million primary nuclear insurance with Nuclear Electric Insurance Limited ("NEIL"). The total nuclear property insurance is $2.75 billion. NEIL also provides insurance coverage against the extra expense incurred in purchasing replacement power during prolonged accidental outages. The insurance provides coverage for outages for 156 weeks, after a 21- week waiting period. NEIL insurance is subject to retrospective premium adjustment under which the Company could be assessed up to approximately $11.3 million per loss. LOW LEVEL RADIOACTIVE WASTE: The Company currently uses the Barnwell, South Carolina waste disposal facility for low level radioactive waste; however, continued access to Barnwell is not assured and the Company has implemented a low level radioactive waste management program so that Unit 1 and Unit 2 are prepared to properly handle interim on-site storage of low level radioactive waste for at least a 10 year period. Under the Federal Low Level Waste Policy Amendment Act of 1985, New York State was required by January 1, 1993 to have arranged for the disposal of all low level radioactive waste within the state or in the alternative, contracted for the disposal at a facility outside the state. To date, New York State has made no funding available to support siting for a disposal facility. NUCLEAR FUEL DISPOSAL COST: In January 1983, the Nuclear Waste Policy Act of 1982 (the "Nuclear Waste Act") established a cost of $.001 per KWh of net generation for current disposal of nuclear fuel and provides for a determination of the Company's liability to the DOE for the disposal of nuclear fuel irradiated prior to 1983. The Nuclear Waste Act also provides three payment options for liquidating such liability and the Company has elected to delay payment, with interest, until the year in which the Company initially plans to ship irradiated fuel to an approved DOE disposal facility. As of December 31, 1997, the Company has recorded a liability of $114.3 million for the disposal of nuclear fuel irradiated prior to 1983. Progress in developing the DOE facility has been slow and it is anticipated that the DOE facility will not be ready to accept deliveries until at least 2010. However, in July 1996, the United States Circuit Court of Appeals for the District of Columbia ruled that the DOE must begin accepting spent fuel from the nuclear industry by January 31, 1998 even though a permanent storage site will not be ready by then. The DOE did not appeal this decision. On January 31, 1997, the Company joined a number of other utilities, states, state agencies and regulatory commissions in filing a suit in the U.S. Court of Appeals for the District of Columbia against the DOE. The suit requested the court to suspend the utilities payments into the Nuclear Waste Fund and to place future payments into an escrow account until the DOE fulfills its obligation to accept spent fuel. On June 3, 1997, the DOE notified utilities that it likely will not meet its January 31, 1998 deadline and that the delay was unavoidable pursuant to the terms of the standard contract with DOE for fuel disposal. DOE also indicated it was not obligated to provide a financial remedy for such unavoidable delay. On November 14, 1997 the United States Court of Appeals for the District of Columbia Circuit issued a writ of mandamus precluding DOE from excusing its own delay on the grounds that it has not yet prepared a permanent repository or interim storage facility. On December 11, 1997, 27 utilities, including the Company, petitioned the DOE to suspend their future payments to the Nuclear Waste Fund until the DOE begins moving fuel from their plant sites. The petition further sought permission to escrow payments to the waste fund beginning in February 1998. On January 12, 1998, the DOE denied the petition. The Company is unable to determine the final outcome of this matter. The Company has several alternatives under consideration to provide additional storage facilities, as necessary. Each alternative will likely require NRC approval, may require other regulatory approvals and would likely require incurring additional costs, which the Company has included in its decommissioning estimates for both Unit 1 and its share of Unit 2. The Company does not believe that the possible unavailability of the DOE disposal facility until 2010 will inhibit operation of either Unit.
NOTE 4. JOINTLY-OWNED GENERATING FACILITIES The following table reflects the Company's share of jointly-owned generating facilities at December 31, 1997. The Company is required to provide its respective share of financing for any additions to the facilities. Power output and related expenses are shared based on proportionate ownership. The Company's share of expenses associated with these facilities is included in the appropriate operating expenses in the Consolidated Statements of Income. Under PowerChoice, the Company will divest all of its fossil and hydro generation assets with a net book value of $1.1 billion, including its interests in jointly-owned facilities. In thousands of dollars ----------------------------------------------- Percent Utility Accumulated Construction Ownership Plant Depreciation Work in Progress - ------------------------------------------------------------------------------------------ Roseton Steam Station Units No. 1 and 2 (a) 25 $ 96,110 $ 54,130 $ 432 Oswego Steam Station Unit No. 6 (b) 76 $ 270,316 $125,089 $ 39 Nine Mile Point Nuclear Station Unit No. 2 (c) 41 $1,507,721 $327,006 $6,748 - ------------------------------------------------------------------------------------------ (a) The remaining ownership interests are Central Hudson Gas and Electric Corporation ("Central Hudson"), the operator of the plant (35%), and Consolidated Edison Company of New York, Inc. (40%). Output of Roseton Units No. 1 and 2, which have a capability of 1,200,000 KW, is shared in the same proportions as the cotenants' respective ownership interests. (b) The Company is the operator. The remaining ownership interest is Rochester Gas and Electric ("RG&E") (24%). Output of Oswego Unit No. 6, which has a capability of 850,000 KW, is shared in the same proportions as the cotenants' respective ownership interests. (c) The Company is the operator. The remaining ownership interests are Long Island Lighting Company ("LILCO") (18%), New York State Electric & Gas Corporation ("NYSEG") (18%), RG&E (14%), and Central Hudson (9%). Output of Unit 2, which has a capability of 1,143,000 KW, is shared in the same proportions as the cotenants' respective ownership interests. In June 1997, LILCO and Long Island Power Authority ("LIPA") entered into an agreement, whereby, upon completion of certain transactions, LILCO's stock would be sold to LIPA. It is anticipated that LIPA would own LILCO's 18% ownership interest in Unit 2. In July 1997, the New York State Public Authorities Control Board unanimously approved the agreements related to the LIPA transaction, subject to certain conditions, and LILCO's stockholders subsequently approved this transaction.
NOTE 5. CAPITALIZATION - ---------------------- CAPITAL STOCK The Company is authorized to issue 185,000,000 shares of common stock, $1 par value; 3,400,000 shares of preferred stock, $100 par value; 19,600,000 shares of preferred stock, $25 par value; and 8,000,000 shares of preference stock, $25 par value. The table below summarizes changes in the capital stock issued and outstanding and the related capital accounts for 1995, 1996 and 1997: COMMON STOCK $1 PAR VALUE -------------------------- SHARES AMOUNT* - -------------------------------------------------------- December 31, 1994: 144,311,466 $144,311 Issued 20,657 21 Redemptions Foreign currency translation adjustment - -------------------------------------------------------- December 31, 1995: 144,332,123 144,332 Issued 33,091 33 Redemptions Foreign currency translation adjustment - -------------------------------------------------------- December 31, 1996: 144,365,214 144,365 Issued 54,137 54 Redemptions Foreign currency translation adjustment - -------------------------------------------------------- December 31, 1997: 144,419,351 $144,419 ======================================================== * In thousands of dollars
PREFERRED STOCK $100 PAR VALUE --------------------------------------- SHARES NON-REDEEMABLE* REDEEMABLE* - -------------------------------------------------------------- December 31, 1994: 2,376,000 $210,000 $27,600 (a) Issued - - - Redemptions (18,000) - (1,800) Foreign currency translation adjustment - -------------------------------------------------------------- December 31, 1995: 2,358,000 $210,000 $25,800 (a) Issued - - - Redemptions (18,000) - (1,800) Foreign currency translation adjustment - -------------------------------------------------------------- December 31, 1996: 2,340,000 $210,000 $24,000 (a) Issued - - - Redemptions (18,000) - (1,800) Foreign currency translation adjustment - -------------------------------------------------------------- December 31, 1997: 2,322,000 $210,000 $22,200 (a) ============================================================== * In thousands of dollars (a) Includes sinking fund requirements due within one year.
PREFERRED STOCK $25 PAR VALUE --------------------------------------- CAPITAL STOCK PREMIUM AND EXPENSE SHARES NON-REDEEMABLE* REDEEMABLE* (NET)* - ---------------------------------------------------------------------------- December 31, 1994: 12,774,005 $230,000 $89,350 (a) $1,779,504 Issued - - - 283 Redemptions (366,000) - (9,150) 1,319 Foreign currency translation adjustment 3,141 - ---------------------------------------------------------------------------- December 31, 1995: 12,408,005 $230,000 $80,200 (a) $1,784,247 Issued - - - 214 Redemptions (344,000) - (8,600) (28) Foreign currency translation adjustment (708) - ---------------------------------------------------------------------------- December 31, 1996: 12,064,005 $230,000 $71,600 (a) $1,783,725 Issued - - - 426 Redemptions (282,801) - (7,070) 104 Foreign currency translation adjustment (4,567) - ---------------------------------------------------------------------------- December 31, 1997: 11,781,204 $230,000 $64,530 (a) $1,779,688 ============================================================================ * In thousands of dollars (a) Includes sinking fund requirements due within one year. The cumulative amount of foreign currency translation adjustment at December 31, 1997 was $(15,448).
NON-REDEEMABLE PREFERRED STOCK (Optionally Redeemable) The Company had certain issues of preferred stock which provide for optional redemption at December 31, as follows: - -------------------------------------------------------------- In thousands Redemption price per of dollars share (Before adding Series Shares 1997 1996 accumulated dividends) - -------------------------------------------------------------- Preferred $100 par value: 3.40% 200,000 $20,000 $20,000 $103.50 3.60% 350,000 35,000 35,000 104.85 3.90% 240,000 24,000 24,000 106.00 4.10% 210,000 21,000 21,000 102.00 4.85% 250,000 25,000 25,000 102.00 5.25% 200,000 20,000 20,000 102.00 6.10% 250,000 25,000 25,000 101.00 7.72% 400,000 40,000 40,000 102.36 Preferred $25 par value: 9.50% 6,000,000 150,000 150,000 25.00 (a) Adjustable Rate - Series A 1,200,000 30,000 30,000 25.00 Series C 2,000,000 50,000 50,000 25.00 - -------------------------------------------------------------- $440,000 $440,000 ============================================================== (a) Not redeemable until 1999.
MANDATORILY REDEEMABLE PREFERRED STOCK At December 31, the Company had certain issues of preferred stock, as detailed below, which provide for mandatory and optional redemption. These series require mandatory sinking funds for annual redemption and provide optional sinking funds through which the Company may redeem, at par, a like amount of additional shares (limited to 120,000 shares of the 7.45% series). The option to redeem additional amounts is not cumulative. The Company's five year mandatory sinking fund redemption requirements for preferred stock, in thousands, for 1998 through 2002 are as follows: $10,120; $7,620; $7,620; $7,620 and $3,050, respectively. The aggregate preference of preferred shares upon involuntary liquidation of the Company is the aggregate par value of such shares, plus an amount equal to the dividends accumulated and unpaid on such shares to the date of payment whether or not earned or declared. - --------------------------------------------------------------------------------- Redemption price per share (Before adding Shares In thousands of dollars accumulated dividends) Eventual Series 1997 1996 1997 1996 1997 Minimum - --------------------------------------------------------------------------------- Preferred $100 par value: 7.45% 222,000 240,000 $ 22,200 $ 24,000 $101.69 $100.00 Preferred $25 par value: 7.85% 731,204 914,005 18,280 22,850 25.28 25.00 8.375% 100,000 200,000 2,500 5,000 25.00 25.00 Adjustable Rate- Series B 1,750,000 1,750,000 43,750 43,750 25.00 25.00 - --------------------------------------------------------------------------------- 86,730 95,600 Less sinking fund requirements 10,120 8,870 - --------------------------------------------------------------------------------- $ 76,610 $ 86,730 =================================================================================
LONG-TERM DEBT Long-term debt at December 31 consisted of the following: - ------------------------------------------------------------- In thousands of dollars ----------------------- SERIES DUE 1997 1996 - ------------------------------------------------------------- First mortgage bonds: 6 1/4% 1997 $ - $ 40,000 6 1/2% 1998 60,000 60,000 9 1/2% 2000 150,000 150,000 6 7/8% 2001 210,000 210,000 9 1/4% 2001 100,000 100,000 5 7/8% 2002 230,000 230,000 6 7/8% 2003 85,000 85,000 7 3/8% 2003 220,000 220,000 8% 2004 300,000 300,000 6 5/8% 2005 110,000 110,000 9 3/4% 2005 150,000 150,000 7 3/4% 2006 275,000 275,000 *6 5/8% 2013 45,600 45,600 9 1/2% 2021 150,000 150,000 8 3/4% 2022 150,000 150,000 8 1/2% 2023 165,000 165,000 7 7/8% 2024 210,000 210,000 *8 7/8% 2025 75,000 75,000 * 7.2% 2029 115,705 115,705 - ------------------------------------------------------------- Total First Mortgage Bonds 2,801,305 2,841,305 Promissory notes: *Adjustable Rate Series due July 1, 2015 100,000 100,000 December 1, 2023 69,800 69,800 December 1, 2025 75,000 75,000 December 1, 2026 50,000 50,000 March 1, 2027 25,760 25,760 July 1, 2027 93,200 93,200 Term Loan Agreement 105,000 105,000 Unsecured notes payable: Medium Term Notes, Various rates, due 2000-2004 20,000 20,000 Other 154,295 156,606 Unamortized premium (discount) (9,884) (10,708) - -------------------------------------------------------------- TOTAL LONG-TERM DEBT 3,484,476 3,525,963 Less long-term debt due within one year 67,095 48,084 - -------------------------------------------------------------- $3,417,381 $3,477,879 ============================================================== *Tax-exempt pollution control related issues
Several series of First Mortgage Bonds and Promissory Notes were issued to secure a like amount of tax-exempt revenue bonds issued by NYSERDA. Approximately $414 million of such securities bear interest at a daily adjustable interest rate (with a Company option to convert to other rates, including a fixed interest rate which would require the Company to issue First Mortgage Bonds to secure the debt) which averaged 3.63% for 1997 and 3.46% for 1996 and are supported by bank direct pay letters of credit. Pursuant to agreements between NYSERDA and the Company, proceeds from such issues were used for the purpose of financing the construction of certain pollution control facilities at the Company's generating facilities or to refund outstanding tax-exempt bonds and notes (see Note 6). Other long-term debt in 1997 consists of obligations under capital leases of approximately $29.7 million, a liability to the DOE for nuclear fuel disposal of approximately $114.3 million and a liability for IPP contract terminations of approximately $10.3 million. The aggregate maturities of long-term debt for the five years subsequent to December 31, 1997, excluding capital leases, in millions, are approximately $64, $108, $158, $310 and $230 respectively. The Company's aggregate maturities will increase significantly upon closing of the MRA. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - "Master Restructuring Agreement and the PowerChoice Agreement." NOTE 6. BANK CREDIT ARRANGEMENTS The Company has an $804 million senior debt facility with a bank group consisting of a $255 million term loan facility, a $125 million revolving credit facility and $424 million for letters of credit. The letter of credit facility provides credit support for the adjustable rate pollution control revenue bonds issued through the NYSERDA discussed in Note 5. As of December 31, 1997, the amount outstanding under the senior debt facility was $529 million, consisting of $105 million under the term loan facility and a $424 million letter of credit, leaving the Company with $275 million of borrowing capability under the facility. The facility expires on June 30, 1999 (subject to earlier termination if the Company separates its fossil/hydro generation business from its transmission and distribution business, or any other significant restructuring plan). The interest rate applicable to the facility is variable based on certain rate options available under the agreement and currently approximates 7.7% (but capped at 15%). The Company is currently negotiating with the lenders to replace the senior debt facility with a larger facility to finance part of the MRA. The Company did not have any short-term debt outstanding at December 31, 1997 and 1996.
NOTE 7. FEDERAL AND FOREIGN INCOME TAXES - ----------------------------------------- See Note 9 - "Tax Assessments." Components of United States and foreign income before income taxes: In thousands of dollars 1997 1996 1995 - --------------------------------------------------------------- United States $315,027 $269,128 $400,087 Foreign (1,621) 28,522 17,609 Consolidating eliminations (3,476) (17,402) (10,267) - --------------------------------------------------------------- Income before extraordinary item and income taxes $309,930 $280,248 $407,429 =============================================================== /TABLE Following is a summary of the components of Federal and foreign income tax and a reconciliation between the amount of Federal income tax expense reported in the Consolidated Statements of Income and the computed amount at the statutory tax rate: In thousands of dollars 1997 1996* 1995 - -------------------------------------------------------------- Components of Federal and foreign income taxes: Current tax expense: Federal $ 77,565 $ 96,011 $ 67,366 Foreign - 3,708 3,900 - --------------------------------------------------------------- 77,565 99,719 71,266 - --------------------------------------------------------------- Deferred tax expense: Federal 47,836 382 84,002 Foreign 1,194 2,393 4,125 - --------------------------------------------------------------- 49,030 2,775 88,127 - --------------------------------------------------------------- Total $126,595 $102,494 $159,393 =============================================================== Reconciliation between Federal and foreign income taxes and the tax computed at prevailing U.S. statutory rate on income before income taxes: Computed tax $108,475 $ 98,087 $142,601 - --------------------------------------------------------------- Increase (reduction) attributable to flow-through of certain tax adjustments: Depreciation 36,411 28,103 31,033 Cost of removal (8,168) (8,849) (9,247) Deferred investment tax credit amortization (7,454) (8,018) (8,589) Other (2,669) (6,829) 3,595 - --------------------------------------------------------------- 18,120 4,407 16,792 - --------------------------------------------------------------- Federal and foreign income taxes $126,595 $102,494 $159,393 =============================================================== * Does not include the deferred tax benefit of $36,273 in 1996 associated with the extraordinary item for the discontinuance of regulatory accounting principles.
At December 31, the deferred tax liabilities (assets) were comprised of the following: In thousands of dollars 1997 1996 ---- ---- Alternative minimum tax (17,448) (64,313) Unbilled revenue (88,859) (83,577) Other (247,438) (237,850) ---------- ---------- Total deferred tax assets (353,745) (385,740) ---------- ---------- Depreciation related 1,358,827 1,421,550 Investment tax credit related 79,858 84,294 Other 302,092 237,414 ---------- ---------- Total deferred tax liabilities 1,740,777 1,743,258 ---------- ---------- Accumulated deferred income taxes $1,387,032 $1,357,518 =========== ===========
NOTE 8. PENSION AND OTHER RETIREMENT PLANS The Company and certain of its subsidiaries have non- contributory, defined-benefit pension plans covering substantially all their employees. Benefits are based on the employee's years of service and compensation level. The Company's general policy is to fund the pension costs accrued with consideration given to the maximum amount that can be deducted for Federal income tax purposes. Net pension cost for 1997, 1996 and 1995 included the following components: - ----------------------------------------------------------------- In thousands of dollars ----------------------- 1997 1996 1995 - ----------------------------------------------------------------- Service cost - benefits earned during the period $ 27,100 $ 25,000 $ 22,500 Interest cost on projected benefit obligation 75,200 71,700 73,000 Actual return on plan assets (188,200) (134,100) (215,600) Net amortization and deferral 100,400 55,700 140,300 - ----------------------------------------------------------------- Total pension cost (1) $ 14,500 $ 18,300 $ 20,200 ================================================================= (1) $3.2 million for 1997, $3.8 million for 1996, and $4.1 million for 1995 was related to construction labor and, accordingly, was charged to construction projects.
The following table sets forth the plan's funded status and amounts recognized in the Company's Consolidated Balance Sheets:
- -------------------------------------------------------------- In thousands of dollars ----------------------- At December 31, 1997 1996 - -------------------------------------------------------------- Actuarial present value of accumulated benefit obligations: Vested benefits $ 990,415 $803,202 Non-vested benefits 73,430 83,107 - -------------------------------------------------------------- Accumulated benefit obligations 1,063,845 886,309 Additional amounts related to projected pay increases 108,583 141,472 - -------------------------------------------------------------- Projected benefits obligation for service rendered to date 1,172,428 1,027,781 Plan assets at fair value, consisting primarily of listed stocks, bonds, other fixed income obligations and insurance contracts (1,304,338) (1,159,822) - -------------------------------------------------------------- Plan assets in excess of projected benefit obligations (131,910) (132,041) Unrecognized net obligation at January 1, 1987 being recognized over approximately 19 years (19,446) (22,005) Unrecognized net gain from actual return on plan assets different from that assumed 265,100 219,680 Unrecognized net gain from past experience different from that assumed and effects of changes in assumptions amortized over 10 years 19,920 66,129 Prior service cost not yet recognized in net periodic pension cost (50,473) (49,651) - --------------------------------------------------------------- Pension liability included in the consolidated balance sheets $ 83,191 $ 82,112 =============================================================== Principle Actuarial Assumptions (%): Discount Rate 7.00 7.50 Rate of increase in future compensation levels (plus merit increases) 2.50 2.50 Long-term rate of return on plan assets 9.25 9.25 ===============================================================
In addition to providing pension benefits, the Company and its subsidiaries provide certain health care and life insurance benefits for active and retired employees and dependents. Under current policies, substantially all of the Company's employees may be eligible for continuation of some of these benefits upon normal or early retirement. The Company accounts for the cost of these benefits in accordance with PSC policy requirements which comply with SFAS No. 106. The Company has established various trusts to fund its future postretirement benefit obligation. In 1997, 1996 and 1995, the Company made contributions to such trusts of approximately $13.5 million, $28.5 million and $53.1 million, respectively, which represent the amount received in rates and from cotenants. Net postretirement benefit cost for 1997, 1996 and 1995 included the following components:
- ----------------------------------------------------------------- In thousands of dollars ---------------------------- 1997 1996 1995 - ----------------------------------------------------------------- Service cost - benefits attributed to service during the period $12,300 $12,900 $12,600 Interest cost on accumulated benefit obligation 34,800 37,500 45,400 Actual return on plan assets (24,500) (12,900) (11,200) Amortization of the transition obligation over 20 years 10,900 13,500 18,800 Net amortization 9,500 6,000 14,600 - ----------------------------------------------------------------- Total postretirement benefit cost $43,000 $57,000 $80,200 ================================================================= The following table sets forth the plan's funded status and amounts recognized in the Company's Consolidated Balance Sheets: - ----------------------------------------------------------- In thousands of dollars ----------------------- At December 31, 1997 1996 - ----------------------------------------------------------- Actuarial present value of accumulated benefit obligations: Retired and surviving spouses $392,832 $370,259 Active eligible 43,299 31,030 Active ineligible 83,720 69,441 - ------------------------------------------------------------ Accumulated benefit obligation 519,851 470,730 Plan assets at fair value, consisting primarily of listed stocks, bonds and other fixed obligations (181,101) (143,071) - ----------------------------------------------------------- Accumulated postretirement benefit obligation in excess of plan assets 338,750 327,659 Unrecognized net loss from past experience different from that assumed and effects of changes in assumptions (48,466) (36,048) Prior service cost not yet recognized in postretirement benefit cost 30,086 39,205 Unrecognized transition obligation being amortized over 20 years (163,350) (174,240) - ----------------------------------------------------------- Accrued postretirement benefit liability included in the consolidated balance sheet $157,020 $156,576 =========================================================== =========================================================== Principal actuarial assumptions (%): Discount rate 7.00 7.50 Long-term rate of return on plan assets 9.25 8.00 Health care cost trend rate: Pre-65 7.00 8.00 Post-65 6.00 6.50 ===========================================================
During 1996, the Company changed the eligibility requirements for plan benefits for employees who retire after May 1, 1996. Generally, plan benefits are now accrued for eligible participants beginning after age 45. Previous to this change, the Company accrued these benefits over the employees' service life. The effect of this change resulted in a decrease in the accumulated benefit obligation for active ineligible employees. At December 31, 1997, the assumed health cost trend rates gradually decline to 5.0% in 2001. If the health care cost trend rate was increased by one percent, the accumulated postretirement benefit obligation as of December 31, 1997 would increase by approximately 6.7% and the aggregate of the service and interest cost component of net periodic postretirement benefit cost for the year would increase by approximately 5.8%. The Company recognizes the obligation to provide postemployment benefits if the obligation is attributable to employees' past services, rights to those benefits are vested, payment is probable and the amount of the benefits can be reasonably estimated. At December 31, 1997 and 1996, the Company's postemployment benefit obligation is approximately $13.3 million and $13 million, respectively. NOTE 9. COMMITMENTS AND CONTINGENCIES See Note 2. LONG-TERM CONTRACTS FOR THE PURCHASE OF ELECTRIC POWER: At January 1, 1998, the Company had long-term contracts to purchase electric power from the following generating facilities owned by NYPA:
- ----------------------------------------------------------------- Expiration Purchased Estimated date of capacity annual Facility contract in MW capacity cost - ----------------------------------------------------------------- Niagara - hydroelectric project 2007 951 $27,369,000 St. Lawrence - hydroelectric project 2007 104 1,300,000 Blenheim-Gilboa - pumped storage generating station 2002 270 7,500,000 - ----------------------------------------------------------------- 1,325 $36,169,000 =================================================================
The purchase capacities shown above are based on the contracts currently in effect. The estimated annual capacity costs are subject to price escalation and are exclusive of applicable energy charges. The total cost of purchases under these contracts and the recently cancelled contract with Fitzpatrick nuclear plant was approximately, in millions, $91.0, $93.3 and $92.5 for the years 1997, 1996 and 1995, respectively. In May 1997, the Company cancelled its commitment to purchase 110 MW of capacity from the Fitzpatrick facility. The Company continues to have a contract with Fitzpatrick to purchase for resale up to 46 MW of power for NYPA's economic development customers. Under the requirements of PURPA, the Company is required to purchase power generated by IPPs, as defined therein. The Company has 141 PPAs with 148 facilities, of which 143 are on line, amounting to approximately 2,695 MW of capacity at December 31, 1997. Of this amount 2,382 MW is considered firm. The following table shows the payments for fixed and other capacity costs, and energy and related taxes the Company estimates it will be obligated to make under these contracts without giving effect to the MRA. The payments are subject to the tested capacity and availability of the facilities, scheduling and price escalation.
- --------------------------------------------------------- (In thousands of dollars) SCHEDULABLE FIXED COSTS VARIABLE COSTS ------------------ -------------- YEAR CAPACITY OTHER ENERGY AND TAXES TOTAL - --------------------------------------------------------------- 1998 $247,740 $41,420 $ 906,590 $1,195,750 1999 252,130 42,450 943,720 1,238,300 2000 242,030 44,080 974,080 1,260,190 2001 244,620 45,650 1,042,380 1,332,650 2002 248,940 47,330 1,063,830 1,360,100 - ----------------------------------------------------------------
The capacity and other fixed costs relate to contracts with 11 facilities, where the Company is required to make capacity and other fixed payments, including payments when a facility is not operating but available for service. These 11 facilities account for approximately 774 MW of capacity, with contract lengths ranging from 20 to 35 years. The terms of these existing contracts allow the Company to schedule energy deliveries from the facilities and then pay for the energy delivered. The Company estimates the fixed payments under these contracts will aggregate to approximately $8 billion over their terms, using escalated contract rates. Contracts relating to the remaining facilities in service at December 31, 1997, require the Company to pay only when energy is delivered, except when the Company decides that it would be better to pay a particular project a reduced energy payment to have the project reduce its high priced energy deliveries as described below. The Company currently recovers schedulable capacity through base rates and energy payments, taxes and other schedulable fixed costs through the FAC. The Company paid approximately $1,106 million, $1,088 million and $980 million in 1997, 1996 and 1995 for 13,500,000 MWh, 13,800,000 MWh and 14,000,000 MWh, respectively, of electric power under all IPP contracts. On July 9, 1997, the Company announced the MRA to terminate, restate or amend certain IPP power purchase contracts. As a result of negotiations, the MRA currently provides for the termination, restatement or amendment of 28 PPAs with 15 IPPs, in exchange for an aggregate of approximately $3,616 million in cash and 42.9 million shares of the Company's common stock and certain fixed price swap contracts. Under the terms of the MRA, the Company would terminate PPAs representing approximately 1,180 MW of capacity and restate contracts representing 583 MW of capacity. The restated contracts are structured to be in the form of financial swaps with fixed prices for the first two years changing to an indexed pricing formula thereafter. The contract quantities are fixed for the full ten year term of the contracts. The MRA also requires the Company to provide the IPP Parties with a number of fixed price swap contracts with a term of seven years beginning in 2003. The terms of the MRA have been and continue to be modified. Since 1996, the Company has negotiated 2 long term and several limited term contract amendments whereby the Company can reduce the energy deliveries from the facilities. These reduced energy agreements resulted in a reduction of IPP deliveries of approximately 1,010,000 MWh and 984,000 MWh during 1997 and 1996, respectively. SALE OF CUSTOMER RECEIVABLES: The Company has established a single-purpose, wholly-owned financing subsidiary, NM Receivables Corp., whose business consists of the purchase and resale of an undivided interest in a designated pool of customer receivables, including accrued unbilled revenues. For receivables sold, the Company has retained collection and administrative responsibilities as agent for the purchaser. As collections reduce previously sold undivided interests, new receivables are customarily sold. NM Receivables Corp. has its own separate creditors which, upon liquidation of NM Receivables Corp., will be entitled to be satisfied out of its assets prior to any value becoming available to the Company. The sale of receivables are in fee simple for a reasonably equivalent value and are not secured loans. Some receivables have been contributed in the form of a capital contribution to NM Receivables Corp. in fee simple for reasonably equivalent value, and all receivables transferred to NM Receivables Corp. are assets owned by NM Receivables Corp. in fee simple and are not available to pay the parent Company's creditors. At December 31, 1997 and 1996, $144.1 and $250 million, respectively, of receivables had been sold by NM Receivables, Corp. to a third party. The undivided interest in the designated pool of receivables was sold with limited recourse. The agreement provides for a formula based loss reserve pursuant to which additional customer receivables are assigned to the purchaser to protect against bad debts. At December 31, 1997, the amount of additional receivables assigned to the purchaser, as a loss reserve, was approximately $64.4 million. Although this represents the formula- based amount of credit exposure at December 31, 1997 under the agreement, historical losses have been substantially less. To the extent actual loss experience of the pool receivables exceeds the loss reserve, the purchaser absorbs the excess. Concentrations of credit risk to the purchaser with respect to accounts receivable are limited due to the Company's large, diverse customer base within its service territory. The Company generally does not require collateral, i.e., customer deposits. 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 2, 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. ENVIRONMENTAL CONTINGENCIES: 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 124 sites with which it has been or may be associated, including 76 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 and costs 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 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 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 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 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 spring 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. In a motion currently pending before the court, the New York State Attorney General has moved to dismiss the Company's claims against the State of New York, the New York State Department of Transportation, the Thruway Authority and Canal Corporation. The Company has opposed this motion. 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. CONSTRUCTION PROGRAM: The Company is committed to an ongoing construction program to assure delivery of its electric and gas services. The Company presently estimates that the construction program for the years 1998 through 2002 will require approximately $1.4 billion, excluding AFC and nuclear fuel. For the years 1998 through 2002, the estimates, in millions, are $328, $269, $264, $275 and $300, respectively, which includes $26, $25, $22, $20 and $38, respectively, related to non-nuclear generation. The impact of the ice storm (see Note 13) on the construction program will not be known until restoration efforts have been completed. These amounts are reviewed by management as circumstances dictate. Under PowerChoice, the Company will separate, through sale or spin-off, the Company's non-nuclear power generation business from the remainder of the business. GAS SUPPLY, STORAGE AND PIPELINE COMMITMENTS: In connection with its gas business, the Company has long-term commitments with a variety of suppliers and pipelines to purchase gas commodity, provide gas storage capability and transport gas commodity on interstate gas pipelines. The table below sets forth the Company's estimated commitments at December 31, 1997, for the next five years, and thereafter. (In thousands of dollars) YEAR GAS SUPPLY GAS STORAGE/PIPELINE - ---- ---------- -------------------- 1998 $103,990 $95,720 1999 78,380 99,490 2000 56,110 81,550 2001 53,140 60,170 2002 39,860 26,610 Thereafter 155,560 71,130 With respect to firm gas supply commitments, the amounts are based upon volumes specified in the contracts giving consideration for the minimum take provisions. Commodity prices are based on New York Mercantile Exchange quotes and reservation charges, when applicable. For storage and pipeline capacity commitments, amounts are based upon volumes specified in the contracts, and represent demand charges priced at current filed tariffs. At December 31, 1997, the Company's firm gas supply commitments extend through October 2006, while the gas storage and transportation commitments extend through October 2012. Beginning in May 1996, as a result of a generic rate proceeding, the Company was required to implement service unbundling, where customers could choose to buy natural gas from sources other than the Company. To date the migration has not resulted in any stranded costs since the PSC has allowed utilities to assign the pipeline capacity to the customers choosing another supplier. This assignment is allowed during a three-year period ending March 1999, at which time the PSC will decide on methods for dealing with the remaining unassigned or excess capacity. In September 1997, the PSC indicated that it is unlikely utilities will be allowed to continue to assign pipeline capacity to departing customers after March 1999. The Company is unable to predict how the PSC will resolve these issues. NOTE 10. FAIR VALUE OF FINANCIAL AND DERIVATIVE FINANCIAL INSTRUMENTS The following methods and assumptions were used to estimate the fair value of each class of financial instruments: CASH AND SHORT-TERM INVESTMENTS: The carrying amount approximates fair value because of the short maturity of the financial instruments. LONG-TERM DEBT AND MANDATORILY REDEEMABLE PREFERRED STOCK: The fair value of fixed rate long-term debt and redeemable preferred stock is estimated using quoted market prices where available or discounting remaining cash flows at the Company's incremental borrowing rate. The carrying value of NYSERDA bonds and other long-term debt are considered to approximate fair value. DERIVATIVE FINANCIAL INSTRUMENTS: The fair value of futures and forward contracts are determined using quoted market prices and broker quotes.
The financial instruments held or issued by the Company are for purposes other than trading. The estimated fair values of the Company's financial instruments are as follows: - ------------------------------------------------------------------------------------------ In thousands of dollars ------------------------------------------------- At December 31, 1997 1996 - ------------------------------------ --------------------- ---------------------- Carrying Fair Carrying Fair Amount Value Amount Value - ------------------------------------ --------------------- ---------------------- Cash and short-term investments $ 378,232 $ 378,232 $ 325,398 $ 325,398 Mandatorily redeemable preferred stock 86,730 87,328 95,600 86,516 Long-term debt: First Mortgage bonds 2,801,305 2,878,368 2,841,305 2,690,707 Medium-term notes 20,000 22,944 20,000 21,994 Promissory notes 413,760 413,760 413,760 413,760 Other 229,634 229,634 228,461 228,461
In 1997, the Company's energy marketing subsidiary began to engage in both trading and non-trading activities generally using gas futures and electric and gas forward contracts. At December 31, 1997, for both trading and non-trading activities, the fair value of long and short positions was approximately $59.9 million and $57.6 million, respectively. These fair values exceed the weighted average fair value of open positions for the period ending December 31, 1997. The positions above extend for a period of less than one year. With respect to these activities the Company does not have any material counterparty credit risk at December 31, 1997. Transactions entered into for trading purposes are accounted for on a mark-to-market basis with changes in fair value recognized as a gain or loss in the period of the change. At December 31, 1997, the open trading positions consisted of off-balance sheet electric and gas forward contracts. These positions consisted of long and short electric forward contracts with fair values of $45.3 million (1,878,000 MWh) and $44.3 million (1,778,000 MWh), respectively, and long and short gas forward contracts with fair values of $9.4 million (7.1 million Dth) and $10.2 million (7.3 million Dth), respectively. The quantities above represent notional contract quantities. The effects of trading activities on the Company's 1997 results of operations were not material. Activities for non-trading purposes generally consist of transactions entered into to hedge the market fluctuations of contractual and anticipated commitments. Gas futures contracts are primarily used for hedging purposes. The change in fair value of these transactions are deferred until the gain or loss on the hedged item is recognized. The fair value of open positions for non-trading purposes at December 31, 1997, as well as the effect of these activities on the Company's results of operations for the same period ending, was not material. The Company's investments in debt and equity securities consist of trust funds for the purpose of funding the nuclear decommissioning of Unit 1 and its share of Unit 2 (see Note 3 - "Nuclear Plant Decommissioning"), short-term investments held by Opinac Energy Corporation (a subsidiary) and a trust fund for certain pension benefits. The Company has classified all investments in debt and equity securities as available for sale and has recorded all such investments at their fair market value at December 31, 1997. The proceeds from the sale of investments were $159.7 million, $99.4 million and $70.3 million in 1997, 1996 and 1995, respectively. Net realized and unrealized gains and losses related to the nuclear decommissioning trust are reflected in "Accumulated depreciation and amortization" on the Consolidated Balance Sheets, which is consistent with the method used by the Company to account for the decommissioning costs recovered in rates. The unrealized gains and losses related to the investments held by Opinac Energy Corporation and the pension trust are included, net of tax, in "Common stockholders' equity" on the Consolidated Balance Sheets, while the realized gains and losses are included in "Other income and deductions" on the Consolidated Income Statements. The recorded fair values and cost basis of the Company's investments in debt and equity securities is as follows:
- -------------------------------------------------------------------------------------------- In thousands of dollars ------------------------------------------------------------------------- At December 31, 1997 1996 - --------------- ---------------------------------- ----------------------------------- Gross Gross Unrealized Fair Unrealized Fair Security Type Cost Gain (Loss) Value Cost Gain (Loss) Value - --------------- ---------------------------------- ----------------------------------- U.S. Government Obligations $ 14,136 $ 1,864 $ (4) $ 15,996 $ 24,782 $1,530 $ (33) $26,279 Commercial Paper 106,035 1,542 - 107,577 90,495 739 - 91,234 Tax Exempt Obligations 80,115 5,884 (55) 85,944 75,590 3,209 (147) 78,652 Corporate Obligations 92,949 17,368 (830) 109,487 62,723 8,524 (422) 70,825 Other 3,025 - - 3,025 2,586 - - 2,586 -------- -------- ------ -------- -------- ------- -------- -------- $296,260 $26,658 $(889) $322,029 $256,176 $14,002 $ (602) $269,576 ======== ======= ====== ======== ======== ======= ======== ========
Using the specific identification method to determine cost, the gross realized gains and gross realized losses were: In thousands of dollars ----------------------- Year Ended December 31, 1997 1996 1995 - ----------------------- ---- ---- ---- Realized gains $3,487 $2,121 $2,523 Realized losses 686 806 328
The contractual maturities of the Company's investments in debt securities is as follows: - --------------------------------------------------------- In thousands of dollars ----------------------------- At December 31, 1997 Fair Value Cost - --------------------------------------------------------- Less than 1 year $106,677 $105,135 1 year to 5 years 10,845 10,654 5 years to 10 years 52,526 50,351 Due after 10 years 113,946 104,353
NOTE 11. STOCK BASED COMPENSATION Under the Company's stock compensation plans, stock units and stock appreciation rights ("SARs") may be granted to officers, key employees and directors. In addition, the Company's plans allow for the grant of stock options to officers. In 1997, 1996 and 1995 the Company granted 209,918 units and 296,300 SARs, 291,228 units and 376,600 SARs and 169,500 units and 414,000 SARs, respectively. Also, in 1995 the Company granted 85,375 stock options. At December 31, 1997, there were 668,132 units, 1,086,900 SARs and 298,583 options outstanding. Stock units are payable in cash at the end of a defined vesting period, determined at the date of the grant, based upon the Company's stock price for a defined period. SARs become exercisable, as determined at the grant date, and are payable in cash based upon the increase in the Company's stock price from a specified level. As such, for these awards, compensation expense is recognized over the vesting period of the award based upon changes in the Company's stock price for that period. Options were granted over the period 1992 to 1995 and become exercisable three years and expire ten years from the grant date. These options are all considered to be antidilutive for EPS calculations. Included in the results of operations for the years ending 1997 and 1996, is approximately $3.2 and $2.6 million, respectively, related to these plans. As permitted by SFAS No. 123 - "Accounting for Stock-Based Compensation" ("SFAS No. 123") the Company has elected to follow Accounting Principles Board Opinion No. 25-"Accounting for Stock Issued to Employees" (APB No. 25) and related interpretations in accounting for its employee stock options. Under APB No. 25, no compensation expense is recognized for stock options because the exercise price of the Company's employee stock options equals the market price of the underlying stock on the grant date. Since stock units and SARs are payable in cash, the accounting under APB No. 25 and SFAS No. 123 is the same. Therefore, the pro-forma disclosure of information regarding net income, as required by SFAS No. 123, relates only to the Company's outstanding stock options, the effect of which is immaterial to the financial statements for the years ended 1997, 1996 and 1995. There is no effect on earnings per share for these years resulting from the pro-forma adjustments to net income. NOTE 12. INFORMATION REGARDING THE ELECTRIC AND GAS BUSINESSES The Company is engaged principally in the business of production, purchase, transmission, distribution and sale of electricity and the purchase, distribution, sale and transportation of gas in New York State. The Company provides electric service to the public in an area of New York State having a total population of about 3,500,000, including among others, the cities of Buffalo, Syracuse, Albany, Utica, Schenectady, Niagara Falls, Watertown and Troy. The Company distributes or transports natural gas in areas of central, northern and eastern New York having a total population of about 1,700,000 nearly all within the Company's electric service area. Certain information regarding the Company's electric and natural gas segments is set forth in the following table. General corporate expenses, property common to both segments and depreciation of such common property have been allocated to the segments in accordance with the practice established for regulatory purposes. Identifiable assets include net utility plant, materials and supplies, deferred finance charges, deferred recoverable energy costs and certain other regulatory and other assets. Corporate assets consist of other property and investments, cash, accounts receivable, prepayments, unamortized debt expense and certain other regulatory and other assets. At December 31, 1997, total plant assets consisted of approximately 24% Nuclear, 20% Fossil/Hydro, 42% Transmission and Distribution, 11% Gas and 3% Common.
In thousands of dollars ----------------------- 1997 1996 1995 ---- ---- ---- Operating revenues: Electric $3,309,441 $3,308,979 $3,335,548 Gas 656,963 681,674 581,790 - ----------------------------------------------------------------- Total $3,966,404 $3,990,653 $3,917,338 ================================================================= Operating income: Electric $ 462,240 $ 438,590 $ 587,282 Gas 96,599 83,748 96,752 - ----------------------------------------------------------------- Total $ 558,839 $ 522,338 $ 684,034 ================================================================= Federal and foreign income taxes: Electric 96,590 79,574 133,246 Gas 30,005 22,920 26,147 - ----------------------------------------------------------------- Total 126,595 102,494 159,393 ================================================================= Income before extraordinary item $ 183,335 $ 177,754 $ 248,036 ================================================================= Depreciation and amortization: Electric $ 311,683 $ 302,825 $ 292,995 Gas 27,958 27,002 24,836 - ----------------------------------------------------------------- Total $ 339,641 $ 329,827 $ 317,831 ================================================================= Construction expenditures (including nuclear fuel): Electric $ 221,915 $ 277,505 $ 285,722 Gas 68,842 74,544 60,082 - ----------------------------------------------------------------- Total $ 290,757 $ 352,049 $ 345,804 ================================================================= Identifiable assets: Electric $7,257,163 $7,372,370 $7,592,287 Gas 1,185,001 1,203,184 1,123,045 - ----------------------------------------------------------------- Total 8,442,164 8,575,554 8,715,332 Corporate assets 1,141,977 852,081 762,537 - ----------------------------------------------------------------- Total assets $9,584,141 $9,427,635 $9,477,869 =================================================================
NOTE 13. SUBSEQUENT EVENT 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; however, the final costs of the storm will not be known as crews continue to make final repairs to temporary measures to restore service and salvage operations cannot be completed until spring. The preliminary estimate of the total cost of the restoration and rebuild efforts could exceed $125 million. A portion of the cost will be capitalized; however, at this time, the Company is unable to determine the capital portion until rebuild efforts have been completed and all labor, material and other costs, including charges from other utilities and contractors, have been received and analyzed. The Company is pursuing 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. Absent recovery, the Company would face a charge to earnings in the first quarter of 1998 to reflect its estimate of unrecoverable, non-capitalized costs.
NOTE 14. QUARTERLY FINANCIAL DATA (UNAUDITED Operating revenues, operating income, net income (loss) and earnings (loss) per common share by quarters from 1997, 1996 and 1995, respectively, are shown in the following table. The Company, in its opinion, has included all adjustments necessary for a fair presentation of the results of operations for the quarters. Due to the seasonal nature of the utility business, the annual amounts are not generated evenly by quarter during the year. 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 in the winter. In thousands of dollars ----------------------- BASIC AND BASIC AND DILUTED DILUTED NET EARNINGS OPERATING OPERATING INCOME (LOSS) PER QUARTER ENDED REVENUES INCOME (LOSS) COMMON SHARE - ---------------------------------------------------------------- December 31, 1997 $ 960,304 $ 86,024 $ 7,881 $ (.01) 1996 971,106 117,832 (25,808) (.24) 1995 966,478 132,228 27,874 .13 - ---------------------------------------------------------------- September 30, 1997 $ 896,570 $110,174 $ 31,683 $ .15 1996 895,713 47,119 (12,916) (.16) 1995 887,231 142,732 46,941 .26 - ---------------------------------------------------------------- June 30, 1997 $ 945,698 $130,704 $ 40,749 $ .22 1996 960,771 142,755 52,992 .30 1995 938,816 152,297 54,485 .31 - ---------------------------------------------------------------- March 31, 1997 $1,163,832 $231,937 $103,022 $ .65 1996 1,163,063 214,632 96,122 .60 1995 1,124,813 256,777 118,736 .75 - ----------------------------------------------------------------
In the fourth quarter of 1996 the Company recorded an extraordinary item for the discontinuance of regulatory accounting principles of $103.6 million (47 cents per common share). In the third quarter of 1996 the Company increased the allowance for doubtful accounts by $68.5 million (31 cents per common share). In the fourth quarter of 1995, the Company recorded $16.9 million (8 cents per common share) for MERIT earned in accordance with the 1991 Agreement. NOTE 15. ADJUSTMENT OF 1997 FINANCIAL STATEMENTS 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 2 - "Rate and Regulatory Issues and Contingencies," should be charged to expense in the quarter in which the MRA closes. Accordingly, the 1997 financial statements, as presented herein, have been restated to eliminate this charge and the Company expects that the second quarter 1998 financial statements will reflect such $190 million charge.
ELECTRIC AND GAS STATISTICS ELECTRIC CAPABILITY Thousands of KW ---------------- December 31, 1997 % 1996 1995 - ------------------------------------------------------------ Owned: Coal 1,360 16.7 1,333 1,316 Oil* 646 7.9 636 636 Dual Fuel - Oil/Gas 700 8.6 700 700 Nuclear 1,082 13.3 1,082 1,082 Hydro 661 8.1 617 665 ----- ---- ----- ----- 4,449 54.6 4,368 4,399 ----- ---- ----- ----- Purchased: New York Power Authority - Hydro 1,325 16.2 1,310 1,325 - Nuclear - - 110 110 IPPs 2,382 29.2 2,406 2,390 ----- ---- ----- ----- 3,707 45.4 3,826 3,825 ----- ---- ----- ----- Total capability** 8,156 100.0 8,194 8,224 ===== ===== ===== ===== Electric peak load 6,348 6,021 6,211 ===== ===== ===== * In 1994, Oswego Unit No. 5 (an oil-fired unit with a capability of 850,000 KW) was put into long-term cold standby, but could be returned to service in three months. ** Available capability can be increased during heavy load periods by purchases from neighboring interconnected systems. Hydro station capability is based on average December stream- flow conditions.
ELECTRIC STATISTICS 1997 1996 1995 - ---------------------------------------------------------------- Electric sales (Millions of KWh): Residential 9,905 10,109 10,055 Commercial 11,552 11,564 11,613 Industrial 7,191 7,148 7,061 Industrial-Special 4,507 4,326 4,053 Municipal service 235 246 229 Other electric systems 3,746 5,431 4,305 Subsidiary - 303 368 - ----------------------------------------------------------------- 37,136 39,127 37,684 Electric revenues (Thousands of dollars): Residential $1,227,245 $1,252,165 $1,214,848 Commercial 1,233,417 1,237,385 1,237,502 Industrial 531,164 524,858 523,996 Industrial-Special 61,820 58,444 56,250 Municipal service 54,545 53,795 50,860 Other electric systems 83,794 113,391 88,936 Miscellaneous 117,456 53,698 143,625 Subsidiary - 15,243 19,531 - ----------------------------------------------------------------- $3,309,441 $3,308,979 $3,335,548 Electric customers (Average): Residential 1,404,345 1,405,083 1,399,725 Commercial 146,039 145,149 144,731 Industrial 1,970 2,045 2,122 Industrial-Special 85 99 83 Other 1,519 1,302 1,488 Subsidiary - 13,557 13,508 - ----------------------------------------------------------------- 1,553,958 1,567,235 1,561,657 Residential (Average): Annual KWh use per customer 7,053 7,195 7,184 Cost to customer per KWh (in cents) 12.39 12.39 12.08 Annual revenue per customer $873.89 $891.17 $867.92
GAS STATISTICS 1997 1996 1995 - ----------------------------------------------------------------- Gas Sales (Thousands of Dth): Residential 55,203 56,728 51,842 Commercial 22,069 25,353 23,818 Industrial 1,381 2,770 2,660 Other gas systems 28 30 161 - ----------------------------------------------------------------- Total sales 78,681 84,881 78,481 Spot market 2,451 10,459 1,723 Transportation of customer- owned gas 152,813 134,671 144,613 - ----------------------------------------------------------------- Total gas delivered 233,945 230,011 224,817 Gas Revenues (Thousands of dollars): Residential $ 436,136 $ 417,348 $ 368,391 Commercial 148,213 162,275 143,643 Industrial 6,549 13,325 11,530 Other gas systems 130 138 762 Spot market 6,346 37,124 3,096 Transportation of customer- owned gas 55,657 50,381 48,290 Miscellaneous 3,932 1,083 6,078 - ----------------------------------------------------------------- $ 656,963 $ 681,674 $ 581,790 Gas Customers (Average): Residential 484,862 477,786 471,948 Commercial 40,955 41,266 40,945 Industrial 186 206 225 Other 6 6 1 Transportation 843 713 652 - ----------------------------------------------------------------- 526,852 519,977 513,771 Residential (Average): Annual dekatherm use per customer 113.9 118.7 109.8 Cost to customer per Dth $ 7.90 $ 7.36 $ 7.11 Annual revenue per customer $899.51 $873.50 $780.58 Maximum day gas sendout (Dth) 1,133,370 1,152,996 1,211,252
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K. (a) Certain documents filed as part of the Form 10-K. (1) INDEX OF FINANCIAL STATEMENTS Report of Independent Accountants Consolidated Statements of Income and Retained Earnings for each of the three years in the period ended December 31, 1997 Consolidated Balance Sheets at December 31, 1997 and 1996 Consolidated Statements of Cash Flows for each of the three years in the period ended December 31, 1997 Notes to Consolidated Financial Statements Separate financial statements of the Company have been omitted since it is primarily an operating company and all consolidated subsidiaries are wholly-owned directly or by subsidiaries. (2) The following financial statement schedules of the Company for the years ended December 31, 1997, 1996 and 1995 are included: Report of Independent Accountants on Financial Statement Schedule Consolidated Financial Statement Schedule: II--Valuation and Qualifying Accounts and Reserves The Financial Statement Schedule above should be read in conjunction with the Consolidated Financial Statements in Part II, Item 8 (Financial Statements and Supplementary Data). Schedules other than those mentioned above are omitted because the conditions requiring their filing do not exist or because the required information is given in the financial statements, including the notes thereto. (3) List of Exhibits: See Exhibit Index. (b) Reports on Form 8-K: Form 8-K Reporting Date - October 10, 1997 Item reported - Item 5. Other Events. Registrant filed information concerning the PowerChoice settlement. Form 8-K Reporting Date - February 11, 1998 Item reported - Item 5. Other Events. Registrant filed information concerning the January 1998 ice storm. (c) Exhibits. See Exhibit Index. (d) Financial Statement Schedule. See (a)(2) above. REPORT OF INDEPENDENT ACCOUNTANTS ON FINANCIAL STATEMENT SCHEDULE - ----------------------------------------------------------------- To the Board of Directors of Niagara Mohawk Power Corporation Our audits of the consolidated financial statements of Niagara Mohawk Power Corporation referred to in our report dated March 26, 1998 appearing in this Form 10-K also included an audit of the Financial Statement Schedule listed in Item 14(a) of this Form 10- K. In our opinion, this Financial Statement Schedule presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. /s/ PRICE WATERHOUSE LLP Syracuse, New York March 26, 1998
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES - --------------------------------------------------------- SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES - ------------------------------------------------------------ (In Thousands of Dollars) Column A Column B Column C Column D Column E - ------------------------ ---------- ---------------------- ---------- --------- Additions ---------------------- Balance at Charged to Charged to Balance Beginning Costs and Other Deductions at End Description of Period Expenses Accounts (a) of Period - ------------------------ ---------- ---------- ---------- ---------- --------- Allowance for Doubtful Accounts - deducted from Accounts Receivable in the Consolidated Balance Sheets 1997 $52,096 $ 46,549 $ 3,000 (b) $39,097 $62,548 1996 20,000 127,648 800 (b) 96,352 52,096 1995 3,600 31,284 16,400 (b) 31,284 20,000 (a) Uncollectible accounts written off net of recoveries of $14,416, $12,842, and $10,830 in 1997, 1996 and 1995, respectively. (b) The Company increased its allowance for doubtful accounts in 1995 and recorded a regulatory asset of $16,400, which reflects the amount that the Company expects to recover in rates. In 1996, regulatory asset increased by $800 to $17,200 and in 1997, regulatory asset increased $3,000 to $20,200.
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES - --------------------------------------------------------- SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES - ------------------------------------------------------------ (In Thousands of Dollars) Column A Column B Column C Column D Column E - ------------------------ ---------- ---------------------- ---------- --------- Additions ---------------------- Balance at Charged to Charged to Balance Beginning Costs and Other at End Description of Period Expenses Accounts Deductions of Period (c) - ------------------------ ---------- ---------- ---------- ---------- --------- Miscellaneous Valuation Reserves 1997 $37,740 $ 2,207 $ - $ 4,049 $35,898 1996 39,426 10,261 - 11,947 37,740 1995 29,197 18,719 - 8,490 39,426 (c) The reserves relate primarily to certain inventory and non-rate base properties.
NIAGARA MOHAWK POWER CORPORATION EXHIBIT INDEX - ------------- In the following exhibit list, NMPC refers to the Company and CNYP refers to Central New York Power Corporation, a predecessor company. Each document referred to below is incorporated by reference to the files of the Commission, unless the reference to the document in the list is preceded by an asterisk. Previous filings with the Commission are indicated as follows: A--NMPC Registration Statement No. 2-8214; C--NMPC Registration Statement No. 2-8634; F--CNYP Registration Statement No. 2-3414; G--CNYP Registration Statement No. 2-5490; V--NMPC Registration Statement No. 2-10501; X--NMPC Registration Statement No. 2-12443; Z--NMPC Registration Statement No. 2-13285; CC--NMPC Registration Statement No. 2-16193; DD--NMPC Registration Statement No. 2-18995; GG--NMPC Registration Statement No. 2-25526; HH--NMPC Registration Statement No. 2-26918; II--NMPC Registration Statement No. 2-29575; JJ--NMPC Registration Statement No. 2-35112; KK--NMPC Registration Statement No. 2-38083; OO--NMPC Registration Statement No. 2-49570; QQ--NMPC Registration Statement No. 2-51934; SS--NMPC Registration Statement No. 2-52852; TT--NMPC Registration Statement No. 2-54017; VV--NMPC Registration Statement No. 2-59500; CCC--NMPC Registration Statement No. 2-70860; III--NMPC Registration Statement No. 2-90568; OOO--NMPC Registration Statement No. 33-32475; PPP--NMPC Registration Statement No. 33-38093; QQQ--NMPC Registration Statement No. 33-47241; RRR--NMPC Registration Statement No. 33-59594; b--NMPC Annual Report on Form 10-K for year ended December 31, 1990; and c--NMPC Annual Report on Form 10-K for year ended December 31, 1992; and d--NMPC Annual Report on Form 10-K for year ended December 31, 1993; and e--NMPC Annual Report on Form 10-K for year ended December 31, 1994; and f--NMPC Annual Report on Form 10-K for year ended December 31, 1995; and g--NMPC Annual Report on Form 10-K for year ended December 31, 1996. h--NMPC Quarterly Report on Form 10-Q for quarter ended March 31, 1993; and i--NMPC Quarterly Report on Form 10-Q for quarter ended September 30, 1993; and j--NMPC Quarterly Report on Form 10-Q for quarter ended June 30, 1995; and k--NMPC Quarterly Report on Form 10-Q for quarter ended September 30, 1996; l--NMPC Quarterly Report on Form 10-Q for quarter ended June 30, 1997; and m--NMPC Quarterly Report on Form 10-Q for quarter ended September 30, 1997. n--NMPC Report on Form 8-K dated July 9, 1997; and o--NMPC Report on Form 8-K dated October 10, 1997. 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.
INCORPORATION BY REFERENCE ---------------------------------- PREVIOUS PREVIOUS EXHIBIT EXHIBIT NO. DESCRIPTION OF INSTRUMENT FILING DESIGNATION - ---------- ------------------------- -------- ---------------- 3(a)(1) --Certificate of Consolidation of New York Power and Light Corporation, Buffalo Niagara Electric Corporation and Central New York Power Corporation, filed in the office of the New York Secretary of State, January 5, 1950. e 3(a)(1) 3(a)(2) --Certificate of Amendment of Certificate of Incorporation of NMPC, filed in the office of the New York Secretary of State, January 5, 1950. e 3(a)(2) 3(a)(3) --Certificate of Amendment of Certificate of Incorporation of NMPC, pursuant to Section 36 of the Stock Corporation Law of New York, filed August 22, 1952, in the office of the New York Secretary of State. e 3(a)(3) 3(a)(4) --Certificate of NMPC pursuant to Section 11 of the Stock Corporation Law of New York filed May 5, 1954 in the office of the New York Secretary of State. e 3(a)(4) 3(a)(5) --Certificate of Amendment of Certificate of Incorporation of NMPC, pursuant to Section 36 of the Stock Corporation Law of New York, filed January 9, 1957 in the office of the New York Secretary of State. e 3(a)(5) 3(a)(6) --Certificate of NMPC pursuant to Section 11 of the Stock Corporation Law of New York, filed May 22, 1957 in the office of the New York Secretary of State. e 3(a)(6) 3(a)(7) --Certificate of NMPC pursuant to Section 11 of the Stock Corporation Law of New York, filed February 18, 1958 in the office of the New York Secretary of State. e 3(a)(7) 3(a)(8) --Certificate of Amendment of Certificate of Incorporation of NMPC under Section 805 of the Business Corporation Law of New York, filed May 5, 1965 in the office of the New York Secretary of State. e 3(a)(8) 3(a)(9) --Certificate of Amendment of Certificate of Incorporation of NMPC under Section 805 of the Business Corporation Law of New York, filed August 24, 1967 in the office of the New York Secretary of State. e 3(a)(9) 3(a)(10) --Certificate of Amendment of Certificate of Incorporation of NMPC under Section 805 of the Business Corporation Law of New York, filed August 19, 1968 in the office of the New York Secretary of State. e 3(a)(10) 3(a)(11) --Certificate of Amendment of Certificate of Incorporation of NMPC under Section 805 of the Business Corporation Law of New York, filed September 22, 1969 in the office of the New York Secretary of State. e 3(a)(11) 3(a)(12) --Certificate of Amendment of Certificate of Incorporation of NMPC under Section 805 of the Business Corporation Law of New York, filed May 12, 1971 in the office of the New York Secretary of State. e 3(a)(12) 3(a)(13) --Certificate of Amendment of Certificate of Incorporation of NMPC under Section 805 of the Business Corporation Law of New York, filed August 18, 1972 in the office of the New York Secretary of State. e 3(a)(13) 3(a)(14) --Certificate of Amendment of Certificate of Incorporation of NMPC under Section 805 of the Business Corporation Law of New York, filed June 26, 1973 in the office of the New York Secretary of State. e 3(a)(14) 3(a)(15) --Certificate of Amendment of Certificate of Incorporation of NMPC under Section 805 of the Business Corporation Law of New York, filed May 9, 1974 in the office of the New York Secretary of State. e 3(a)(15) 3(a)(16) --Certificate of Amendment of Certificate of Incorporation of NMPC under Section 805 of the Business Corporation Law of New York, filed March 12, 1975 in the office of the New York Secretary of State. e 3(a)(16) 3(a)(17) --Certificate of Amendment of Certificate of Incorporation of NMPC under Section 805 of the Business Corporation Law of New York, filed May 7, 1975 in the office of the New York Secretary of State. e 3(a)(17) 3(a)(18) --Certificate of Amendment of Certificate of Incorporation of NMPC under Section 805 of the Business Corporation Law of New York, filed August 27, 1975 in the office of the New York Secretary of State. e 3(a)(18) 3(a)(19) --Certificate of Amendment of Certificate of Incorporation of NMPC under Section 805 of the Business Corporation Law of New York, filed May 7, 1976 in the office of the New York Secretary of State. e 3(a)(19) 3(a)(20) --Certificate of Amendment of Certificate of Incorporation of NMPC under Section 805 of the Business Corporation Law of New York filed September 28, 1976 in the office of the New York Secretary of State. e 3(a)(20) 3(a)(21) --Certificate of Amendment of Certificate of Incorporation of NMPC under Section 805 of the Business Corporation Law of New York filed January 27, 1978 in the office of the New York Secretary of State. e 3(a)(21) 3(a)(22) --Certificate of Amendment of Certificate of Incorporation of NMPC under Section 805 of the Business Corporation Law of New York filed May 8, 1978 in the office of the New York Secretary of State. e 3(a)(22) 3(a)(23) --Certificate of Correction of the Certificate of Amendment filed May 7, 1976 of the Certificate of Incorporation under Section 105 of the Business Corporation Law of New York filed July 13, 1978 in the office of the New York Secretary of State. e 3(a)(23) 3(a)(24) --Certificate of Amendment of Certificate of Incorporation of NMPC under Section 805 of the Business Corporation Law of New York filed July 17, 1978 in the office of the New York Secretary of State. e 3(a)(24) 3(a)(25) --Certificate of Amendment of Certificate of Incorporation of NMPC under Section 805 of the Business Corporation Law of New York filed March 3, 1980 in the office of the New York Secretary of State. e 3(a)(25) 3(a)(26) --Certificate of Amendment of Certificate of Incorporation of NMPC under Section 805 of the Business Corporation Law of New York filed March 31, 1981 in the office of the New York Secretary of State. e 3(a)(26) 3(a)(27) --Certificate of Amendment of Certificate of Incorporation of NMPC under Section 805 of the Business Corporation Law of New York filed March 31, 1981 in the office of the New York Secretary of State. e 3(a)(27) 3(a)(28) --Certificate of Amendment of Certificate of Incorporation of NMPC under Section 805 of the Business Corporation Law of New York filed April 22, 1981 in the office of the New York Secretary of State. e 3(a)(28) 3(a)(29) --Certificate of Amendment of Certificate of Incorporation of NMPC under Section 805 of the Business Corporation Law of New York filed May 8, 1981 in the office of the New York Secretary of State. e 3(a)(29) 3(a)(30) --Certificate of Amendment of Certificate of Incorporation of NMPC under Section 805 of the Business Corporation Law of New York filed April 26, 1982 in the office of the New York Secretary of State. e 3(a)(30) 3(a)(31) --Certificate of Amendment of Certificate of Incorporation of NMPC under Section 805 of the Business Corporation Law of New York filed January 24, 1983 in the office of the New York Secretary of State. e 3(a)(31) 3(a)(32) --Certificate of Amendment of Certificate of Incorporation of NMPC under Section 805 of the Business Corporation Law of New York filed August 3, 1983 in the office of the New York Secretary of State. e 3(a)(32) 3(a)(33) --Certificate of Amendment of Certificate of Incorporation of NMPC under Section 805 of the Business Corporation Law of New York filed December 27, 1983 in the office of the New York Secretary of State. e 3(a)(33) 3(a)(34) --Certificate of Amendment of Certificate of Incorporation of NMPC under Section 805 of the Business Corporation Law of New York filed December 27, 1983 in the office of the New York Secretary of State. e 3(a)(34) 3(a)(35) --Certificate of Amendment of Certificate of Incorporation of NMPC under Section 805 of the Business Corporation Law of New York filed June 4, 1984 in the office of the New York Secretary of State. e 3(a)(35) 3(a)(36) --Certificate of Amendment of Certificate of Incorporation of NMPC under Section 805 of the Business Corporation Law of New York filed August 29, 1984 in the office of the New York Secretary of State. e 3(a)(36) 3(a)(37) --Certificate of Amendment of Certificate of Incorporation of NMPC under Section 805 of the Business Corporation Law of New York filed April 17, 1985, in the office of the New York Secretary of State. e 3(a)(37) 3(a)(38) --Certificate of Amendment of Certificate of Incorporation of NMPC under Section 805 of the Business Corporation Law of New York filed May 3, 1985, in the office of the New York Secretary of State. e 3(a)(38) 3(a)(39) --Certificate of Amendment of Certificate of Incorporation of NMPC under Section 805 of the Business Corporation Law of New York filed December 24, 1986 in the office of the New York Secretary of State. e 3(a)(39) 3(a)(40) --Certificate of Amendment of Certificate of Incorporation of NMPC under Section 805 of the Business Corporation Law of New York filed June 1, 1987 in the office of the New York Secretary of State. e 3(a)(40) 3(a)(41) --Certificate of Amendment of Certificate of Incorporation of NMPC under Section 805 of the Business Corporation Law of New York filed July 16, 1987 in the office of the New York Secretary of State. e 3(a)(41) 3(a)(42) --Certificate of Amendment of Certificate of Incorporation of NMPC under Section 805 of the Business Corporation Law of New York filed May 27, 1988 in the office of the New York Secretary of State. e 3(a)(42) 3(a)(43) --Certificate of Amendment of Certificate of Incorporation of NMPC under Section 805 of the Business Corporation Law of New York filed September 27, 1990 in the office of the New York Secretary of State. e 3(a)(43) 3(a)(44) --Certificate of Amendment of Certificate of Incorporation of NMPC under Section 805 of the Business Corporation Law of New York filed October 18, 1991 in the office of the New York Secretary of State. e 3(a)(44) 3(a)(45) --Certificate of Amendment of Certificate of Incorporation of NMPC under Section 805 of the Business Corporation Law of New York filed May 5, 1994 in the office of the New York Secretary of State. e 3(a)(45) 3(a)(46) --Certificate of Amendment of Certificate of Incorporation of NMPC under Section 805 of the Business Corporation Law of New York filed August 5, 1994 in the office of the New York Secretary of State. e 3(a)(46) *3(b) --By-Laws of NMPC, as amended February 26, 1998. 4(a) --Agreement to furnish certain debt instruments. e 4(b) 4(b)(1) --Mortgage Trust Indenture dated as of October 1, 1937 between NMPC (formerly CNYP) and Marine Midland Bank, N.A. (formerly named The Marine Midland Trust Company of New York), as Trustee. F ** _________________________ ** Filed October 15, 1937 after effective date of Registration Statement No. 2-3414. 4(b)(2) --Supplemental Indenture dated as of December 1, 1938, supplemental to Exhibit 4(1). VV 2-3 4(b)(3) --Supplemental Indenture dated as of April 15, 1939, supplemental to Exhibit 4(1). VV 2-4 4(b)(4) --Supplemental Indenture dated as of July 1, 1940, supplemental to Exhibit 4(1). VV 2-5 4(b)(5) --Supplemental Indenture dated as of October 1, 1944, supplemental to Exhibit 4(1). G 7-6 4(b)(6) --Supplemental Indenture dated as of June 1, 1945, supplemental to Exhibit 4(1). VV 2-8 4(b)(7) --Supplemental Indenture dated as of August 17, 1948, supplemental to Exhibit 4(1). VV 2-9 4(b)(8) --Supplemental Indenture dated as of December 31, 1949, supplemental to Exhibit 4(1). A 7-9 4(b)(9) --Supplemental Indenture dated as of January 1, 1950, supplemental to Exhibit 4(1). A 7-10 4(b)(10) --Supplemental Indenture dated as of October 1, 1950, supplemental to Exhibit 4(1). C 7-11 4(b)(11) --Supplemental Indenture dated as of October 19, 1950, supplemental to Exhibit 4(1). C 7-12 4(b)(12) --Supplemental Indenture dated as of February 20, 1953, supplemental to Exhibit 4(1). V 4-16 4(b)(13) --Supplemental Indenture dated as of April 25, 1956, supplemental to Exhibit 4(1). X 4-19 4(b)(14) --Supplemental Indenture dated as of March 15, 1960, supplemental to Exhibit 4(1). CC 2-23 4(b)(15) --Supplemental Indenture dated as of October 1, 1966, supplemental to Exhibit 4(1). GG 2-27 4(b)(16) --Supplemental Indenture dated as of July 15, 1967, supplemental to Exhibit 4(1). HH 4-29 4(b)(17) --Supplemental Indenture dated as of August 1, 1967, supplemental to Exhibit 4(1). HH 4-30 4(b)(18) --Supplemental Indenture dated as of August 1, 1968, supplemental to Exhibit 4(1). II 2-30 4(b)(19) --Supplemental Indenture dated as of March 15, 1977, supplemental to Exhibit 4(1). VV 2-39 4(b)(20) --Supplemental Indenture dated as of August 1, 1977, supplemental to Exhibit 4(1). CCC 4(b)(40) 4(b)(21) --Supplemental Indenture dated as of March 1, 1978, supplemental to Exhibit 4(1). CCC 4(b)(42) 4(b)(22) --Supplemental Indenture dated as of June 15, 1980, supplemental to Exhibit 4(1). CCC 4(b)(46) 4(b)(23) --Supplemental Indenture dated as of November 1, 1985, supplemental to Exhibit 4(1). III 4(b)(64) 4(b)(24) --Supplemental Indenture dated as of October 1, 1989, supplemental to Exhibit 4(1). OOO 4(b)(73) 4(b)(25) --Supplemental Indenture dated as of June 1, 1990, supplemental to Exhibit 4(1). PPP 4(b)(74) 4(b)(26) --Supplemental Indenture dated as of November 1, 1990, supplemental to Exhibit 4(1). PPP 4(b)(75) 4(b)(27) --Supplemental Indenture dated as of March 1, 1991, supplemental to Exhibit 4(1). QQQ 4(b)(76) 4(b)(28) --Supplemental Indenture dated as of October 1, 1991, supplemental to Exhibit 4(1). QQQ 4(b)(77) 4(b)(29) --Supplemental Indenture dated as of April 1, 1992, supplemental to Exhibit 4(1). QQQ 4(b)(78) 4(b)(30) --Supplemental Indenture dated as of June 1, 1992, supplemental to Exhibit 4(1). RRR 4(b)(79) 4(b)(31) --Supplemental Indenture dated as of July 1, 1992, supplemental to Exhibit 4(1). RRR 4(b)(80) 4(b)(32) --Supplemental Indenture dated as of August 1, 1992, supplemental to Exhibit 4(1). RRR 4(b)(81) 4(b)(33) --Supplemental Indenture dated as of April 1, 1993, supplemental to Exhibit 4(1). h 4(b)(82) 4(b)(34) --Supplemental Indenture dated as of July 1, 1993, supplemental to Exhibit 4(1). i 4(b)(83) 4(b)(35) --Supplemental Indenture dated as of September 1, 1993, supplemental to Exhibit 4(1). i 4(b)(84) 4(b)(36) --Supplemental Indenture dated as of March 1, 1994, supplemental to Exhibit 4(1). d 4(b)(85) 4(b)(37) --Supplemental Indenture dated as of July 1, 1994, supplemental to Exhibit 4(1). e 4(86) 4(b)(38) --Supplemental Indenture dated as of May 1, 1995, supplemental to Exhibit 4(1). j 4(87) 4(b)(39) --Agreement dated as of August 16, 1940, between CNYP, The Chase National Bank of the City of New York, as Successor Trustee, and The Marine Midland Trust Company of New York, as Trustee. G 7-23 10-1 --Agreement dated March 1, 1957 between the Power Authority of the State of New York and NMPC as to sale, transmission and disposition of St. Lawrence power. Z 13-11 10-2 --Agreement dated February 10, 1961 between the Power Authority of the State of New York and NMPC as to sale, transmission and disposition of Niagara redevelopment power. DD 13-6 10-3 --Agreement dated July 26, 1961 between the Power Authority of the State of New York and NMPC supplemental to Exhibit 10-2. DD 13-7 10-4 --Agreement dated as of March 23, 1973 between the Power Authority of the State of New York and NMPC as to the sale, transmission and disposition of Blenheim-Gilboa power. OO 5-8 10-5 --Agreement dated January 23, 1970 between Consolidated Gas Supply Corporation (formerly named New York State Natural Gas Corporation) and NMPC. KK 5-8 10-6a --New York Power Pool Agreement dated as of February 1, 1974 between NMPC and six other New York utilities and the Power Authority of the State of New York. QQ 5-10 10-6b --New York Power Pool Agreement dated as of April 27, 1975 between NMPC and six other New York electric utilities and the Power Authority of the State of New York (the parties to the Agreement have petitioned the Federal Power Commission for an order permitting such Agreement, which increases the reserve factor of all parties from .14 to .18, to supersede the New York Power Pool Agreement dated as of February 1, 1974). TT 5-10b 10-7 --Agreement dated as of October 31, 1968 between NMPC, Central Hudson Gas & Electric Corporation and Consolidated Edison Company of New York, Inc. as to Joint Electric Generating Plant (the Roseton Station). JJ 5-10 10-8a --Memorandum of Understanding dated as of May 30, 1975 between NMPC and Rochester Gas & Electric Corporation with respect to Oswego Unit No. 6. SS 5-13 10-8b --Memorandum of Understanding dated as of May 30, 1975 between NMPC and Rochester Gas and Electric Corporation with respect to Oswego Unit No. 6. SS 5-13 10-8c --Basic Agreement dated as of September 22, 1975 between NMPC and Rochester Gas and Electric Corporation with respect to Oswego Unit No. 6. VV 5-13b 10-9a --Memorandum of Understanding dated as of May 30, 1975 between NMPC and four other New York electric utilities with respect to Nine Mile Point Nuclear Station Unit No. 2. SS 5-14 10-9b --Basic Agreement dated as of September 22, 1975 between NMPC and four other New York electric utilities with respect to Nine Mile Point Nuclear Station Unit No. 2. VV 5-14b 10-9c --Nine Mile Point Nuclear Station Unit No. 2 Operating Agreement. c 10-19 10-10a --Memorandum of Understanding dated as of May 16, 1974, as amended May 30, 1975, between NMPC and three other New York electric utilities with respect to the Sterling Nuclear Station. SS 5-15 10-10b --Basic Agreement dated as of September 22, 1975 between NMPC and three other New York electric utilities with respect to the Sterling Nuclear Stations. VV 5-15b 10-11 --Master Restructuring Agreement, dated as of July 9, 1997, between the Company and the sixteen independent power producers signatory thereto. n 10.28 10-12 --PowerChoice settlement filed with the PSC on October 10, 1997 o 99-9 *10-13 --PSC Opinion and Order regarding approval of the PowerChoice settlement agreement with PSC, issued and effective March 20, 1998. *10-14 --Preferred Consent, December, 1997 (A)10-15 --NMPC Officers' Incentive Compensation Plan - Plan Document. b 10-16 (A)10-16 --NMPC Long Term Incentive Plan - Plan Document. l 10-1 (A)10-17 --NMPC Management Incentive Compensation Plan - Plan Document. b 10-17 (A)10-18 --CEO Special Award Plan. l 10-2 (A)10-19 --NMPC Deferred Compensation Plan. d 10-16 *(A)10-20 --Amendment to NMPC Deferred Compensation Plan (A)10-21 --NMPC Performance Share Unit Plan. d 10-17 (A)10-22 --NMPC 1992 Stock Option Plan. d 10-18 (A)10-23 --NMPC 1995 Stock Incentive Plan f 10-31 (A)10-24 --Employment Agreement between NMPC and David J. Arrington, Sr. Vice President, Human Resources, dated December 20, 1996. g 10-17 (A)10-25 --Employment Agreement between NMPC and Albert J. Budney, Jr., President and Chief Operating Officer, December 20, 1996. g 10-18 (A)10-26 --Employment Agreement between NMPC and William E. Davis, Chairman of the Board and Chief Executive Officer, dated December 20, 1996. g 10-19 (A)10-27 --Employment Agreement between NMPC and Darlene D. Kerr, Sr. Vice President, Energy Distribution, dated December 20, 1996. g 10-20 (A)10-28 --Employment Agreement between NMPC and Gary J. Lavine, Sr. Vice President, Legal and Corporate Relations, dated December 20, 1996. g 10-21 (A)10-29 --Employment Agreement between NMPC and John W. Powers, Sr. Vice President, and Chief Executive Officer, dated December 20, 1996. g 10-22 (A)10-30 --Employment Agreement between NMPC and B. Ralph Sylvia, Executive Vice President, Electric Generation and Chief Nuclear Officer, dated December 20, 1996. g 10-23 (A)10-31 --Employment Agreement between NMPC and Theresa A. Flaim, Vice President - Corporate Strategic Planning, dated December 20, 1996. g 10-24 (A)10-32 --Employment Agreement between NMPC and Steven W. Tasker, Vice President - Controller, dated December 20, 1996. g 10-25 (A)10-33 --Employment Agreement between NMPC and Kapua A. Rice, Corporate Secretary, dated December 20, 1996. g 10-26 (A)10-34 --Amendment to Employment Agreement between NMPC and David J. Arrington, Albert J. Budney, Jr., William E. Davis, Darlene D. Kerr, Gary J. Lavine, John W. Powers and B. Ralph Sylvia, dated June 9, 1997. l 10-3 (A)10-35 --Employment Agreement between NMPC and William F. Edwards, dated September 25, 1997. m 10-4 *(A)10-36 --Employment Agreement between NMPC and John H. Mueller, dated January 19, 1998. (A)10-37 --Deferred Stock Unit Plan for Outside Directors g 10-27 *11 --Statement setting forth the computation of average number of shares of common stock outstanding. *12 --Statements Showing Computations of Certain Financial Ratios. *21 --Subsidiaries of the Registrant. *23 --Consent of Price Waterhouse LLP, independent accountants. *27 -- Financial Data Schedule. - ------------------------- (A) Management contract or compensatory plan or arrangement required to be filed as an exhibit pursuant to Item 601 of Regulation S-K.
EXHIBIT 11 - ---------- NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARIES COMPUTATION OF AVERAGE NUMBER OF SHARES OF COMMON STOCK OUTSTANDING Average Number of Shares Out- standing as Shown on Consolidated (1) (2) Statements of In- Shares of Number (3) come (3 Divided Common of Days Share Days by Number of Days Year Ended December 31, Stock Outstanding (2 x 1) in Year) - ----------------------- --------- ----------- ---------- ----------------- 1997 ---- January 1 - December 31 144,365,214 365 52,693,303,110 Shares issued at various times during the period - Acquisition - Syracuse Suburban Gas Company, Inc. 54,137 * 14,260,096 ----------- -------------- 144,419,351 52,707,563,206 144,404,283 =========== ============== =========== 1996 ---- January 1 - December 31 144,332,123 366 52,825,557,018 Shares issued at various times during the year - Acquisition - Syracuse Suburban Gas Company, Inc. 33,091 * 6,397,653 ----------- -------------- 144,365,214 52,831,954,671 144,349,603 =========== ============== =========== 1995 ---- January 1 - December 31 144,311,466 365 52,673,685,090 Shares issued - Dividend Reinvestment Plan - January 31 19,016 335 6,370,360 Acquisition - Syracuse Suburban Gas Company, Inc. - October 4 1,641 89 146,049 ----------- -------------- 144,332,123 52,680,201,499 144,329,319 =========== ============== =========== * Number of days outstanding not shown as shares represent an accumulation of weekly, monthly and quarterly issues throughout the year. Share days for shares issued are based on the total number of days each share was outstanding during the year. Note: Earnings per share calculated on both a basic and diluted basis are the same due to the effects of rounding.
EXHIBIT 12 - ---------- NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES 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 Year Ended December 31, ------------------------------------------------------------ 1997 1996 1995 1994 1993 ---- ---- ---- ---- ---- A. Net Income per Statements of Income $183,335 $110,390 $248,036 $176,984 $271,831 B. Taxes Based on Income or Profits 126,595 66,221 159,393 111,469 147,075 -------- -------- -------- -------- -------- C. Earnings, Before Income Taxes 309,930 176,611 407,429 288,453 418,906 D. Fixed Charges (a) 304,451 308,323 314,973 315,274 319,197 -------- -------- -------- -------- -------- E. Earnings Before Income Taxes and Fixed Charges 614,381 484,934 722,402 603,727 738,103 F. Allowance for Funds Used During Construction 9,706 7,355 9,050 9,079 16,232 -------- -------- -------- ------- ------- G. Earnings Before Income Taxes and Fixed Charges without AFC $604,675 $477,579 $713,352 $594,648 $721,871 ======== ======== ======== ======== ======== Preferred Dividend Factor: H. Preferred Dividend Requirements $ 37,397 $ 38,281 $ 39,596 $ 33,673 $ 31,857 -------- -------- -------- --------- -------- I. Ratio of Pre-Tax Income to Net Income (C / A) 1.69 1.60 1.64 1.63 1.54 -------- --------- --------- --------- --------- J. Preferred Dividend Factor (H x I) $ 63,201 $ 61,250 $ 64,937 $ 54,887 $ 49,060 K. Fixed Charges as above (D) 304,451 308,323 314,973 315,274 319,197 -------- -------- -------- -------- -------- L. Fixed Charges and Preferred Dividends Combined $367,652 $369,573 $379,910 $370,161 $368,257 ======== ======== ======== ======== ======== M. Ratio of Earnings to Fixed Charges (E / D) 2.02 1.57 2.29 1.91 2.31 -------- -------- -------- -------- -------- N. Ratio of Earnings to Fixed Charges without AFC (G / D) 1.99 1.55 2.26 1.89 2.26 -------- -------- -------- -------- -------- O. Ratio of Earnings to Fixed Charges and Preferred Dividends Combined (E / L) 1.67 1.31 1.90 1.63 2.00 -------- ------- -------- -------- -------- (a) Includes a portion of rentals deemed representative of the interest factor: $26,149 for 1997, $26,600 for 1996, $27,312 for 1995, $29,396 for 1994 and $27,821 for 1993.
EXHIBIT 21 - ---------- NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES SUBSIDIARIES OF THE REGISTRANT Name of Company State of Organization --------------- --------------------- Opinac North America, Inc. Delaware (Note 1) NM Uranium, Inc. Texas EMCO-TECH, Inc. (Note 2) New York NM Holdings, Inc. (Note 3) New York Moreau Manufacturing Corporation New York Beebee Island Corporation New York NM Receivables Corp. New York NOTE 1: At December 31, 1997, Opinac North America, Inc. owns Opinac Energy Corporation and Plum Street Enterprises, Inc. Opinac Energy Corporation has a 50 percent interest in CNP, which is incorporated in the Province of Ontario, Canada. CNP owns Cowley Ridge Partnership (an Alberta, Canada general partnership) and Canadian Niagara Wind Power Company, Inc. (incorporated in the Province of Alberta, Canada). Plum Street Enterprises, Inc., ("Plum Street") an unregulated company, is incorporated in the State of Delaware. Plum Street owns Plum Street Energy Marketing, Inc. (incorporated in the State of Delaware), Global Energy Enterprises India Private Limited, 90% of Dolphin Investments International, Inc. (a corporation organized and existing under the laws of Nevis, West Indies, which owns 45% of Atlantis Energie Systems AG (a corporation organized and existing under the laws of the Federal Republic of Germany)), 25% of Telergy Joint Venture and 26% of Direct Global Power, Inc. NOTE 2: EMCO-TECH, Inc. is inactive at December 31, 1997. NOTE 3: At December 31, 1997, NM Holdings, Inc. owns Salmon Shores, Inc., Moreau Park, Inc., Riverview, Inc., Hudson Pointe, Inc., Upper Hudson Development, Inc., Land Management & Development, Inc., OPropco, Inc. and LandWest, Inc. EXHIBIT 23 - ---------- CONSENT OF INDEPENDENT ACCOUNTANTS - ---------------------------------- We hereby consent to the incorporation by reference in the Registration Statement on Form S-8 (Nos. 33-36189, 33-42771 and 333-13781) and to the incorporation by reference in the Prospectus constituting part of the Registration Statement on Form S-3 (Nos. 33-50703, 33-51073, 33-54827 and 33-55546 and 333-49541) and in the Prospectus/Proxy Statement constituting part of the Registration Statement on Form S-4 (No. 333-49769) of Niagara Mohawk Power Corporation of our report dated March 26, 1998, except Note 2 (third paragraph) and Note 15, as to which the date is May 29, 1998 appearing in the Company's Form 10-K/A dated May 29, 1998. We also consent to the incorporation by reference of our report on the financial statement schedules, which appears in the Form 10-K. /s/ Price Waterhouse LLP Syracuse, New York May 29, 1998 SIGNATURES - ---------- Pursuant to the requirements of Section 13 or 15(d) 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 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 YEAR DEC-31-1997 DEC-31-1997 PER-BOOK 6868044 371709 1091700 1176824 75864 9584141 144419 1779688 803420 2727527 76610 440000 3417381 0 0 0 67095 10120 0 0 2968908 9584141 3966404 126595 3407565 3407565 558839 24997 583836 273906 183335 37397 145938 0 0 537575 1.01 0
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