-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: keymaster@town.hall.org Originator-Key-Asymmetric: MFkwCgYEVQgBAQICAgADSwAwSAJBALeWW4xDV4i7+b6+UyPn5RtObb1cJ7VkACDq pKb9/DClgTKIm08lCfoilvi9Wl4SODbR1+1waHhiGmeZO8OdgLUCAwEAAQ== MIC-Info: RSA-MD5,RSA, W2/Wom67ixz4bfSBI8FN21YIe6fE4cjeK31fd5IdZG4M3INpd8UnyVHV/kRID3UG ue2VbbZlgbGra1kpuUxFCA== 0000071932-94-000056.txt : 19941122 0000071932-94-000056.hdr.sgml : 19941122 ACCESSION NUMBER: 0000071932-94-000056 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 2 CONFORMED PERIOD OF REPORT: 19940930 FILED AS OF DATE: 19941114 SROS: NONE FILER: COMPANY DATA: COMPANY CONFORMED NAME: NIAGARA MOHAWK POWER CORP /NY/ CENTRAL INDEX KEY: 0000071932 STANDARD INDUSTRIAL CLASSIFICATION: 4931 IRS NUMBER: 150265555 STATE OF INCORPORATION: NY FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: 1934 Act SEC FILE NUMBER: 001-02987 FILM NUMBER: 94560158 BUSINESS ADDRESS: STREET 1: 300 ERIE BLVD W CITY: SYRACUSE STATE: NY ZIP: 13202 BUSINESS PHONE: 3154741511 MAIL ADDRESS: STREET 1: 300 ERIE BLVD W CITY: SYRACUSE STATE: NY ZIP: 13202 FORMER COMPANY: FORMER CONFORMED NAME: CENTRAL NEW YORK POWER CORP DATE OF NAME CHANGE: 19710419 10-Q 1 SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-Q (Mark One) [ X ] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended September 30, 1994 ------------------------------------------------- OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 Commission file number 1-2987. NIAGARA MOHAWK POWER CORPORATION -------------------------------- (Exact name of registrant as specified in its charter) State of New York 15-0265555 ------------------ ---------- (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 300 Erie Boulevard West Syracuse, New York 13202 (Address of principal executive offices) (Zip Code) (315) 474-1511 Registrant's telephone number, including area code Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YES [X] NO [ ] Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date. Common stock, $1 par value, outstanding at October 31, 1994 - 143,972,960 NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES FORM 10-Q - For The Quarter Ended September 30, 1994 INDEX Part I. Financial Information Page Item 1. Financial Statements. a) Consolidated Statements of Income - Three Months and Nine Months Ended September 30, 1994 and 1993 3 b) Consolidated Balance Sheets - September 30, 1994 and December 31, 1993 5 c) Consolidated Statements of Cash Flows - Nine Months Ended September 30, 1994 and 1993 7 d) Notes to Consolidated Financial Statements 8 e) Review by Independent Accountants 17 f) Independent Accountants' Report on the Limited Review of the Interim Financial Information 18 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations. 19 Part II. Other Information Item 1. Legal Proceedings. 39 Item 5. Other Events. 41 Item 6. Exhibits and Reports on Form 8-K. 44 Signature 45 PART 1. FINANCIAL INFORMATION ----------------------------- ITEM 1. FINANCIAL STATEMENTS. ----------------------------- NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES --------------------------------------------------------- CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) ----------------------------------------------
THREE MONTHS ENDED SEPTEMBER 30, --------------------------- 1994 1993 --------- ---------- (In thousands of dollars) OPERATING REVENUES: Electric $ 861,002 $ 812,323 Gas 57,808 67,629 918,810 879,952 OPERATING EXPENSES: Operation: Fuel for electric generation 47,155 57,454 Electricity purchased 285,013 210,378 Gas purchased 20,487 33,202 Other operation expense 177,033 191,958 Maintenance 51,252 59,003 Depreciation and amortization 77,456 69,281 Federal and foreign income taxes 28,487 31,631 Other taxes 122,990 118,506 809,873 771,413 OPERATING INCOME 108,937 108,539 OTHER INCOME AND (DEDUCTIONS): Allowance for other funds used during construction 854 2,129 Federal and foreign income taxes 787 3,472 Other items (net) 5,838 4,613 7,479 10,214 INCOME BEFORE INTEREST CHARGES 116,416 118,753 INTEREST CHARGES: Interest on long-term debt 65,543 69,733 Other interest 5,265 2,845 Allowance for borrowed funds used during construction (2,775) (2,420) 68,033 70,158 NET INCOME 48,383 48,595 Dividends on preferred stock 9,070 7,808 BALANCE AVAILABLE FOR COMMON STOCK $ 39,313 $ 40,787 Average number of shares of common stock outstanding (in thousands) 143,540 142,012 Balance available per average share of common stock $ .27 $ .29 Dividends paid per share of common stock .28 .25 /TABLE PART 1. FINANCIAL INFORMATION ----------------------------- ITEM 1. FINANCIAL STATEMENTS. ----------------------------- NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES --------------------------------------------------------- CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) ----------------------------------------------
NINE MONTHS ENDED SEPTEMBER 30, --------------------------- 1994 1993 --------- ---------- (In thousands of dollars) OPERATING REVENUES: Electric $2,641,575 $2,490,392 Gas 492,493 454,844 3,134,068 2,945,236 OPERATING EXPENSES: Operation: Fuel for electric generation 161,927 175,074 Electricity purchased 830,143 621,040 Gas purchased 260,669 252,545 Other operation expense 523,741 582,488 Maintenance 145,236 161,299 Depreciation and amortization 229,804 205,559 Federal and foreign income taxes 161,773 155,940 Other taxes 377,866 362,414 2,691,159 2,516,359 OPERATING INCOME 442,909 428,877 OTHER INCOME AND (DEDUCTIONS): Allowance for other funds used during construction 2,512 6,090 Federal and foreign income taxes 5,259 11,869 Other items (net) 12,238 6,797 20,009 24,756 INCOME BEFORE INTEREST CHARGES 462,918 453,633 INTEREST CHARGES: Interest on long-term debt 201,404 211,275 Other interest 13,386 8,370 Allowance for borrowed funds used during construction (6,278) (6,888) 208,512 212,757 NET INCOME 254,406 240,876 Dividends on preferred stock 23,158 24,191 BALANCE AVAILABLE FOR COMMON STOCK $ 231,248 $ 216,685 Average number of shares of common stock outstanding (in thousands) 142,987 139,814 Balance available per average share of common stock $ 1.62 $ 1.55 Dividends paid per share of common stock .81 .70 /TABLE NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES --------------------------------------------------------- CONSOLIDATED BALANCE SHEETS ---------------------------
SEPTEMBER 30, 1994 DECEMBER 31, (UNAUDITED) 1993 ------------ ------------ (In thousands of dollars) UTILITY PLANT: Electric plant $ 8,196,173 $7,991,346 Nuclear fuel 468,613 458,186 Gas plant 894,563 845,299 Common plant 273,771 244,294 Construction work in progress 528,945 569,404 Total utility plant 10,362,065 10,108,529 Less-Accumulated depreciation and amortization 3,429,124 3,231,237 Net utility plant 6,932,941 6,877,292 OTHER PROPERTY AND INVESTMENTS 266,975 221,008 CURRENT ASSETS: Cash, including temporary cash investments of $88,004 and $100,182, respectively 145,894 124,351 Accounts receivable (less-allowance for doubtful accounts of $3,600) 230,498 258,137 Unbilled revenues 185,800 197,200 Electric margin recoverable 48,423 21,368 Materials and supplies, at average cost: Coal and oil for production of electricity 25,723 29,469 Gas storage 37,597 31,689 Other 159,569 163,044 Prepaid taxes 48,825 23,879 Prepaid pension expense 39,933 37,238 Other prepayments 27,928 29,498 950,190 915,873 REGULATORY AND OTHER ASSETS (Note 3): Unamortized debt expense 157,266 154,210 Deferred recoverable energy costs 48,935 67,632 Deferred finance charges 239,880 239,880 Income taxes recoverable 527,995 527,995 Recoverable environmental restoration costs 240,000 240,000 Other 190,908 175,187 1,404,984 1,404,904 $ 9,555,090 $9,419,077 /TABLE NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES ---------------------------------------------------------- CONSOLIDATED BALANCE SHEETS --------------------------- CAPITALIZATION AND LIABILITIES ------------------------------
SEPTEMBER 30, 1994 DECEMBER 31, (UNAUDITED) 1993 ------------- ------------ (In thousands of dollars) CAPITALIZATION: COMMON STOCKHOLDERS' EQUITY: Common stock - $1 par value; authorized 185,000,000 shares; issued 143,886,104 and 142,427,057 shares, respectively $ 143,886 $ 142,427 Capital stock premium and expense 1,778,894 1,762,706 Retained earnings 666,833 551,332 ---------- ---------- 2,589,613 2,456,465 ---------- ---------- CUMULATIVE PREFERRED STOCK, AUTHORIZED 3,400,000 SHARES, $100 PAR VALUE: Non-redeemable (optionally redeemable), issued 2,100,000 shares 210,000 210,000 Redeemable (mandatorily redeemable), issued 276,000 shares and 294,000 shares, respectively 25,800 27,600 CUMULATIVE PREFERRED STOCK, AUTHORIZED 19,600,000 SHARES, $25 PAR VALUE: Non-redeemable (optionally redeemable), issued 3,200,000 shares 80,000 80,000 Redeemable (mandatorily redeemable), issued 10,290,005 shares and 4,840,005 shares, respectively 231,850 95,600 547,650 413,200 Long-term debt 3,244,472 3,258,612 Total capitalization 6,381,735 6,128,277 CURRENT LIABILITIES: Short-term debt 359,001 368,016 Long-term debt due within one year 68,078 216,185 Sinking fund requirements on redeemable preferred stock 27,200 27,200 Accounts payable 225,158 299,209 Payable on outstanding bank checks 63,151 35,284 Customers' deposits 14,741 14,072 Accrued taxes 63,880 56,382 Accrued interest 68,458 70,529 Accrued vacation pay 41,370 40,178 Other 133,794 82,145 1,064,831 1,209,200 REGULATORY AND OTHER LIABILITIES: Accumulated deferred income taxes 1,373,246 1,313,483 Deferred finance charges 239,880 239,880 Unbilled revenues 83,568 94,968 Deferred pension settlement gain 53,266 62,282 Customers refund for replacement power cost disallowance 5,770 23,081 Other 112,794 107,906 1,868,524 1,841,600 COMMITMENTS AND CONTINGENCIES (NOTE 2): Liability for environmental restoration 240,000 240,000 $9,555,090 $9,419,077 /TABLE NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES --------------------------------------------------------- CONSOLIDATED STATEMENTS OF CASH FLOWS ------------------------------------- INCREASE (DECREASE) IN CASH (UNAUDITED) ----------------------------------------
NINE MONTHS ENDED SEPTEMBER 30, 1994 1993 ------------- ------------ (In thousands of dollars) CASH FLOWS FROM OPERATING ACTIVITIES: Net income $ 254,406 $ 240,876 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization 229,804 205,559 Amortization of nuclear fuel 29,316 27,917 Provision for deferred Federal income taxes 59,763 27,127 Electric margin recoverable (27,055) (14,216) Allowance for other funds used during construction (2,511) (6,090) Deferred recoverable energy costs 18,697 28,853 Amortization of nuclear replacement power cost disallowance (17,311) (17,790) Increase in net accounts receivable 27,639 622 (Increase) Decrease in materials and supplies (76) 21,959 Decrease in accounts payable and accrued expenses (37,251) (42,819) Increase in accrued interest and taxes 5,427 40,339 Changes in other assets and liabilities 21,800 (8,954) NET CASH PROVIDED BY OPERATING ACTIVITIES 562,648 503,383 CASH FLOWS FROM INVESTING ACTIVITIES: Construction additions (294,582) (282,235) Nuclear fuel (10,427) (17,327) Less: Allowance for other funds used during construction 2,512 6,090 Acquisition of utility plant (302,497) (293,472) Increase in materials and supplies related to construction 1,390 1,177 Decrease in accounts payable and accrued expenses related to construction (9,313) (10,705) Proceeds from sale of investment in oil and gas subsidiary - 95,408 Increase in other investments (45,413) (21,168) Other (15,557) (8,979) NET CASH USED IN INVESTING ACTIVITIES (371,390) (237,739) CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from the sale of common stock 23,765 110,337 Issuance of preferred stock 150,000 - Issuance of long-term debt 325,705 635,000 Reductions in long-term debt (486,586) (416,990) Redemption of preferred stock (15,550) (15,550) Net change in short-term debt (9,015) (262,698) Dividends paid (136,768) (122,569) Other (21,266) (26,090) NET CASH USED IN FINANCING ACTIVITIES (169,715) (98,560) NET INCREASE IN CASH 21,543 167,084 Cash at beginning of period 124,351 43,894 CASH AT END OF PERIOD $ 145,894 $ 210,978 SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION: Interest paid $ 221,482 $ 216,952 Income taxes paid 93,001 90,347 SUPPLEMENTAL SCHEDULE OF NONCASH INVESTING AND FINANCING ACTIVITIES: Liability for environmental restoration - 10,000 /TABLE NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. The Company, in the opinion of management, has included adjustments (which include normal recurring adjustments) necessary for a fair statement of the results of operations for the interim periods presented. The consolidated financial statements for 1994 are subject to adjustment at the end of the year when they will be audited by independent accountants. The consolidated financial statements and notes thereto should be read in conjunction with the financial statements and notes for the years ended December 31, 1993, 1992 and 1991 included in the Company's 1993 Annual Report to Shareholders on Form 10-K. The Company's electric sales tend to be substantially higher in summer and winter months as related to weather patterns in its service territory; gas sales tend to peak in the winter. Notwithstanding other factors, the Company's quarterly net income will generally fluctuate accordingly. Therefore, the earnings for the three-month and nine-month periods ended September 30, 1994, should not be taken as an indication of earnings for all or any part of the balance of the year. Certain amounts have been reclassified on the accompanying Consolidated Financial Statements to conform with the 1994 presentation. 2. Contingencies. Environmental issues: The public utility industry typically utilizes and/or generates in its operations a broad range of potentially hazardous wastes and by- products. These wastes or by-products may not have previously been considered hazardous, and may not be considered hazardous currently, but may be identified as such by Federal, state or local authorities in the future. 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 assure 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 been advised that various Federal, state or local agencies believe that certain properties require investigation and has prioritized the sites based on available information in order to enhance the management of investigation and remediation, if determined to be necessary. The Company is currently aware of 89 sites with which it has been or may be associated, including 46 which are Company-owned. The Company-owned sites include 23 former coal gasification (MGP) sites, 11 industrial waste sites and 12 operating property sites where corrective actions may be deemed necessary to prevent, contain and/or remediate contamination of soil and/or water in the vicinity. Of these Company-owned sites, Saratoga Springs is on the Federal National Priorities List for Uncontrolled Hazardous Waste Sites (NPL) published by the Environmental Protection Agency (EPA). The 43 non-owned sites with which the Company has been or may be associated are generally industrial disposal waste sites where some of the disposed waste materials are alleged to have originated from the Company's operations. Pending the results of investigations, the Company may be required to contribute some proportionate share of remedial costs. Not included in the 89 sites are seven sites for which the Company has reached final settlement agreements with other potentially responsible parties (PRP), five sites where further remedial activity is not considered necessary and three sites where remediation activities have been completed. The Company is also aware of approximately 20 formerly- owned MGP sites with which the Company has been or may be associated and which may require future investigation and possible remediation. Also, approximately 11 fire training sites used by the Company have been identified but not investigated. Presently, the Company has not determined its potential involvement with such sites and has made no provision for potential liabilities associated therewith. Investigations at each of the Company-owned sites are designed to (1) determine if environmental contamination problems exist, (2) determine the extent, rate of movement and concentration of pollutants, (3) if necessary, determine the appropriate remedial actions required for site restoration and (4) where appropriate, identify other parties who should bear some or all of the cost of remediation. Legal action against such other parties, if necessary, will be initiated. After site investigations have been completed, the Company expects to determine site- specific remedial actions necessary and to estimate the attendant costs for restoration. However, since technologies are still developing and the Company has not yet undertaken any full-scale remedial actions following regulatory requirements at any identified sites, nor have any detailed remedial designs been prepared or submitted to appropriate regulatory agencies, the ultimate cost of remedial actions may change substantially as investigation and remediation progresses. The Company estimates that 40 of the 46 owned sites will require some degree of remediation and post-remedial monitoring. This conclusion is based upon a number of factors, including the nature of the identified or potential contaminants, the location and size of the site, the proximity of the site to sensitive resources, the status of regulatory investigation and knowledge of activities at similarly situated sites. Although the Company has not extensively investigated many of those sites, it believes it has sufficient information to estimate a range of cost of investigation and remediation. As a consequence of site characterizations and assessments completed to date, the Company has accrued a liability of $210 million for these owned sites, representing the low end of the range of the estimated cost for investigation and remediation. The high end of the range is presently estimated at approximately $515 million. The majority of these cost estimates relate to the MGP sites. Of the 23 MGP sites, the Harbor Point (Utica, NY) and Saratoga Springs sites are being investigated and remediated pursuant to separate regulatory Consent Orders. The remaining 21 MGP sites are the subject of an Order on Consent executed with the New York State Department of Environmental Conservation (DEC) providing for an investigation and remediation program over approximately ten years. Preliminary site assessments have been conducted or are in process at eight of these 21 sites, with remedial investigations either currently in process or scheduled for five sites in 1994. Remedial investigations have been conducted or are in process for five industrial waste sites and for three operating properties where corrective actions were considered necessary. The Company recently completed preliminary assessments at the fire training sites which it owns and determined five sites will require further investigation. These sites and the costs to investigate them are included in the sites discussed above and the amounts accrued at September 30, 1994. With respect to the 43 sites with which the Company has been or may be associated as a PRP, nine are listed on the NPL. Total costs to investigate and remediate these sites are estimated to be approximately $570 million; however, the Company estimates its share of this total at approximately $30 million and this amount has been accrued at September 30, 1994. The seven sites for which final settlement agreements have been executed resulted in payment by the Company of amounts not considered to be material. For the 9 sites included on the NPL, the estimated aggregate liability for these sites is not material and is included in the determination of the amounts accrued. Estimates of the Company's potential liability for sites not owned by the Company, but for which the Company has been identified as a PRP, have been derived by estimating the total cost of site clean-up and then applying the related Company contribution factor to that estimate. Estimates of the total clean-up costs are determined by using all available information from investigations conducted to date, negotiations with other PRPs and, where no other basis is available at the time of estimate, the EPA figure for average cost to remediate a site listed on the NPL as disclosed in the Federal Register of June 23, 1993 (58 FR No. 119). The contribution factor is then calculated using either a per capita share based upon the total number of PRPs named or otherwise identified, which assumes all PRPs will contribute equally, or the percentage agreed upon with other PRPs through steering committee negotiations or by other means. Actual Company expenditures for these sites 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 in certain of these PRP sites and is contesting liability accordingly. The EPA advised the Company by letter that it is one of 833 PRPs under Superfund for the investigation and cleanup of the Maxey Flats Nuclear Disposal Site in Morehead, Kentucky. The Company has contributed to a study of this site and estimates that the cost to the Company for its share of investigation and remediation based on its contribution factor of 1.3% would approximate $1 million, which the Company believes will be recoverable in the ratesetting process. On July 21, 1988, the Company received notice of a motion by Reynolds Metals Company to add the Company as a third party defendant in an ongoing Superfund lawsuit in Federal District Court, Northern District of New York. This suit involves PCB oil contamination at the York Oil Site in Moira, New York. Waste oil was transported to the site during the 1960's and 1970's by contractors of Peirce Oil Company (owners/operators of the site) who picked up waste oil at locations throughout Central New York, allegedly including one or more Company facilities. On May 26, 1992, the Company was formally served in a Federal Court action initiated by the government against 8 additional defendants. Pursuant to the requirements of a case management order issued by the Court on March 13, 1992, the Company has also been served in related third and fourth- party actions for contribution initiated by other defendants. These actions have been consolidated into a single action filed in February 1994 by the federal government against several entities, including the Company, which did not accept the government's proposed final terms of settlement. The Company intends to vigorously oppose and defend against the government's characterization of its liability in this matter. The Company believes that costs incurred in the investigation and restoration process for both Company- owned sites and sites with which it is associated will be recoverable in the ratesetting process, see Note 3. Rate agreements in effect since 1991 provide for recovery of anticipated investigation and remediation expenditures. The Company's 1994 rate settlement includes $21.7 million for site investigation and remediation. The Staff of the New York State Public Service Commission (PSC Staff) reserves the right to review the appropriateness of the costs incurred. While the PSC Staff has not challenged any remediation costs to date, the PSC Staff asserted in the gas rate proceeding that the Company must, in future rate proceedings, justify why it is appropriate that remediation costs associated with non-utility property owned by the Company be recovered from ratepayers. Based upon management's assessment that remediation costs will be recovered from ratepayers, a regulatory asset has been recorded representing the future recovery of remediation obligations accrued to date. The Company is currently providing notices of insurance claims to carriers with respect to the investigation and remediation costs for manufactured gas plant and industrial waste sites. The Company is unable to predict whether such insurance claims will be successful. Tax assessments: The Internal Revenue Service (IRS) has conducted an examination of the Company's Federal income tax returns for the years 1987 and 1988 and has submitted a Revenue Agents' Report to the Company. The IRS has proposed various adjustments to the Company's federal income tax liability for these years which could increase the Federal income tax liability by approximately $80 million before assessment of penalties and interest. Included in these proposed adjustments are several significant issues involving Nine Mile Point Nuclear Station Unit 2 (Unit 2). The Company is vigorously defending its position on each of the issues, and submitted a protest to the IRS in 1993. Pursuant to the Unit 2 settlement entered into with the New York State Public Service Commission (PSC) in 1990, to the extent the IRS is able to sustain disallowances, the Company will be required to absorb a portion of any disallowance. The Company believes any such disallowance will not have a material impact on its financial position or results of operations. Litigation: On March 22, 1993, a complaint was filed in the Supreme Court of the State of New York, Albany County against the Company and certain of its officers and employees. The plaintiff, Inter-Power of New York, Inc. (Inter-Power), alleges, among other matters, fraud, negligent misrepresentation and breach of contract in connection with the Company's alleged termination of a power purchase agreement in January 1993. The plaintiff sought enforcement of the original contract or compensatory and punitive damages in an aggregate amount that would not exceed $1 billion, excluding pre-judgment interest. On July 19, 1994, the New York Supreme Court granted the Company's motion for an order directing dismissal of Inter- Power's complaint for lack of merit and denied Inter- Power's cross-motion to compel disclosure. The order was entered July 26, 1994. On August 23, 1994, Inter-Power filed a notice of appeal of this decision which was rejected on November 2, 1994. The Company cannot predict whether Inter-Power will pursue further appeals of this decision. The Company believes it has meritorious defenses and will continue to defend the lawsuit vigorously. On November 12, 1993, Fourth Branch Associates Mechanicville (Fourth Branch) filed suit against the Company and several of its officers and employees in the New York Supreme Court, Albany County, seeking compensatory damages of $50 million, punitive damages of $100 million and injunctive and other related relief. The suit grows out of the Company's termination of a contract for Fourth Branch to operate and maintain a hydroelectric plant the Company owns in the Town of Halfmoon, New York. Fourth Branch's complaint also alleges claims based on the inability of Fourth Branch and the Company to agree on terms for the purchase of power from a new facility that Fourth Branch hoped to construct at the Mechanicville site. On January 3, 1994, the defendants filed a joint motion to dismiss Fourth Branch's complaint. This motion has yet to be decided. On March 16, 1994, the Court denied Fourth Branch's motion for preliminary judgment. The Company also notified Fourth Branch by letter dated March 1, 1994, that the Licensing Agreement between Fourth Branch and the Company is terminated. On March 15, 1994, Fourth Branch petitioned the Federal Energy Regulatory Commission (FERC) for Extraordinary Relief. The Company responded in opposition to this petition before FERC. FERC has taken no action on Fourth Branch's petition other than to seek information and plans relating to the continued safe operation of existing facilities. The Company supplied such information. The Company understands that Fourth Branch has filed for bankruptcy. On October 26, 1994, Fourth Branch, through its attorneys filed a petition with the PSC requesting the PSC to direct the Company to sell the Mechanicville facility to Fourth Branch for fair value and to relinquish its colicensee status on the FERC license, or in the alternative, to require the Company to turn over its investment in the plant from rate base. The Company will strongly oppose this petition. The Company believes it has meritorious defenses and intends to defend the lawsuit vigorously. The Company can neither provide any judgment regarding the likely outcome of this litigation, nor provide any estimate or range of possible loss it might incur as a result of such litigation. 3. Regulatory and Other Assets. Certain expenses and credits, normally reflected in income as incurred, are recognized when included in rates and recovered from or refunded to customers. As such, the Company has recorded the following regulatory assets which are expected to result in future revenues as these costs are recovered through the ratemaking process. Historically, all costs of this nature which are determined by the PSC to have been prudently incurred have been recoverable through rates in the course of normal ratemaking procedures and the Company believes that the items detailed below will be afforded similar treatment. Additionally, the Company's rate plan described below under "1995 Five-Year Rate Plan Filing" contemplates no change in this approach to such recoverability, even though the plan recognizes that in a more competitive environment an effective response to the general pressure to manage costs and preserve or expand markets is vital to maintaining profitability. September 30, December 31, 1994 1993 (In thousands) Income taxes recoverable $ 527,995 $ 527,995 Deferred finance charges 239,880 239,880 Recoverable environmental restoration costs 240,000 240,000 Unamortized debt expense 157,266 154,210 Deferred unregulated generators contract termination costs 47,493 50,680 Deferred postemployment benefit costs 53,946 30,741 Deferred gas pipeline costs 28,000 31,000 Deferred recoverable energy costs 48,935 67,632 Other 61,469 62,766 Total $1,404,984 $1,404,904 Income taxes recoverable represents the expected tax consequences of temporary differences between the recorded book bases and the tax bases of assets and liabilities. These amounts are amortized and recovered as the related temporary differences reverse. Deferred finance charges represent the deferral of the discontinued portion of allowance for funds used during construction (AFC) related to construction work in process at Unit 2 which was included in rate base. This amount is offset by a corresponding deferred credit. Both amounts await future disposition by the PSC. Recoverable 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. Current rates provide an annual allowance to recover anticipated annual expenditures. Unamortized debt expense represents the costs to issue long-term debt securities including premiums on certain debt retirements prior to maturity. These amounts are amortized ratably over the lives of the related issues in accordance with PSC directives. Deferred unregulated generators contract termination costs represent the Company's cost to buy out certain unregulated generator projects. Approximately $15 million of these costs are currently being recovered over a three-year period beginning in 1994. The remaining costs are being addressed in the Company's current rate filing. Deferred postemployment benefit costs represent the excess of such costs recognized in accordance with SFAS No. 106 over the amount received in rates. These costs are being phased-in to rates and amounts deferred will be amortized and recovered, in accordance with the PSC's policy statement, over a period not to exceed 20 years. Deferred gas pipeline costs represent the estimated restructuring costs the Company anticipates incurring as a result of FERC Order No. 636. These costs are treated as a cost of purchased gas and are recoverable through the operation of the gas adjustment clause mechanism over a period of approximately 7 years, with recovery more heavily weighted in the first 3 years. Deferred recoverable energy costs includes the difference between actual fuel costs and the fuel revenues received through the Company's fuel adjustment clause (FAC) and the unamortized portion of the Company's mandated contribution to decommission the Department of Energy's (DOE) uranium enrichment facilities. The fuel costs are amortized as they are collected from customers while the costs to decommission the DOE facilities are being amortized and recovered, as a fuel cost, over a fifteen year period. The costs to decommission DOE facilities result from the Energy Policy Act of 1992, which requires domestic utilities to contribute amounts, escalated for inflation, based upon the amount of uranium enriched by DOE for each utility. NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES REVIEW BY INDEPENDENT ACCOUNTANTS The Company's independent accountants, Price Waterhouse LLP, have made limited reviews (based on procedures adopted by the American Institute of Certified Public Accountants) of the unaudited Consolidated Balance Sheet of Niagara Mohawk Power Corporation and Subsidiary Companies as of September 30, 1994 and the unaudited Consolidated Statements of Income for the three-month and nine-month periods ended September 30, 1994 and 1993 and of Cash Flows for the nine months ended September 30, 1994 and 1993. The accountants' report regarding their limited reviews of the Form 10-Q of Niagara Mohawk Power Corporation and its subsidiaries appears on the next page. That report does not express an opinion on the interim unaudited consolidated financial information. Price Waterhouse LLP has not carried out any significant or additional audit tests beyond those which would have been necessary if their report had not been included. Accordingly, such report is not a "report" or "part of the Registration Statement" within the meaning of Sections 7 and 11 of the Securities Act of 1933 and the liability provisions of Section 11 of such Act do not apply. PRICE WATERHOUSE LLP ONE MONY PLAZA SYRACUSE NY 13202 TELEPHONE 315-474-6571 REPORT OF INDEPENDENT ACCOUNTANTS November 10, 1994 To the Stockholders and Board of Directors of Niagara Mohawk Power Corporation 300 Erie Boulevard West Syracuse NY 13202 We have reviewed the condensed consolidated balance sheet of Niagara Mohawk Power Corporation and its subsidiaries as of September 30, 1994, and the related condensed consolidated statements of income for the three-month and nine-month periods ended September 30, 1994 and 1993 and of cash flows for the nine- months ended September 30, 1994 and 1993. These financial statements are the responsibility of the Company's management. We conducted our review in accordance with standards established by the American Institute of Certified Public Accountants. A review of interim financial information consists principally of applying analytical procedures to financial data and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with generally accepted auditing standards, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion. Based on our review, we are not aware of any material modifications that should be made to the condensed consolidated financial statements referred to above for them to be in conformity with generally accepted accounting principles. We have previously audited, in accordance with generally accepted auditing standards, the consolidated balance sheet at December 31, 1993, and the related consolidated statements of income and retained earnings and of cash flows for the year then ended (not presented herein); and in our report dated January 27, 1994, we expressed an unqualified opinion (containing an explanatory paragraph relating to the Company's involvement as a defendant in lawsuits relating to actions with respect to certain purchased power contracts) on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 1993 is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived. /s/ Price Waterhouse LLP Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations Financial Position, Liquidity and Capital Resources The potential intensity and accelerating pace of competition may be the most significant factor driving fundamental changes in the way utilities, including the Company, are being managed. The Company believes that the price of electricity may be the most important element of future success in the industry and has intensified its efforts to reduce various costs that significantly influence the price of electricity. As described below, the Company, as part of its downsizing efforts, is completing an early retirement and voluntary separation program under which 1,380 employees elected to participate. Efforts to reduce tax burdens continue, with the New York State Senate having passed a measure to phase out the gross receipts tax. While this measure was not enacted into law, real change may be possible in the next legislative session. The Company is also making progress in reducing excessive property tax levies. The dismissal of the Inter-power lawsuit and developments in the Sithe/Alcan proceeding as described in the Notes to Financial Statements and Part II of this 10-Q, respectively, also demonstrate the Company's commitment to reducing excessive unregulated generator payments. These steps exemplify the Company's resolve to reduce its cost structure and are part of the overall effort to address the many issues confronting the Company as further described herein. Early Retirement and Voluntary Separation Programs On July 29, 1994, the Company announced a plan to achieve further substantial reductions in its staffing levels in an effort to bring the Company's staffing levels and work practices more into line with other peer group utilities and become more competitive in its cost structure. The plan included an early retirement program and a voluntary separation program. On August 30, 1994, union employees, representing approximately 70% of the Company's workforce, approved amendments to the current labor agreement with the Company which offered union employees the early retirement and voluntary separation plans, in exchange for a negotiated package of work rule changes. Elections under the programs became final on October 26, 1994 and 1,380 employees have taken advantage of the early retirement and voluntary separation program. Most of the participants in the programs terminated their employment as of October 31, 1994. While the Company does not have a final cost estimate for the programs, it believes the cost will be in the range of $100 to $130 million. The programs are expected to yield labor cost savings of approximately $75 million in 1995, which includes capital and expense. While the Company generally intends to share the savings from the programs with customers in 1995, it has not determined the method by which the sharing would be accomplished. Although the staffing reductions are expected to produce long term savings, the Company may be required to record a charge against earnings in the fourth quarter of 1994. The Company may decide to seek recovery from customers of all or a portion of the cost of the program, but can provide no assurance that the PSC would approve such recovery. Competition The Company is experiencing a loss of industrial load across its system for a variety of reasons. In some cases, customers have found alternative suppliers or are generating their own power. In other cases a weakened economy has forced customers to relocate or shut down. As a first step in addressing the threat of further loss of industrial load, the PSC approved a rate (referred to as SC-10) under which the Company was allowed to negotiate individual contracts with some of its largest industrial and commercial customers to provide them with electricity at lower prices. Under this rate, customers had to demonstrate that they could generate power more economically than the Company's service. The SC-10 tariff has now been superseded by SC-11 as described below. During the year that SC-10 was in place, eighteen contracts were signed, and seventeen are still in effect. Most of the existing contracts are three year fixed price agreements expiring in late 1996 and early 1997. The total annual SC-10 discounts amount to $7.9 million, which preserve $32 million in net revenue. As discussed below under "PSC's Flexible Rates Guidelines; Wholesale Market Proceeding", the PSC issued an order for Phase I of its generic competitiveness proceeding, requiring the Company (and other New York utilities with flexible tariffs) to file amendments to SC-10. On August 10, 1994, the Company filed for a new service classification, SC-11, for Individually Negotiated Contract Rates. The tariffs for SC-11 are effective immediately. While all existing contracts under SC-10 will continue in place, all new contract rates will be administered under the new SC-11 service classification. SC-11 was created to respond to demonstrated non-residential competitive pricing scenarios including, but not limited to, on-site generation, fuel switching, facility relocation and partial plant production shifting. Contracts will be negotiated on a case-by-case basis, for a term not to exceed seven years, with prices generally subject to a floor of the marginal cost of service plus one cent per kilowatt hour. The Company will apply the sharing provisions of SC-10 as described under the 1994 Rate Agreement for SC-11 in 1994. The Company expects a significant number of industrial customers to negotiate contracts and many of these contracts should be revenue enhancing. As of October 31, 1994, approximately 40 customers had active requests to the Company for an SC-11 contract. Of the ten customers that entered into negotiations with the Company, three have accepted offers. Those three contracts provide additional net revenues to the Company of $122,000 annually. Incremental load is priced at competitive rates based on current market conditions. Contract lengths are from three to seven years. Under the terms of its 1994 Rate Agreement, the Company filed a "competitiveness" study with the PSC on April 7, 1994, entitled "The Impacts of Emerging Competition in the Electric Utility Industry." The assessment of competition contained in the report describes the initial results of the Company's CIRCA 2000 (Comprehensive Industry Restructuring and Competitive Assessment for the 2000s) studies. Although there is considerable debate about what changes should occur in the electric industry and even more uncertainty about what will actually happen, the study explores the Company's best estimate of how impacts would vary depending on the extent of changes in the industry and the pace at which those changes are allowed to unfold. The report presents a brief review of federal energy policy and the current debate over industry restructuring as background information. A discussion of the competitive forces that the Company faces is followed by an assessment of the competitiveness of the Company's electricity supply costs and an explanation of the potential financial effects of increased competition. Certain adversaries of the Company in New York State and certain governmental officials have stated that the best way for the Company to address competitive issues would be to take substantial, but unspecified in amount, writedowns of its assets, particularly its nuclear and fossil generating plants. The Company's position is that any proper solution to the problems posed by increasing competition and deregulation must be substantially more evenhanded, and will necessarily be more complicated, than any such proposal. With respect to writedowns, the Company's position continues to be that any revaluation of its assets needs to address the entire catalogue of assets, including generation, transmission and distribution assets. The Company sells electricity generated from diverse supply sources to reduce sensitivity to changes in the economics of any single fuel source. However, the average cost of these diverse sources may be greater than any single fuel source. While the Company's average generation costs are competitive with costs of new suppliers of electricity, the current excess supply of capacity in the Northeast and Canada has significantly depressed wholesale prices, which may be indicative of retail prices in the near term if competition quickly expands. Under these circumstances, by-pass of the Company's systems is a growing threat, although no regulatory structure for bypass currently exists in New York State. There is increasing public debate within several municipalities in the Company's service territory on the issue of by-pass. While municipalities across the country have long been able to form municipal utilities, the Energy Policy Act of 1992 might increase the appeal of municipalization because the law allows FERC to mandate open wholesale access to transmission. Municipalization has the potential to adversely affect the Company's customer base and profitability. From a broader industry perspective, the assessment concludes that selective discounting to avoid uneconomic by-pass is likely to be effective in the current regulatory and competitive regime. Full retail competition, if not managed appropriately and consistently, could create significantly higher prices for core customers, jeopardize the financial viability of the electric utility industry and devastate the social programs delivered by the industry. While aggressive cost management must be part of any response to competition, it alone cannot address the financial consequences that may arise from a sudden and dramatic policy change. Regulators, legislators, and utilities must collaborate to create a fair and equitable transition to increased competition that addresses the obligation to serve, incumbent burdens, transition costs, and exit fees. On November 1, 1994, Governor Cuomo requested the State Energy Planning Board, in cooperation with other state agencies, the Energy Association, the Independent Power Producers of New York and other public interest groups to convene a series of public forums across the state. The purpose of the public forums is to pursue, from a broad public policy perspective, all opportunities to reduce electricity costs while assuring, to the extent possible, that the transition to a more competitive electric industry proceeds in a fair and equitable manner. A report on additional actions to be considered in reducing electricity rates and bills is due to the governor by July 1, 1995. The Company believes this to be an appropriate beginning to the process of managing the transition to a more competitive market, but is unable to predict the outcome of the process. PSC's Flexible Rates Guidelines; Wholesale Market Proceeding On June 2, 1994, the PSC announced the adoption of guidelines to govern flexible electric rates offered by utilities to retain qualified customers in the face of growing competition from unregulated generators. The guidelines concluded, among other things: (i) that such rates should be available for customers who have "realistic competitive alternatives," (ii) that utilities should not be mandated to offer such rates, (iii) that there should be a sharing between stockholders and ratepayers of the lost revenues resulting from such discounts, (iv) that a floor should be calculated by each utility, which should generally be no lower than the marginal cost of service plus one cent per kilowatt hour ($0.01/kWh), and (v) that such flexible rate contracts should not be fixed for periods longer than seven years. The PSC noted that the flexible rates being offered by the Company, as well as New York State Electric and Gas Corporation and Rochester Gas and Electric Corporation, should serve as models. On June 20, 1994, the PSC announced the commencement of Phase II of its proceeding, which will examine issues related to the establishment of a "wholesale competitive market" to provide power that would be wheeled to local utilities over the interconnected transmission line system in the state. The PSC also asked parties to the proceeding, who include the PSC's staff, independent power producers and industrial customer groups as well as traditional utilities: (i) to explore the pros and cons of different market structures, (ii) to identify the most efficient structure for competition among electric providers and (iii) to help determine "whether or not utilities as providers of transmission and distribution services should divest themselves of their generating assets." Similar rate initiatives on competitively priced natural gas are being addressed in a comprehensive generic investigation, currently being conducted by the PSC, into issues involving the restructuring of gas utility services to respond to emerging competition. In response to these competitive forces and changes in regulation being faced by the Company, the Company has from time to time considered, and expects to continue to consider, various strategies designed to enhance its competitive position and to increase its ability to adapt to and anticipate changes in its utility business. These strategies may include business combinations with other companies, internal restructurings involving the potential separation of its generation, transmission and/or distribution businesses, on a wholesale or retail basis, acquisitions of related or unrelated businesses, and additions to or disposition of portions of its franchised service territories. The Company may from time to time be engaged in preliminary discussions, either internally or with third parties, regarding one or more of these potential strategies. No assurances can be given as to whether, when or on what terms any potential transaction of the type described above may actually occur, or as to the ultimate effect thereof on the financial condition or competitive position of the Company. With respect to the foregoing, the New York State Energy Plan (SEP), issued October 31, 1994 and referred to in Part II. Item 5 Other Events, calls upon the New York Power Authority and the state's investor-owned utilities to study the feasibility of creating a joint entity to operate and maintain the nuclear generating stations in the state and to provide a preliminary report within six months of the issuance of the final SEP. The report also calls for the development of a fully competitive wholesale generation market in the state within five years and observes that if utility generation is separated from transmission, the PSC "should consider carefully the valuation and allocation of utility assets in the regulated and competitive sectors". 1995 Five-Year Rate Plan Filing On February 4, 1994, the Company made a combined electric and gas rate filing for rates to be effective January 1, 1995 seeking a $133.7 million (4.3%) increase in electric revenues and a $24.8 million (4.1%) increase in gas revenues. The electric filing includes a proposal to institute a methodology to establish rates beginning in 1996 and running through 1999. The proposal would provide for rate indexing to a quarterly forecast of the consumer price index as adjusted for a productivity factor. The methodology sets a price cap, but the Company could elect not to raise its rates up to the cap. Such a decision would be based on the Company's assessment of the market. The Niagara Mohawk Electric Revenue Adjustment Mechanism (NERAM) and certain expense deferral mechanisms would be eliminated, while the fuel adjustment clause would be modified to cap the Company's exposure to fuel and purchased power cost variances from forecast at $20 million annually. However, certain items (so-called "Z factors") which are not within the Company's control would be outside of the indexing. Such items would include legislative, accounting, regulatory and tax law changes as well as environmental and nuclear decommissioning costs. These items and the existing balances of certain other deferral items, such as Measured Equity Return Incentive Term (MERIT) and demand-side management (DSM), would be recovered or returned using a temporary rate surcharge. The proposal would also establish a minimum return on equity that, if not achieved, would permit the Company to refile for new base rates subject to indexing or to seek some other form of rate relief, although there would be no assurance as to the form or amount of such rate relief, if any. Conversely, in the event earnings exceeded an established maximum allowed return on equity, such excess earnings would be used to accelerate recovery of regulatory assets. The proposal would provide the Company with greater flexibility to adjust prices within customer classes to meet competitive pressures from alternative electric suppliers while increasing the risk that the Company will earn less than its allowed rate of return. Gas rate adjustments beyond 1995 would follow traditional regulatory methodology. The PSC must rule on the Company's rate request by twelve weeks, to March 29, 1995. The Company would absorb one-half of the costs (the lost margin) arising because of the extension from January 1, 1995. The remainder of the costs would be recovered through a noncash credit to income, and is dependent upon the amount of rate relief ultimately granted by the PSC for 1995. Based on its filing, the Company would absorb approximately $28 million. Temporary gas rates would be instituted for the full twelve weeks. On August 31, 1994, the PSC Staff proposed an overall decrease in electric revenues from 1994 levels of approximately $146 million, excluding anticipated sales growth. This contrasts with the Company's proposed total revenue increase, excluding sales growth, of $146 million for 1995 (which reflects corrections and updates filed with the PSC in May 1994). Because the Company's proposed total revenue increase reflects an effective date of March 29, 1995, while the PSC Staff's proposal is an annualized amount, the difference between the two positions is approximately $366 million. The more significant adjustments proposed by the PSC Staff include disallowance of $90 million in purchased power payments made principally to unregulated generators; additional adjustments to the 1995 unregulated generator forecast for prices, capacity levels and in-service dates of certain projects, reductions in operating and maintenance expenses stemming largely from the PSC Staff's contention that the Company's forecast was unsupported; and assumed increases in revenues from sales to other utilities and transmission revenues. The PSC Staff also proposes to disallow certain unregulated generator buyout costs equal to approximately $12 million in 1995 and to set the electric return on equity at 10.5%, as compared to the Company's request of 11%. The PSC Staff recommends that gas revenues be reduced by $5 million in 1995, while also recommending a return on equity of 10.5% (as opposed to the Company's request of 11.59%). The reduction from the Company's gas proposal relates principally to lower departmental expenses and higher expected sales in 1995. In response to the Company's electric indexing proposal for 1996 through 1999, the PSC Staff proposed the use of a different index based on the annual change in a national average electricity price, elimination of all of the Company-proposed Z-factors including those for fuel and purchased power costs, environmental costs, nuclear decommissioning and accounting and tax law changes, and elimination of the minimum and maximum return on equity limit. The PSC Staff went well beyond the Company's proposal by recommending a "regulatory regime that accepts market based prices for utility generation." The PSC Staff's plan would limit, in increasing amounts, the amount of embedded generation costs (including certain plant and unregulated generator costs) that could be charged to customers. The reference price each year would be based initially upon the Company's marginal cost of generation until a reliable market price becomes available. After a 10 year phase-down, the Company would only be able to charge a market-related price for generation. The Company would be forced to absorb the difference between its embedded costs and what it could charge customers, regardless of whether its past practices were prudent or even mandated by government action. While the PSC Staff's case contains no financial modelling of the potential consequences of its proposal on the Company, such consequences, if the plan is adopted as proposed could be substantial. The PSC Staff's plan is based on a price ceiling rather than a cost of service theory of ratemaking--a departure from the Company's case and all prior New York State rate-making principles in the modern era. It in effect also proposes a substantial but unquantified disallowance with respect to the Company's generating plants and a similar but undifferentiated disallowance with respect to the difference between estimated market costs of power and the amount the Company is required by law and PSC mandate to pay for unregulated generator power. If those elements of the PSC Staff's case were to be implemented as proposed, the Company would also be required to discontinue the application of Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation" and incur substantial writeoffs. These writeoffs would arise not only from disallowed plant costs and purchased power costs, but also because the departure from cost-based ratemaking would result in a writeoff of a substantial portion of the $1.4 billion of regulatory assets on the Company's balance sheet no longer being recoverable. The Company has not quantified all of the amounts which might be involved, but estimates appear to be of an order of magnitude that would adversely affect the Company's ability to access the capital markets on reasonable and customary terms, its dividend paying capacity, its ability to continue to make payments to unregulated generators and its ability to maintain current levels of service to its customers. Senior members of the PSC Staff and other senior public officials in Albany have made it clear that the PSC trial staff's proposal was developed independent of consultation with Commissioners, that the trial staff functions independently of those individuals and that the process in this proceeding is far from complete. In the meantime, the Company is continuing to aggressively advocate its own position. The continued application of SFAS No. 71 to the financial reports and financial statements of electric utilities, including the Company, as competition continues to expand in the industry will be an issue during this transition period. The Company is unable to predict the outcome of these proceedings, or the possible attendant financial consequences. However, the Company strongly believes that its unregulated generator administrative practices were prudent and should not be disallowed, that the Company's unregulated generator purchases are in large part the result of government policy and should be recovered at no penalty to the shareholders and that a transition plan to a more competitive environment must provide for an equitable allocation of transition costs. In addition, the Company believes that any transition to a more competitive rate structure should be addressed in a generic proceeding rather than the Company's current rate filing. See the last paragraph of "Competition" under Item 2. above. The ultimate impact on the Company's financial condition will depend on the pace of change in the marketplace, the actions of regulators in response to that change and the actions of the Company in controlling costs and competing effectively while remaining in substantial part a regulated enterprise. The Company is unable to predict the results of the interaction of these factors. 1994 Rate Agreement On February 2, 1994, the PSC approved an increase in gas rates of $10.4 million or 1.7%. To comply with this rate order, the Company filed tariffs with an effective date of February 12, 1994. The Company was allowed to collect the revised rates retroactive to January 1, 1994, through the implementation of a surcharge factor. The rate order also permitted the Company to implement for the first time a weather normalization clause with an effective date of February 12, 1994. The PSC also approved the Company's electric supplement agreement with the PSC Staff and other parties to extend certain cost recovery mechanisms in the 1993 Rate Agreement without increasing electric base rates for calendar year 1994. On May 12, 1994, the PSC issued a final order approving the 1994 electric supplement agreement and the $10.4 million (1.7%) gas rate increase. The goal of the supplement is to keep total electric bill impacts for 1994 at or below the rate of inflation. Modifications were made to the NERAM and MERIT provisions, which determine how these amounts are to be distributed to various customer classes and also provide for the Company to absorb 20% of margin variances (within certain limits) originating from SC-10 rate discounts (as described below) and certain other discount programs for industrial customers as well as 20% of the gross margin variance from NERAM targets for industrial customers. The Company estimated its maximum shareholder exposure at September 30, 1994, on such variances for 1994 to be approximately $9 million. The supplement also allows the Company to begin recovery over three years of approximately $15 million of unregulated generator buyout costs, subject to final PSC determination as to the reasonableness of such costs. Common Stock Dividend On October 27, 1994, the Board of Directors authorized a common stock dividend of $.28 per share, which will be paid on November 30, 1994 to shareholders of record on November 7, 1994. Unregulated Generators In recent years, a leading factor in the increases in customer bills and the deterioration of the Company's competitive position has been the requirement to purchase power from unregulated generators at prices in excess of the Company's internal cost of production and in volumes greater than the Company's needs. While the Company favors the presence of unregulated generators in satisfying its generating needs, the Company also believes it is paying a premium to unregulated generators for energy and capacity it does not currently need. The Company estimates that it paid a premium of $206 million in 1993 and expects to overpay by $352 million in 1994 and $421 million in 1995. The Company has initiated a series of actions to address this situation, but expects that in large part the higher costs will continue. In order to deal with the growth of excess supply, the Company has taken numerous actions to realign its supply with demand. These actions include mothballing and retirement of Company owned generating facilities and buy outs of unregulated generator projects, as well as the implementation of an aggressive wholesale marketing effort. Such actions have been successful in bringing installed capacity reserve margins down to levels in line with normal planning criteria. By the end of 1994, the Company expects virtually all unregulated generator capacity to be on line and unregulated generator payments are projected to grow less than 6% annually during the rest of the decade. On August 18, 1992, the Company filed a petition with the PSC which calls for the implementation of "curtailment procedures." Under existing FERC and PSC policy, this petition would allow the Company to limit its purchases from unregulated generators when demand is low. While the Administrative Law Judge has submitted recommendations to the PSC, the Company cannot predict the outcome of this case. Also, the Company has commenced settlement discussions with certain unregulated generators regarding curtailments. On April 5, 1994, after informing the PSC of its progress in settlement, the Company requested the PSC to expedite the consideration of its petition. As of October 31, 1994, the Company was conducting discussions with 31 unregulated generator projects representing approximately 809 MW of capacity. These discussions address the issues contained in its petitions and disputes. In addition, the Company has settled the issues discussed above with 39 projects amounting to 1,093 MW of generating capacity. On February 4, 1994, the Company notified the owners of nine projects with contracts that provide for front-end loaded payments of the Company's demand for adequate assurance that the owners will perform all of their future repayment obligations, including the obligation to deliver electricity in the future at prices below the Company's avoided cost and the repayment of any advance payment balance which remains outstanding at the end of the contract. See Part II. Item 1. Legal Proceedings, for responses to the Company's notifications. Financing Plans and Financial Positions The Company's financing plan for 1994 has been substantially completed. During March 1994, $210 million of 6-7/8% series First Mortgage Bonds due March 1, 2001 were issued. Proceeds from the issuance were used in connection with the retirement of $200 million of outstanding higher-rate First Mortgage Bonds. During July 1994, $115.7 million of New York State Energy Research and Development Authority Bonds, 7.20% series were issued to redeem $75.69 million of 11-1/4% series and $40.015 million of 11-3/8% series. During August 1994, the Company issued $150 million of preferred stock 9-1/2% series. Through October 31, 1994, approximately 1.5 million shares of common stock have been issued through the Dividend Reinvestment and Employee Plans for approximately $25 million. The original projection of long-term financing was reduced during the third quarter of 1994 because the Company announced the sale of its unregulated subsidiary HYDRA-CO Enterprises, Inc. (HYDRA- CO) (expected to close prior to year-end), proceeds from which will reduce the Company's capital requirements, enabling the Company to reduce the amount of its common equity financing and delaying its plans for a previously announced underwritten public offering of common stock. Assuming PSC Staff's rate proposals (discussed above) are not adopted in their entirety, the Company believes that traditionally available sources of financing should be sufficient to satisfy the Company's external financing needs during the period 1994 through 1998. At November 1, 1994, the Company could issue $2,311 million aggregate principal amount of First Mortgage Bonds under the earnings test set forth in the Company's Mortgage Trust Indenture assuming a 10% interest rate. This includes approximately $1,271 million on the basis of retired bonds and $1,040 million supported by additional property currently certified and available. A total of $200 million of Preference Stock is currently authorized and unissued. The Company also has authorized unissued Preferred Stock totaling $255.2 million. The Company continues to explore and utilize, as appropriate, other methods of raising funds. The Company's Charter restricts the amount of unsecured indebtedness which may be incurred by the Company to 10% of consolidated capitalization plus $50 million. The Company has not reached this restrictive limit. On September 8, 1994, Moody's Investors Service placed the credit ratings of the Company under review for possible downgrade. The review was prompted by both the PSC's September 8 decision on Sithe/Alcan and the August 31 proposal from the PSC Staff to reduce the Company's electric and gas rates over the next five years. Moody's current rating for the Company's senior secured debt is Baa2. On September 9, 1994, Standard and Poor's (S&P) placed its ratings on the Company, Con Ed and Long Island Lighting Company on credit watch with negative implications. This action by S&P reflects continued concern about a shift in the regulatory environment in New York State that would be even more hostile to the financial health of the state's utilities. S&P's current rating for the Company's senior secured debt is BBB-, the lowest investment grade rating. Cash flows to meet the Company's requirements for the first nine months of 1994 and 1993 are reported in the Consolidated Statements of Cash Flows on Page 7. 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. Working capital deficits may also be temporarily created as 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. However, the Company has sufficient borrowing capacity to fund such deficits as necessary. Material Changes in Results of Operations Three Months Ended September 30, 1994 versus Three Months Ended September 30, 1993 The following discussion presents the material changes in results of operations for the third quarter of 1994 in comparison to the same period in 1993. The Company's quarterly results of operations reflect the seasonal nature of its business, with peak electric loads in summer and winter periods. Gas sales peak principally in the winter. The earnings for the three month period should not be taken as an indication of earnings for all or any part of the balance of the year. Earnings for the third quarter were $39.3 million or $.27 per share, as compared with $40.8 million or $.29 per share in 1993. As shown in the table below, electric revenues increased $48.7 million or 6.0% from 1993. This increase resulted primarily from higher fuel adjustment clause revenues to cover increasing payments to unregulated generators, an increase in sales to other electric systems as the Company's generation is more available since more of its own load is being satisfied by unregulated generator purchases, and the second stage rate increase granted in September 1993. Consistent with the terms of the NERAM, the Company deferred for future recovery the electric gross margin shortfall from the rate case forecast of $13.5 million and $4.0 million in the third quarters of 1994 and 1993, respectively. The decrease in demand-side management (DSM) revenues relates to a change in recovery of certain costs in base rates versus inclusion in a separate DSM surcharge. Fuel adjustment clause revenues $45.9 million Sales to other electric systems 13.3 NERAM revenues 9.5 Increase in base rates 5.3 DSM revenues (1.4) Sales to ultimate consumers (6.4) Miscellaneous operating revenues (8.1) MERIT revenues (9.4) ----- $48.7 million ===== Electric kilowatt-hour sales to ultimate consumers were approximately 8.4 billion in the third quarter of 1994, a 0.9% increase from 1993. After considering the effects of weather, the Company estimates sales to ultimate consumers increased 1.3%. Sales for resale increased 885 million kilowatt-hours (99.1%) resulting in an increase in total electric kilowatt-hour sales of 963 million (10.4%). Electric fuel and purchased power costs increased $64.3 million or 24.0%. This increase is the result of a $70.0 million increase in purchased power costs (principally payments to unregulated generators) and a $9.3 million net increase in costs deferred and recovered through the operation of the fuel adjustment clause offset by a decrease in fuel costs of $15.0 million. The decrease in fuel costs reflects a combination of greater unregulated generator purchases and nuclear generation which reduced the need to operate fossil plants during the third quarter of 1994. Gas revenues decreased $9.8 million or 14.5% in 1994 from the comparable period in 1993 as set forth in the table below: Transportation of customer-owned gas $ 1.8 million Sales to ultimate consumers 1.2 Increase in base rates 0.8 Purchased gas adjustment clause revenues 0.4 Miscellaneous operating revenues (0.7) MERIT revenues (2.3) Spot market sales (11.0) ----- $(9.8) million ===== Gas sales to ultimate consumers were 5.8 million dekatherms, a 3.1% increase from the third quarter of 1993. After considering the effects of weather, the Company estimates sales to ultimate consumers increased 5.7%. Transportation of customer-owned gas increased 4.3 million dekatherms (28.9%). This increase was caused by dual fuel customers who switched from alternative fuels based on market price and availability. These increases were offset by a decrease in spot market sales (sales for resale) which are generally from the higher priced gas available to the Company and therefore yield margins that are substantially lower than traditional sales to ultimate consumers. In 1994, the Company retains only 15% of the profit margin on spot market sales, compared to 100% in 1993. The other 85% is passed back to ratepayers. As a result of a slight decrease in dekatherms purchased for ultimate consumer sales coupled with a 11.2 million decrease in dekatherms purchased for spot market sales, and a $6.8 million decrease in purchased gas costs and certain other items recognized and recovered through the purchased gas adjustment clause, offset by a $4.9 million increase in the cost of dekatherms purchased, the total cost of gas included in expense decreased 38.3% in 1994. The Company's net cost per dekatherm sold, as charged to expense and excluding spot market purchases, decreased from $3.43 in 1993 to $3.19 in 1994.
Three Months Ended September 30, (In Millions) Increase % 1994 1993 (Decrease) Change Other operation expense $177.0 $ 192.0 $(15.0) (7.8) Maintenance 51.3 59.0 (7.7) (13.1) Depreciation and amortization 77.5 69.3 8.2 11.8 Federal and foreign income taxes, net 27.7 28.2 (0.5) (1.8) Other taxes 123.0 118.5 4.5 3.8 Other items (net) 5.8 4.6 1.2 26.1 Interest charges 70.8 72.6 (1.8) (2.5)
Other operation expense decreased primarily due to the decrease in nuclear costs and the decrease in amortization of other regulatory deferrals, which expired in 1993. Maintenance expense decreased principally due to less expenses on the fossil stations because of economy shutdowns at the Oswego and Albany plants coupled with less maintenance performed on transmission lines during the third quarter of 1994 as compared to 1993. Depreciation and amortization increased due to the closing of major orders to plant in service during late 1993 and early 1994. Other taxes increased primarily because of higher real estate taxes. Interest charges decreased from 1993, primarily due to the refunding of debt to obtain lower interest rates. Material Changes in Results of Operations Nine Months Ended September 30, 1994 versus Nine Months Ended September 30, 1993 The following discussion presents the material changes in results of operations for the first nine months of 1994 in comparison to the same period in 1993. The Company's quarterly results of operations reflect the seasonal nature of its business, with peak electric loads in summer and winter periods. Gas sales peak principally in the winter. The earnings for the nine month periods should not be taken as an indication of earnings for all or any part of the balance of the year. Earnings for the first nine months of 1994 were $231.2 million or $1.62 per share, as compared with $216.7 million or $1.55 per share in 1993. A report supporting the achievement of the Company's MERIT program goals for 1993 was submitted in February 1994 to the parties to the 1991 Financial Recovery Agreement. On June 2, 1994, the PSC allowed the Company to begin recovery of at least an $18.4 million MERIT award (of a maximum award of $30 million), to be billed to customers over a twelve-month period. The Company sought an award of $20.5 million and further adjustments may be allowed as the PSC finalizes its review. The Company had previously recorded $10 million of this award in 1993 based on management's assessment at that time of the achievement of objectively measured criteria. The shortfall from the full award reflects the increasing difficulty of achieving the targets established in customer service and the introduction of cost benchmarking with other utilities as a criterion. As shown in the table below, electric revenues increased $151.2 million or 6.1% from 1993. This increase results primarily from higher recoveries through the operation of the fuel adjustment clause mechanism, the increase in sales to other electric systems, and the second stage rate increase granted in September 1993. Sales to ultimate customers increased as compared to 1993 but this level of sales was substantially below the forecast used in establishing rates. In accordance with the NERAM, the Company deferred for future recovery the resulting electric gross margin shortfall of $52.7 million in the first nine months of 1994 as compared with $44.2 million in 1993. Revenues of $8.4 million ($7.7 electric and $.7 gas) were recorded in the nine months ended September 30, 1994, in accordance with the preliminary MERIT allowance for 1993. MERIT revenues recorded in the first nine months of 1993 were $10.3 million. Fuel adjustment clause revenues $ 83.3 million Sales to other electric systems 58.0 Increase in base rates 35.0 Sales to ultimate consumers 10.7 NERAM revenues 8.5 MERIT revenues (1.5) Miscellaneous operating revenues (18.3) DSM revenues (24.5) ------ $151.2 million ====== Electric kilowatt-hour sales to ultimate consumers were approximately 25.9 billion in 1994, a 1.2% increase from 1993. After considering the effects of weather, the Company estimates sales to ultimate consumers increased slightly (0.2%). During the first nine months of 1994, industrial sales increased as shown in the table below. Industrial-Special sales are New York State Power Authority allocations of low-cost power to specified customers. See detail in table below. Sales for resale increased 3.1 million kilowatt-hours (116.2%) resulting in a net increase in total electric kilowatt-hour sales of 3.4 million (12.2%). Sales for resale increased due to the availability of Company generation for sale as a result of an increase in required purchases from unregulated generators. As established in rates, the Company retains 40% of the gross margin variance from the forecast of sales for resale, with the remainder passed back to ratepayers. On July 21, 1994, the Company set an all- time electric summer peak load sending out 6,312,000 kilowatts. Changes in electric revenues and sales by customer group are detailed in the table below:
Revenues (Thousands) Sales (GwHrs) % % 1994 Residential . . . . . . . . . . . . . $ 953,803 $ 891,707 7.0 8,086 8,030 0.7 Commercial . . . . . . . . . . . . . 972,878 937,381 3.8 9,055 9,177 (1.3) Industrial . . . . . . . . . . . . . 433,957 417,225 4.0 5,538 5,309 4.3 Industrial - Special . . . . . . . . 37,901 31,947 18.6 3,048 2,891 5.4 Municipal . . . . . . . . . . . . . . 37,005 37,191 (0.5) 152 155 (1.9) Total to Ultimate Consumers . . . . . 2,435,544 2,315,451 5.2 25,879 25,562 1.2 Other Electric Systems . . . . . . . 130,399 72,404 80.1 5,807 2,686 116.2 Miscellaneous . . . . . . . . . . . . 75,632 102,537 (26.2) - - - Total . . . . . . . . . . . . . . . $2,641,575 $2,490,392 6.1 31,686 28,248 12.2
Electric fuel and purchased power costs increased $196.0 million or 24.6%. This increase is the result of a $218.2 million increase in purchased power costs (principally payments to unregulated generators), offset by a $2.4 million net decrease in costs deferred and recovered through the operation of the fuel adjustment clause and by a decrease in fuel costs of $19.8 million. The decrease in fuel costs reflects a combination of greater unregulated generator purchases and nuclear generation, which reduced the need to operate fossil plants during the first nine months of 1994.
Nine Months Ended September 30, 1994 Fuel & % Change from Purchased Power 1994 1993 prior year KwHr. Cost FUEL FOR ELECTRIC GENERATION: (IN MILLIONS OF DOLLARS) GwHrs. Cost GwHrs. Cost GwHrs. Cost Cents/KwHr ------ ------ ------ ------ ------ ------ ---------- Coal 5,147 $ 81.4 5,326 $ 83.9 (3.4) (3.0) 1.58 cents Oil 1,165 37.6 1,728 57.8 (32.6) (34.9) 3.23 Natural Gas 354 9.4 475 11.2 (25.5) (16.1) 2.66 Nuclear 6,321 37.4 5,708 32.7 10.7 14.4 .59 Hydro 2,634 - 2,627 - 0.3 - - ------ ------ ----- ------ ----- ----- ---- 15,621 165.8 15,864 185.6 (1.5) (10.7) 1.06 ------ ------ ------ ------ ----- ----- ---- ELECTRICITY PURCHASED: Unregulated Generators 11,075 716.5 8,277 525.6 33.8 36.3 6.47 Other 7,866 109.6 6,512 82.3 20.8 33.2 1.39 ------ ------ ------ ------ ----- ----- ---- 18,941 826.1 14,789 607.9 28.1 35.9 4.36 ------ ------ ------ ------ ----- ----- ---- 34,562 991.9 30,653 793.5 12.8 25.0 2.87 ------ ------ ------ ------ ----- ----- ---- Fuel adjustment clause - 0.2 - 2.6 - (92.3) - Losses/Company use 2,876 - 2,405 - 19.6 - - ------ ------ ------ ------ ----- ----- ---- 31,686 $992.1 28,248 $796.1 12.2 24.6 3.13 ====== ====== ====== ====== ===== ===== cents ====
Gas revenues increased $37.6 million or 8.3% in 1994 from the comparable period in 1993 as set forth in the table below: Sales to ultimate consumers and other sales $39.7 million Purchased gas adjustment clause revenues 12.0 Increase in base rates 6.2 Miscellaneous operating revenues 4.1 Transportation of customer-owned gas 0.7 MERIT revenues (1.5) Spot market sales (23.6) ------ $37.6 million ===== Gas sales, excluding transportation of customer owned gas, were 68.4 million dekatherms, a 9.2% increase from the first nine months of 1993. After considering the effects of weather, the Company estimates sales to ultimate consumers increased 4.5%. Spot market sales (sales for resale) are generally the higher priced gas available to the Company and therefore yield margins that are substantially lower than traditional sales to ultimate consumers. Dekatherms transported increased by 11.9 million (24.2%). Changes in gas revenues and dekatherm sales by customer group are detailed in the table below:
Revenues (Thousands) Sales (Thousands of Dekatherms) % % 1994 1993 Change 1994 1993 Change Residential . . . . . . . . . . . . . $319,995 280,473 14.1 45,369 42,203 7.5 Commercial . . . . . . . . . . . . . 127,012 108,154 17.4 20,378 17,889 13.9 Other Gas Systems . . . . . . . . . . 840 701 19.8 174 203 (14.3) Transportation of Customer- Owned Gas . . . . . . . . . . . . . . 26,860 26,164 2.7 61,105 49,194 24.2 Spot Market Sales . . . . . . . . . . 4,204 28,065 (85.0) 1,481 12,500 (88.2) Miscellaneous . . . . . . . . . . . . 1,771 (104) (1802.9) - - - Total . . . . . . . . . . . . . . $492,493 $454,844 8.3 130,961 124,296 5.4
As a result of a 6.3 million increase in dekatherms purchased and withdrawn from storage for ultimate consumer sales offset by a 23.7 million decrease in dekatherms purchased for spot market sales, coupled with a $31.8 million increase in the cost of dekatherms purchased and a $.8 million decrease in purchased gas costs and certain other items recognized and recovered through the purchased gas adjustment clause, the total cost of gas included in expense increased 3.2% in 1994. The Company's net cost per dekatherm sold, as charged to expense, excluding spot market purchases, increased from $3.81 in 1993 to $3.91 in 1994.
Nine Months Ended September 30, (In Millions) Increase % 1994 1993 (Decrease) Change Other operation expense $ 523.7 $582.5 $ (58.8) (10.1) Maintenance 145.2 161.3 (16.1) (10.0) Depreciation and amortization 229.8 205.6 24.2 11.8 Federal and foreign income taxes, net 156.5 144.1 12.4 8.6 Other taxes 377.9 362.4 15.5 4.3 Other items (net) 12.2 6.8 5.4 79.4 Interest charges 214.8 219.6 (4.8) (2.2) /TABLE Other operation expense decreased primarily due to decreases in nuclear costs associated with the Unit 1 refueling outage in the first-half of 1993, decreased DSM program expenses and the decrease in amortization of other regulatory deferrals, which expired in 1993. Maintenance expense decreased principally due to lower nuclear expenses because of the Unit 1 refueling and maintenance outage in the first half of 1993. Depreciation and amortization increased due to the closing of major orders to plant in service during late 1993 and early 1994. Federal income taxes (net) increased as a result of an increase in pre-tax income. Other taxes increased primarily because of higher real estate, payroll and state sales taxes. Interest charges decreased primarily due to the refunding of debt to obtain lower interest rates. NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES PART II Item 1. Legal Proceedings. 1. On February 4, 1994, the Company notified the owners of nine projects with contracts that provide for front-end loaded payments of the Company's demand for adequate assurance that the owners will perform all of their future repayment obligations, including the obligation to deliver electricity in the future at prices below the Company's avoided cost and the repayment of any advance payment which remains outstanding at the end of the contract. The projects at issue total 426 MW. The Company's demand is based on its assessment of the amount of advance payment to be accumulated under the terms of the contracts, future avoided costs, and future operating costs of the projects. As of November 10, 1994, the Company has received the following responses to these notifications: On March 4, 1994, Encogen Four Partners, L.P. filed a complaint in the U.S. District Court (Southern District of New York) alleging breach of contract and prima facie tort by the Company. Encogen seeks compensatory damages of approximately $1 million and unspecified punitive damages. In addition, Encogen seeks a declaratory judgment that the Company is not entitled to assurances of future performance from Encogen. On April 4, 1994, the Company filed its answer and counterclaim for declaratory judgment relating to the Company's exercise of its right to demand adequate assurance. Encogen has amended its complaint, rescinded its prima facie tort claim, and filed a motion for judgment on the pleadings, which is scheduled for December 2, 1994; On March 4, 1994, Sterling Power Partners, L.P., Seneca Power Partners, L.P., Power City Partners, L.P. and AG- Energy, L.P. filed a complaint in New York State Supreme Court, New York County seeking a declaratory judgment that: (a) the Company does not have any legal right to demand assurances of plaintiffs' future performance; (b) even if such a right existed, the Company lacks reasonable insecurity as to plaintiffs' future performance; (c) the specific forms of assurances sought by the Company are unreasonable; and (d) if the Company is entitled to any form of assurances, plaintiffs have provided adequate assurances. On April 4, 1994, the Company filed its answer and counterclaim for declaratory judgment relating to the Company's exercise of its right to demand adequate assurance. On October 5, 1994, Sterling moved for summary judgment. The court has scheduled a hearing on the motion for November 16, 1994; and On March 7, 1994, NorCon Power Partners, L.P. filed a complaint in the District Court (Southern District of New York) seeking a temporary restraining order against the Company to prevent the Company from taking any action on its February 4 letter. On March 14, 1994, the Court entered the interim relief sought by NorCon. On April 4, 1994, the Company filed its answer and counterclaim for declaratory judgment relating to the Company's exercise of its right to demand adequate assurance. On November 2, 1994, NorCon filed for summary judgment. The court has indicated that it will advise the Company on December 2, 1994 regarding what, if any, response is due. The Company cannot predict the outcome of these actions or the response otherwise to its February 4, 1994 notifications, but will continue to press for adequate assurance that the owners of these projects will honor their repayment obligations. The Company is involved in a number of court cases regarding the price of energy it is required to purchase in excess of contract levels from certain unregulated generators ("overgeneration"). The Company has paid the unregulated generators based on its long-run avoided cost for all such overgeneration rather than the price which the unregulated generators contend is applicable under the contracts. The Company cannot predict the outcome of these actions, but will continue to aggressively press its position. Item 5. Other Events. 1. Sithe/Alcan In April 1994, the New York State Public Service Commission (PSC) ruled that, in the event Sithe Independence Power Partners Inc. (Sithe) ultimately obtained authority to sell electric power at retail, those retail sales would be subject to a lower level of regulation than the PSC presently imposes on the Company. Sithe, which will sell electricity to Consolidated Edison of New York, Inc. (Con Ed) and the Company on a wholesale basis from its 1,040 megawatt natural gas cogeneration plant, plans to provide steam to Alcan Rolled Products (Alcan). Sithe also proposes to sell a portion of its electricity output on a retail basis to Alcan, currently a customer of the Company. The PSC has previously ruled that under the Public Service Law Sithe must obtain a PSC certificate before it may use its electricity generating facilities to serve any retail customers. Although Sithe continues to contend that these retail sales are not subject to regulation by the PSC, Sithe has filed an application for authority to provide such services subject to PSC regulation. In briefs filed with the PSC on July 26, 1994, the Company stated that retail sales by Sithe's Independence Plant should be prohibited because such transactions would result in higher electricity bills for the Company's other customers, would not further economic efficiency and would not provide economic development benefits. The Company maintained that if the PSC nevertheless granted the certificate, the PSC must require that Sithe compensate the Company for any lost revenue so that the Company's remaining customers are not harmed. On September 8, 1994, the PSC authorized sales by Sithe of electricity directly to Alcan and to Liberty Paperboard (Liberty), a potential new industrial customer. The Company had opposed such authorizations. In his report to the PSC, the Administrative Law Judge (ALJ) recommended that Sithe pay the Company a fee based upon the prices at which Sithe would sell to Alcan. The ALJ recommended a fee structured to produce a net present value of approximately $19.6 million based on annual payments tied to long-run avoided costs (LRACs) to be paid over a period of ten years. On September 29, 1994, the PSC's decision confirmed the ALJ's report and fee structure. For 1995, the ALJ's recommended fee would be approximately $3.9 million. He recommended against a fee in connection with Sithe's sale to Liberty. On October 12, 1994, the Company filed an appeal in State Supreme Court, Albany County, which states that the April 1994 PSC Order is a violation of legal procedure and precedent and should be reversed. The Company cannot predict the outcome of this proceeding, but will continue to press its position. 2. Sale of Subsidiary During October 1994, the Company announced that it would sell its wholly-owned subsidiary, HYDRA-CO, and unregulated generator, to CMS Generation Co., an independent power subsidiary of CMS Energy Corp., Dearborn, Michigan. The buyer was determined through a competitive auction and the sale is expected to realize proceeds of more than $200 million. The Company's goal is to consummate the sale by the end of 1994. The sale is not expected to have a material effect on the Company's financial position or results of operations for 1994. 3. Unit 1 Economic Study Under the terms of a previous regulatory agreement, the Company agreed to prepare and update studies of the advantages and disadvantages of continued operation of Unit 1 prior to the start of the next two refueling outages. The first report, which recommended continued operation of Unit 1 over the remaining term of its license (2009), was filed with the PSC in March 1990 and a second study in November 1992 also indicated that the Unit could continue to provide benefits for the term of its license if operating costs can be reduced and generating output improved above its then historical average. The third study was filed with the PSC on November 1, 1994. This study agreed with previous studies which confirmed continued operation over the remaining term of its license. The Company believes no further economic studies are currently required for this Unit, although the Company will continue as a matter of course to examine the economic and strategic issues related to operation of all its generating units. The operating experience at Unit 1 has improved substantially since the prior study. Unit 1's capacity factor has been about 94% since the last refueling outage. In connection with the Economic Study, the Company also updated its estimated costs to decommission Unit 1. The estimate includes amounts for both radioactive and non- radioactive dismantlement costs, as well as spent fuel storage cost estimates until the fuel can be transferred to a permanent federal repository. The estimate of radioactive ($255 million) and non-radioactive ($50 million) dismantlement in 1993 dollars is approximately $305 million. Fuel storage and plant maintenance estimates will increase the total estimated costs to approximately $515 million (in 1993 dollars), and this amount escalates to $1.4 billion, largely due to a plan which would delay dismantlement to coincide with Unit 2's decommissioning, currently scheduled to begin in 2026. The company is unable to predict what reaction, if any, may ensue from its regulators and other parties in connection with this study. 4. Final 1994 New York State Energy Plan On October 31, 1994, The State Energy Planning Board issued the final 1994 New York State Energy Plan, which calls for significant reductions in state energy taxes and endorses greater competition in utility purchases of electricity. The plan places increased emphasis on the use of energy policy as a means to lower electricity costs and to promote sustained economic development. The plan continues New York's commitment to narrowing the gap between its electricity prices and the national averages and supports the strong consensus that New York should foster the development of competitive wholesale generation markets. It also recommends retail competition should occur when fair treatment of all customer classes, of competitors, of energy efficiency and renewables, and of capital committed in prudent response to past government mandates is reasonably assured. The Company is unable to predict how this plan will influence regulatory policy. 5. New York State Proposals During October 1994, the governor of New York announced that at his request, the president of the New York Power Authority (NYPA) and the chairman of the Long Island Power Authority (LIPA) have invited the Long Island Lighting Company (LILCO) to begin immediate negotiations for the public purchase of LILCO. The governor stated that the "bottom line" requirement for undertaking the purchase would be the immediate realization of a 10 percent reduction in Long Island electric rates. One of the factors involved in this action is the increasing amount of competition in the utility marketplace. Also during 1994, the NYPA issued a report to its trustees concerning a restructuring effort for the 21st century. This report stated that a major step toward a competitive electric industry would be to separate transmission from generation. It also stated that another significant advance toward cutting the price of electricity would be the creation of a single operating company for all six of New York State's nuclear power plants. The report recommends creation of a New York State Electrical Thruway that would combine all of the State's transmission lines into one independent entity. The effect on the Company's financial position or results of operations based on the above events, if any, cannot be determined at this time. Item 6. Exhibits and Reports on Form 8-K. (a) Exhibits: Exhibit 11 - Computation of the Average Number of Shares of Common Stock Outstanding for the Three and Nine Months Ended September 30, 1994 and 1993. Exhibit 12 - Statement Showing Computations of Ratio of Earnings to Fixed Charges, Ratio of Earnings to Fixed Charges without AFC and Ratio of Earnings to Fixed Charges and Preferred Stock Dividends for the Twelve Months Ended September 30, 1994. Exhibit 15 - Accountants' Acknowledgement Letter. Exhibit 27 - Financial Data Schedule. (b) Reports on Form 8-K: Form 8-K Reporting Date - August 8, 1994. Items reported - Item 5. Other Events. Registrant filed information concerning the filing of the form of the underwriting agreement dated August 1, 1994. Form 8-K Reporting Date - September 26, 1994. Items reported - Item 5. Other Events. Registrant filed information concerning rate case proceedings, Early Retirement and Voluntary Separation Program, and an update on competition, and credit ratings. NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. NIAGARA MOHAWK POWER CORPORATION (Registrant) Date: November 14, 1994 By /s/ Steven W. Tasker Steven W. Tasker Vice President-Controller and Principal Accounting Officer, in his respective capacities as such EXHIBIT 11 NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES --------------------------------------------------------- Computation of the Average Number of Shares of Common Stock Outstanding For the Three and Nine Months Ended September 30, 1994 and 1993
(4) Average Number of Shares Outstanding As (1) (2) (3) Shown on Consolidated Shares of Number of Share Statement of Income Common Days Days (3 divided by number Stock Outstanding (2 x 1) of Days in Period) -------- ----------- ------- --------------------- FOR THE THREE MONTHS ENDED SEPTEMBER 30, JULY 1 - SEPTEMBER 30, 1994 143,316,804 92 13,185,145,968 SHARES SOLD AT VARIOUS TIMES DURING THE PERIOD - DIVIDEND REINVESTMENT PLAN 279,100 * 8,525,566 EMPLOYEE SAVINGS FUND PLAN 290,200 * 11,995,200 ----------- -------------- 143,886,104 13,205,666,734 143,539,856 =========== ============== =========== JULY 1 - SEPTEMBER 30, 1993 141,960,209 92 13,060,339,228 SHARES SOLD AT VARIOUS TIMES DURING THE PERIOD - DIVIDEND REINVESTMENT PLAN 151,548 * 4,732,778 ----------- -------------- 142,111,757 13,065,072,006 142,011,652 =========== ============== =========== (4) Average Number of Shares Outstanding As (1) (2) (3) Shown on Consolidated Shares of Number of Share Statement of Income Common Days Days (3 divided by number Stock Outstanding (2 x 1) of Days in Period) -------- ----------- ------- --------------------- FOR THE NINE MONTHS ENDED SEPTEMBER 30: JANUARY 1 - SEPTEMBER 30, 1994 142,427,057 273 38,882,586,561 SHARES SOLD AT VARIOUS TIMES DURING THE PERIOD - DIVIDEND REINVESTMENT PLAN 700,447 * 76,681,828 EMPLOYEE SAVINGS FUND PLAN 758,600 * 76,225,500 ----------- -------------- 143,886,104 39,035,493,889 142,987,157 =========== ============== =========== JANUARY 1 - MAY 4, 1993 137,159,607 124 17,007,791,268 SHARES SOLD MAY 5, 1993 4,494,000 ----------- MAY 5 - SEPTEMBER 30, 1993 141,653,607 149 21,106,387,443 SHARES SOLD AT VARIOUS TIMES DURING THE PERIOD - DIVIDEND REINVESTMENT PLAN 457,041 * 54,818,062 PURCHASE- SYRACUSE SUBURBAN 1,109 * 248,346 ----------- -------------- 142,111,757 38,169,245,119 139,814,085 =========== ============== =========== NOTE: Earnings per share calculated on both a primary and fully diluted basis are the same due to the effects of rounding. Number of days outstanding not shown as shares represent an accumulation of weekly and monthly sales throughout the quarter. Share days for shares sold are based on the total number of days each share was outstanding during the quarter. /TABLE EXHIBIT 12 NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES ---------------------------------------------------------
Statement Showing Computation of Ratio of Earnings to Fixed Charges, Ratio of Earnings to Fixed Charges without AFC and Ratio of Earnings to Fixed Charges and Preferred Stock Dividends for the Twelve Months Ended September 30, 1994 (in thousands of dollars) A. Net income $ 285,362 B. Taxes Based on Income or Profits 159,517 ---------- C. Earnings, Before Income Taxes 444,879 D. Fixed Charges (a) 314,370 ---------- E. Earnings Before Income Taxes and Fixed Charges 759,249 F. Allowance for Funds Used During Construction (AFC) 12,044 ---------- G. Earnings Before Income Taxes and Fixed Charges without AFC $ 747,205 ========= PREFERRED DIVIDEND FACTOR: H. Preferred Dividend Requirements $ 30,825 --------- I. Ratio of Pre-tax Income to Net Income (C/A) 1.559 ---------- J. Preferred Dividend Factor (HxI) $ 48,056 K. Fixed Charges as Above (D) 314,370 ---------- L. Fixed Charges and Preferred Dividends Combined $ 362,426 ========== M. Ratio of Earnings to Fixed Charges (E/D) 2.42 ========== N. Ratio of Earnings to Fixed Charges without AFC (G/D) 2.38 ========== O. Ratio of Earnings to Fixed Charges and Preferred Dividends Combined (E/L) 2.09 ========== (a) Includes a portion of rentals deemed representative of the interest factor ($27,848). /TABLE PRICE WATERHOUSE LLP ONE MONY PLAZA SYRACUSE NY 13202 TELEPHONE 315-474-6571 EXHIBIT 15 ---------- November 10, 1994 SECURITIES AND EXCHANGE COMMISSION 450 FIFTH STREET NW WASHINGTON DC 20549 Dear Sirs: We are aware that Niagara Mohawk Power Corporation has included our report dated November 10, 1994 (issued pursuant to the provisions of Statement on Auditing Standards No. 71) in the Registration Statements on Form S-8 (Nos. 33-36189, 33-42720, 33-42721, 33-42771 and 33-54829) and in the Prospectus constituting part of the Registration Statements on Form S-3 (Nos. 33-45898, 33-50703, 33-51073, 33-54827, 33-55546 and 33-59594). We are also aware of our responsibilities under the Securities Act of 1933. Yours very truly, /s/ Price Waterhouse LLP EX-27 2
OPUR1 THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE CONSOLIDATED BALANCE SHEET, CONSOLIDATED STATEMENT OF INCOME AND CONSOLIDATED STATEMENT OF CASH FLOWS AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS. 1000 9-MOS DEC-31-1994 SEP-30-1994 PER-BOOK 6932941 266975 950190 1404984 0 9555090 143886 1778894 666833 2589613 257650 290000 3244472 359001 0 0 68078 0 0 0 2746276 9555090 3134068 161773 2529386 2691159 442909 20009 462918 208512 254406 23158 231248 115747 0 562648 1.62 0
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