-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, HcORDMJgbbp1UYEV2oc4I8MnfZaL5UshYv6v0OXTuF61ly/s7SjEV96xhlm3tl9V 3xtzJbdsByly6uIi/+yVrw== 0000071932-96-000015.txt : 19960813 0000071932-96-000015.hdr.sgml : 19960813 ACCESSION NUMBER: 0000071932-96-000015 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 2 CONFORMED PERIOD OF REPORT: 19960630 FILED AS OF DATE: 19960812 SROS: NYSE FILER: COMPANY DATA: COMPANY CONFORMED NAME: NIAGARA MOHAWK POWER CORP /NY/ CENTRAL INDEX KEY: 0000071932 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC & OTHER SERVICES COMBINED [4931] IRS NUMBER: 150265555 STATE OF INCORPORATION: NY FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: 1934 Act SEC FILE NUMBER: 001-02987 FILM NUMBER: 96608829 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 10-Q 6 MONTHS 1996 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 June 30, 1996 - --------------------------------------------- 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 July 31, 1996 - 144,365,214 NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES FORM 10-Q - For The Quarter Ended June 30, 1996 INDEX - ----- PART I. FINANCIAL INFORMATION Glossary of Terms Item 1. Financial Statements. a) Consolidated Statements of Income - Three Months and Six Months ended June 30, 1996 and 1995 b) Consolidated Balance Sheets - June 30, 1996 and December 31, 1995 c) Consolidated Statements of Cash Flows - Six Months ended June 30, 1996 and 1995 d) Notes to Consolidated Financial Statements e) Review by Independent Accountants f) Independent Accountant's Report on the Limited Review of the Interim Financial Information Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations. PART II. OTHER INFORMATION Item 4. Submission of Matters to a Vote of Security Holders. Item 5. Other Information. Item 6. Exhibits and Reports on Form 8-K. Signature Exhibit Index NIAGARA MOHAWK POWER CORPORATION - -------------------------------- GLOSSARY OF TERMS - ----------------- TERM DEFINITION - ---- ---------- COPS Competitive Opportunities Proceeding DSM Demand-Side Management Dth Dekatherms FAC Fuel Adjustment Clause FERC Federal Energy Regulatory Commission GwHrs Gigawatt-hours HYDRA-CO HYDRA-CO Enterprises, Inc. ISO Independent System Operator Kwh Kilowatt-hour NOPR Notice of Proposed Rulemaking PRP Potentially responsible party PSC New York State Public Service Commission SFAS Statement of Financial Accounting Standards No. 71 No. 71 "Accounting for the Effects of Certain Types of Regulation" SFAS Statement of Financial Accounting Standards No. 121 No. 121 "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of" UG Unregulated Generator Unit 1 Nine Mile Point Nuclear Station Unit No. 1 Unit 2 Nine Mile Point Nuclear Station Unit No. 2 PART 1. FINANCIAL INFORMATION - ----------------------------- ITEM 1. FINANCIAL STATEMENTS. - ----------------------------- NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES - --------------------------------------------------------- CONSOLIDATED STATEMENTS OF INCOME - (UNAUDITED) - -----------------------------------------------
THREE MONTHS ENDED JUNE 30, --------------------------- 1996 1995 ---------- ---------- (In thousands of dollars) OPERATING REVENUES: Electric $ 804,457 $ 811,565 Gas 156,314 127,251 ---------- ---------- 960,771 938,816 ---------- ---------- OPERATING EXPENSES: Operation: Fuel for electric generation 36,937 33,934 Electricity purchased 301,057 292,533 Gas purchased 80,557 57,178 Other operation expense 155,105 141,468 Maintenance 45,238 50,888 Depreciation and amortization 82,142 79,148 Federal and foreign income taxes 29,392 30,312 Other taxes 116,980 131,370 ---------- ---------- 847,408 816,831 ---------- ---------- OPERATING INCOME 113,363 121,985 ---------- ---------- OTHER INCOME AND (DEDUCTIONS): Allowance for other funds used during construction 794 312 Federal and foreign income taxes 857 1,207 Other items (net) 6,731 2,397 ---------- ---------- 8,382 3,916 ---------- ---------- INCOME BEFORE INTEREST CHARGES 121,745 125,901 ---------- ---------- INTEREST CHARGES: Interest on long-term debt 68,597 66,020 Other interest 789 7,445 Allowance for borrowed funds used during construction (633) (2,049) ---------- ---------- 68,753 71,416 ---------- ---------- NET INCOME 52,992 54,485 Dividends on preferred stock 9,532 10,046 ---------- ---------- BALANCE AVAILABLE FOR COMMON STOCK $ 43,460 $ 44,439 ========== ========== Average number of shares of common stock outstanding (in thousands) 144,337 144,330 Balance available per average share of common stock $ .30 $ .31 Dividends paid per share of common stock $ .00 $ .28 SIX MONTHS ENDED JUNE 30, ------------------------- 1996 1995 --------- ---------- (In thousands of dollars) OPERATING REVENUES: Electric $1,655,594 $1,693,485 Gas 468,240 370,144 ---------- ---------- 2,123,834 2,063,629 ---------- ---------- OPERATING EXPENSES: Operation: Fuel for electric generation 86,501 78,340 Electricity purchased 588,365 579,404 Gas purchased 270,552 183,657 Other operation expense 317,971 296,282 Maintenance 91,394 95,654 Depreciation and amortization 164,206 157,464 Federal and foreign income taxes 86,015 108,684 Other taxes 247,458 263,754 ---------- ---------- 1,852,462 1,763,239 ---------- ---------- OPERATING INCOME 271,372 300,390 ---------- ---------- OTHER INCOME AND (DEDUCTIONS): Allowance for other funds used during construction 1,202 312 Federal and foreign income taxes 4,661 (7,598) Other items (net) 9,183 18,472 ---------- ---------- 15,046 11,186 ---------- ---------- INCOME BEFORE INTEREST CHARGES 286,418 311,576 ---------- ---------- INTEREST CHARGES: Interest on long-term debt 136,788 129,369 Other interest 2,171 14,577 Allowance for borrowed funds used during construction (1,655) (5,591) ---------- ---------- 137,304 138,355 ---------- ---------- NET INCOME 149,114 173,221 Dividends on preferred stock 19,151 20,261 ---------- ---------- BALANCE AVAILABLE FOR COMMON STOCK $ 129,963 $ 152,960 ========== ========== Average number of shares of common stock outstanding (in thousands) 144,335 144,327 Balance available per average share of common stock $ .90 $ 1.06 Dividends paid per share of common stock $ .00 $ .56 /TABLE NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES - --------------------------------------------------------- CONSOLIDATED BALANCE SHEETS - ---------------------------
ASSETS - ------ JUNE 30, 1996 (UNAUDITED) DECEMBER 31, 1995 ------------- ----------------- (In thousands of dollars) UTILITY PLANT: Electric plant $ 8,564,705 $ 8,543,429 Nuclear fuel 524,027 517,681 Gas plant 1,055,615 1,017,062 Common plant 280,221 281,525 Construction work in progress 252,943 289,604 ---------- ---------- Total utility plant 10,677,511 10,649,301 Less-Accumulated depreciation and amortization 3,726,076 3,641,448 ---------- ---------- Net utility plant 6,951,435 7,007,853 ---------- ---------- OTHER PROPERTY AND INVESTMENTS 194,059 218,417 ---------- ---------- CURRENT ASSETS: Cash, including temporary cash investments of $275,002 and $114,415, respectively 338,518 153,475 Accounts receivable (less allowance for doubtful accounts of $20,000) 420,723 471,442 Materials and supplies, at average cost: Coal and oil for production of electricity 21,917 27,509 Gas storage 22,305 26,431 Other 136,239 141,820 Prepaid taxes 60,823 17,239 Other 47,743 45,834 ---------- ---------- 1,048,268 883,750 ---------- ---------- REGULATORY ASSETS (Note 3): Regulatory tax asset 470,198 470,198 Deferred finance charges 239,880 239,880 Deferred environmental restoration costs (Note 2) 225,000 225,000 Unamortized debt expense 85,040 92,548 Postretirement benefits other than pensions 67,744 68,933 Other 150,379 204,253 ---------- ---------- 1,238,241 1,300,812 ---------- ---------- OTHER ASSETS 79,461 67,037 ---------- ---------- $ 9,511,464 $ 9,477,869 ========== ========== /TABLE NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES - ---------------------------------------------------------- CONSOLIDATED BALANCE SHEETS - --------------------------- CAPITALIZATION AND LIABILITIES - ------------------------------
JUNE 30, 1996 (UNAUDITED) DECEMBER 31, 1995 ------------- ----------------- (In thousands of dollars) CAPITALIZATION: COMMON STOCKHOLDERS' EQUITY: Common stock - $1 par value; authorized 185,000,000 shares; issued 144,349,839 and 144,332,123 shares, respectively $ 144,350 $ 144,332 Capital stock premium and expense 1,784,259 1,784,247 Retained earnings 715,336 585,373 ---------- ---------- 2,643,945 2,513,952 ---------- ---------- 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 240,000 and 258,000 shares, respectively 22,200 24,000 CUMULATIVE PREFERRED STOCK, AUTHORIZED 19,600,000 SHARES, $25 PAR VALUE: Non-redeemable (optionally redeemable), issued 9,200,000 shares 230,000 230,000 Redeemable (mandatorily redeemable), issued 3,008,005 and 3,208,005 shares, respectively 69,100 72,850 ---------- ---------- 531,300 536,850 ---------- ---------- Long-term debt 3,505,896 3,582,414 ---------- --------- TOTAL CAPITALIZATION 6,681,141 6,633,216 ---------- --------- CURRENT LIABILITIES: Long-term debt due within one year 48,524 65,064 Sinking fund requirements on redeemable preferred stock 7,900 9,150 Accounts payable 198,697 268,603 Payable on outstanding bank checks 31,743 36,371 Customers' deposits 14,451 14,376 Accrued taxes 77,837 14,770 Accrued interest 63,840 64,448 Accrued vacation pay 35,825 35,214 Other 65,298 57,748 ---------- ---------- 544,115 565,744 ---------- ---------- REGULATORY LIABILITIES (NOTE 3): Deferred finance charges 239,880 239,880 Other 2,787 2,712 ---------- ---------- 242,667 242,592 ---------- ---------- OTHER LIABILITIES: Accumulated deferred income taxes 1,407,987 1,388,799 Employee pension and other benefits 248,280 245,047 Deferred pension settlement gain 25,861 32,756 Unbilled revenues 16,181 28,410 Other 120,232 116,305 ---------- ---------- 1,818,541 1,811,317 ---------- ---------- COMMITMENTS AND CONTINGENCIES (NOTES 2 AND 3): Liability for environmental restoration 225,000 225,000 ---------- ---------- $9,511,464 $9,477,869 ========== ========== /TABLE NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES - --------------------------------------------------------- CONSOLIDATED STATEMENTS OF CASH FLOWS - ------------------------------------- INCREASE (DECREASE) IN CASH (UNAUDITED) - ---------------------------------------
SIX MONTHS ENDED JUNE 30, 1996 1995 ------------- ------------ (In thousands of dollars) CASH FLOWS FROM OPERATING ACTIVITIES: Net income $ 149,114 $ 173,221 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization 164,206 157,464 Amortization of nuclear fuel 21,058 12,727 Provision for deferred income taxes 22,442 60,126 Gain on sale of subsidiary - (11,257) (Increase) decrease in net accounts receivable 38,490 (6,616) Decrease in materials and supplies 13,067 13,928 Decrease in accounts payable and accrued expenses (58,728) (86,933) Increase in accrued interest and taxes 62,459 49,517 Changes in other assets and liabilities 11,206 10,023 ---------- ---------- NET CASH PROVIDED BY OPERATING ACTIVITIES 423,314 372,200 ---------- ---------- CASH FLOWS FROM INVESTING ACTIVITIES: Construction additions (115,986) (149,386) Nuclear Fuel (6,346) (8,543) ---------- ---------- Acquisition of utility plant (122,332) (157,929) Decrease in materials and supplies related to construction 2,232 1,722 Decrease in accounts payable and accrued expenses related to construction (14,682) (21,733) (Increase) decrease in other investments 24,919 (72,079) Proceeds from sale of subsidiary (net of cash sold) - 161,087 Other (7,629) 2,661 ---------- ---------- NET CASH USED IN INVESTING ACTIVITIES (117,492) (86,271) ---------- ---------- CASH FLOWS FROM FINANCING ACTIVITIES: Increase in long-term debt 105,000 275,000 Net change in revolving credit agreements (170,000) (99,000) Reductions of preferred stock (6,800) (9,300) Reductions in long-term debt (29,341) (21,447) Net change in short-term debt - (306,750) Dividends paid (19,151) (101,086) Other (487) (11,527) ---------- --------- NET CASH USED IN FINANCING ACTIVITIES (120,779) (274,110) ---------- --------- NET INCREASE IN CASH 185,043 11,819 Cash at beginning of period 153,475 94,330 ---------- ---------- CASH AT END OF PERIOD $ 338,518 $ 106,149 ========== ========== SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION: Interest paid $141,743 $146,118 Income taxes paid $52,219 $29,997
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES - --------------------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - ------------------------------------------ NOTE 1. UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS 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 1996 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, 1995, 1994 and 1993 included in the Company's 1995 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 six-month periods ended June 30, 1996, 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 1996 presentation. NOTE 2. CONTINGENCIES ENVIRONMENTAL CONTINGENCIES: The public utility industry typically utilizes and/or generates in its operations a broad range of potentially hazardous wastes and by- products. The Company believes it is handling identified wastes and by-products in a manner consistent with federal, state and local requirements and has implemented an environmental audit program to identify any potential areas of concern and 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 also been advised that various federal, state or local agencies believe certain properties require investigation and has prioritized the sites based on available information in order to enhance the management of investigation and remediation, if necessary. The Company is currently aware of 88 sites with which it has been or may be associated, including 44 which are Company-owned. With respect to non-owned sites, the Company may be required to contribute some proportionate share of remedial costs. Investigations at each of the Company-owned sites are designed to (1) determine if environmental contamination problems exist, (2) if necessary, determine the appropriate remedial actions required for site restoration and (3) where appropriate, identify other parties who should bear some or all of the cost of remediation. Legal action against such other parties will be initiated where appropriate. After site investigations are completed, the Company expects to determine site-specific remedial actions and to estimate the attendant costs for restoration. However, since technologies are still developing the ultimate cost of remedial actions may change substantially. Estimates of the cost of remediation and post-remedial monitoring are based upon a variety of factors, including identified or potential contaminants, location, size and use of the site, proximity to sensitive resources, status of regulatory investigation and knowledge of activities at similarly situated sites, and the United States Environmental Protection Agency figure for average cost to remediate a site. Actual Company expenditures are dependent upon the total cost of investigation and remediation and the ultimate determination of the Company's share of responsibility for such costs, as well as the financial viability of other identified responsible parties since clean-up obligations are joint and several. The Company has denied any responsibility in certain of these PRP sites and is contesting liability accordingly. As a consequence of site characterizations and assessments completed to date and negotiations with PRP's, the Company has accrued a liability in the amount of $225 million, which is reflected in the Company's Consolidated Balance Sheets at June 30, 1996 and December 31, 1995. This represents the low end of the range of its share of the estimated cost for investigation and remediation. The potential high end of the range is presently estimated at approximately $905 million, including approximately $400 million in the unlikely event the Company is required to assume 100% responsibility at non-owned sites. Prior to 1995, the Company recovered 100% of its costs associated with site investigation and restoration (SIR). In the Company's 1995 rate order, costs incurred during 1995 for the investigation and restoration of Company-owned sites and sites with which it is associated were subject to 80%/20% (ratepayer/Company) sharing. In 1995, the Company incurred $11.5 million of such costs, resulting in a disallowance of $2.3 million (before tax), which the Company recognized as a loss in Other items (net) on the Consolidated Statements of Income. The PSC stated in its opinion, dated December 1995, its decision to require sharing was "on a one-time, short-term basis only, pending its further evaluation of the issue in future proceedings." In July 1996, the Administrative Law Judge (ALJ) issued a Recommended Decision in the Company's November 1995 gas rate filing that recommended 100% recovery of its SIR costs. (See Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations - "1996 Gas Rate Filing"). The Company has recorded a regulatory asset representing the remediation obligations to be recovered from ratepayers. Where appropriate, the Company has provided notices of insurance claims to carriers with respect to the investigation and remediation costs for manufactured gas plant, industrial waste sites and sites for which the Company has been identified as a PRP. The Company is unable to predict whether such insurance claims will be successful and, if successful, what the ratemaking disposition will be. 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 Company's Federal income tax liability by approximately $80 million, before assessment of penalties and interest. Included in these proposed adjustments are several significant issues involving 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 PSC in 1990, to the extent the IRS is able to sustain adjustments, the Company will be required to absorb a portion of any assessment. The Company believes any such disallowance will not have a material impact on its financial position or results of operations under traditional ratemaking. The Company is currently attempting to finalize a settlement of these issues with the Appeals Division of the IRS. In addition, the IRS has conducted an examination of the Company's Federal income tax returns for the years 1989 and 1990. The Company received a Revenue Agents' Report in late January 1996. The IRS has raised the issue concerning the deductibility of payments made to UGs in accordance with certain contracts that include a provision for a tracking account. A tracking account represents amounts the PSC required the Company to pay UGs that are in excess of the Company's actual avoided costs, including a carrying charge. The IRS proposes to disallow a current deduction for amounts paid in excess of the avoided costs of the Company. Although the Company believes that any such disallowances for the years 1989 and 1990 will not have a material impact on its financial position or results of operations, it believes that a disallowance for these above-market payments for the years subsequent to 1990 could have a material adverse affect on its cash flows. The Company is vigorously defending its position on this issue. The IRS has commenced its examination of the Company's Federal income tax returns for the years 1991 through 1993. LITIGATION: The Company is unable to predict the ultimate disposition of the lawsuits referred to below. However, the Company believes it has meritorious defenses and intends to defend these lawsuits vigorously, but can neither provide any judgment regarding the likely outcome nor provide any estimate or range of possible loss. Accordingly, no provision for liability, if any, that may result from these lawsuits has been made in the Company's financial statements. (a) In March 1993, Inter-Power of New York, Inc. (Inter- Power), filed a complaint against the Company and certain of its officers and employees in the Supreme Court of the State of New York, Albany County (NYS Supreme Court). Inter-Power alleged, 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. In early 1994, the NYS Supreme Court dismissed two of the plaintiff's claims; this dismissal was upheld by the Appellate Division, Third Department of the NYS Supreme Court. Subsequently, the NYS Supreme Court granted the Company's motion for summary judgment on the remaining causes of action in Inter-Power's complaint. In August 1994, Inter-Power appealed this decision and on July 27, 1995, the Appellate Division, Third Department affirmed the granting of summary judgment as to all counts, except for one dealing with an alleged breach of the power purchase agreement relating to the Company's having declared the agreement null and void on the grounds that Inter- Power had failed to provide it with information regarding its fuel supply in a timely fashion. This one breach of contract claim was remanded to the NYS Supreme Court for further consideration. (b) In November 1993, Fourth Branch Associates Mechanicville (Fourth Branch) filed an action against the Company and several of its officers and employees in the NYS Supreme Court, seeking compensatory damages of $50 million, punitive damages of $100 million and injunctive and other related relief. The lawsuit 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. In January 1994, the Company filed a motion to dismiss Fourth Branch's complaint. By order dated November 7, 1995, the Court granted the Company's motion to dismiss the complaint in its entirety. Fourth Branch has filed an appeal from the Court's order. Fourth Branch has filed for protection under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court for the Northern District of New York. On January 5, 1996, Fourth Branch vacated the Mechanicville site. The Company and Fourth Branch recently entered into negotiations under a FERC mediation process. As a result of these negotiations, the Company and Fourth Branch have entered into an agreement in principle which would result in a transfer of the hydroelectric plant to Fourth Branch for $1 million. In addition, the agreement in principle includes a provision that would require the discontinuance of all litigation between the parties. The agreement in principle is scheduled to be finalized in late September 1996. However, the appeal is still scheduled to be argued in the Fall 1996. (c) 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 UGs ("overgeneration"). The Company has paid the UGs based on its short-run avoided cost (under Service Class No. 6) for all such overgeneration rather than the price which the UGs contend is applicable under the contracts. At June 30, 1996, the amount of overgeneration adjustments in dispute that the Company estimates it has not paid or accrued is approximately $29 million, exclusive of interest. NOTE 3. RATE AND REGULATORY ISSUES AND CONTINGENCIES The Company's financial statements conform to generally accepted accounting principles, as applied to regulated public utilities and reflect the application of SFAS No. 71. Substantively, SFAS No. 71 permits a public utility regulated on a cost-of-service basis to defer certain costs when authorized to do so by the regulator which would otherwise be charged to expense. These deferred costs are known as regulatory assets, which in the case of the Company are approximately $996 million, net of approximately $243 million of regulatory liabilities at June 30, 1996. The portion of the $996 million which relates to the electric business is approximately $882 million, net of approximately $243 million of regulatory liabilities. Generally, regulatory assets and liabilities are allocated to the portion of the business that incurred the underlying transaction that resulted in the recognition of the regulatory asset or liability. The allocation methods used between electric and gas are consistent with those used in prior regulatory proceedings. While the allocation of regulatory assets and liabilities at June 30, 1996 is based on management's assessment, should the Company discontinue the application of SFAS No. 71, for all or a portion of its business, a final allocation would be made by evaluating circumstances at that time. Currently, substantially all of the Company's regulatory assets have been approved by the PSC and are being amortized to expense as they are being recovered in rates as last established in April 1995. RATE FILING: The Company filed in February 1996 a request to increase electric rates. This rate increase request of 4.1% for 1996 and 4.2% for 1997 was based on the Company's cost of providing service. These rate increases are predicated on a requested rate of return on common stock equity (ROE) of approximately 11% on an annual basis and recover the Company's cost of providing electric service. At a public session on May 2, 1996, the PSC rejected the Company's request for a 1996 temporary rate increase primarily on the basis that the request did not meet the PSC's legal standard for approving emergency rate increases. In their remarks, the Chairman of the PSC and the ALJ assigned to the proceeding indicated that emergency rate relief requires meeting a higher standard than traditional cases and that a financial crisis did not exist that would jeopardize the provision of safe and adequate service. In addition, the Chairman of the PSC stated that an increase in electric rates would have a negative impact on economic conditions in the regions served by the Company, which he stated that the Company itself recognized in its PowerChoice proposal. The PSC Chairman also stated that the PowerChoice proposal better addresses the long- term viability of the Company, whereas a temporary rate increase does not. Accordingly, results for 1996 will reflect regulatory lag and resulting reduced ROE; however, the Company believes that the rejection of a temporary rate increase does not indicate that the Company is no longer regulated on a cost-of-service basis. Until the Company's PowerChoice proposal or another acceptable alternative is implemented, the Company will continue to pursue its traditional rate request for 1997. Originally, the Company expected an ALJ Recommended Decision in early October and a PSC decision in January 1997. However, in late May 1996 and July 1996, the Company and the PSC staff jointly requested 60-day and 30-day extensions, respectively, so parties can focus on the negotiations related to the Company's PowerChoice proposal, including its negotiations with UGs. These extensions will reduce the amount of revenues and significantly reduce the amount of earnings the Company would realize in 1997 from any price increases granted, absent additional cost reductions. The ALJ approved the 60-day extension and the request for the additional 30-day extension is pending. Without temporary rate relief in 1996, the Company estimates that its 1997 rate request will require an overall electric price increase of nearly 9%. The Company expects that the PSC will approve cost-of-service based rate increases that provide for a reasonable rate of return until such time as the implementation of the PowerChoice proposal or a new competitive market model becomes probable. As a result the Company believes that it will continue to be regulated on a cost-of-service basis which will enable it to continue to apply SFAS No. 71 and that its regulatory assets are currently probable of recovery. While various proposals have been made to develop a new regulatory model, including the Company's PowerChoice proposal, none of these proposals are currently probable of implementation since a number of parties are required to act on the change in the regulatory model. For the reasons noted above, the Company believes that it continues to meet the requirements for the application of SFAS No. 71 to the electric business. However, there are a number of events that could change that conclusion during the third quarter of 1996 and beyond. Those future events include: inaction or inadequate action on the Company's 1997 rate request by the PSC; a decision by the Company in the future not to pursue the rate request as filed; significant unanticipated reduction in electricity usage by customers; significant unanticipated customer discounts; unsuccessful results in UG negotiations; adverse results of litigation; and a change in the regulatory model becoming probable. As discussed in Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations in the Company's Form 10-K for the fiscal year ended December 31, 1995, the Company was unable to earn its allowed ROE in 1995 and expects to earn substantially below its allowed ROE in 1996. In addition, if the Company's rate increase proposals with respect to 1997 and future years under traditional ratemaking are not approved, then the Company will, more likely than not, be unable to earn a reasonable ROE for such years. The inability of the Company to earn a reasonable ROE over a sustained period would indicate that its rates are not based on its cost of service. In such a case, application of SFAS No. 71 would be discontinued. The resulting after-tax charges against income would reduce retained earnings, the balance of which is currently approximately $715 million. Various requirements under applicable law and regulations and under corporate instruments, including those with respect to issuance of debt and equity securities, payment of common dividends and certain types of transfers of assets could be adversely impacted by any such write-downs. (See the discussion in Item 5. Other Information - "NRC Advanced NOPR.") COMPETITION: The public utility industry in general, and the Company in particular, is facing increasing competitive threats. As competition increases in the marketplace, it is possible that the Company may no longer be able to continue to apply the fundamental accounting principles of SFAS No. 71. The Company believes that in the future some form of market-based pricing will replace cost-based pricing in certain aspects of its business. In that regard, in October 1995, the Company filed its PowerChoice proposal with the PSC. (See Form 10-K for fiscal year ended December 31, 1995, Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - "PowerChoice Proposal.") The PowerChoice proposal, as amended by the Company's August 1, 1996 announcement discussed below, would: - Create a competitive wholesale electricity market and allow direct access by retail customers. - Separate the Company's non-nuclear power generation business from the remainder of the business. - Provide relief from overpriced UG contracts that were mandated by public policy. - Stabilize average prices for Company electric customers, with reductions to industrial customers to facilitate economic and job growth in the service territory. The separated non-nuclear generation business would no longer be rate-regulated and, accordingly, existing regulatory assets related to the non-nuclear power generation business, amounting to $100 million, net of approximately $2 million of regulatory liabilities at June 30, 1996, would be charged against income if and when PowerChoice (or a similar proposal) becomes probable of implementation. Of the remaining electric business, under PowerChoice, the Company has proposed that its electric transmission and distribution business continue to be rate- regulated on a cost-of-service basis (but with performance objectives) and, accordingly, it would continue to apply SFAS No. 71. The Company currently expects to retain ownership of its nuclear assets, but will continue to investigate various options that may be available to mitigate the risk of ownership of these assets. While the Company expects to pursue performance based cost-of-service regulation, the ultimate form and substance of rate regulation applied to nuclear operations will determine whether SFAS No. 71 can continue to be applied. If the Company determines it could no longer apply SFAS No. 71, existing nuclear regulatory assets of $281 million, net of nuclear regulatory liabilities of $240 million at June 30, 1996 would be charged against income. The PowerChoice proposal also includes provisions for recovery of "stranded costs" by the generation business through surcharges on rates for retail transmission and distribution customers. Stranded costs are those costs of utilities that may become unrecoverable due to a change in the regulatory environment and include costs related to the Company's generating plants, regulatory assets and overpriced UG contracts. As discussed below, the Company has offered to buy out 44 UG contracts for a combination of cash and securities. While the Company believes that buy out costs should be recoverable as part of the implementation of PowerChoice, or a form thereof, resolution of this issue is subject to negotiation and approval of the PSC as discussed below. Until resolved, no assurance can be given as to the total amount recoverable or whether the criteria of SFAS No. 71 can be met to record a regulatory asset for the amount recoverable. Critical to the stabilization of average prices and restructuring of the Company's markets and business envisioned in the PowerChoice proposal are substantial reductions in the Company's embedded cost structure. The Company has commenced negotiations with the UGs under the broad supervision of representatives of the New York State government. The Company's objective is to reduce UG costs as a result of these negotiations. On August 1, 1996 the Company announced it had offered to terminate 44 UG contracts in exchange for a combination of cash and securities from a new restructured Niagara Mohawk Power Corporation. The offer, if accepted, would clear the way for implementation of PowerChoice, or a form thereof, which the Company has indicated depends upon reducing the cost of power the Company is required to purchase from UGs. Under the plan, the Company would terminate contracts which account for more than 90% of the above-market power costs that the Company is required to buy from UGs in exchange for a combination of cash and securities to be issued by a restructured Niagara Mohawk Power Corporation, which would include electric and gas transmission and distribution assets and nuclear assets. The new securities would be subordinate to existing first mortgage bonds and not impair the rights of first mortgage bondholders. The plan would also create a separate non-nuclear generating company. The offer is subject to negotiation and is conditioned on receipt of appropriate regulatory and other approvals including PSC approval of an appropriate price structure consistent with the levels envisioned by the PowerChoice proposal. The Company cannot predict whether the offer will be accepted and implemented as proposed. The Company's desire is to conclude negotiations on the offer in the fourth quarter of 1996. The Company does not presently expect that its PowerChoice proposal or any other alternative proposal could be fully effective before sometime in 1997, at the earliest. In addition, the Company cannot predict whether the PowerChoice proposal, in its current or a modified form, or an alternative proposal will be implemented. PSC AND FERC REGULATORY PROCEEDINGS: On May 16, 1996, the PSC issued its decision in its COPS case to restructure New York State's electric industry. (See Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations - "PSC Competitive Opportunities Proceeding - Electric.") Although the PSC's decision outlines its overall vision of how the electricity industry should be deregulated and restructured for competition, it did not provide a detailed plan for implementation and instead ordered filings from the major utilities, except the Company and Long Island Lighting Company (LILCO), by October 1, 1996. The October 1 filings are required to address the corporate structure of each utility both in the short and long term and the schedule for and cost of attaining that structure; a schedule for introducing retail access to all of the utility's customers and a set of unbundled tariffs that are consistent with the retail access program; and a rate plan to be effective for the transition to a competitive market, including mechanisms to reduce rates and address stranded costs. The Company was exempted from the October 1 filing by the PSC because the PSC determined that the Company's PowerChoice restructuring proposal met the requirements of the PSC's decision in its COPS proceeding. In April 1996, FERC issued its final rules on open transmission access and stranded cost issues. (See Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations - "FERC Rulemaking on Open Access and Stranded Cost Recovery.") IMPAIRMENT OF LONG-LIVED ASSETS: In March 1995, the FASB issued SFAS No. 121. This Statement, which the Company adopted in 1996, requires that long-lived assets and certain identifiable intangibles held and used by an entity, be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. In performing the review for recoverability, the Company is required to estimate future undiscounted cash flows expected to result from the use of the asset and its eventual disposition. Furthermore, this Statement amends SFAS No. 71 to clarify that regulatory assets should be charged against earnings if the assets are no longer considered probable of recovery rather than probable of loss. While the Company is unable to predict the outcome of its PowerChoice proposal, or various FERC and PSC initiatives, it has analyzed the provisions of SFAS No. 121, as it relates to the impairment of its investment in generating plant, under two scenarios: traditional cost-based rate-making and its PowerChoice proposal, as filed. As a result of these analyses, the effects of adopting SFAS No. 121, as it relates to the impairment of its investment in generating plant, did not have an effect on its results of operations and financial condition. However, to the extent the PowerChoice proposal is significantly altered or an alternative proposal is implemented, a new asset impairment analysis must be performed, with no assurance as to whether an impairment might exist. In addition, the Company expects that the PSC will approve cost-of-service based rate increases until such time as a new competitive regulatory model is developed. 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 June 30, 1996 and the unaudited Consolidated Statements of Income for the three-month and six- month periods ended June 30, 1996 and 1995 and the unaudited Consolidated Statements of Cash Flows for the six-months ended June 30, 1996 and 1995. 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 August 12, 1996 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 June 30, 1996, and the related condensed consolidated statements of income for the three-month and six-month periods ended June 30, 1996 and 1995 and of cash flows for the six months ended June 30, 1996 and 1995. 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, 1995, and the related consolidated statements of income, retained earnings and cash flows for the year then ended (not presented herein); and in our report dated January 25, 1996, we expressed an unqualified opinion (containing an explanatory paragraph with respect to the Company's application of Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain Types of Regulation [SFAS No. 71] on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 1995 is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived. To the Stockholders and Board of Directors August 12, 1996 Page 2 As discussed in Note 3, the Company believes that it continues to meet the requirements for application of SFAS No. 71 and that its regulatory assets are currently probable of recovery in future rates charged to customers. There are a number of events that could change these conclusions in the third quarter of 1996 and beyond, resulting in material adverse effects on the Company's financial condition and results of operations. As also discussed in Note 3, the Company's PowerChoice proposal, in its current form, would restructure the Company to facilitate a transition to a competitive electric generation market. If it becomes probable that the proposal (or a similar proposal) will be implemented and certain other conditions are met by third parties, the Company would discontinue application of SFAS No. 71 with respect to the non-nuclear portion of its electric generation business and write-off the related net regulatory assets, currently approximately $100 million. While the Company expects to pursue performance based cost-of-service regulation, the form and substance of rate regulation applied to nuclear operations will determine whether SFAS No. 71 can continue to be applied. If the Company determines it could no longer apply SFAS No. 71, existing nuclear net regulatory assets, currently approximately $281 million, would be written-off. Such actions, in the aggregate, could have a material adverse effect on the Company's results of operations and financial condition. /s/ Price Waterhouse LLP - ------------------------ ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS. FINANCIAL CHALLENGES The Company faces significant challenges in its efforts to maintain its financial condition in the face of expanding competition. While utilities across the nation must address these concerns to varying degrees, the Company believes that it is more financially vulnerable because of its large industrial customer base, an oversupply of high-cost mandated power purchases from UGs, an excess supply of wholesale power at relatively low prices, a high tax burden, a stagnant economy in the Company's service territory and significant investments in nuclear plants. Moreover, solving the problems the Company faces, including the implementation of PowerChoice, requires the cooperation and agreement of third parties outside the Company's control and, thus, limits the options available to solve those problems and keep the Company financially viable. COMPANY PROPOSAL TO BUY OUT UG CONTRACTS On August 1, 1996 the Company announced it had offered to terminate 44 UG contracts in exchange for a combination of cash and securities from a newly restructured Niagara Mohawk Power Corporation. The offer, if accepted, would clear the way for the implementation of PowerChoice, which the Company has indicated depends upon reducing the cost of power the Company is required to purchase from UGs. The 44 contracts represent more than 90% of the above-market cost of mandated purchases by the Company. The securities included in the offer would be issued by a restructured Niagara Mohawk Power Corporation, which would include electric and gas transmission and distribution assets and nuclear assets. The new securities would be subordinate to the existing first mortgage bonds of the Company. The proposed buy out would not impair the rights of the Company's existing first mortgage bondholders. The buy out offer is conditioned on receipt of appropriate regulatory and other approvals including PSC approval of an appropriate price structure consistent with the levels envisioned by the PowerChoice proposal. The Company cannot predict whether the offer will be accepted and implemented as proposed. The Company's desire is to conclude negotiations on the offer in the fourth quarter of 1996, with the appropriate approvals following in early 1997. 1996 AND 1997 ELECTRIC RATE FILING When PowerChoice was announced, the Company said that failure to approve the plan would mean continued price escalation under traditional regulation, or failing that, further deterioration in the Company's financial condition. While negotiations are continuing on PowerChoice, in view of increasing UG payments, discounts and continued weak sales expectations, the Company found it necessary to seek price increases. The Company filed for price increases of 4.1% for 1996 and 4.2% for 1997. The 1996 rate filing was for temporary rate relief for which the Company asked for immediate action. As discussed in Note 3, on May 2, 1996, the PSC rejected the Company's request for a temporary rate increase primarily on the basis that the request did not meet the PSC's legal standard for approving emergency rate increases. The Company is continuing to pursue its traditional rate request for 1997 in order to preserve the Company's right to traditional cost-based rates in the event that an acceptable solution cannot be achieved through negotiation of the PowerChoice proposal. The Company expects that the PSC will approve cost-of-service based rate increases until such time as implementation of a new competitive market model becomes probable. PSC COMPETITIVE OPPORTUNITIES PROCEEDING - ELECTRIC (See Form 10-K for the fiscal year ended December 31, 1995, Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - "PSC Competitive Opportunities Proceeding - Electric.") On May 16, 1996 the PSC issued its decision in its COPS case to restructure New York State's electric industry. The decision calls for a competitive wholesale power market in early 1997 and the introduction of retail access for all electric customers in early 1998. The goals cited in its decision included lowering consumer rates, increasing choice, continuing reliability of service, continuing environmental and public policy programs, mitigating concerns about market power and continuing customer protections and the obligation to serve. To implement its policies, the PSC directed major utilities, excluding the Company and LILCO, to file restructuring proposals and rate plans by October 1, 1996, consistent with these goals. The Company was exempt from this filing since it had already filed its PowerChoice restructuring proposal. Subsequent to these October 1 filings, all parties in the COPS proceeding will be able to review and comment on the documents. The PSC will then review each filing. In addition, the PSC decision states that recovery of utility stranded costs may be accomplished by a non-bypassable "wire charge" to be imposed by distribution companies. Stranded costs are utility costs that may become unrecoverable due to a change in the regulatory environment. The calculation of the amount of stranded costs, and the timing of recovery, will be determined individually for each utility as part of the October 1 filings. The PSC decision suggests that a careful balancing of customer and utility interests and expectations is necessary, and the level of stranded cost recovery will ultimately depend upon the particular circumstances of each utility. Between now and October 1, the PSC stated that collaborative efforts would take place to accomplish the following: - distinguish and classify transmission and distribution facilities; - continue reviewing the role of Energy Service Companies (ESCOs) in a competitive retail market, including the development of licensing requirements and consumer safeguards, policies relating to the transfer of the obligation to serve, funding mechanisms that might be needed to assure fairness among all ESCOs and matters related to billing and metering functions; - address transmission pricing; and - set forth the structure of the ISO, and the Market Exchange. The PSC stated that the ISO must have the authority and the means to ensure reliability of the bulk power system. The Company believes that the PSC's objectives in its COPS decision are consistent with the Company's PowerChoice proposal. The Company cannot predict the outcome of this matter or its effects on the Company's results of operations or financial condition. FERC RULEMAKING ON OPEN ACCESS AND STRANDED COST RECOVERY (See Form 10-K for the fiscal year ended December 31, 1995, Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - "FERC NOPR on Stranded Investment.") In April 1996, the FERC issued two final rules and a NOPR. The first rule addresses open transmission access and stranded cost issues. The second rule requires utilities to establish electronic systems to share information about available transmission capacity and also establishes standards of conduct. The NOPR proposes to establish a new system for utilities to use in reserving capacity on their own and others' transmission lines. The first rule opens wholesale power sales to competition. Under this rule, public utilities owning, controlling or operating transmission lines are required to file non-discriminatory open access tariffs that offer others the same service they provide themselves, and in accordance with the pro forma tariff issued by the FERC. In addition, the first rule provides for the full recovery of stranded wholesale costs, leaving it up to the states to decide the issue of recovery of stranded retail costs, unless the state regulators lack authority to decide this issue. However, the FERC said it will determine stranded cost recovery in the case where retail customers become wholesale purchasers through municipalization. FERC's final rules did not require the divestiture of generation from transmission, nor did it require an ISO to run the transmission grid. However, the FERC did offer guidelines for the creation of ISOs that are subject to its approval. The NOPR proposes that each utility would replace the open access pro forma tariff with a capacity reservation tariff (CRT), by December 31, 1997. Under the proposed CRT, utilities and all other power market participants would reserve firm rights to transfer power between designated receipt and delivery points. FERC stated its belief that the proposed reservation-based service appears to be more compatible with open access systems. In May 1996, the New York Power Pool's (NYPP) Executive Committee approved the restructuring of the NYPP, of which the Company is a member, into an ISO in order to comply with FERC's guidelines. The NYPP plans to file an ISO tariff with the FERC by September 1996. The Company is actively involved in the restructuring of the NYPP into a statewide ISO. In late May 1996, the Company was among a number of parties which filed petitions with the FERC seeking rehearing of certain portions of its first rule. The Company stated that various exceptions to the principle of full recovery of stranded costs adopted in that rule would distort competition in the markets for electric power which the rule was designed to promote. In addition, the Company stated that these limitations on the recovery of stranded costs may deprive utilities of a reasonable opportunity to recover their prudently incurred costs, particularly in the case of utilities, including the Company, that face high levels of stranded costs due to past government mandates. The Company also urged the FERC to make certain technical changes to its rules for the recovery of stranded costs in the municipalization context. The Company is unable to predict the outcome of this matter. MULTI-YEAR GAS RATE PROPOSAL In November 1995, the Company filed for a 5.8% gas rate increase to be effective October 1, 1996. (See Form 10-K for the fiscal year ended December 31, 1995, Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - "PowerChoice Proposal - Multi-Year Gas Rate Proposal.") In addition, the Company proposed a performance- based regulation (PBR) mechanism, including a gas cost incentive mechanism for gas operations to become effective October 1, 1997. This filing also included a complete unbundling of the Company's sales service allowing customers to choose alternative gas suppliers plus a move to a rate structure for the transportation of gas that would mitigate the throughput risk to the Company. It also proposed the discontinuation of the weather normalization clause and sought flexibility in pursuing unregulated opportunities related to the gas business. In March 1996, in a generic rate proceeding, the PSC ordered all New York utilities to refile their tariffs to implement a service unbundling by May 1996. The Company refiled its tariff on April 29, 1996 which became effective on a temporary basis on June 1, 1996. Under the approved tariff, all of the Company's gas customers, including residential and commercial customers, have the opportunity to buy natural gas from other sources with the company providing delivery service for a separate fee. These changes have not had nor would be expected to have a material impact on the Company's natural gas throughput risk since the Company sells gas at cost and the margins derived from the delivery service are essentially the same as the sales service. The revised rate structure that had been proposed by the Company to reduce the throughput risk has been transferred into the Company's November 1995 rate proceeding. In addition to the tariff filing to implement service unbundling, the Company and other utilities filed a petition for rehearing of certain of the determinations made in the PSC's March 1996 Order. These determinations included the PSC's requirement that converting customers are responsible for pipeline capacity held by the utility on their behalf for only a three-year period rather than for the remaining life of the pipeline contract. In addition, the March 1996 Order states that the utility is obligated to provide back-up service to a converting customer or provide service to a new customer even if the utility does not currently have sufficient pipeline capacity needed to serve that customer. However, the March 1996 Order is unclear as to how the costs of such capacity would be recovered by the utility after the three-year period. The Company also asked for clarification regarding the "test" the PSC would use to determine whether the utility has adequately demonstrated its efforts to relieve itself of "excess" capacity. In July 1996, the PSC staff recommended no substantive changes to the PSC's March 1996 Order. The ALJ assigned to the Company's gas rate case proceeding issued a recommended decision in July 1996 which would allow the Company to increase its base rates $8.4 million or 1.4% and included an allowed ROE of 11.4%. In addition, the ALJ recommended that the PBR proposal and rate restructuring be addressed in a second phase of this gas rate proceeding. The ALJ also recommended the continuation of the weather normalization clause. With respect to the Company's site investigation and restoration costs (see Note 2. Contingencies - "Environmental Contingencies"), the ALJ recommended 100% recovery of these costs. A PSC decision is expected in late October 1996. The Company is unable to predict the outcome of this proceeding. COMMON STOCK DIVIDEND The board of directors omitted the common stock dividend for the first three quarters of 1996. This action was taken to help stabilize the Company's financial condition and provide flexibility as the Company addresses growing pressure from mandated power purchases and weaker sales. In making future dividend decisions, the board will evaluate, along with standard business considerations, the level and timing of future rate relief, the progress of negotiating with UGs within the context of its PowerChoice proposal, the degree of competitive pressure on its prices, and other strategic considerations. FINANCING PLANS AND FINANCIAL POSITION (See Form 10-K for the fiscal year ended December 31, 1995, Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - "Financial Position, Liquidity and Capital Resources.") On April 25, 1996, Moody's Investors Service (Moody's) lowered its ratings on the Company's senior secured debt, to Ba3 from Ba1; senior unsecured debt to B2 from Ba2; its preferred stock to b3 from ba3. Moody's "Not Prime" rating for the Company's commercial paper remains unchanged. Moody's stated that it downgraded the long-term credit ratings of the Company, based on the limited progress made in achieving the goals identified in the Company's PowerChoice proposal, among other financial concerns, which may ultimately lead to a voluntary bankruptcy filing. In addition, Moody's stated that due to the level of uncertainty and potential volatility of the situation, its rating outlook on the Company remains negative. On May 22, 1996, Standard & Poor's (S&P) lowered its ratings on the Company's senior secured debt to BB- from BB; senior unsecured debt to B from B+; its preferred stock to B- from B; and commercial paper to not rated from B. S&P stated that the downgrade results from the inability of the financially weak Company and the UGs to make substantive progress in their renegotiation of UG contracts. In addition, S&P stated that the lack of progress after several months of negotiations between the Company and the UGs increases the uncertainty that a settlement can be achieved. Cash flows to meet the Company's requirements for the first six months of 1996 and 1995 are reported in the Consolidated Statements of Cash Flows on Page 7. During March 1996, the Company completed an $804 million senior debt facility with a bank group for the purposes of consolidating and refinancing certain of the Company's existing working capital lines of credit and letter of credit facilities and providing additional reserves of bank credit. This senior debt facility will enhance the Company's financial flexibility during the period 1996 through June 1999. The senior debt facility consists of a $255 million term loan facility, a $125 million revolving credit facility and $424 million for letters of credit. The letter of credit facility provides credit support for the adjustable rate pollution control revenue bonds issued through the New York State Energy and Development Authority. As of June 30, 1996, the amount outstanding under the senior debt facility was $105 million, comprised entirely of borrowing under the term loan facility, leaving the Company with $275 million of borrowing capability under the facility. The Company does not anticipate that it will need to borrow any additional amounts under the senior debt facility for the remainder of 1996, since it believes that it will be able to satisfy its financing needs internally. The facility expires on June 30, 1999 (subject to earlier termination upon the implementation of the Company's PowerChoice restructuring proposal or any other significant restructuring plan). This facility is collateralized by first mortgage bonds which were issued on the basis of additional property. As of June 30, 1996, the Company could issue an additional $1,311 million aggregate principal amount of first mortgage bonds under the Company's mortgage trust indenture. This amount is based upon retired bonds without regard to an interest coverage test. The Company believes that it will spend approximately $290 million for construction in 1996. For the six months ended June 30, 1996, the Company had incurred approximately $116.0 million for construction additions. 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 a result of the seasonal nature of the Company's operations as well as timing differences between the collection of customer receivables and the payment of fuel and purchased power costs. The Company is experiencing a significant deterioration in its collections as compared to prior years' experience and is taking steps to improve collection. The Company believes it has sufficient borrowing capacity to fund such deficits as necessary in the near term. External financing plans are subject to periodic revision as underlying assumptions are changed to reflect developments, market conditions and, most importantly, implementation of the Company's PowerChoice proposal or in the alternative, the Company's rate proceedings. The ultimate level of financing during the period 1996 through 1999 will reflect, among other things: the outcome of the restructuring envisioned in the PowerChoice proposal (or a similar proposal), including the Company's recent offer to buy out 44 UG contracts; the alternatives the Company may pursue if the Company's offer is not accepted; the outcome of the 1997 and future traditional rate requests; levels of common dividend payments, if any, and preferred dividend payments; the Company's competitive position and the extent to which competition penetrates the Company's markets; uncertain energy demand due to the weather and economic conditions; and the extent to which the Company reduces non- essential programs and manages its cash flow during this period. The Company could also be affected by the outcome of the NRC's consideration of new rules for adequate financial assurance of nuclear decommissioning obligations. (See Item 5. Other Information - "NRC Advanced NOPR"). In the longer term, in the absence of PowerChoice or some reasonably equivalent solution, financing will depend on the amount of rate relief that may be granted. RESULTS OF OPERATIONS The following discussion presents the material changes in results of operations for the three months and six months ended June 30, 1996 in comparison to the same periods in 1995. The Company's 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 months and six months periods should not be taken as an indication of earnings for all or any part of the balance of the year. THREE MONTHS ENDED JUNE 30, 1996 VERSUS THREE MONTHS ENDED JUNE 30, 1995 Earnings for the second quarter were $43.5 million or 30 cents per share, as compared with $44.4 million or 31 cents per share in 1995. Earnings for the second quarter were lower because 1995 earnings included the recording of $9.4 million of revenues earned under the Unit 1 operating incentive sharing mechanism that increased 1995 earnings by 4 cents per share. However, this was partially offset by higher electric and natural gas sales due to the colder weather in 1996. ELECTRIC REVENUES As shown in the table below, electric revenues decreased $7.1 million or 0.9 % from 1995, primarily due to a decrease in miscellaneous electric revenues. Miscellaneous electric revenues were lower in 1996 because 1995 electric revenues included the recording of $29.1 million of unbilled, non-cash revenues in accordance with the 1995 rate order and $9.4 million of revenues earned under the Unit 1 operating incentive sharing mechanism established in the 1991 Financial Recovery Agreement. In addition, FAC revenues decreased $6.4 million, even though the Company made increased payments to UGs. FAC revenues decreased in part due to the higher generation from nuclear and hydro facilities that have lower fuel costs. In 1995, the lower water supply limited the amount of hydroelectric power that the Company could produce. In addition, Units 1 and 2 were taken out of service in early 1995 for planned refueling and maintenance outages. The decrease in FAC revenues also reflects a higher amount of transmission and resale revenues ($6.7 million) passed on to customers. However, higher electric and natural gas sales due to the colder weather and higher electric rates (effective April 26, 1995) partly offset those factors that contributed to lower electric revenues. Sales to other electric utilities $ 14.5 million Increase in base rates 14.0 Changes in volume and mix of sales to ultimate customers 11.0 DSM revenues (1.7) FAC revenues (6.4) Unit 1 incentive surcharge (9.4) Unbilled revenues (29.1) ------- $ (7.1) million ======= ELECTRIC SALES Electric Kwh sales to ultimate consumers were approximately 8.1 billion in the second quarter of 1996, a 3.0% increase from the same period in 1995 due in part to colder weather. After adjusting for the effects of weather, sales to ultimate consumers increased 1.9%, principally to industrial customers. Sales for resale increased 776 billion kwhs (100.5%) due to an increased demand for electricity in the northeast, resulting in a net increase in total electric kwh sales of 1,012 billion (11.6%). Sales for resale generally result in low margin contribution to the Company due to regulatory sharing mechanisms and relatively low prices caused by excess supply. Electric fuel and purchased power costs increased $11.6 million or 3.6%. This increase is the result of a $32.2 million increase in actual purchased power costs (including increased payments to UGs of $36.4 million or 15.3%), partially offset by a $19.0 million decrease in costs deferred and recovered through the operation of the FAC and a $1.6 million decrease in actual fuel costs. The decrease in fuel costs reflects a 21.9% decrease in Company generation due to UG purchase requirements, which reduced the operation of the Company's fossil plants during the second quarter of 1996. GAS REVENUES Gas revenues increased $29.1 million or 22.8% in the second quarter of 1996 from the comparable period in 1995 as set forth in the table below: Sales to ultimate consumers $17.8 million Purchased gas adjustment clause revenues 6.8 Spot market sales 4.5 ----- $29.1 million ===== GAS SALES Due to colder weather in the second quarter of 1996, gas sales to ultimate consumers increased 2.6 million dth or 15.7% from 1995. After adjusting for the effects of weather, sales to ultimate consumers increased 7.0%. Spot market sales (sales for resale) which are generally from the higher priced gas available to the Company and therefore yield margins that are substantially lower than traditional sales to ultimate consumers, also increased. In addition, changes in purchased gas adjustment clause revenues are generally margin-neutral. The total cost of gas included in expense increased 40.9% in 1996. This was the result of a 1.3 million increase in Dth purchased and withdrawn from storage for ultimate consumer sales ($4.8 million) and a $4.1 million increase in Dth purchased for spot market sales, coupled with an 8.6% increase in the average cost per Dth purchased ($4.7 million) and a $9.8 million increase in purchased gas costs and certain other items recognized and recovered through the purchased gas adjustment clause (GAC). The Company's net cost per Dth sold, as charged to expense and excluding spot market purchases, increased to $5.24 in 1996 from $4.30 in 1995. Other operation expense increased $13.6 million primarily as a result of an increase in bad debt expense ($5.0 million). The Company has experienced a significant increase in past due accounts receivable and is taking steps to improve its collections. To the extent these steps are unsuccessful, the Company will likely experience a higher level of bad debt expense. Maintenance expense decreased $5.7 million primarily as the result of a decrease in nuclear maintenance expenses ($9.0 million). Nuclear maintenance costs were higher in 1995 primarily due to a planned refueling and maintenance outage at Unit 2 (April 8, 1995 - June 2, 1995). Other taxes decreased by approximately $14.4 million partly due to the adjustment of 1995 Dunkirk Generating Steam Station (Dunkirk Station) real estate tax amortization due to a tax settlement refund ($5.7 million). In May 1996, the Company entered into a six year agreement with Chautauqua County and the City of Dunkirk regarding the real estate taxes paid and to be paid for its Dunkirk Station. The Company not only received a tax settlement refund from prior year overassessments, but also had its annual taxes reduced to an amount that is somewhat less than pre-litigation levels. In addition, 1996 taxes were lower because 1995 taxes included the amortization of the New York State sales tax audit costs ($2.8 million). SIX MONTHS ENDED JUNE 30, 1996 VERSUS SIX MONTHS ENDED JUNE 30, 1995 Earnings for the first six months of 1996 were $130.0 million or $0.90 per share, as compared with $153.0 million or $1.06 per share in 1995. Earnings for the first six months were lower because 1995 earnings included the recording of a one-time, non- cash adjustment of prior years' DSM incentive revenues of $17 million, $9.4 million of revenues earned under the Unit 1 operating incentive sharing mechanism and a gain on the sale of HYDRA-CO of $11.3 million that collectively increased 1995 earnings by 17 cents per share. In addition, increased operating expenses of $21.7 million or 10 cents per share also contributed to lower 1996 earnings. However, a decrease in other taxes of $16.3 million or 7 cents per share and higher electric and natural gas sales due to the colder weather partially offset those factors that contributed to lower 1996 earnings. In addition, 1995 earnings included a fuel target penalty of $10.1 million while 1996 earnings included a fuel target incentive of $4.7 million, resulting in a net favorable impact on 1996 earnings as compared to 1995 earnings of $14.8 million or 7 cents per share. The Company is required to share with ratepayers, subject to certain limitations, fuel and purchased power cost fluctuations from amounts forecast in rates. ELECTRIC REVENUES As shown in the table below, electric revenues, decreased $37.9 million or 2.2% from 1995, primarily due to a decrease in miscellaneous electric revenues. Miscellaneous electric revenues were lower in 1996 because 1995 electric revenues included the recording of $55.5 million of unbilled, non-cash revenues in accordance with the 1995 rate order, $9.4 million of revenues earned under the Unit 1 operating incentive sharing mechanism and a one-time, non-cash adjustment of prior years' DSM incentive revenues of $17 million. In addition, FAC revenues decreased $21.2 million, even though the Company made increased payments to UGs. FAC revenues decreased in part due to the higher generation from nuclear and hydro facilities that have lower fuel costs. In 1995, the low water supply limited the amount of hydroelectric power that the Company could produce. In addition, Units 1 and 2 were taken out of service in early 1995 for planned refueling and maintenance outages. The decrease in FAC revenues also reflects a higher amount of transmission and resale revenues ($11.2 million) passed on to customers. However, higher electric and natural gas sales due to the colder weather and higher electric rates (effective April 26, 1995) partly offset those factors that contributed to lower electric revenues. Increase in base rates $ 44.9 million Sales to other electric utilities 20.7 Changes in volume and mix of sales to ultimate customers 3.2 Unit 1 incentive surcharge (9.4) DSM revenues (20.6) FAC revenues (21.2) Unbilled revenues (55.5) ------ $(37.9) million ======= ELECTRIC SALES Electric kwh sales to ultimate consumers were approximately 17.0 billion in 1996, a 2.1% increase from the same period in 1995 primarily as a result of colder weather. After adjusting for the effects of weather, sales to ultimate consumers would have increased 0.3%. Sales for resale increased 1,035 million Kwh (60.7%) due to increased demand for electricity in the northeast, resulting in a net increase in total electric Kwh sales of 1,393 million (7.5%). Sales for resale generally result in low margin contribution to the Company due to regulatory sharing mechanisms and relatively low prices caused by excess supply.
SIX MONTHS ENDED JUNE 30, ELECTRIC REVENUES (Thousands) SALES (GwHrs) ---------------------------------- -------------------------- % % 1996 1995 Change 1996 1995 Change Residential $ 657,485 $ 621,412 5.8 5,402 5,216 3.6 Commercial 610,595 619,364 ( 1.4) 5,789 5,737 0.9 Industrial 256,409 267,044 ( 4.0) 3,553 3,526 0.8 Industrial - Special 29,083 28,388 2.4 2,150 2,067 4.0 Other 25,770 25,468 1.2 113 109 3.7 --------- ---------- ------ ------ ------ ----- Total to Ultimate Consumers 1,579,342 1,561,676 1.1 17,007 16,655 2.1 Other Electric Systems 57,641 36,979 55.9 2,740 1,705 60.7 Miscellaneous 8,542 85,043 (90.0) - - - Subsidiary 10,069 9,787 2.9 200 194 3.1 ---------- --------- ------ ----- ------ ----- TOTAL $1,655,594 $1,693,485 ( 2.2) 19,947 18,554 7.5 ========== ========= ====== ====== ====== ===== /TABLE As indicated in the table below, internal generation increased in 1996, principally at Unit 1 and Unit 2. From February 8, 1995 to April 4, 1995, Unit 1 was taken out of service for a planned refueling and maintenance outage. From April 8, 1995 to June 2, 1995, Unit 2 was taken out for a planned refueling and maintenance outage. The amount of electricity delivered to the Company by UGs decreased by approximately 616 Gwhrs (8.5%), but total UG costs increased by approximately $42.8 million (8.5%), as explained below. HYDROELECTRIC UG PROJECTS Due to high precipitation and spring run-off levels so far this year, hydroelectric UG projects increased energy deliveries to the Company by 425 Gwhrs under Power Purchase Agreements (PPAs) which compelled increased payments to those UGs of $38.4 million. The Company's increased payments to hydroelectric UGs was primarily the result of the UGs' ability to produce more energy in contrast to 1995, when low water availability limited the amount of electricity hydroelectric UGs could produce. In addition, a major new hydroelectric UG came on line in November 1995, contributing to the increase in hydroelectric deliveries. "MUST RUN" UG COGENERATION PROJECTS A substantial portion of the Company's portfolio of UG projects operate on a "must run" basis. This means that they tend to run to the maximum production levels regardless of the need or economic value of the electricity produced. With respect to "must run" UG cogeneration projects, a number of elements combined to reduce the aggregate deliveries from and payments to "must run" UGs. In total, "must run" UGs delivered 583 Gwhrs less, resulting in UG payments of $11.4 million less. These elements included renegotiation of certain contracts, maintenance outages at certain UG facilities and lower deliveries from other facilities. SCHEDULABLE COGENERATION PROJECTS The Company has renegotiated PPAs with a number of UG cogeneration projects in order to obtain the right to schedule the electricity deliveries of the project. In the case of schedulable UG projects, although the terms of these PPAs allow the Company to schedule energy deliveries from the facilities and then pay for the energy delivered, the Company is also required to make fixed payments. Fixed payments are due whether or not the plant produces electricity so long as it is available for service. (See Form 10-K for the fiscal year ended December 31, 1995, Part II, Item 8. Notes to Consolidated Financial Statements - Note 9. Commitments and Contingencies - "Long-term Contracts for the Purchase of Electric Power.") Quantities from schedulable cogeneration UGs decreased 458 Gwhrs. Payments to schedulable UGs increased by $15.8 million, primarily due to increased fixed payments of approximately $19.7 million. The increase in fixed payments are caused by the fixed payments made to a new schedulable UG whose plant came on line in May 1995 and due to escalation factors included in the PPAs that the Company has with the schedulable UGs. In addition, payment rates for electricity delivered from schedulable UGs increased from last year's levels due to the increase in the cost of natural gas.
SIX MONTHS ENDED JUNE 30, GwHrs Cost Cents/KwHr. -------------------------- ------------------------- ------------ (Millions) FUEL FOR ELECTRIC GENERATION: % % 1996 1995 Change 1996 1995 Change 1996 1995 Coal 3,507 3,279 7.0 $49.6 $48.2 2.9 1.4 1.5 Oil 269 347 (22.5) 11.4 14.0 (18.6) 4.2 4.0 Natural Gas 50 492 (89.8) 2.2 9.2 (76.1) 4.4 1.9 Nuclear 4,506 2,763 63.1 25.3 15.5 63.2 0.6 0.6 Hydro 2,156 1,538 40.2 -- -- -- -- -- ------ ----- ---- ---- ---- ---- --- --- 10,488 8,419 24.6 88.5 86.9 1.8 0.8 1.0 ------ ----- ---- ---- ---- ---- --- --- ELECTRICITY PURCHASED: Unregulated generators: Capacity -- -- -- 106.5 86.6 23.0 -- -- Energy and taxes 6,668 7,284 (8.5) 437.9 415.0 5.5 6.6 5.7 ------ ------ ---- ----- ----- ---- --- --- Total UG purchases 6,668 7,284 (8.5) 544.4 501.6 8.5 8.2 6.9 Other 4,551 4,828 (5.7) 61.4 66.4 (7.5) 1.4 1.4 ------ ------ ---- ----- ----- ---- --- --- 11,219 12,112 (7.4) 605.8 568.0 6.7 5.4 4.7 ------ ------ ---- ----- ----- ---- --- --- 21,707 20,531 5.7 694.3 654.9 6.0 3.2 3.2 ------ ------ ---- ----- ----- ---- --- --- Fuel adjustment clause -- -- -- (19.4) 2.8 -- -- -- Losses/Company use 1,760 1,977 (11.0) -- -- -- -- -- ------ ------ ---- ----- ----- ---- ---- ---- 19,947 18,554 7.5 $674.9 $657.7 2.6 3.4 3.5 ====== ====== ==== ===== ===== ==== ==== ==== /TABLE GAS REVENUES Gas revenues increased $98.1 million or 26.5% in 1996 from the comparable period in 1995 as set forth in the table below: Sales to ultimate customers $43.4 million Spot market sales 27.8 Purchased gas adjustment clause revenues 26.9 ----- $98.1 million ===== GAS SALES Due to colder weather in 1996, gas sales to ultimate consumers increased 8.3 million dth or 15.5% from 1995. After adjusting for the effects of weather, sales to ultimate consumers increased 2.5%. Spot market sales (sales for resale), which are generally from the higher priced gas available to the Company and therefore yield margins that are substantially lower than traditional sales to ultimate consumers, also increased. In addition, changes in purchased gas adjustment clause revenues are generally margin- neutral.
SIX MONTHS ENDED JUNE 30, GAS REVENUES (Thousands) SALES (Thousands of Dth) ------------------------------- ------------------------------- % % 1996 1995 Change 1996 1995 Change Residential $291,938 $242,830 20.2 41,593 36,111 15.2 Commercial 116,252 94,854 22.6 18,261 15,900 14.8 Industrial 9,680 6,548 47.8 1,975 1,501 31.6 -------- -------- --------- ------- ------- ------- Total to Ultimate Consumers 417,870 344,232 21.4 61,829 53,512 15.5 Other Gas Systems 77 625 (87.7) 17 135 (87.4) Transportation of Customer-Owned Gas 25,448 24,179 5.2 63,255 72,793 (13.1) Spot Market Sales 28,369 551 5,048.6 7,023 272 2,482.0 Miscellaneous (3,524) 557 (732.7) - - - ---------- ------- --------- ------- ------- ------- Total to System Core Customers $468,240 $370,144 26.5 132,124 126,712 4.3 ========= ======== ========= ======= ======= ======= /TABLE The total cost of gas included in expense increased 47.3%. This was the result of an 8.3 million increase in Dth purchased and withdrawn from storage for ultimate consumer sales ($23.9 million) and a $21.8 million increase in Dth purchased for spot market sales, coupled with a 13.2% increase in the average cost per Dth purchased ($22.5 million) and an $18.7 million increase in purchased gas costs and certain other items recognized and recovered through the purchased GAC. The Company's net cost per Dth sold, as charged to expense and excluding spot market purchases, increased to $4.19 in the first six months of 1996 from $3.60 in the same period in 1995. Other operation expense increased $21.7 million primarily as a result of an increase in bad debt expense ($9.3 million). The Company has experienced a significant increase in past due accounts receivable and is taking steps to improve its collections. To the extent these steps are unsuccessful, the Company will likely experience a higher level of bad debt expense. In April 1996, the Company and the local unions of the International Brotherhood of Electrical Workers, representing all of the Company's 6,100 unionized employees, agreed on a five- year-three month labor agreement. The agreement includes a 1996 base salary freeze, and moderate salary increases through 2001. However, represented employees will have up to a 2% incentive opportunity that will be based upon Company savings achieved in 1996. In addition, changes were made in the new labor agreement affecting pension and health and retirement benefits. The Company does not believe that costs of the new contract will have a material adverse affect on its results of operations or financial condition. Maintenance expense decreased $4.3 million primarily as the result of a decrease in nuclear maintenance expenses ($14.4 million), offset in part, by an increase in amortization of regulatory deferrals and increased labor expense associated with storms in January 1996. On February 8, 1995, Unit 1 was taken out of service for a planned refueling and maintenance outage and returned to service on April 4, 1995. Its next refueling and maintenance outage is scheduled to begin in February 1997. On April 8, 1995, Unit 2 was taken out of service for a planned refueling and maintenance outage and returned to service on June 2, 1995. Its next refueling outage is scheduled for Fall 1996. Other items (net) decreased by $9.3 million in the first six months of 1996 from the comparable period in 1995 principally because 1995 includes proceeds from the sale of HYDRA-CO. ($21.6 million), partially offset by certain accounting requirements of the 1995 rate order. Federal income taxes (net) decreased by approximately $10.4 million primarily due to a decrease in pre-tax income. Other taxes decreased by approximately $16.3 million partly due to the adjustment of 1995 Dunkirk Station real estate tax amortization due to a tax settlement refund ($5.7 million). In May 1996, the Company entered into a six year agreement with Chautauqua County and the City of Dunkirk regarding the real estate taxes paid and to be paid for its Dunkirk Station. The Company not only received a tax settlement refund from prior year overassessments, but also had its annual taxes reduced to an amount that is somewhat less than pre-litigation levels. In addition, 1996 taxes were lower because 1995 taxes included the amortization of the New York State sales tax audit costs ($2.8 million). PART II. OTHER INFORMATION - --------------------------- NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES - --------------------------------------------------------- ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS. At the Company's annual meeting of shareholders on May 7, 1996, the election of Directors was as follows: WITHHELD FOR AUTHORITY --- --------- William F. Allyn 114,429,341 6,832,783 William E. Davis 112,556,971 8,705,153 William J. Donlon 111,597,890 9,664,234 Anthony H. Gioia 114,299,992 6,962,132 Dr. Patti McGill Peterson 114,336,046 6,926,078 ITEM 5. OTHER INFORMATION. NRC ADVANCED NOPR In April 1996, the U.S. Nuclear Regulatory Commission (NRC) issued an advanced NOPR that proposes a change in the nuclear decommissioning rules. Current NRC regulations allow a utility to set aside decommissioning funds annually over the estimated life of a plant (See Form 10-K for the fiscal year ended December 31, 1995, Part II, Item 8. Notes to Consolidated Financial Statements - Note 3. Nuclear Operations - "Nuclear Plant Decommissioning"). Despite the growing trend toward deregulation and asset divestiture, the NRC will take actions to insure adequate funding for decommissioning. The following are some of the changes that the NRC is considering: - Requiring the utility to assure the NRC that they can finance the total estimated cost of nuclear decommissioning in the event they are no longer a rate regulated entity and do not have a guaranteed source of income. - Requiring a deregulated utility to periodically report to the NRC on the status of its nuclear decommissioning funds. - Allowing a utility to take a credit for a positive, real rate of return on nuclear decommissioning trust funds during a period of safe storage, i.e., a phase in decommissioning when the plant is maintained in a state that allows the radioactivity on site to decay. The Company participated in comments filed by the Nuclear Energy Institute in June 1996 on behalf of the commercial nuclear industry in response to the NRC advanced NOPR. As noted therein, the Company believes that it is appropriate for the NRC to contemplate rulemaking in this area, but that any such rulemaking should establish requirements for the assurance of decommissioning funds availability that are flexible and not prescriptive as to how licensees attain the required level of assurance. The Company is unable to determine the outcome of this matter. COURT RULING ON DISPOSAL OF SPENT NUCLEAR FUEL In July 1996, the United States Circuit Court of Appeals for the District of Columbia ruled that the Department of Energy (DOE) must begin accepting used fuel from the nuclear industry by 1998 even though a permanent storage site will not be ready by then. The Company is unable to determine the outcome of this matter. The Company currently has contracts with the DOE for the disposal of spent nuclear fuel for both Units 1 and 2. Spent nuclear fuel storage facilities at Units 1 and 2 are expected to accommodate spent nuclear fuel discharges, while also having sufficient space available to maintain full core off load capability, through the years 2009 and 2012, respectively. 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 Months and Six Months Ended June 30, 1996 and 1995. 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 June 30, 1996. Exhibit 15 - Accountants' Acknowledgement Letter. Exhibit 27 - Financial Data Schedule. In accordance with Paragraph 4(iii) of Item 601(b) of Regulation S-K, the Company agrees to furnish to the Securities and Exchange Commission, upon request, a copy of the agreements comprising the $804 million senior debt facility that the Company completed with a bank group during March 1996. The total amount of long-term debt authorized under such agreement does not exceed 10 percent of the total consolidated assets of the Company and its subsidiaries. (b) Reports on Form 8-K: No reports on Form 8-K were filed during the quarter for which this report is filed. 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: August 12, 1996 By /s/ Steven W. Tasker Steven W. Tasker Vice President-Controller and Principal Accounting Officer NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES - --------------------------------------------------------- EXHIBIT INDEX - ------------- Exhibit Page Number Description Number ------- ----------- ------ 11 Computation of the Average Number of Shares of Common Stock Outstanding for the Three Months and Six Months Ended June 30, 1996 and 1995. 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 June 30, 1996. 15 Accountants' Acknowledgement Letter. 27 Financial Data Schedule.
EXHIBIT 11 NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES - --------------------------------------------------------- Computation of the Average Number of Shares of Common Stock Outstanding For the Three and Six Months Ended June 30, 1996 and 1995 (4) Average Number of Shares Outstanding As Shown on Consolidated Statement (1) (2) (3) of Income Shares of Number Share (3 divided by Common of Days Days number of Days Stock Outstanding (2 x 1) in Period) --------- ----------- ------- --------------- FOR THE THREE MONTHS ENDED JUNE 30: APRIL 1 - JUNE 30, 1996 144,332,855 91 13,134,289,805 SHARES SOLD - ACQUISITION - SYRACUSE SUBURBAN GAS COMPANY, INC. 16,984 20 339,680 ----------- -------------- 144,349,839 13,134,629,485 144,336,588 =========== ============== =========== APRIL 1 - JUNE 30, 1995 144,330,482 91 13,134,073,862 144,330,482 =========== ============== =========== FOR THE SIX MONTHS ENDED JUNE 30: JANUARY 1 - JUNE 30, 1996 144,332,123 182 26,268,446,386 SHARES SOLD AT VARIOUS TIMES DURING THE PERIOD - ACQUISITION - SYRACUSE SUBURBAN GAS COMPANY, INC. - 17,716 * 447,284 ----------- -------------- 144,349,839 26,268,893,670 144,334,581 =========== ============== =========== JANUARY 1 - JUNE 30, 1995 144,311,466 181 26,120,375,346 SHARES SOLD AT VARIOUS TIMES DURING THE PERIOD - DIVIDEND REINVESTMENT PLAN 19,016 * 2,871,416 ----------- -------------- 144,330,482 26,123,246,762 144,327,330 =========== ============== =========== 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.
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 June 30, 1996 (in thousands of dollars). A. Net Income $223,929 B. Taxes Based on Income or Profits 124,465 ------- C. Earnings, Before Income Taxes 348,394 D. Fixed Charges (a) 309,879 ------- E. Earnings Before Income Taxes and Fixed Charges 658,273 F. Allowance for Funds Used During Construction (AFC) 6,004 ------- G. Earnings Before Income Taxes and Fixed Charges without AFC $652,269 ======= PREFERRED DIVIDEND FACTOR: H. Preferred Dividend Requirements $ 38,486 ------- I. Ratio of Pre-tax Income to Net Income (C/A) 1.556 ------- J. Preferred Dividend Factor (HxI) $ 59,884 K. Fixed Charges as Above (D) 309,879 ------- L. Fixed Charges and Preferred Dividends Combined $369,763 ======= M. Ratio of Earnings to Fixed Charges (E/D) 2.12 ======= N. Ratio of Earnings to Fixed Charges without AFC (G/D) 2.10 ======= O. Ratio of Earnings to Fixed Charges and Preferred Dividends Combined (E/L) 1.78 ======= (a) Includes a portion of rentals deemed representative of the interest factor ($27,205). EXHIBIT 15 August 12, 1996 Securities and Exchange Commission 450 Fifth Street, N.W. Washington, D.C. 20549 Dear Sirs: We are aware that Niagara Mohawk Power Corporation has included our report dated August 12, 1996 (issued pursuant to the provisions of Statement on Auditing Standards No. 71) in the Registration Statements on Form S-8 (Nos. 33-36189, 33-42771 and 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 and 33-55546). We are also aware of our responsibilities under the Securities Act of 1933. Yours very truly, /s/ Price Waterhouse LLP - ------------------------
EX-27 2 FDS - 6 MO 10Q 1996
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 6-MOS DEC-31-1996 JUN-30-1996 PER-BOOK 6951435 194059 1048268 1238241 79461 9511464 144350 1784259 715336 2643945 91300 440000 3505896 0 0 0 48524 7900 0 0 2773899 9511464 2123834 86015 1766447 1852462 271372 15046 286418 137304 149114 19151 129963 0 0 423314 .90 0
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