ML17059C116

1997 Annual Rept for Chge. W/Form 10-K

ML17059C116
Person / Time
Site:	Nine Mile Point
Issue date:	12/31/1997
From:	Ganci P, Mack J CENTRAL HUDSON GAS & ELECTRIC CORP.
To:
Shared Package
ML17059C114	List: ML17059C113 ML17059C115 ML17059C116 ML18041A064
References
NUDOCS 9807070353
Download: ML17059C116 (174)

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t Eisenhower Hall, the United States MilitaryAcademy at West Point 1997 Annual Report and Form 10-K 9807070353 980b30 PDR ADOCK 05000220 PDR

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l ~Ia L j Cover: Central Hudson provides Energy Solutions for our 3 electric and natural gas customers.

The United States Military Academy at g(l West Point is a major gas customer, and the summer of 1997 marked the first full season that gas was used to provide air conditioning for Eisenhower Hall.

For more information about gas cooling at Eisenhower Hall and a variety of other Energy Solutions, see pages four through ten of this report.

Eisenhower Hall was named after Dwight D. Eisenhower, the Supreme Commander of the Allied Expeditionary Forces in Europe during World War II and the 34th President of the United States.

The military insignia shown on the right is displayed on the front of the building.

Contents Financial Highlights page 1 Report to Shareholders page 2 Report for the Year 1997 page 4 Financial Profile page 11 Corporate & Stock Information page 12 Form 10-K Annual Report page 13 Directors k Officers inside back cover Financial Highliglhts 1 97 1996 change Operating Revenues $ 520,277)000 $ 513,971,000 1.2%

Net Income 55,086,000 56,082,000 (1.8)%

Earnings Per Share $ 2.97 $ 2.99 (.7)%

Average Shares Outstanding 17,435,000 17,549,000 (.6)%

Dividends Declared Per Share $ 2.135 $ 2.115 .9%

Total Assets $ 1,252,090,000 $ 1,249,106,000 .2%

Electric Sales Own Territory (kwh.) 4,490,317,000 4,608,211,000 (2.6)%

Natural Gas Firm Sales (thousands of cubic feet) 10,285,000 10,850,000 (5.2)%

Electric Customers Own Territory (average) 266,471 263,781 1.0%

Firm Gas Customers (average) 617337 60,470 1.4%

I Central Hudson Gas & Electric Corporation

John E. Mack III,seated, Chairman of the Board and Chief Executive Officer; and Paul J. Ganci, President and Chief Operating Officer.

"In a competitive business world we'e going to be a winner." This quote was displayed on the cover of our 1994 Annual Report. The purpose for repeating it as a prologue to this year's letter is to re-affirm our confi-dence in the directors, officers, management and union employees as being the best of the utility industry.

1997 was a year of continued growth, solid financial performance and improved productivity. Earnings per share were $ 2.97 for 1997, a slight decrease from 1996 reflecting unseasonal weather.

Dividends paid to shareholders increased one percent from $2.11 in 1996 to $ 2.13 in 1997. During the past five years, the average annual return to shareholders was 14.9 percent, and in 1997 it was 48.4 percent, ranking 15th out of 96 electric utilities in the United States.

Book value per share increased from $ 26.87 at the end of 1996 to $ 27.61 at the end of 1997.

In the past, we have pointed out that while the overall trend in utility credit ratings in recent years has been downward, Central Hudson's has trended upward. During 1997, Standard 8z Poor's upgraded the Company's secured debt rating to A from A- based on a strengthened financial profile, which is expected to continue to improve. This profile reflects our competitive prices, a flexible and diverse fuel and energy supply mix and management's commitment to credit quality.

2 Central Hudson Gas & Electric Corporation

We believe that this upgrade, which marked the first time that the Company has received an A rating from Standard & Poor's since 1975, recognizes our efforts to aggressively manage our costs and strengthen our financial position in anticipation of a competitive marketplace.

In our January 15, 1998 letter to shareholders, we informed you about the status of an Amended and Restated Settlement Agreement, dated January 2, 1998, which was executed and filed with the New York State Public Service Commission.

As we pointed out, this agreement, which was approved on February 4, 1998, provides a balanced approach for providing retail access to all of our customers by July 1, 2001 and provides shareholders with the oppor-tunity for full cost recovery of all expenditures made by the Company to fulfillits obligation to serve and provide safe, reliable energy to customers within our franchised service territory. In addition, the agreement pro-vides for the formation of a holding company no later than June 30, 2001.

The agreement also requires that the Company auction its fossil-fueled generating stations no later than June 30, 2001. The agreement calls for the customer share of the net sale proceeds above net book value to be applied as customer benefits to offset regulatory assets and the Company's net investment in the Nine Mile Point 2 Nuclear Station.

Although the Company retains the right to bid in the auction through an unregulated affiliate, we can make no projections as to the outcome of the auction or other strategic alternatives the Company may pursue, nor can we estimate the future impact of regulation on the restructured com-pany. As part of the transition process we willreevaluate our financial policies, including the appropriate level of the common dividend.

The theme of this year's Annual Report illustrates how we are building partnerships with customers through our Energy Solutions program, which provides a broad range of products and services to help solve a multitude of business challenges.

Our longstanding presence in the Community helps us understand the needs of our customers. Our employees live and work in the commu-nities we serve. We are accessible, we are responsive and we strive to be successful by continuously exceeding the expectations of our customers, meeting the needs of our employees and retaining the confidence of our shareholders.

Very truly yours, Chairman of the Board President and and Chief Executive Officer Chief Operating Officer 3

Central Hudson Gas & Electric Corporation

Central Hudson and its predecessor companies have been serving the Mid-Hudson Valley since 1850. We are the "local" utility company, with longstanding roots in the Valley. We are honored to serve the people of the region. We value them as customers and we want to continue serving them in the months and years ahead. Being the local utility company, we have a presence in the community which helps us understand the needs of our customers. We are accessible and we are responsive. We are able to meet our customers'xpectations.

Eisenhower Hall is the main cadet activities building at the United States Military Academy at West Point, Orange County. Central Hudson has been providing natural gas service to West Point since 1931. When the academy was considering replacing an aging electric air conditioning system in 'it'll.l)IX(l IIPITlilt

.'L Eisenhower Hall, Central Hudson Xi'I!lV I'AI'I'/

'lllodezniga((on ol CoIkInca(l recommended the use of natural gas scie ce Ba(ldMII

INCLUDES; CHEMISTRY, BIOLOGY, cooling, which was consistent with the JOURNALISTS% MEDIA CENTER.

COMPUTER SERVICES federal government's objective of using AND PLANETARIUM clean natural gas as a fuel whenever possible because of environmental considerations. In this instance, gas supplied by Central Hudson replaced Natural gas is replacing oil at the State University of New York at electricity supplied by a neighboring New Paltz, Ulster County. Phase I was completed with the installation utility company. Looking north from of gas service to five major buildings for hot water and other West Point, the Hudson River passes applications. Phase II will involve the conversion of large bc' to through the Hudson Highlands. natural gas. Eventually, natural gas will serve the entire camp Central Hudson Gas & Electric Corporation

t Central Hudson collaborated with a major performing arts organization, city government, onomic development agencies and business organizations to create a Riverfront Amphitheater as a new entertainment venue on the Hudson River in Poughkeepsie, Dutchess County. Central Hudson provided a variety of lighting design and related electric services which helped make possible the initial concert by Sawyer '

Brown, recognized as America's top I country band. This partnership helped re-enforce Central Hudson's presence in the community and its reputation as the "local" energy supplier.

Rare geological beauty and exceptional outdoor recreational activities characterize the Minnewaska State Park Preserve, located near New Paltz, Ulster County. Keeping the environment in mind, Central Hudson developed a comprehensive Environmental Management and Construction Plan for rebuilding an electric transmission line which was built through Minnewaska in the 1930s when the land was privately owned.

One innovative aspect of the plan was the use of a helicopter to transport personnel and equipment to work areas, thus eliminating the need to move heavy trucks and materials along the park's trails and carriageways. In addition, all construction personnel received formal environmental sensitivity training regarding the project, which will enhance the reliability of electric service in the region.

The photograph shows a large helicopter transporting a transmission structure, which weighs about 8,000 pounds.

5 Central Hudson Gas & Electric Corporation

Central Hudson has a strong, working relationship with Hunter Mountain, dating back almost 40 years to when the ski center first opened in Greene County.

Over the years, Central Huds helped Hunter Mountain introduce new electric snowmaking technology to produce more snow, operate more efficiently and control costs. The ski center, the largest in the Catskills, recently took advantage of Central Hudson's new low-cost financing program to add more energy efficient equipment, which will enhance its reputation as the "Snowmaking Capital of the d$ P4~ ~pl~ World." Snowmaking began a few weeks after the fall foliage reached its peak.

Customers can depend on us... to respond in creative ways to their energy-related problems...

to offer greater choice, service and value. For example, Central Hudson introduced a Service Guarantee on April 1 of last year. Under this program, Central Hudson guarantees that it wil p scheduled appointments with an electric or gas customer or it will credit $ 20 to the customer account. During the last nine months of 1997, 10,078 appointments were made, and 9,960

-or 98.8%- were kept on schedule. Central Hudson's ability to distinguish its products and services in a competitive energy marketplace depends upon meeting its customers'xpectations.

As a result, the Service Guarantee goal for 1998 is to keep 100% of all scheduled appointments.

Favorable experience with "ground source" heat pumps in campus buildings encouraged Bard College to install additional heat pumps in student residences, which were being renovated and expanded. The college, located in Annandale-on-Hudson, Dutchess County, is one of the leading liberal arts colleges in the Northeast. Ground source heat pumps, which are quickly becoming the most reliable and competitive system for heating, c ing and water heating, are becoming attractive f in commercial and educational buildings as w as for residential use.

6 Central Hudson Gas & Electric Corporation

Passengers on an early morning Delta flight to Atlanta used new boarding bridges which are part of a $ 15.4 million renovation program at Stewart International Airport, located in the Newburgh area, Orange County. The expansion project doubled the size of the terminal and added a number of other passenger amenities. Natural gas was selected for heating and water heating in the expanded facility. Stewart, recognized as the "economic engine" for the future development of the Mid-Hudson Valley, is the

-s first commercial airport in the country to receive federal approval to proceed with privatization under the Federal Aviation Administration's pilot program.

t is about 2 a.m. on a snowy November morning at the Poughkeepsie Train Station, where Metro North passenger cars on the Hudson line are being heated for early morning trips into New York City. During 1997, Metro North contacted Central Hudson about the possibility of replacing diesel fuel with electricity for heating train cars in the winter and cooling them in the summer. Metro North also wanted to service the train cars at the Poughkeepsie station rather k I than at various locations along the Hudson line. Central Hudson worked closely with Metro North to develop a solution to this energy problem prior to the arrival of cold weather.

/4 addition, a large number of h were installed at the station for both safety and security.

7 Central Hudson Gas & Electric Corporation

We'z e yomz jzzzez gy SollmlL;zozzs cozzzyzzzy Hudson's Energy Solutions program has expanded from an initiative to help commercial 'entral and industrial customers become more competitive to a broad-based program which offers Energy Solutions to residential customers as well: such things as energy-related products, services and expertise. During 1998, a number of new products and services will be introduced to enhance our focus on meeting the needs of our customers.

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'reserving the natural environment was a major priority in the construction of Mohonk Preserve's $ 2.8 million visitors center, located near New Paltz, Ulster County. By using native materials for construction and ~l

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An innovative application of a ground-LL source heat pump will use renewable energy resources located below the earth's surface to provide central heating, cooling and hot water for the 9,200 square-foot center. In addition to being The dilemma: how tomaintainiceforindoorskatingat theIce Time Sports energy efficient and cost effective, the Complex when the outside temperature is 90 degrees and the humidity is heat pump will have virtually no effect 80 percent. The Energy Solution: install an insulated foilceiling above the on the environment, no emissions and no ice rink to control condensation. By utilizing Central Hudson's energy risk of fuel leaks on the site. efficiency expertise, Ice Time solved an operating problem, reduced energy costs and created a business opportunity all at the same time. Ice Time, whichopenedoneyearagoinNewburgh,Orange County,o lly planned to operate only during the winter months. The suspei oil ceiling, however, has been a major factor in enabling Ice Time to operate year-round.

8 Central Hudson Gas & Electric Corporation

nklin Corporation, located in Pleasant Valley, utchess County, is a leading supplier of data nsmission technologies to telephone companies throughout North America. Upon learning that this customer was planning a plant expansion, and realizing the emphasis that Conklin Corporation places on producing high quality products, Central Hudson assisted by conducting an Industrial Competitiveness Survey. Based on the results of the survey, which analyzed manufacturing operations, recommendations were made to enhance productivity and quality control.

Conklin Corporation was the first ISO 9001 registered company in the Mid-Hudson Valley, and it has been recognized as a Supplier of Excellence for three consecutive years by GTE Telephone. Pictured above is Conklin's family of ISDN Multiplexers, which allow telephone companies to deploy high-speed data service anywhere there is a need. Their small size represents a packaging breakthrough utilizing advanced manufacturing methods which provide customers with a 40% savings. The products are used for telecommuting, high-speed Internet access, distance learning and tele-medicine, all of which are rapidly growing applications.

ondout Reservoir in Ulster County is part of the reservoir system which supplies an average of billion gallons of water per day for the City of New York. Central Hudson is working with the city's Department of Environmental Protection to determine how various electrotechnologies may be used to help protect the quality of drinking water from the Catskill Mountains watershed.

9 Central Hudson Gas 8c Electric Corporation

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J After considering all options, more than 1,000 customers have elected to lease an electric water heater from Central Hudson.

For as little as $ 10.95 a month, this popular program provides installation and i Cw) 24-hour service and repairs for the life of the lease. During 1997, water heater leases were up 32%.

More and more customers are selecting clean-burning natural gas fireplaces over wood-burning fireplaces. There is no chopping, no splitting, no stacking, no sparks, no smoke, no soot and no ash. To enhance sales, Central Hudson offers low-cost financing to customers.

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~41.,rC r g When considering outdoor lighting, an increasing number of home-owners, residential developments and businesses are choosing low-cost, leased 1' options from Central Hudson. A light installed n existing pole starts at less then $ 10 per month. Outdoor lighting sales were up 33% in 1997.

IO Central Hudson Gas & Electric Corporation

0 4 Electric Sales 0

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1993 1994 1995 1996 1997 1993 1994 1995 1996 1997 6,517',483',719',718* 6,164*

'Billing Degree Days Ratio of Funds From Operations EPS & Dividends To Total Interest Charges Cl Dividends Paid 5.5 Q EPS 2.5 5

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20 10 tli 1993 1994 1995 1996 1997 1993 1994 1995 1996 1997 II Central Hudson Gas R Electric Corporation

Corporate cR Stock Information Annual Meeting The annual meeting of holders of common stock will be held on Tuesday, April 7, 1998 at 10:30 a.m. at the Corporation's General Offices, 284 South Avenue, Poughkeepsie, New York.

The management welcomes the personal attendance of shareholders at this meeting. A summary report of the meeting will be mailed to all shareholders of record at a later date.

Financiol and Statistical Report A comprehensive ten-year financial and statistical supplement to this Annual Report will be available to shareholders attending the Annual Meeting. Copies may also be obtained by writing or calling Steven V. Lant, Treasurer and Assistant Secretary, 284 South Avenue, Poughkeepsie, NY 12601; telephone (914) 486-5254.

Security Analysts and Institutional Investors Steven V. Lant, Treasurer and Assistant Secretary; telephone (914) 486-5254.

Multiple Copies of this Annual Report Shareholders who receive multiple copies of this Annual Report may, if they choose, reduce the number received by calling First Chicago Trust Company of New York at (800) 428-9578.

Common Stock Purchase Plan Central Hudson offers a Stock Purcliase Plan under which investors may conveniently purchase common stock and reinvest cash dividends. All brokerage and other fees to acquire shares are paid by the Corporation. To participate, contact Paul J. Gajdos, Director - Office Services and Shareholder Relations, at (914) 486-5204 or First Chicago Trust Company of New York at (800) 428-9578.

Internet This Annual Report, our SEC filings and the Prospectus for our Stock Purchase Plan, as well as other information about the Company, is available by accessing our Web site at www.cenhud.corn.

Transfer Agent cR Registrar, Common and Preferred Stock/Shareholder Information First Chicago Trust Company of New York, PO Box 2500, Jersey City, NJ 07303-2500. Internet: www.fctc.corn; telephone (800) 428-9578 between 8:30 a.m. and 7 p.m. weekdays.

Stock Exchange Listing/Stock Trading Symbol Common: New York Stock Exc/range - CNH General Counsel enIIfClill Gould & Wilkie One Chase Man)rattan Plaza U(ol3QoA New York, NY 10005 Your Energy Solutions Company" I

Independent Accountants Price Waterhouse LLP Common Stock Market Price and Dividends Paid Per Share 1177 Avenue of the Americas 1997 1996 Ncw York, NY 10036

~W ~vl CJl~l ~w 1" Quarter $ 33'/s $ 30'/z $ 53 $ 31'/2 $ 28'/4 $ .525 2"" Quarter 34'/4 29'/4 .53 31'/4 28 /s 525 3" Quarter 357/s 32i/ 535 31 r/ 29r/ 53 4'h Quarter 437/s 34>>/r6 535 31r/z 29 S3 12 Central Hudson Gas & Electric Corporation

SECURITIES AND EXCHANGE COMMISSION Washington, D. C. 20549 FORM I 0-K ANNUALREPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended......................December 31, 1997 Commission file number 1-3268 CENTRAL HUDSON GAS 8t ELECTRIC CORPORATION (Exact name of registrant as specified in its charter)

New York I 4-0555980 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.)

284 South Avenue, Poughkeepsie, New York I 260 I -4879 (Address of principal executive offices) (Zip Code)

Registrant's telephone number, including area code (914) 452-2000 Securities registered pursuant to Section 12(b) of the Act:

Title of each class Name of each exchange on which registered Common Stock, $ 5.00 par value New York Stock Exchange Securities registered pursuant to Section 12(g) of the Act:

Title of each class Cumulative Preferred Stock:

4 I/2% Series 4.75% Series Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of Registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ X ]

The aggregate market value of the voting and non-voting common equity held by non-affiliates of the Registrant as of February 9, 1998 was $ 689,835,480 based upon the lowest price at which Registrant's Common Stock was traded on such date, as reported on the New York Stock Exchange listing of composite transactions.

The number of shares outstanding of Registrant's Common Stock, as of February 9, 1998, was 17,245,887.

DOCUMENTS INCORPORATED BY REFERENCE Certain portions of Registrant's Annual Report to Shareholders, for the fiscal year ended December 31, 1997, are r

-- incorporated by reference in Parts I, II and IV of this Report.

Registrant's definitive Proxy Statement, to be dated March 2, 1998, and to be used in connection with its Annual Meeting of Shareholders to be held on April 7, 1998, is incorporated by reference in Part III hereof.

l3 Central Hudson Gas & Electric Corporation

TABLE OF CONTENTS Page PART I ITEN I BUSINESS 15 Generally 15 Rates 15 Regulation 16 Construction Program and Financing 16 Fuel Supply and Cost 16 Environmental Quality 17 Research and Development 19 Other Matters 19 Executive Officers of the Company 20 ITEN 2 PROPERTIES 22 Electric 22 Ncw York Power Pool/Independent System Operator 24 Gas 24 Other Matters 25 ITEN 3 LEGAL PROCEEDINGS ITEN 4 SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS PART II ITEM S MARKET FOR THE COMPANY'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS ITEN 6 SELECTED FINANCIALDATA ITEM 7 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIALCONDITION AND RESULTS OF OPERATIONS 28 ITEM 7A QUANTITATIVEAND QUALITATIVEDISCLOSURE ABOUT MARKET RISK 38 ITEN 8 FINANCIALSTATEMENTS AND SUPPLEMENTARY DATA 38 ITEM 9 CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIALDISCLOSURE 61 PART III ITEN 10 DIRECTORS AND EXECUTIVE OFFICERS OF THE COMPANY ITEM I I EXECUTIVE COMPENSATION 61 ITEM 12 SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT 62 ITEN 13 CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS PART IY ITEN 14 SIG NATURES EXHIBITS, FINANCIALSTATEMENT SCHEDULE, AND REPORTS ON FORM 8-K

-0 l4 Central Hudson Gas 8 Electric Corporation

PART I Forward Looking Statements This Form 10-K may contain statements which, to the extent they are not recitations of historical fact, constitute "forward-looking statements'ithin the meaning of the Securities Litigation Reform Act of 1995 ("Reform Act"). All such forward-looking statements are intended to be subject to the safe harbor protection provided by thc Reform Act. A number of important factors affecting thc Company's business and financial results could cause actual results to differ materially from those stated in the forward-looking statements. Those factors include developments in the legislative, regulatory and competitive environment, electric and gas industry restructuring and certain environmental matters.

ITEN I Business Generally Registrant ("Company" ) is a gas and electric corporation formed on December 31, 1926, as a consolidation of several operating utilities which had been accumulated under one management during the previous 26 years. Thc Company generates, purchases and distributes electricity, and purchases and distributes gas. The Company, in the opinion of its general counsel, has, with minor exceptions, valid franchises, unlimited in duration, to serve a territory extending about 85 miles along the Hudson River and about 25 to 40 miles east and west from such River. The southern end of the territory is about 25 miles north of New York City, and the northern end is about 10 miles south of the City of Albany. The territory, comprising approximately 2,600 square miles, has a population estimated at 622300. Electric service is available throughout the territory, and natural gas service is provided in and about thc cities of Poughkeepsie, Beacon, Newburgh and Kingston and in certain outlying and intervening territories. The number of Company employees at December 31, 1997 was 1,196.

The Company's territory reflects a diversified economy, including manufacturing industries, rcscarch firms, farms, overnmental agencies, public and private institutions, resorts, and wholesale and retail trade operations.

For information concerning revenues and operating income before taxes (expressed as percentages) and operating profits and information regarding identifiable assets for the electric and gas segments, which are the significant industry segments of the Company, sec Note 10 - "Departmental Information" of the Notes to the Financial Statements refcrrcd to in Item 8 hereof (each such Note being hereinafter called the "Note").

Consumption of electricity in New York State has stabilized and there is an excess of electric generating capacity in the State.

In 1998, as the competitive market place is developed for electric utilities, it is anticipated that electric customers will have the opportunity to purchase energy and related services from sources other than their local utility. These opportunities exist today for natural gas customers.

See Item 7 hereof under thc caption "Competition/Deregulation" and Note 1 - "Regulatory Matters" herein for a discussion of the current settlemcnt negotiations regarding the October 1, 1996 submissions of thc New York utilities as part of the Public Service Commission of the State of New York's ("PSC") Competitive Opportunities Proceeding which may affect future operations of the Company.

Rates Generally: The electric and gas rates of the Company applicable to service supplied to retail customers within the State of New York are regulated by the PSC. Transmission rates and rates for electricity sold for resale in interstate commerce are regulated by the Federal Energy Regulatory Commission ("FERC").

The Company's present retail rate structure consists of various service classifications covering residential, commercial and industrial customers. During 1997, the average price of electricity to such customers was 8.55 cents per kilowatthour ("kWh"),

representing no change from the 1996 average price.

Rate Procccdings - Electric and Gas: For information regarding the Company's most rcccnt clcctric and gas cases filed with e PSC, see Item 7 hereof under the caption "Rate Proceedings."

Cost Adjustment Clauses: For information with respect to the Company's electric and gas cost adjustment clauses, see Note 2 - "Summary of Significant Accounting Policies" herein under thc caption "Rates, Rcvenucs and Cost Adjustment Clauses."

IS Central Hudson Gas & Electric Corporation

Regulation Generally: The Company is subject to regulation by the PSC with respect to, among other things, service rendered (including the rates charged), major transmission facility siting, energy planning, accounting procedures and issuance of securities.

Certain of the Company's activities, including accounting and the acquisition and disposition of certain property, are subject to regulation by the FERC, under the Federal Power Act, by reason of the Company's transmission and sale for resale of electric energy in interstate commerce.

The Company is not subject to the provisions of the Natural Gas Act.

In the opinion of general counsel for the Company, the Company's major hydroelectric facilities are not required to be licensed under the Federal Power Act.

Purchased Electric Power Generation: Pursuant to the provisions of the federal Public UtilityRegulatory Policies Act of 1978 ("PURPA"), and the New York Public Service Law, the Company is required to enter into long-term contracts to purchase electric power generated by small hydro, alternative energy and cogeneration facilities which meet qualification standards established by such statutes and the regulatory programs promulgated thereunder. With respect to facilities qualified under PURPA, the Company must pay its avoided cost (i.e., the cost the Company would otherwise incur to generate the increment of power purchased) for electric power purchased from qualified facilities, which, under the New York Public Service Law, is "at rates just and reasonable to electric [...] corporation ratepayers." As of December 31, 1997, the Company's avoided cost at the 115 kV transmission level was approximately 3.0 cents per kWh.

As of December 31, 1997, 19 Megawatts ("MW")of generation, qualifying for avoided cost payments by the Company was interconnected with the Company's system. The opportunity under PURPA and the New York Public Service Law to require the Company to purchase power from qualifying facilities could serve as an inducement to the Company's industrial and commercial customers to install their own qualifying on-site generation facilities to reduce their purchases of electric power from the Company This action would result in losses of revenues from such customers. However, as of December 31, 1997, no significant customer has indicated to the Company the intention to pursue such alternative.

Construction Program and Financing The Company is engaged in a construction program which is presently estimated to involve total cash expenditures during the period 1998 through 1999 of approximately $ 109.8 million. The Company's principal construction projects consist of those designed to improve the reliability, efficiency and environmental compatibility of the Company's generating facilities and those required to expand, reinforce and replace the Company's transmission, substation, distribution and common facilities.

For estimates of construction expenditures, internal funds available, mandatory and optional redemption of long-term securities, and working capital requirements for the two-year period 1998-1999, see the subcaption "Construction Program" in Item 7 hereof under the caption "Capital Resources and Liquidity."

For a discussion of the Company's capital structure, financing program and short-term borrowing arrangements, see Notes 5, 6 and 7 "Short-term Borrowing Arrangements," "Capitalization - Capital Stock" and "Capitalization - Long-term Debt," respectively, and Item 7 hereof under the subcaptions "Capital Structure," "Financing Program" and "Short-Term Debt" of the caption "Capital Resources and Liquidity."

The Company's Certificate of Incorporation and its various debt instruments do not contain any limitations upon the issuance of authorized, but unissued, preferred stock and common stock or of unsecured short-term debt.

The Company's various debt instruments include limitations as to the amount of additional funded indebtedness which the Company can issue. The Company believes such limitations will not impair its ability to issue any or all of the debt described under the above-referenced subcaption "Financing Program."

Fuel Supply and Cost The Company's two primary fossil fuel-fired electric generating stations are the Roseton Steam Electric Generating Plant

("Roseton Plant" ) (described in Item 2 hereof under the subcaptions "Electric - General" and "Electric - Roseton Plant" ) and the Danskammer Point Steam Electric Generating Station ("Danskammer Plant" ) (referred to in Item 2 hereof under the subcaption "Electric - General" ). Unit 2 of the Roseton Plant, which Plant is fully equipped to burn both residual oil and natural gas, has been the predominant operating unit of that Plant's two units during 1997, with Unit 1 available on an alternate basis. Units 1 and 2 of the Danskammer Plant, which are equipped to bum residual oil or natural gas, are only operated when the demand for power is high or purchased power and energy exchange contracts are uneconomical. Units 3 and 4 of the Danskammer Plant, which are operated predominantly, are capable of burning coal, natural gas, or residual oil.

l6 Central Hudson Gas & Electric Corporation

For the 12 months ended December 31, 1997, the sources and related costs of electric generation for the Company were as follows:

Aggregate Percentage Costs in 1997 Sources of Generation of Energy Generated ($ 000)

Purchased Power 34.0% $ 56,002 Coal 38.5 40,159 Gas 4.8 7,600 Nuclear 13.7 4,100 Oil 6.6 11,437 Hydroelectric 2.4 638 100.0%

Fuel Handling Costs 1,536 Deferred Fuel Cost 509

$ 121,981 Residual Oil: At December 31, 1997, there were 438,176 barrels of fuel oil in inventory in Company-owned tanks for use in the Danskammer and Roseton Plants, which amount represents an average daily supply of 36 days. The oil storage capacity as of December 31, 1997 for these Plants was 16,251 and 1,079,000 barrels, respectively. The Company's share of the Roseton Plant's oil storage capacity is 377,650 barrels.

During 1997, there were no purchases of fuel oil made for the Danskammer Plant.

During 1997, the Roseton Plant's fuel oil requirements were supplied under onc firm and two spot market contracts. The prices under the firm contract were determined on the basis of published market indices in effect at the time of delivery. The term of the firm contract became effective on September 1, 1996 and continues through August 31, 1998. This firm contract permits the Company to make certain spot purchases from others.

Coal: In order to provide for its future requirements for coal to be burned in Units 3 and 4 at the Danskammer Plant, the Company, effective January I, 1997, entered into two supply contracts for the purchase of an aggregate of 720,000 tons per year of low sulfur (0.7% maximum) coal.

One contract provides for the delivery of coal by water from sources in Venezuela and Columbia, South America. The base price of purchases under this contract was fixed for the period which ended on December 31, 1997. As required by this contract, the price is renegotiated by the parties on an annual basis. The contract, as last renegotiated, now covers the term from January 1, 1998 through December 31, 2000.

The second contract, which provides for the delivery of domestic coal by rail, expires on December 31, 1998. The base price of purchases is fixed for the term of that contract.

The Company has also entered into a long-term rail contract for the delivery of coal. This contract covers the period January I, 1997 - December 31, 2001. During the first two years of this contract, rail rates are fixed, and thereafter, such rates will be negotiated by the parties. I The Company also purchased during 1997 a portion of its coal supply on the spot market.

Nuclear: For information regarding fuel reloading at Unit No. 2 of the Nine Mile Point Nuclear Station ("Nine Mile 2"), of which the Company owns a 9% interest, sec Item 7 hereof under the subcaption "Nuclear Operations" under the caption "Results of Operations."

Environmental Quality The Company is subject to regulation by federal, state and, to some extent, local authorities with respect to the environmental effects of its operations, including regulations relating to air and water quality, aesthetics, levels of noise, hazardous wastes, toxic substances, protection of vegetation and wildlife and limitations on land use. In connection with such regulation, certain permits are quired with respect to the Company's facilities, which permits have been obtained and/or are in the renewal process. Generally, e principal environmental areas and requirements to which the Company is subject are as follows:

Air: State regulations affecting the Company's existing electric generating plants govern the sulfur content of fuel used therein, the emission of particulate matter and certain other pollutants thcrcfiom and the visibility of such emissions. In addition, federal l7 Central Hudson Gas & Electric Corporation

and state ambient air quality standards for sulfur dioxide, nitrogen oxides and suspended particulates must be complied with in the area surrounding thc Company's generating plants. Based on the operation of its continuous emission stack monitoring systems and its ambient air quality monitoring system in the area surrounding the Roseton and Danskammer Plants, the Company believes that present air quality standards for nitrogen oxides, sulfur dioxide and particulates are satisfied in those areas.

Thc Danskammer Plant burns coal having a maximum sulfur content of 0.7%, fuel oil having a maximum sulfur content of 1%

and natural gas. The sulfur content of the oil burned at the Roseton Plant is limited by stipulation with, among others, the New York State Department of Environmental Conservation ("NYSDEC"), to an amount not exceeding 1.5% maximum and 1.3%

weighted annual average. Such sulfur content limitation at the Roseton Plant can be modified by the NYSDEC in the event of technological changes at such Plant, provided that the sulfur dioxide and nitrogen oxides emissions are limited to that which would have been generated by the use of oil with a sulfur content of 1.3% on a weighted annual average. Natural gas fuel is also burned at the Roseton Plant.

For a discussion of the impact of the Clean Air Act Amendments of 1990 ("CAA Amendments" ) on the Company's efforts to attain and maintain national ambient air quality standards for cmissions from its fossil-fueled electric power plants and for a discussion of the proposal of the Federal Environmental Protection Agency ("EPA") to modify emission standards for nitrogen oxides and suspended particulates, see Note 9 - "Commitments and Contingencies," hereof under the caption, "Environmental Matters - Clean Air Act Amendments."

Except as set forth above, the Company is unable to predict the effect (including cost) of these programs on its power plant operations since the details of the CAA Amendments are yet to be completely established by implementing regulations to be issued over a period of years by the EPA and the NYSDEC.

IVntcr: The Company is required to comply with applicable state and federal laws and regulations governing the discharge of pollutants into receiving waters.

The discharge of any pollution into navigable waterways is prohibited except in compliance with a permit issued by the EPA under the National Pollutant Discharge Elimination System ("NPDES") established under the Clean Water Act. Likewise, under thc New York Environmental Conservation Law industrial waste cannot be discharged into state waters without a State Pollutant Discharge Elimination System ("SPDES") permit issued by the NYSDEC. Issuance of a SPDES permit satisfies the NPDES permit requirement.

The Company has received SPDES permits for both the Roseton Plant and the Danskammer Plant, its Eltings Corners maintenance and warehouse facility, and its Rifton Recreation and Training Center. The SPDES permits for the Roseton and Danskammer Plants expired on October I and November 1, 1992, respectively, and such permit renewal applications are pending before the NYSDEC.

Thc Roscton Plant application is currently being reviewed in a NYSDEC proceeding. The subject of the restriction on use of water for cooling purposes at that Plant (as referred to in Item 3 hereof under the caption "Environmental Litigation") is being considcrcd in that proceeding.

It is the Company's belief that the expired SPDES permits continue in full force and effect pending issuance of the new SPDES permits.

For further discussion of the Company's compliance with the Clean Water Act and the Company's SPDES permit renewal proceeding, see Note 9 - "Commitments and Contingencies," hereof under the caption "Environmental Matters - Clean Water Act Compliance."

Toxic Substances and Hazardous Wastes: The Company is subject to state and federal laws and regulations relating to the use, handling, storage, treatment, transportation and disposal of industrial, hazardous and toxic wastes.

The NYSDEC in 1986 added to the New York State Registry of Inactive Hazardous Waste Disposal Sites (the "Registry" ) six locations at which gas manufacturing plants owned or operated by the Company or by predecessors to the Company were once located. Two other sites, which formerly contained gas manufacturing plants, have been identified by the Company. The Company studied these eight sites to determine whether they contain any hazardous wastes which could pose a threat to the environment or public health and, if such wastes were located at such sites, to determine the remedial actions which may be appropriate.

All of these eight sites were studied using the Phase I guidelines of the NYSDEC and five such sites were studied using the more extensive Phase II guidelines of the NYSDEC. As a result of these studies, the Company concluded that no remedial actions were required at any of these sites. In 1991, the NYSDEC advised the Company that four of the six sites had been deleted from such Registry. In 1992, the NYSDEC advised the Company that the two remaining sites listed on the Registry had been deleted from the Registry. Thc NYSDEC also indicated that such deletions of the sites were subject to reconsideration in the future, at IS Central Hudson Gas & Electric Corporation

which time new analytical tests may be required to determine whether or not wastes on site are hazardous. If, as a result of such potential new analytical tests, or otherwisc, remedial actions were ultimately required at these sites by the NYSDEC, the cost thereof could have a material adverse effect (the extent of which cannot be reasonably estimated) on thc financial condition of the Company if the Company could not recover all, or a substantial portion thereof, through insurance and rates.

For a discussion oF litigation filed against the Company involving one of the eight sites by the City of Newburgh, New York and the Company's response thereto, see Note 9 - "Commitments and Contingencies," hereof under the subcaption "Environmental Matters - Former Manufactured Gas Plant Facilities."

In August 1992, the NYSDEC notified the Company that the NYSDEC suspected that the Company's offices at Little Britain Road in New Windsor, New York, may constitute an inactive hazardous waste disposal site. Pursuant to a Consent Order entered into between the Company and the NYSDEC, the Company performed a preliminary site assessment and, on January 31, 1996, a draft final report ("site assessment rcport") prepared by the Company's consultant was submitted to the NYSDEC for its review, evaluation and comment. As a result of the NYSDEC's review of this site assessmcnt report, the Company agreed to perform additional testing. The draft rcport on this additional testing was submitted to the PIYSDEC on December 6, 1996. These reports both indicated that a limited amount of subsurface soil contamination was detected near one corner of the site and that contaminants were also detected in the ground water beneath the site. Operations conducted on thc site by thc Company since it purchased the property in 1978 are not belicvcd to have contributed to either the soil or thc ground water contamination. The Company can make no (i) prcdiction regarding w)iat action thc NYSDEC may take with regard to the draft reports, or (ii) prediction as to the outcome of recovery attempts against third parties by the Company. However, the Company believes that the cost of such site assessment and remediation, if any, will not be material.

Other: Thc Company estimates that expenditures attributable, in whole or in substantial part, to environmental considerations totaled $ 8.4 million in 1997, of which about $ .5 million related to capital projects and $ 7.9 million were charged to expense. It is estimated that in 1998 the total of such expenditures will be approximately $ 10.6 million.

Thc Company is not involved as a defendant in any court litigation with respect to environmental matters and, to the best of its knowledge, no litigation against it is threatened with respect thereto, except with respect to the litigation described in Item 3 hereof under the captions "Environmental Litigation" and "Environmental Claims - Newburgh Manufactured Gas Site," and as described in Mote 9 - "Commitments and Contingencies," under the caption "Environmental Matters - Former Manufactured Gas Plant acilities."

t Research and Development The Company is engaged in the conduct and support of research and development ("R&D")activities that are focused on providing enhanced customer service at lower costs while improving existing energy technologies and developing new technologies related to the production, distribution and conservation of energy.

Thc Company lcvcragcs its R&D expenditures by contributing to projects sponsored by various state and national research consortia and seeking external funding for those sponsored by the Company. In addition, New York law requires electric and gas utilitics to contribute to research undertaken by the New York State Energy Research and Development Authority.

The Company's expenditures, net of revenues from royalties, for electric and gas research and development projects amounted to $ 3.3 million in 1996 and $ 3.6 million in 1997. The Company projects that its 1998 expenditures for research and development will total approximately $ 3.4 million.

Other Matters Municipal Utilities: Article 14-A of thc New York General Municipal Law permits any municipality to construct, lease, purchase, own, acquire, usc and/or operate any utility service for the benefit of its inhabitants, and, in furtherance thereof, permits any municipality to acquire, through purchase or condemnation, the public utility service of any public utility company.

The current and projected excess supply of electricity in the Northeastern United States and in Canada has significantly depressed wholesale prices, and the increased level of competition in thc electric utility industry could cause municipalization efforts to intensify. Thc Company is not aware of any municipalization efforts in its franchise area.

PASNY Economic Development Powcri The New York State Economic Development Power Allocation Board is authorized law to solicit applications for "economic development power" by municipalities or municipal agcncics on behalf of businesses hich normally use a minimum peak electric demand of 400 kW for purposes of economic development, particularly job creation.

"Economic Development Power" ("EDP") is electric power generated at the Fitzpatrick Nuclear Gcncrating Station of the Power Authority oF the State of New York ("PASNY") which is available for such purpose. Should such power bc allocated to a customer within the Company's service territory, the Company would be required to wheel such power to the user at a cost-based rate, which must be approved by the PSC and/or by the FERC.

l9 Central Hudson Gas & Electric Corporation

As of December 31, 1997, the Company is not aware of any of its electric customers having applied for such EDP.

In addition, in 1997 the New York State Governor signed legislation making 400 MW of low cost power available to commercial and industrial customers as well as not-for-profit organizations. Energy available under this "Power for Jobs" program will be obtained from PASNY as well as competitively bid sources, including private utilities. The Company will receive a credit against its gross receipts tax liability, under Section 186-a of the New York Tax Law, for any lost revenue resulting from customers participating in this program.

Electric Economic Development Rate: The Company's tariff includes an economic development electric rate discount provision for large industrial customers (which exhibit new annual electric load of 500 kW or more) taking substation or transmission service and locating or expanding their business operations within the Company's service territory. Certain energy efficiency guidelines must also be met by eligible customers. Qualifying customers pay lower electric prices for the increased load, with savings on current rates for ten years. Customers must apply for the discount by October I, 1999. As of December 31, 1997, the Company had four industrial customers participating under this rate structure.

Labor Relations: The Company has agreements with the International Brotherhood of Electrical Workers for its 834 unionized employees, representing production and maintenance employees, customer relations representatives, service workers and clerical cmployces, excluding persons in managerial, professional or supervisory positions, which agreements were renegotiated effective July 1, 1994 and continue through June 30, 1998. The agreements provide for an average general wage increase of 3.2%

in each of the first three years of such agreements and a 3.5% increase in the fourth year of such agreements, and certain additional fringe benefits.

Afliliatcs:

iI Central Hudson Enterprises Corporation ("CHEC") is engaged in the business of conducting energy audits, providing services related to the design, financing, installation and maintenance of energy conservation measures and cogeneration systems for private businesses, institutional organizations and governmental entities and participates in cogeneration, small hydro and alternate energy production projects, directly or through one or morc of its affiliates.

an n. n n i 1  : These corporations, each a wholly-owned subsidiary of the Company, were established to either hold real property for the future use of the Company or to participate in energy-related ventures. Currently, the assets held by these subsidiaries are not material.

CHEC and the other subsidiaries noted above (with the exception of Phoenix Development Company, Inc.) would become subsidiaries of a proposed holding company as part of a restructuring of the Company described in Item 7 hereof under the caption, "Competition/Deregulation - Competitive Opportunities Proceeding" and in Note I - "Regulatory Matters" hereof under the caption "Amended Set tlemcnt Agreement."

Executive Officers of the Company The names of the current officers of the Board of Directors and the executive officers of the Company, their positions held and business experience during thc past five (5) years and ages (at December 31, 1997) are as follows:

Officers of the Board Name of Officer, Age and Position Held Principal Occupation or Employmcnt and Positions and Offices with the Company during the past five (5) years John E. Mack, III, 63, Present positions, except Chairman Chairman of thc Board and Chief Executive Officer; of the Committee on Finance, April 1996 Chairman of the Executive, Retirement and Finance Committees Jack Effron, 64, Present position since April 1994; President Chairman of Committee on Compensation and Succession of EFCO Products, a bakery ingredients corporation; member of the St. Francis Health Care Foundation; Chairman of the Chief Executive's Network for Manufacturing of the Council of Industry of Southeastern New York Heinz K. Fridrich, 64, Present position since April 1995; Courtesy Profess Chairman of Committee on Audit University of Florida at Gainesville, since 1994; Vice President - Manufacturing, International Business Machines Corporation, December 1992 - September 1993; Board of Trustees; Mount St. Mary College 20 Central Hudson Gas & Electric Corporation

Executive Officers of the Company Name of Officer, Age and Position Held Principal Occupation or Employment and Positions and Offices with the Company during the past five (5) years Paul J. Ganci, 59, Present position President and Chief Operating Officer Carl E. Meyer, 50, Present position since April 1996; Vice President-Sr. Vice President - Customer Services Customer Services, December 1992 - April 1996 Allan R. Page, 50, Present position since April 1996; Vice President-Sr. Vice President - Corporate Services Corporate Services, December 1992 - April 1996 Joseph J. DeVirgilio, Jr., 46, Present position Vice President - Human Resources and Administration Ronald P. Brand, 59, Present position Vice President - Engineering and Environmental Affairs Ellen Ahearn, 43, Present position since April 1994; Assistant Secretary Secretary and Internal Auditing Manager, December 1992-April 1994 Steven V. Lant, 40, Present positions since April 1993; Assistant Treasurer Treasurer and Assistant Secretary and Assistant Secretary, December 1992- April 1993 Donna S. Doyle, 49, Present position since April 1995; Assistant Controller Controller April 1994 - April 1995; Manager of Taxes, Budgets and Customer Accounting, April 1993 - April 1995, Manager of Plant and Depreciation and General Accounting, December 1992- April 1993 Arthur R. Upright, 54, Present position since February 1994; Manager Cost Assistant Vice President - Cost and Rate and Financial Planning and Rate and Financial Planning, December 1992-February 1994 Gladys L. Cooper, 46, Present position since September 1995; leave of Assistant Vice President - Governmental Relations absence for educational purposes December 1992-September 1995; Secretary, December 1992 - April 1994 James P. Lovette, 48, Present position since October 1997; Plant Assistant Vice President - Fossil Production Superintendent, December 1992 - November 1997 There are no family relationships existing among any of the executive officers of the Company.

Each of the above executive officers is elected or appointed annually by the Board of Directors.

2I Central Hudson Gas & Electric Corporation

ITEN 2 Properties Electric General: The net capability of the Company's electric generating plants as of December 31, 1997, the net output of each plant for the year ended December 31, 1997, and the year each plant was placed in service or rehabilitated are as set forth below:

Electric Generating (MW) *Net Capability (96-97) 1997 Unit Plant T e of Fuel Year Placed In Service Summer Winter Net Out ut MWh Dan skammer Residual Oil, 1951-1967 499 497 2,359,884 Plant ** Natural Gas and Coal Roseton Plant Residual Oil 1974 422 419 510,944 (35% share)** and Natural Gas Nevcrsink Water 1953 23 23 70/10 Hydro Station Dashville Water 1920 11,752 Hydro Station Sturgeon Pool Water 1924 16 16 53@52 Hydro Station High Falls Water 1986 7/97 Hydro Station Coxsackic Gas Kerosene or 1969 20 25 3,128 Turbine ("GT") Natural Gas So. Cairo GT Kerosene 1970 19 21 2,008 Nine Mile 2 Nuclear 1988 102 104 794,475 Plant (9% share)

Total 1,107 1,112 3,813350 Rejlects maxitnum one. hour net capability of the Company's ownership ofgeneration resources and, therefore, does not include finn purchases or sales.

~~ Plants subject to auction based on Amended Settlement Agreement as described in Item 7 hereof under thc caption I

"Cotnpetition/Deregulation - Competitive Opportunities Proceeding" and in blate - "Regulatory hfatters."

The Company has a contract with PASNY which entitles thc Company to 49 MW net capability from thc Blenheim-Gilboa Pumped Storage Hydroelectric Plant through 2002.

See Item 1 hereof, under the caption "Regulation" and the subcaption "Purchased Electric Power Generation," with respect to alternative electric power generation interconnected with the Company's system..

Thc Company owns 83 substations having an aggregate transformer capacity of 4A million kVA. The transmission system consists of 588 pole miles of line and the distribution system of 7/94 pole miles of overhead lines and 856 trench miles of underground lines.

Load and Capacity: The Company's maximum one-hour demand within its own territory, for the year ended Deccmbcr 31, 1997, occurred on July 15, 1997 and amounted to 917 MW. The Company's maximum one-hour demand within its own territory, for that part of thc 1997-1998 winter capability period through February 9, 1998 occurred on December 10, 1997 and amounted to 752 MW.

Based on current projections of peak one-hour demands for the three-year period comprising thc 1998 summer capability period through the winter capability period of 2000-2001, the Company estimates that it will have capacity available to satisfy its projected peak demands plus the estimated installed reserve gcncrating capacity requirements which it is required to maintain as a member of thc New York Power Pool ("NYPP"), described herein.

22 Central Hudson Gas R Electric Corporation

The following table sets forth the amounts of any excess capacity by summer and winter capability periods for such three-year period:

Excess of Capacity over Peak Plus Capability Forecasted Peak Plus Installed Available NYPP Installed Reserve Requirements Period Peak (MW) Reserve of 18% (MW) Ca acit (MW) (MW) Percent 1998 Summer 910 1074 1174 100 9.3 1998-99 Winter 870 10744 1179 105 9.8 1999 Summer 925 1092 1174 82 7.5 1999-00 Winter 885 10924'109 1179 87 8.0 2000 Summer 940 1174 65 5.9 2000-01 Winter 905 1109* 1179 70 6.3

• Summer period peak plus reserve requirements carry over to the following winter period.

Roscton Plant: The Roseton Plant is located in the Company's franchise area at Roseton, New York, and is owned by the Company, Consolidated Edison Company of New York ("Con Edison" ) and Niagara Mohawk Power Corporation ("Niagara Mohawk") as tenants-in-common. The Roseton Plant, placed in commercial operation in 1974, has a generating capacity of 1,200 MW consisting of two 600 MW generating units, both of which are capable of being fired either by residual oil or natural gas (see subcaption below entitled "Gas - Sufficiency of Supply and Future Gas Supply" ). Thc Company is acting as agent for the owners with respect to operation of the Roseton Plant. Generally, the owners share the costs and expenses of the operation of such Plant in accordance with their respective ownership interests.

The Company, under a 1968 Agreement ("Basic Agreement" ), has the option to purchase thc interests of Niagara Mohawk (25%) and of Con Edison (40%) in the Roseton Plant in December 2004. The exercise of this option is subject to PSC approval.

However, by agrecmcnt, dated March 30, 1994, between the Company and Niagara Mohawk, Niagara Mohawk was given, among other things, an option to retain its 25% interest in the Roseton Plant, provided that Niagara Mohawk exercises such option by May 31, 1999.

In March 1997, Niagara Mohawk and the Company entered into a Power Sales and Option Agreement which, among other hings, provides the Company with various options from 1998 through 2004 to purchase capacity and associated energy from Niagara Mohawk's interest in the Roseton Plant.

On December 1, 1997, as part of its restructuring proposal, Niagara Mohawk filed with the PSC a plan to divest its fossil-fueled and hydroelectric generating assets by auction by mid-1999. Niagara Mohawk's 25% interest in the Roseton Plant would be part of such divestiture.

As part of Con Edison's Amended and Restated Agreement and Settlement, as amended on September 19, 1997, between Con Edison, the Staff of thc PSC ("Staff') and others, and as approved by the PSC by its Order issued and effective November 3, 1997, Con Edison agreed to develop a plan to divest and transfer certain of its electric generating assets to unregulated entities, including third parties and Con Edison affiliates, by the end of 2002. Con Edison's 40% interest in the Roseton Plant would be subject to such divestiture.

The Company cannot predict what effect any auction/transfer of Niagara Mohawk's and/or Con Edison's interests in the Roseton Plant would have on the Company's interest in the Roseton Plant.

For information with respect to the Company's obligation to divest itself of its interest in the Roscton Plant, see Item 7 hereof under the caption "Competition/Deregulation - Competitive Opportunities Proceeding" and Note 1 - "Regulatory Matters," under the subcaption "Amended Settlement Agreement."

The 345 kV transmission lines and related facilities to connect the Roseton Plant with other points in the system of the Company and with the systems of Con Edison and Niagara Mohawk to the north and west of such Plant are 100%-owned by the Company. The share of each of the parties in the output of the Roseton Plant is transmitted over these lines pursuit to a certain transmission agreement relating to such Plant, which provides, among other things, for compensation to the Company for such use by the other parties. In addition, the Company has contract rights which entitle the Company to the lesser of 300 MW, or one quarter of thc capacity in a 345 kV transmission line owned by PASNY, which connects the Roseton Plant with a Con Edison substation to the east of such Plant in East Fishkill, New York. In exchange for these rights, the Company agreed to provide ASNY capacity in the 345 kV transmission lines the Company owns from the Roseton Plant, to the extent it can do so after tisfying its obligations to Con Edison and Niagara Mohawk.

Nine Mile 2 Plant: For a discussion of the Company's ownership interest in, costs for, and certain operating matters relating to the Nine Mile 2 Plant, see Item 7 hereof under the subcaption "Nuclear Operations," Note 3 - "Nine Mile 2 Plant," and Note 2-

"Summary of SigniTicant Accounting Policies," under the subcaption "Jointly-Owned Facilities."

23 Central Hudson Gas & Electric Corporation

New York Power Pool/Independent System Operator The Company is a member of the NYPP consisting of the major investor-owned electric utility companies in the State and PASNY. The members of the NYPP, by agreement, provide for coordinated operation of their bulk power electric systems with the objectives of using the most economical source of electricity, for the maintenance of a reserve margin equal to at least 18% of each member's forecasted peak load and for the sale and interchange of electric generating capability and energy among such members.

The members of the NYPP also provide for the cooperative development of long-range plans for the expansion on an integrated basis of the bulk power supply system for New York State, compatible with environmental standards, and appropriately related to interstate and international capacity and reliability considerations.

As part of the ongoing discussions regarding the restructuring of the electric industry in New York State referred to in Item 7 hereof under the caption "Competition/Deregulation," proposals have been made to restructure the NYPP. In a filing with FERC, dated January 31, 1997, the member systems of the NYPP proposed a new market structure that would include as its key elements the establishment of an Independent System Operator ("ISO"), the New York State Reliability Council ("NYSRC"), and the New York Power Exchange ("NYPE"). The ISO, NYSRC and NYPE would collectively replace the NYPP. A supplemental filing expanding the proposed restructure of NYPP was made by NYPP to FERC in December, 1997. The Company is unable to predict the outcome of these FERC filings.

The ISO's principal mission would be to maintain the reliability of the New York State bulk power systems and to provide transmission service on a comparable and non-discriminatory basis. The ISO wouhl be open to buyers, sellers, consumers and environmental groups and transmission providers; each of these groups would be represented on the Board of Directors of the ISO, which is proposed to be a not-for-profit New York corporation. The NYSRC's mission would be to promote and preserve the reliability of the bulk power system within New York State, through its primary responsibility for the promulgation of reliability rules; the ISO would develop the procedures necessary to operate the system within these reliability rules. The NYSRC is proposed to be govcrncd by a committee comprised of transmission providers and representatives of buyers, sellers, and consumer and environmental groups. The NYPE is proposed to be established as a non-profit corporation that would provide a vehicle through which buyers and sellers could participate in the markets for energy, capacity and ancillary services.

Gas General: The Company's gas system consists of 161 miles of transmission pipelines and 977 miles of distribution pipelines.

During 1997, natural gas was available to firm gas customers at a price competitive with that of alternative fuels. As compared to 1996, in 1997, firm retail gas sales, normalized for weather, increased by 1.17% and the average number of firm gas customers increased by 1.43% or 867. Sales to interruptible customers increased 111% in 1997 as compared to 1996. For further intormation regarding the Company's incentive arrangements for interruptible gas sales, see Item 7 hereof under the subcaption "Interruptible Gas Sales."

For the year ended December 31, 1997, the total amount of gas purchased from all sources was 19,397,777 Mcf., which includes 1,831,307 Mcf. purchased directly for use as a boiler fuel at the Roseton Plant.

The Company also owns two propane-air mixing facilities for emergency and peak shaving purposes located in Poughkeepsie and in Newburgh, New York. Each facility is capable of supplying 8,000 Mcf. per day with propane storage capability adequate to provide maximum facility sendout for up to three consecutive days.

SufIiciency of Supply and Future Gas Supply: The peak daily demand for natural gas by the Company's customers for the year ended December 31, 1997 occurred on January 18, 1997 and amounted to 101,175 Mcf. The Company's peak-day gas capability in 1997 was 116,865 Mcf. The peak daily demand for natural gas by the Company's customers for that part of the 1997-1998 heating season through February 9, 1998, occurred on December 3, 1997 and amounted to 88,903 Mcf.

Fixed Price Option: By PSC Order issued and effective June 5, 1997, the Company filed a rate design for a fixed natural gas price option. The fixed price service option was made available to firm sales customers effective with the 1997-98 heating season in an attempt to stabilize the commodity price that customers pay for natural gas.

This option is offered to residential, commercial and industrial customers whose annual consumption is greater than 500 Ccf (hundred cubic feet) annually. Approximately 36,000 customers qualified for the program on a first-come, first-service basis.

Response to the fixed price option was favorable.

Other: FERC permits non-discriminatory access to the pipeline facilities of interstate gas pipeline transmission companies subject to the jurisdiction of FERC under the Natural Gas Act. This rule allows access to such pipelincs by the pipeline transmission company's customers enabling them to transport gas purchased directly from third parties and spot sources through such pipelines. Such access also permits industrial customers of gas distribution utilities to connect directly with the pipeline 24 Central Hudson Gas & Electric Corporation

transmission company and to contract directly with the pipeline transmission companies to transport gas, thereby by-passing the distribution utility. The PSC has authorized New York State distribution gas utilities to transport customer-owned gas through its facilities upon request of a customer. Currently, interstate pipeline transmission companies are located in certain areas where the Company provides retail gas service (the Towns of Carmel, Pleasant Valley, Coxsackie, and LaGrange in New York State). There has been no adverse revenue impact on the Company as a result of such action by the Company to transport gas.

For a discussion of the PSC proceeding relating to issues associated with the restructuring of the natural gas market, see Item 7 hereof under the subcaption "Competition/Deregulation - Natural Gas - PSC Position Paper."

Other Matters The Danskammer Plant and the Roseton Plant and all of the other principal generating plants and important property units of the Company are held by it in fee simple, except (1) certain rights-of-way, and (2) a portion of the property used in connection with the hydroelectric plants of thc Company consisting of flowage or other riparian rights. The Company's present interests in the Roseton Plant and the Nine Mile 2 Plant are owned as undivided interests as a tenant-in-common with the other utility owners thereof. Certain of the properties of the Company arc subject to rights-of-way and easements which do not interfere with the Company's operations. In thc case of certain distribution lines, the Company owns only a part interest in the poles upon which its wires are installed, the remaining intcrcst being owned by telephone companies. Certain electric transmission facilities owned by others are used by the Company pursuant to long-term contractual arrangements.

All of the physical properties of the Company, other than property such as material and supplies excluded in the Company's First Mortgage Bond Indenture ("Mortgage" ) and its franchises, are subject to the lien of the Mortgage under which all of its Mortgage Bonds are outstanding. Such properties are from time to time subject to liens for current taxes and assessments which the Company pays regularly as and when due.

During the three-year period ended December 31, 1997, the Company made gross property additions of $ 144.0 million and property retirements and adjustments of $ 34.7 million, resulting in a nct increase (including Construction Work in Progress) in utility plant of $ 109.3 million, or 7.7%.

ITEN 3 Legal Proceedings Asbestos Litigation: For a discussion of litigation against the Company involving asbestos, see Note 9 - "Commitments and Contingencies," hereof under the caption "Asbestos Litigation."

Environmental Litigation: On March 23, 1992, in an action brought in 1991 by the Natural Resources Defense Council, Inc.,

the Hudson River Fisherman's Association and Scenic Hudson, Inc., a Consent Order was approved by the Supreme Court of the State of New York, Albany County.

Such Consent Order provides for certain operating restrictions at the Roseton Plant relating to the use of river water for plant cooling purposes, which restrictions have not, and are not expected to impose material additional costs on the Company. The Consent Order was extended until February 1, 1998 by agrccment of thc parties and Court approval. A further extension is being currently negotiated. For a description of the pending NYSDEC proceeding involving the renewal of the SPDES permit for the Roscton Plant, see Item 1 hereof under the subcaption "Environmental Quality - Water," and Note 9 - "Commitments and Contingencies," under the caption "Environmental Matters - Clean Water Act Compliance."

Environmental Claims - Ncwburgh Manufactured Gas Site: For a discussion of litigation filed against the Company by the City of Newburgh, New York, on May 26, 1995 in thc United States District Court, Southern District of New York, and the Company's response thereto, see Note 9 - "Commitments and Contingencies," under the subcaption "Environmental Mattcrs-Former Manufactured Gas Plant Facilities."

Catskill Incident: An explosion occurred in a dwelling in the Company's gas service territory in Catskill, New York in November 1992 which resulted in personal injuries, the death of an occupant and property damage. Lawsuits have been commenced against the Company arising out of such incident, including the following:

By complaint, dated February 2, 1994, Carl Fatzinger, as executor of the estate of Mildred Fatzinger, and Virginia Fatzinger ommenced an action in the Supreme Court of the State of Ncw York, Greene County, against the Company and two other 25 Central Hudson Gas & Electric Corporation

defendants. The complaint seeks an unspecified amount of compensatory and punitive damages based on theories of negligence, absolute liability and gross negligence for the death of Mildred Fatzinger, personal injuries to Virginia Fatzinger and property damage alleged to have been caused by said explosion.

By complaint, dated October 18, 1993 and filed in the Supreme Court of the State of New York, Greene County, Frank Reyes commenced an action against the Company for unspecified personal injuries and property damage alleged to have been caused by said explosion. The complaint seeks $ 2,000,000 in compensatory damages and $ 2,000,000 in punitive damages from the Company, based on theories of negligence and gross negligence.

The Company is investigating these claims and presently has insufficient information on which to predict their outcome. The Company believes that it has adequate insurance with regard to the claims for compensatory damages. The Company's insurance, however, does not extend to punitive damages. Ifpunitive damages werc ultimately awarded in either or both of these lawsuits, such award(s) could have a material adverse effect on the financial condition of the Company. At this time, the Company can make no prediction as to any other litigation which may arise out of this incident.

Wapplngcrs Falls Incident: Two consecutive fires and explosions occurred on February 12, 1994, destroying a residence and commercial establishment in the Village of Wappingers Falls, New York, in the Company's service territory. Lawsuits have been commenced against the Company arising out of such incident, including the following:

On August 31, 1994, the Company was served with a summons and complaint in an action brought by John DeLorenzo against the Company and the Village of Wappingers Falls in the Supreme Court of the State of New York, County of Dutchess. The complaint seeks unspecified amounts of damages, based on a theory of negligence, for personal injuries and property damage allcgcd to have been caused by the incident.

On March 9, 1995, the Company was served with a summons and complaint in an action brought by Cengiz Ceng, individually and as executor under the last will and testament of Nizamettin Ccng, and Tarkan Thomas Ceng against the Company and the Village of Wappingers Falls in the Supreme Court of thc State of New York, County of Dutchess. The complaint sccks recovery of

$ 250,000 from the Company, based on the theory of negligence, for property damages alleged to have been caused by thc incident.

The Company is investigating these claims and prcscntly has insufficient information on which to predict their outcome. The Company believes that it has adequate insurance with regard to the claims for compensatory damages. The Company's insurance, howcvcr, does not extend to punitive damages. Ifpunitive damages were ultimately awarded, in any of these lawsuits, such award(s) could have a material adverse effect on the financial condition of the Company. At this time, the Company can make no prediction as to any other litigation which may arise out of this incident.

ITEN 4 Submission of Natters to a Vote of Security Holders No matter was submitted to a vote of security holders during the fourth quarter of the Company's fiscal year covered by this Report.

PART II ITEN 5 Narket for the Company's Common Equity and Related Stockholder Natters For information regarding the market for the Company's common stock and related stockholder matters, see Item 7 hereof under the captions "Capital Resources & Liquidity - Financing Program" and "Common Stock Dividends and Price Ranges" and Note 6 - "Capitalization - Capital Stock."

Pursuant to applicable statutes and its Certificate of Incorporation, the Company may pay dividends on shares of Preferred and Common Stock only out of surplus.

F or information regarding the replacement, effective January 1, 1997, of the Company's Automatic Dividend Reinvestment and Stock Purchase Plan ("DRP"), Customer Stock Purchase Plan ("CSPP") and Employee Stock Purchase Plan ("ESPP"), by a single new Stock Purchase Plan, see Note 6 - "Capitalization - Capital Stock."

For information on the Company's program to repurchase some of its issued and outstanding common stock pursuant to a program approved by the PSC, see Item 7 hereof under the caption "Financing Program."

26 Central Hudson Gas & Electric Corporation

ITEN 6 Selected Financial Data Five-Year Summary of Consolidated Operations and Selected Financial Data*

ttn Thousands)

Operating Revenues Electric $ 416,429 $ 418,761 $ 409,445 $ 411,082 $ 422,925 Gas. 103848 95210 102770 104 586 94 448 Total 520,277 513,971 512,215 515,668 517,373 Operating Expenses Operations 284,714 267,779 274,665 274,497 274,477 Maintenance .......... 27,574 28,938 29,440 32,716 34,486 Depreciation and amortization ... 43,864 42,580 41,467 40,380 39,682 Taxes, other than income tax ...... 64,879 66,145 66,709 66,899 65,564 Federal income tax. 29 190 32 700 29 040 28 043 28 603 Total 450 221 438 142 441 321 442 535 442 812 Operating Income 70,056 75,829 70,894 73,133 74,561 Other Income Allowance for equity funds used during construction ... 387 466 986 866 934 Federal income tax 2,953 1,632 353 1,237 1,445 Other - net 8 079 4 815 8 886 6 296 5 167 Total 11 419 6,913 10,225 8,399 7,546 Income before Interest Charges ... 81)475 82,742 81,119 81,532 82,107 Interest Charges 26 389 26,660 28,397 30,603 31,717 Nct Income 55,086 56,082 52,722 50,929 50,390 Premium on Preferred Stock Redemption - Net 378 169 Dividends Dcclarcd on Cumulative Preferred Stock ............... 3,230 3,230 4,903 5,127 5,562 Income Available for Common Stock ....... 51,85 Dividends Declared on Common Stock .... 37,137 37,128 36,459 35,541 34,497 Amount Retained in the Business ............. 14,719 15,346 11,191 10,261 10,331 Retained Earnings - beginning of year ..... 105 821 90 475 79 284 69 023 58 692 Retained Earnings - end of year ................ $ 120,540 $ 105,821 $ 90,475 $ 79,284 $ 69,023 Common Stock Average shares outstanding (000s) ..... 17,435 17,549 17,380 17,102 16,725 Earnings per share on average shares outstanding .......... $ 2.97 $ 2.99 $ 2.74 $ 2.68 $ 2.68 Dividends declared per share.............. $ 2.135 $ 2.115 $ 2.095 $ 2.075 $ 2.045 Book value per share (at year-end) .... $ 27.61 $ 26.87 $ 25.96 $ 25.34 $ 24.65 Total Assets . $ 1)252,090 $ 1,249,106 $ 1,250,092 $ 1,250,781 $ 1,264,240 Long-term Debt 361,829 362,040 389,245 389,364 391,810 Cumulative Preferred Stock .......................... 56,030 56,030 69,030 81,030 81,030 Common Equity 4777104 471,709 454,239 436,731 417,846 This summary should be read in conjunction with the Consolidated Financial Statements and Notes thereto included in Item 8 of this Form 10-K.

27 Central Hudson Gas & Electric Corporation

lTEN 7 Nanagement's Discussion And Analysis Of Financial Condition And Results Of Operations 0

COMPETITION/DEREGULATION General The regulatory framework under which utilities operate is undergoing significant change, although the path and pace of that change vary from jurisdiction to jurisdiction. The Company is subject to regulation for retail rates by the PSC and wholesale rates by the FERC. These agencies have each adopted policies that focus on competition in gas and electric markets. As a result, the public utility industry is facing increasing competition and dcrcgulation initiatives across the country and in New York State.

Due to the rapid change in the utility industry, the Company continues to develop strategies designed to enhance its competitive position and to adapt to anticipated changes in its business. The Company's goal is to be the energy services provider of competitive choice in the emerging retail market. In order to achieve this goal, the Company continues to identify and implement measures to increase efficiency and improve effectiveness.

Competitive Opportunities Proceeding In 1994, the PSC instituted the "Competitive Opportunities Proceeding," the overall objective of which is to identify regulatory and rate-making practices that will assist in the transition to a more competitive electric industry. In May 1996, the PSC issued its order in that Proceeding, which required all of the electric utilities subject to that Proceeding, including the Company, to file a restructuring plan by October, 1996. That Plan was required to address, among other things, the structure of the electric utility, both in the short and long-term, and a schedule for the introduction of retail access. The Company filed its response on October 1, 1996 and thereafter began a series of lengthy discussions and negotiations with thc PSC and certain other interested parties which culminated in an Amended and Restated Settlement Agreement, dated January 2, 1998 ("Amended Settlement Agreement" ), among the Company, PSC Staff and certain other parties. The PSC approved the Amended Settlement Agreement at its February 4, 1998 session; however, the PSC had not yet issued its final order at thc time this document was filed with the Securities and Exchange Commission. Generally, the principal points of the Amended Settlement Agreement are as follows: (i) continuation of a basic electric rate freeze for residential, commercial and small industrial customers through June 2001; (ii) a 5% reduction in base electric rates for large industrial customers; (iii) a phase-in of retail access through Junc 30, 2001 to residential, commercial and small industrial customers; (iv) a 10.6% return on equity ("ROE") cap with excess earnings, if any, deferred for stranded cost mitigation; (v) a reasonable opportunity to recover all prudently incurred strandable costs; (vi) functional unbundling of thc Company's Danskammer Plant and its interest in the Roseton Plant in 1998, followed by structural separation by June 30, 2001; (vii) transfer of title by an auction of the Company's Danskammcr Plant and its interest in the Roseton Plant to be completed by June 30, 2001 (an affiliate of the Company can bid); (viii) approval to form a holding company not later than June 30, 2001, which holding company initially would own thc Company and all but one of the Company's existing subsidiaries; and (ix) permission for the Company to transfer up to $ 100 million of equity from thc Company to unregulated affiliates prior to formation of the holding company.

The consideration received by the Company in an auction, referred to in (vii) above, would, up to thc net book value of the assets sold, be available for investmcnt in unregulated operations without PSC approval. Any excess over such net book value would be required to be used to offset the Company's fossil-fueled generation related regulatory assets and, to the extent of any remaining consideration, to reduce the book cost of the Company's investment in the Nine Mile 2 Plant. In the event that the sale price of any such assets were below the Company's then current nct book value, thc diffcrcnce would be preserved for recovery as a strandable cost.

In the event a Company affiliate elects not to bid on any such auction, the Company would retain, prior to application of the consideration described in the immediately preceding paragraph, 10% of such consideration in excess of the book value of the Company's fossil-fueled generation assets, not to exceed in the aggregate $ 17.5 million.

As provided for in the Amended Settlement Agrcemcnt, the Company will withdraw from a certain lawsuit commenced by the Company and certain other utilities in the New York State court system challenging the validity of said May 1996 PSC Order.

The Amended Settlement Agreement creates certain changes to the Company's accounting policies. For more information regarding the Amended Settlement Agreement and its impact on the Company's accounting policies see Note 1 - "Regulatory Matters" herein.

FERC - Electric On April 24, 1996, the FERC released Order Nos. 888 and 889, promoting wholesale competition between public utilities by providing open access, non-discriminatory transmission services. Thc Orders have thc effect of (i) requiring electric utilities to oper their transmission lines to wholesale competitors, while allowing recovery of certain "stranded costs," (ii) requiring electric utilities to establish electronic systems to sharc information about available transmission capacity, subject to certain standards of conduct, 28 Central Hudson Gas & Electric Corporation

and (iii) requiring certain functional separation of power marketing from other operations. The Company duly filed its open access transmission ("OAT") tariff with FERC, as required by Order No. 888, which tariff has been approved by FERC. Under the OAT tariff, the Company must offer transmission service to wholesale customers on a basis that is comparable to that which it provides itself. The Company is also required to offer and/or provide certain ancillary services which contribute to the reliability and security of the transmission system. On December 30, 1996, the NYPP, of which the Company is a member, filed an interim restructuring plan with FERC in response to the requirements of Order No. 888. On January 31, 1997, the NYPP filed an additional restructuring filing, which includes proposals to establish an ISO, a NYPE, and a NYSRC. The NYPP filed a supplemental filing with FERC in December 1997 which expanded the prior restructuring filing. Pending the outcome of such proceedings as the FERC may require in response to such filings, the Company can make no prediction as to the effect on it of these filings, or of compliance with FERC Order Nos. 888 or 889.

Mergers in the Electric Industry In response to the increasingly competitive environment, utilities across the country have been reorganizing to better position themselves financially in their market areas for the future. Thus, mergers and possible mergers have been reported in the news media, including the public announcement of the proposed merger between Long Island Lighting Company ("LILCO")and Brooklyn Union Gas Company, two New York utilities.

Natural Gas-PSC Position Paper On September 4, 1997, thc PSC issued a notice inviting comments on a report prepared by the PSC Staff, entitled "The Future of the Natural Gas Industry" ("Position Paper" ). Recognizing that customer choice has not evolved as expected under the gas generic restructuring orders from the PSC, the PSC Staff reached the conclusion that "the most effective way to establish a robustly competitive market in gas supply is to separate the merchant and distribution function." The Position Paper sets forth a variety of recommendations addressing issues such as upstream capacity, rate design, system reliability, market power, customer communication, social programs and taxes. The PSC Staff believes that a five-year period is necessary for local distribution companies to transition out of the merchant business. The Company is unable to predict what will be the ultimate outcome of such a proposal.

RATE PROCEEDINGS Electric The Company's most recent completed electric rate case was filed November 12, 1992 and, by Order issued and effective February 11, 1994, the PSC permitted the Company to increase its electric base rates by $ 5.133 million (or approximately 1.3% on an annual basis), based on a 10.6% return on common equity, and an 8.58% return on total invested capital. See the caption above "Competition/Deregulation" and the subcaption "Competitive Opportunities Proceeding" thereunder, for a discussion related to the Company's October 1, 1996 filing in that Proceeding.

Gas The Company filed its most recent gas rate case on November 10, 1995, and the PSC, on October 3, 1996, issued its Order and Opinion ("Order" ) regarding the Company's request to increase its natural gas prices. The Order did not provide for an increase in base prices, but did authorize rate moderation to offset a projected revenue deficiency of $ 500,000, largely through the use of previously retained interruptible profits. The PSC also determined that a 10% return on common equity is appropriate for the Company's gas operations.

CAPITAL RESOURCES AND LIQUIDITY Construction Program As shown in the Consolidated Statement of Cash Flows, the cash expenditures related to the Company's construction program amounted to $ 43.5 million in 1997, a $ 5.9 million decrease from the $ 49.4 million expended in 1996. As shown in the table below, cash construction expenditures for 1998 are estimated to be $ 58.1 million, an increase of $ 14.6 million compared to 1997 expenditures.

In 1998, the Company expects to satisfy its external funding requirements, ifany, through issuances of additional debt securities, the amount and type of which cannot be predicted.

29 Central Hudson Gas & Electric Corporation

Estimates of construction expenditures, internal funds available, mandatory and optional redemption or repurchase of long-term securities, and working capital requirements for the two-year period 1998-1999 are set forth by year in the following table:

Total 1999 1998-1999 (In Thousands)

Construction Expenditures* ... $ 58,100 $ 51,700 $ 109,800 Internal Funds Available 55,900 56,600 112,500 Excess of Construction Expenditures over Internal Funds ... 2,200 (4,900) (2,700)

Mandatory Redemption of Long-term debt ..... 100 20,100 20,200 Optional Redemption or Purchase of Securities:

Long-term debt 16,700 16,700 Common stock. 24 000 24 000 48 000 Total. 24,000 40,700 64,700 Other Cash Requirements ... 7,000 11,000 18.000 Total Cash Requirements ... $ 33,300 $ 66,900 $ 100,200

~ Ercluding the equity portion ofAllowance for Funds Used During Construction ("AFDC"),

a noncash item.

Estimates of construction expenditures are subject to continuous review and adjustment, and actual expenditures may vary from estimates. These construction expenditures include capitalized overheads, nuclear fuel and the debt portion of AFDC.

Included in the construction expenditures are expenditures which are required to comply with the Clean Air Act and related Amendments of 1990.

As shown in the table above, it is presently estimated that funds available from internal sources will finance over 100% of the Company's cash construction expenditures for the two-year period 1998-1999. During this same two-year period, total external financing requirements arc projected to amount to $ 100.2 million, of which $ 20.2 million is related to the mandatory redemption of long-term securities and $ 64.7 million is related to the optional redemption of long-term securities and the repurchase of common stock.

Capital Structure Over the period 1988-1997, the Company substantially increased its common equity ratio through retention of a portion of its earnings, offerings of its common stock to thc public, original issuances of its common stock under its DRP and its CSPP (both of which have since been superseded, effective January I, 1997, by the Company's Stock Purchase Plan described in this Item 7 under the caption "Financing Program," below and in Note 6 - "Capitalization - Capital Stock" hereof) and redemption of debt and preferred stock. Onc result of these recent increases in the Company's common equity ratio has been a significant improvement in its interest coverage ratios as shown under the caption "Financial Indices" in this Item 7. The Company's interest coverage ratios have also been improved by the refinancing of a portion of its debt at lower interest rates. Despite a tightening of bond rating criteria applied to the electric utility industry, the Company has maintained or improved its bond ratings since 1991. During 1997, Standard 8t, Poor's Corporation, upgraded the Company's senior debt rating from "A-" to "A." The Company's other bond ratings, which were reaffirmed during 1997, arc "A" by Duff & Phelps Credit Rating Co. and Fitch Investors Service and "A3" by Moody's Investors Service, Inc. The Company's continuing goal is to achieve and maintain bond ratings at the "A"level.

Under the terms of the Amended Settlement Agreement, described under thc caption "Competition/Deregulation" of Item 7 hereof, the Company may invest up to $ 100 million in unregulated businesses prior to thc formation of a holding company, which formation is contemplated to become effective between January 1, 1999 and June 30, 2001. After its formation, such holding company will be free to invest in new businesses subject only to the terms of the Amended Settlement Agreement. As a result of the new investmcnt opportunities the Company expects to become available in 1998 and 1999, the Company may make substantial new investments and may change its capital structure in ways that cannot be predicted at this time.

Set forth below is ce'rtain information with respect to the Company's capital structure at the end of 1997, 1996 and 1995:

Year-cnd Ca ital Structure 1997 1996 1995 Long-term debt. 40.5% 40.1% 42.8%

Short-term debt 1.7 Preferred stock 6.3 6.2 7.5 Common equity 53.2 52.0 49.7 100.0% 100.0% 100.0%

30 Central Hudson Gas & Electric Corporation

~

Financing Program By an Order issued and effective December 4, 1996, the PSC granted the Company authorization to issue and sell, through

~

December 31, 1999, up to an additional $ 40 million of securities. This $ 40 million can be comprised of medium term notes or common stock solely or a combination of medium term notes and common stock. That Order also authorizes the Company to acquire, through December 31, 1999, not more than 2.5 million shares of its issued and outstanding common stock. The Company also received approval to combine its DRP, its CSPP and its ESPP into a new Stock Purchase Plan, effective January 1, 1997.

The Company improved its common equity ratio from 35.4% at December 31, 1987 (following the write down of a portion of the Nine Mile 2 Plant as directed by the PSC) to 52.0% at December 31, 1996, which level was deemed sufficient by the Company.

Pursuant to the aforementioned PSC authorization, the Company, in January 1997, instituted a common stock repurchase program primarily for the purpose of managing continuing growth in its common equity ratio. Under such program the Company repurchased 275,200 shares of its common stock during 1997. Despite such program, the Company's common equity ratio further improved to 53.2% at December 31, 1997. The Company's target level of share repurchase for 1998 will be determined in early 1998 in view of the price per share of common stock, cash flow and opportunities to reinvest in the Compny's business or invest in new businesses.

The Company intends to refinance, if economic, its 8.375% Series NYSERDA Bonds ($ 16.7 million) on or soon after its call date on December I, 1998 at a lower cost. The Company also intends to refund at maturity its 5.38% Series Medium Term Notes

($ 20 million) on January 15, 1999.

Under the terms of the Amended Settlement Agreement described above under the caption "Competitive Opportunities Proceeding," prior to the formation of a new holding company, the Company may transfer up to $ 100 million from its regulated utility business to its unregulated businesses. The Company may, pursuant to this authorization, issue up to $ 100 million of new securities in 1998 or 1999. Following the formation of the holding company contemplated under the Amended Settlement Agreement to occur between January 1, 1999 and June 30, 2001, the Company may issue new securities in furtherance of its business plan to be developed for such holding company. The type of any such securities to be issued after the formation of such holding company and timing of issuance cannot be predicted at this time.

For more information with respect to such Order and the Company's financing program in. general, see Note 6-

"Capitalization - Capital Stock" and Note 7 - "Capitalization - Long-Term Debt."

Short-Term Debt As more fully discussed in Note 5 - "Short-Term Borrowing Arrangements" hereof, the Company has a revolving credit agreement with four commercial banks for borrowing up to $ 50 million through October 23, 2001. In addition, the Company has several committed and uncommitted bank facilities ranging from $ .5 million to $50 million from which it may obtain short-term financing. Such agreements give the Company competitive options to minimize its cost of short-term borrowing. Authorization from the PSC limits the amount the Company may have outstanding at any time under all of its short-term borrowing arrangements to $ 52.0 million in the aggregate.

RESULTS OF OPERATIONS The following discussion and analysis includes an explanation of the significant changes in revenues and expenses when comparing 1997 to 1996 and 1996 to 1995. Additional information relating to changes between these years is provided in the Notes.

Earnings Earnings per sharc of common stock are shown after provision for dividends on preferred stock and are computed on the basis of thc average number of common shares outstanding during the year. The number of common shares, the earnings per share and the rate of return earned on average common equity are as follows:

Earnings per share....

Average shares outstanding (000s) .....................................

Return earned on common equity per financial statements*

1997 17,435

$ 2.97 10.8%

1996 17,549

$ 2.99 11.1%

1995 17,380

$ 2.74 10.5%

~ Return on equity for regulatory rate-making purposes divers from these figures.

Earnings per share in 1997, when compared to 1996 results, decreased $ .02 per share. This decrease resulted substantially from decreased electric and gas net operating revenues (including fuel costs and purchased electricity) attributable largely to decreased I ales resulting primarily from a decrease in usage by residential and industrial electric customers and residential and commercial gas customers due to unseasonable weather experienced in 1997. Billing adjusted heating degree days were 8% lower and cooling degree days were 16% lower, when 1997 results were compared to 1996. The effect of these unseasonable weather conditions alone reduced earnings by an estimated $ .22, despite a 1% increase in the number of customers. Also contributing to the decrease in 1997 3I Central Hudson Gas & Electric Corporation

earnings are decreased electric earnings related to regulatory incentive programs based on fuel costs and energy efficiency, largely due to the reduced availability of purchased power at a cost below the Company's fossil-fueled generation, and increased depreciation expense on the Company's plant and equipment.

Partially offsetting these decreases in 1997 earnings is a $ .09 increase resulting from the net effect of two non-recurring items as follows: the 1997 recording of tax adjustments including additional investment tax credits and related interest refunded from the settlement of various Internal Revenue Service ("IRS") audits, and the 1997 provision for the non-recoverable portion of a purchased power contract. Other items also impacted earnings favorably including: decreased uncollectible accounts, avoided interest expense from the optional redemption in May 1996 of the Company's 8 3/4% Series $ 30 million First Mortgage Bonds, increased interest and dividend income, and decreased interest expense.

Earnings per share in 1996 increased $ .25 per share over 1995 resulting primarily from increased electric and gas net operating revenues caused largely by an increase in usage by residential customers, and the unseasonable hot and/or cold weather conditions experienced in 1996whencomparedto 1995. Hcatingdegreedays were17%higher in 1996 than intheprioryear. Also contributing to the increase in 1996 were the optional redemption of the Company's 7.44% Series Cumulative Preferred Stock in October 1995, 7.72% Series Cumulative Preferred Stock in January 1996 and 8 3/4% Series $ 30 million First Mortgage Bonds in May 1996.

This 1996 increase in earnings per share was partially offset by increased employee wages and associated fringe benefits and thc 1995 non-recurring gain from the sale of long-term stock investments. Various other items unfavorably impacted earnings per share including increased depreciation expense associated with the Company's plant and equipment, decreased interest and dividend income and increased uncollectible accounts.

Operating Revenues Total operating revenues increased $ 6.3 million (1%) in 1997 as compared to 1996 and increased $ 1.8 million (.3%) in 1996, as compared to 1995.

See the table below for details of the variations:

Increase or (Decrease) from Prior Year 1997 1996 Electric C~as Total Electric as Total (In Thousands)

Customer sales . $ (7,860) $ 2,624 $ (5,236) $ 9,784 $ (8,368) $ 1,416 Sales to other utilities ... 4,840 (2,290) 2,550 330 2,475 2,805 Fuel cost adjustment .... (291) 8,846 8,555 (1,248) (2,497) (3,745)

Deferred revenues . 675 (1,125) (450) 677 840 1,517 Miscellaneous. 304 583 887 (227) (10) (237)

Total $ (2)332) $ 8,638 $ 6@06 S 9,316 S(7,560) S 1,756 Sales The Company's sales vary seasonally in response to weather. Generally electric revenues. peak in the summer and gas revenues peak in the winter.

Sales of electricity within the Company's service territory decreased 3% in 1997 and increased 3% in 1996. Electric sales in 1997 decreased primarily because of a decrease in usage by residential and industrial customers largely due to the unseasonable weather conditions cxperienccd in 1997 when compared to 1996. In 1996, electric sales increased largely from an increase in usage by residential customers, and thc unseasonable hot and/or cold weather experienced throughout 1996 when compared to the weather conditions of 1995.

Firm sales of natural gas (which excludes interruptible and transportation sales) decreased 5% in 1997 due primarily to a decrease in usage by residential and commercial customers. In 1996, firm sales of natural gas increased 12% due to an increase in usage by rcsidcntial, commercial and industrial customers.

Changes in sales from last year by major customer classification, including interruptible gas sales are set forth below. Also indicated are the changes related to transportation of customer-owned gas:

% Increase Decrease from Prior Year Electric (Mwh) Gas (Mcf) 1997 1996 1997 1996 Residential . (2) 5 (6) 16 Commercial . I (6) 12 Industrial (6) 3 11 15 Interruptible N/A N/A 111 (78)

Transportation of Customer-Owned Gas ... N/A N/A 74 105 32 Central Hudson Gas & Electric Corporation

Residential and Commercial Sales: Residential electric and gas sales are primarily affected by the growth in the number

~

~

of customers and the change in customer usage. In 1997, residential electric and gas sales and commercial gas sales decreased primarily from a decrease in customer usage largely due to the unseasonable weather experienced in the Company's service territory.

in 1997. Billing adjusted heating degree days were 8% lower and cooling degree days were 16% lower when 1997 results were compared to 1996.

In 1996, residential and commercial electric and gas sales increased primarily due to an increase in customer usage partly caused by unseasonable hot and/or cold weather experienced throughout 1996 in the Company's service territory. Heating degree days were 17% higher in 1996 than in the prior year.

Industrial Electric Sales: In 1997, as compared to 1996, industrial electric sales decreased 6% primarily due to a decrease in usage by a large industrial customer. In 1996, as compared to 1995, industrial electric sales increased 3% largely because of an increase in usage by a large industrial customer.

Industrial Gas Sales: In 1997, firm gas sales to industrial customers increased 11% primarily because of an increase in usage by a large industrial customer. Firm gas sales to industrial customers for 1996 increased 15% substantially because of increased usage by several large industrial customers.

Interruptible Gas Sales: In 1997, interruptible gas sales increased 111% largely due to an increase in natural gas sold for use as a boiler fuel at the Ro'seton Plant. Interruptible gas sales decreased 78% in 1996, due substantially to a decrease in natural gas sold for use as a boiler fuel at the Roseton Plant. The use of gas as a boiler fuel at the Roseton Plant is dependent upon its economic benefit as compared to the use of oil for generation or the purchase of electricity to meet the Company's load requirements. Due to sharing arrangements, as described in the caption "Incentive Arrangements" of Item 7 hereof that are in place for interruptible gas sales and transportation of customer-owned gas, variations from year to year typically have a minimal impact on earnings.

Transportation of Customer-Owned Gast The volume of customer-owned gas transported in 1997 increased 74% and 105% in 1996 due primarily to an increase in usage by a large transportation customer.

Incentive Arrangements Pursuant to certain incentive formulas approved by the PSC, the Company either shares with its customers, certain revenues and/or cost savings exceeding defined predetermined levels, or is penalized in some cases for shortfalls from the targeted levels or defined performance standards.

Incentive formulas are in place for fuel cost variations, sales of electricity and gas to other utilities, interruptible gas sales, capacity release transactions and customer satisfaction.

The net results of these incentive formulas were to increase pretax earnings by $ 700,000, $ 2.9 million and $ 2.8 million during 1997, 1996 and 1995, respectively.

Operating Expenses Changes from the prior year in the components of the Company's operating expenses are listed below:

Increase or (Decrease) from Prior Year 1997 1996 Amount Amount (In Thousands)

Operating Expenses:

Fuel and purchased electricity...... $ 7,584 7 $ 1,134 I Purchased natural gas ................... 10,878 22 (11,703) (19)

Other expenses of operation ........ (1,527) (2) 3,683 4 Maintenance ................ (1,364) (5) (502) (2)

Depreciation and amortization ..... 1,284 3 1,113 3 Taxes, other than income tax ....... (1,266) (2) (564) (I)

Federal income tax ....................... 3 510 11 3.660 13 Total $ 12,079 3 $ (3,179)

The most significant elements of operating expenses are fuel and purchased electricity in the Company's electric department nd purchased natural gas in the Company's gas department. Approximately 29% in 1997 and 27% in 1996 of every revenue dollar illed by the Company's electric department was expended for the combined cost of fuel used in electric generation and purchased electricity. The corresponding figures in the Company's gas department for the cost of purchased gas were 59% and 53%,

respectively.

33 Central Hudson Gas & Electric Corporation

In an effort to keep the cost of electricity at the lowest reasonable level, the Company purchases energy from sources such as other member companies of the NYPP, Canadian hydro sources and energy marketers whenever energy can be purchased at a unit cost lower than the incremental cost of generating the energy in the Company's plants.

Fuel and purchased electricity increased $ 7.6 million (7%) in 1997 primarily because of a 3% increase in total system sales which includes sales to other utilities.

Purchased natural gas increased $ 10.9 million (22%) in 1997 largely due to higher interruptible gas sales, including gas used as a boiler fuel at the Roseton Plant. In 1996, purchased natural gas decreased $ 11.7 million (19%) primarily because of lower interruptible gas sales for usage as a boiler fuel at the Roseton Plant.

Other expenses of operation increased $3.7 million (4%) in 1996 primarily due to increased employee wages and associated fringe benefits and increased uncollectible accounts.

See Note 4 - "Fcdcral Income Tax," herein for an analysis and reconciliation of the federal income tax.

Other Income And Interest Charges Other income (excluding AFDC) increased $ 4.6 million (71%) in 1997 and decreased $ 2.8 million (30%) in 1996. The 1997 increase was due primarily to interest refunded in 1997 from the settlement of various IRS audits and the 1996 charges associated with the optional redemption of the 8 3/4% Series of First Mortgage Bonds. The 1996 decrease was largely due to the non-recurring gain of $ 2.1 million realized in 1995 from the sale of long-term stock investments and the recording of one-time charges associated with the optional redemption of $ 30 million 8 3/4% Series of First Mortgage Bonds in May 1996.

Total interest charges (excluding AFDC) decreased $ 533,000 (2%) in 1997 and $ 1.7 million (6%) in 1996.

The following table sets forth some of the pertinent data on the Company's outstanding debt:

1997 1996 1995 (In Thousands)

Long-term debt:

Debt retired $ 85 $ 30,000 $ 2,562 Outstanding at year-end*:

Amount (including current portion) ........... 363,744 364,026 391,715 Effective rate 6.78% 6.70% 7.00%

Short-term debt:

Average daily amount outstanding ............. $ 1,692 $ 5,477 $ 103 Weighted average interest rate ................... 5.54% 5.59% 6.16%

<</n eluding debt ofsubsidiaries of $ 7.4 million in l997, $ 7.6 million in 1996 and $$.3 million in 1995.

See Note 5 - "Short-Term Borrowing Arrangements" and Note 7 - "Capitalization - Long-Term Debt" for additional information on short-term and long-term debt of the Company.

Nuclear Operations Thc Nine Mile 2 Plant is owned, as tenants-in-common, by the Company, Niagara Mohawk, New York State Electric lk Gas Corporation ("NYSEG"), LILCO and Rochester Gas and Electric Corporation ("Rochester" ). Niagara Mohawk operates the Nine Mile 2 Plant.

The Company owns a 9% interest of the Nine Mile 2 Plant, which is discussed in Note 3 - "Nine Mile 2 Plant." The operations of this Plant have continued to improve. The actual capacity factor of 88.7% for 1997 exceeded the targeted capacity factor of 84%

included in the Company's electric fuel adjustment clause. This resulted in a favorable impact on earnings.

The operating expenses, taxes and depreciation pertaining to the operation of thc Nine Mile 2 Plant are included in the Company's financial results. For both 1997 and 1996, the actual cost of operations was less than the allowable Nine Mile 2 Plant operation and maintenance expenses provided in Supplement No. 5 to the 1990 Settlement Agreement, as approved by the PSC. In both 1997 and 1996, the underruns were entirely deferred for the future benefit of customers (see Note 1 - "Regulatory Matters" ).

The Company has continued to participate actively in the management, operations and accounting committees for the Nine Mile 2 Plant and will do so in the future.

On October 12, 1996, Niagara Mohawk and Rochester announced plans to establish a joint nuclear operation company to be known as New York Nuclear Operating Company ("NYNOC"). NYNOC is envisioned to assume full responsibility for operation of all the nuclear plants in New York State, including the Nine Mile 2 Plant, Niagara Mohawk's Unit No. 1 of thc Nine Mile Point Nuclear Station and Rochester's Ginna Nuclear Plant. Since that time NYNOC has been organized as a New York limited liability company, and Con Edison and PASNY have announced their desire to move forward with the Niagara Mohawk and Rochester plans to implement NYNOC. It is expected that NYNOC could contribute to maintaining a high level of operational performance, contribute to continued satisfactory Nuclear Regulatory Commission ("NRC") regulatory compliance, provide opportunities for continued cost reductions and provide the basis for satisfactory economic regulation by the PSC. Various groups are now involved 34 Central Hudson Gas & Electric Corporation

in the detailed studies and analysis required before a definitive decision to proceed with NYNOC can be made. Sufficient information is not available for the Company to make an assessment of such plans or whether it would consent to such plans to the extent that the Nine Mile 2 Plant is affected. Until such assessmcnt can be made, the Company can take no position with respect to such plans.

The Nine Mile 2 Plant completed its fifth refueling outage November 2, 1996. It is scheduled to commence its sixth refueling outage in May 1998, with a targeted 37-day duration.

A decommissioning study for the Nine Mile 2 Plant was completed in 1995. The study's estimate of the cost to decommission the Nine Mile 2 Plant is significantly higher than previous estimates. The Company believes that decommissioning costs, if higher than currently estimated, will ultimately be recovered in rates, although no such assurance can be given. However, future developments in the utility industry, including the effects of deregulation and increasing competition could change this conclusion.

The Company cannot predict the outcome of these developments. For further information on decommissioning, see Note 3 - "Nine Mile 2 Plant."

In October 1996, Niagara Mohawk, as operating cotenant for the Nine Mile 2 Plant, along with other companies that operate nuclear plants, received a letter from the NRC, requiring it to provide the NRC with information on the "adequacy and availability" of design basis documentation on their nuclear plants within 120 days. Such information will be used by the NRC to verify that companies are in compliance with the terms and conditions of their license(s) and NRC regulations. In addition, it will allow the NRC to determine if other inspection activities or enforcement actions should be taken on a particular company.

The Company believes that the NRC is becoming more stringent as indicated by this letter and that there may be direct cost impact on companies with nuclear plants as a result. The NRC issued a policy statement on the Restructuring and Economic Deregulation of the Electric UtilityIndustry ("Policy Statement") in 1997. The Policy Statement addresses NRC's concerns about the adequacy of decommissioning funds and about the potential impact on operational safety. Current NRC regulations allow a utility to set aside decommissioning funds annually over the estimated life of a plant. In addition to the above Policy Statement, the NRC is proposing to amend its regulations on decommissioning funding to reflect conditions expected from dcrcgulation of the electric power industry. The Company is unable to predict how such increased stringency may affect thc results of operations or financial condition of the Nine Mile 2 Plant.

On August 27, 1997, the PSC Staff issued a "Notice Soliciting Comments on Nuclear Generation" requesting comments and alternative approaches by interested parties on a "Staff Report on Nuclear Generation" ("Nuclear Report" ). The Nuclear Report concludes that nuclear generation, along with non-nuclear generation facilities, should be subject to the discipline of market-based pricing. According to the PSC Staff, the optimal, least cost method for "regulating" generating units is to free them to operate in

~

the wholesale competitive markets where running costs must be recovered in the wholesale market price of power. The Company submitted comments, pointing out the shortcomings in the Nuclear Report, which comments included adopting a process to fully

~

develop the necessary facts and analyses. The NYNOC organizing utilities submitted comments noting that the PSC Staff proposal would nullify the potential benefits of NYNOC. The PSC Staff has yet to respond to the comments and reply comments of the numerous parties. The Company can make no prediction as to the outcome of the Nuclear Report proposal.

On December 30, 1997, the NRC issued its latest systematic assessment of licensee performance ("SALP") review of the Nine Mile Point Nuclear Station for the period June 2, 1996 to Novcmbcr 8, 1997 ("1996/97 SALP Report" ). The Nine Mile Point Nuclear Station is comprised of both Units No. 1 and No. 2. Unit No. 1, located adjacent to the Nine Mile 2 Plant, is owned and operated solely by Niagara Mohawk. The 1996/97 SALP Report, conducted under the revised SALP process that was implemented by the NRC on July 19, 1993, rates licensee performance in four functional areas; operations, maintcnancc, engineering and plant support.

Overall, the NRC indicated that the performance at the Nine Mile Point Nuclear Station was generally good; however, continued management attention was needed to address issues in several areas. The ratings were as follows: (i) operations was rated Category 2 ("good"), which was lower than the Category 1 ("superior") rating on the prior SALP Report (covering the period January 1995 through June 1, 1996); (ii) maintenance was rated Category 2 ("good"), which was thc same rating as on the 1995/

1996 SALP Report; (iii) engineering was rated Category 3 ("acceptable" ), which was lower than the Category 2 in said prior SALP Report; and (iv) plant support was rated Category 2 ("good"), remaining the same as the prior SALP Report.

Other Iviatters Storm Costs: On April 1, 1997, a snow and wind storm disrupted service to approximately 100,000 customers in the Company's scrvicc territory. The restoration costs of the storm totaled approximately $ 8.9 million which, after applying mitigating credits, amounted to $5.3 million as reflected in "Deferred Charges-Other" in the Consolidated Balance Shcct. The Company believes these costs are recoverable in rates and has therefore requested the PSC to authorize deferral of these costs. The Amended Settlement Agreement authorizes the deferral of these costs.

Federal Income Tax Refund: In the second quarter of 1997 the Company received a $ 1.9 million net refund as a result of audits by the IRS of the Company's federal income tax returns for the years 1987-1991. The Company has complied with the PSC notification rcquircmcnts for tax refunds and recorded the refund in the fourth quarter of 1997.

35 Central Hudson Gas & Electric Corporation

Year 2000: The Company is addressing potential adverse impacts from potential Year 2000 computer software failures to ensure the availability and integrity of its financial systems and the reliability of its operational systems. The Company has established processes for evaluating and managing the risks and costs associated with this problem. The Company has, and will continue to make, certain investments in its software systems and applications to ensure the Company is Year 2000 compliant. The financial impact to the Company has not been determined but is not anticipated to be material.

Electric Sales to IBM: The Company's largest customer is International Business Machines Corporation ("IBM"), which accounted for approximately 9% and 10% of the Company's total electric revenues for the years ended December 31, 1997 and 1996, respectively.

IBM announced that it will be investing $700 million at its East Fishkill, New York facility to construct one of the world' most sophisticated microchip manufacturing plants. This facility, slated to open in 1999 with 400 employees, will embrace new technology in developing 12" diameter silicon wafers. This expansion could have a favorable impact on the Company's revenue base and customers.

New Accounting Standards: In June 1997, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards No. 131 "Disclosures about Segments of an Enterprise and Related Information" ("SFAS 131").

This Statement establishes standards for reporting information about operating segments in annual and interim financial statements.

The Company does not expect that the adoption of SFAS 131 will have a significant impact on the reporting requirements of the Company. For a discussion of proposed and new accounting standards from the FASB, see Note 2- "Summary of Significant Accounting Policies," herein.

In February 1996, the FASB issued an exposure draft entitled "Accounting for Certain Liabilities Related to Closure and Removal of Long-Lived Assets," which includes nuclear plant decommissioning. If the accounting standard proposed in such exposure draft were adopted, it could result in higher annual provisions for removal or decommissioning to be recognized earlier in the operating life of nuclear and other generating units and an accelerated recognition of the decommissioning obligation. The FASB is deliberating this issue and the resulting final pronouncement could be different from that proposed in the exposure draft.

The Company can make no prediction at this time as to the ultimate form of such proposed accounting standard, assuming it is adopted, nor can it make any prediction as to its ultimate effect(s) on the financial condition of'he Company.

Other Issues: On an ongoing basis, the Company assesses environmental issues which could impact the Company and its customers. Note 3 - "Nine Mile 2 Plant" and Note 9 - "Commitments and Contingencies" discuss current environmental issues affecting the Company, including (i) the 1995 decommissioning cost study of the Nine Mile 2 Plant, (ii) the Clean Water Act and Clean Air Act Amendments of 1990, which require control of emissions from fossil-fueled electric generating units, (iii) asbestos litigation cases, and (iv) a legal action filed in 1995 against the Company by the City of Newburgh, Ncw York.

36 Central Hudson Gas & Electric Corporation

FINANCIALINDICES Selected financial indices for the last five years are set forth in the following table:

1997 1996 1995 1994 1993 Pretax coverage of total interest charges:

Including AFDC 3.94x 4.08x 3.68x 3.38x 3.29x Excluding AFDC 3.69x 3.83x 3.43x 3.15x 3.15x Funds from Operations . 5.18x 5.29x 4.69x 4.24x 4.27x Pretax coverage of total interest charges and preferred stock dividends ............... 3.37x 3.47x 2.97x 2.74x 2.65x Percent of construction expenditures financed from internal funds ........... 100% 100% 100% 100% 100%

AFDC and Mirror CWIP* as a percentage of income available for common stock ..... 13% 13% 16% 16% 11%

Effective tax rate. 32% 36% 35% 35% 35%

• Refer to /Vote I - "Regulatory hfaners" under subcaptions "Summary of Regulatory Assets and Liabilities" and "Deferred Finance Charges - ¹ne hfile 2 Plant" for a definition ofMirror C)VIP.

CONNON STOCK DIYIDENDSANDPRICE RANGES The Company and its principal predecessors have paid dividends on its common stock in each year commencing in 1903, and the common stock of the Company has been listed on the New York Stock Exchange since 1945. The price ranges and the dividends paid for each quarterly period during the Company's last two fiscal years are as follows:

1997 1996 Hi h Low Dividend Hi h Low Dividend 1st Quarter ...... $ 33 3/8 $ 30 1/2 $ .53 $ 31 I/2 $ 28 3/4 $ .525 2nd Quarter .... 34 3/4 29 3/4 .53 31 I/4 28 7/8 .525 3rd Quarter ..... 35 7/8 32 1/8 .535 31 I/4 29 I/2 .53 4th Quarter ..... 43 7/8 34 11/16 .535 31 I/2 29 .53 On June 27, 1997, the Company increased its quarterly dividend rate to $ .535 per share from $ .53 in 1996. On June 28, 1996, the Company increased its quarterly dividend rate to $ .53 per share from $ .525 per share.

Any determination with regard to future dividend declarations, and the amounts and dates of such dividends, will depend on the circumstances at the time of consideration of such declaration. One such consideration will be the effect on thc Company of the corporate restructuring described in this Item 7 under the caption "Competition/Deregulation."

Thc number of registered holders of common stock as of December 31, 1997 was 22,605. Of these, 21,933 were accounts in the names of individuals with total holdings of 5,544,827 shares, or an average of 253 shares per account. The 672 other accounts, in the names of institutional or other non-individual holders, for the most part, hold shares of common stock for the benefit of individuals.

37 Central Hudson Gas & Electric Corporation

ITEN 7A Quantitative and Qualitative Disclosure About Narket Risk Not Applicable ITEN 8 Financial StatementsAnd Supplementary Data Page I - Index to Financial Statements:

Report of Independent Accountants 39 Statement of Management's Responsibility 39 Consolidated Balance Sheet at December 31, 1997 and 1996 40 Consolidated Statement of Income for the three years ended December 31, 1997 42 Consolidated Statement of Retained Earnings for the three years ended December 31, 1997 42 Consolidated Statement of Cash Flows for the three years ended December 31, 1997 43 Notes to Consolidated Financial Statements 44 Selected Quarterly Financial Data (Unaudited) 60 II - Schedule II - Reserves All other schedules are omitted because they are not applicable or the required information is shown in the Consolidated Financial Statements or the Notes thereto. 61 Supplementary Data Supplementary data that is included in "Selected Quarterly Financial Data (Unaudited)" appears under this Item and reference is made thereto.

38 Central Hudson Gas Sc Electric Corporation

REPORT OF INDEPENDENT ACCOUNTANTS Ql Price Waterhoase LLp To the Board of Directors and Shareholders of Central Hudson Gas & Electric Corporation In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Central Hudson Gas & Electric Corporation and its subsidiaries at December 31, 1997 and 1996, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1997, in conformity with generally accepted accounting principles. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these financial statements in accordance with generally accepted auditing standards which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a rcasonablc basis for thc opinion expressed above.

/~ 43JU ~ t-t.W New York, New York January 23, 1998, except as to Note 1 of the consolidated financial statements which is as of February 4, 1998 STATENENT OF NANAGENENT'S RESPONSIBILITY Management is responsible for the preparation, mtegnty and obJectivity of the consolidated financial statements of Central Hudson Gas & Electric Corporation and its subsidiaries (collectiveiy, the Company) as well as all other information contained in this Form 10-K. The consolidated financial statements have been prepared in conformity with generally accepted accounting principles and, in some cases, reflect amounts based on the best estimates and judgements of the Company's Management, giving due consider-ation to materiality.

The Company maintains adequate systems of internal control to provide reasonable assurance, that, among other things, transac-tions are executed in accordance with Management's authorization, that the consolidated financial statements are prepared in accor-dance with generally accepted accounting principles and that the assets of the Company are properly safeguarded. The systems of in-ternal control are documented, evaluated and tested by the Company's internal auditors on a continuing basis. Due to thc inherent limitations of the cffcctiveness of internal controls, no internal control system can provide absolute assurance that errors will not oc-cur. Management believes that the Company has maintained an effective system of internal control over thc preparation of its flinan-cial information including the consolidated financial statements of the Company as of December 31, 1997.

Independent accountants were cngagcd to audit the consolidated financial statements of the Company and issue their report thereon. The Report of Indepcndcnt Accountants, which is presented above, does not limit the responsibility of Management for in-formation contained in the consolidated financial statements and elsewhere in this Form 10-K.

The Company's Board of Directors maintains a Committee on Audit which is composed of Directors who arc not employees of the Company. The Committee on Audit meets with Management, its Internal Auditing Manager, and its indcpcndent accountants several times a year to discuss internal controls and accounting matters, the Company's consolidated financial statements, the scope and results of the audits pcrformcd by the independent accountants and the Company's Internal Auditing Department. The indepen-dent accountants and the Company's Internal Auditing Manager have direct access to the Committee on Audit.

JOHN E. MACK, III DONNA S. DOYLE Chairman of the Board and Controller Chief Executive Officer January 23, 1998 39 Central Hudson Gas & Electric Corporation

Consolidated Balance Sheet At December 31, (In Thousands) 1997 1996 ASSETS UtilityPlant Electric $ 1,193,735 $ 1,171,798 Gas.. 151,222 145,375 Common. 91,522 87,591 Nuclear fuel. 37,262 36,913 1,473,741 1,441,677 Less: Accumulated depreciation. 560,304 520,999 Nuclear fuel amortization. 33,059 29,748 880,378 890,930 Construction work in progress 52,413 48,699 Nct UtilityPlant 932,791 939,629 Investments and Other Assets Prefundcd pension costs 23,536 10,672 Other. 14,958 12,419 Total Investmcnts and Other Assets 38,494 23,091 Current Assets Cash and cash equivalents. 9,054 4,235 Accounts rcccivable from customers - net of allowance for doubtful accounts; $ 2.8 million in 1997 and $ 3.2 million in 1996 ... 49,643 48,080 Accrued unbilled utility revenues . 16,229 16,042 Other receivables ... 2,073 2,896 Materials and supplies, at average cost:

Fuel. 11,920 14,935 Construction and operating . 12,180 13,160 Special deposits and prepayments. 14,210 13,440 Total Current Assets . 115,309 112,788 Deferred Clmrgcs Regulatory assets (Note 1) 139,236 151,426 Unamortized debt expense 5,002 5,393 21,258 16,779 Total Deferred Charges 165,496 173,598 TOTAL ASSETS $ 1@52,090 $ 1,249,106 The Notes to Consolidated Finanual Statements are an integral part hereof.

40 Central Hudson Gas & Electric Corporation

(In Thousands) 1997 1996 CAPITALIZATIONAND LIABILITIES Capitalization Common Stock Equity Common stock, $ 5 par value (Note 6) . $ 87,775 $ 87,775 Paid-in capital (Note 6) 284,465 284,465 Retained earnings. 1201540 105,821 Reacquired capital stock (Note 6) (9,398)

Capital stock expense (6,278) (6,352)

Total Common Stock Equity 477,104 471,709 Cumulative Prcfcrred Stock (Note 6)

Not subject to mandatory redemption 21)030 21,030 Subject to mandatory redemption 35,000 35,000 Total Cumulative Preferred Stock 56,030 56,030 Long-term Debt (Note 7) .. 361)829, 362,040 Total Capitalization. 894,963 889,779 Current Liabilities Current maturities of long-term debt 1,317 1,362 Notes payable 15,600 Accounts payable .. 24@68 26,137 Dividends payable. 10,052 10,112 Accrued taxes and interest. 3,240 5,347 Accrued vacation 4,339 4,251 Customer deposits. 4,001 4,019 Other 6,545 6,676 Total Current Liabilities .. 53,862 73,504 Deferred Credits and Other Liabilities Regulatory liabilities (Note I) 81,271 74,587 Operating reserves 6,582 4,755 Other 10 019 9 155 Total Deferred Credits and Other Liabilities. 97,872 88,497 Deferred Income Tax (Note 4) 205,393 197,326 Commitments and Contingencies (Notes I, 3 and 9) .

TOTAL CAPITALIZATIONAND LIABILITIES $ 1,252,090 $ 1,249,106 The Notes to Consolidated Financial Statements are an integral part hereof.

4I Central Hudson Gas & Electric Corporation

Consolidated Statement of Income Year Ended December 31, (In Thousands) 1997 1996 1995 Operating Revenues Electric $ 416,429 $ 418,761 $ 409,445 Gas 103 848 95 210 102 770 Total Operating Rcvcnucs. 520,277 513,971 512,215 Operating Expenses Operation:

Fuel used in electric generation . 66,117 58,874 60,940 Purchased electricity 55,864 55,523 52,323 Purchased natural gas 61,514 50,636 62,339 Other expenses of operation. 101,219 102,746 99,063 Maintenance 27,574 28,938 29,440 Depreciation and amortization (Note 2) 43,864 42,580 41,467 Taxes, other than income tax 64,879 66,145 66,709 Federal income tax (Note 4). 29 190 32 700 29 040 Total Operating Expcnscs 450 221 438,142 441,321 Operating Income 70 056 75 829 70 894 Other Income...

Allowance for equity funds used during construction (Note 2) .... 387 466 986 Federal income tax (Note 4) . 2,953 1,632 353 Other - net. 8 079 4 815 8 886 Total Other Income. 11,419 6,913 10,225 Income before Interest Charges. 81 475 82,742 81,119 Interest Clmrgcs Interest on long-term debt 23,097 23,617 25,925 Other interest 2,647 2,626 1,917 Allowance for borrowed funds used during construction (Note 2) ... (261) (523) (514)

Amortization of expense on debt Total Interest Charges ........................................................... 26 660 28 397 Net Income 55,086 56,082 52,722 Premium on Prcfcrrcd Stock Redemptions - Net. 378 169 Dividends Declared on Cumulative Preferred Stock 3 230 3 230 4 903 Income Available for Common Stock $ 51,856 S 52,474 S 47,650 Common Stock:

Average shares outstanding (000s) . 17,435 17,549 17,380 Earnings per share on average shares outstanding . $ 2.97 $ 2.99 $ 2.74 Consolidated Statement of Retained Earnings Year Ended December 31, (In Thousands) 1997 1996 1995 Balance at beginning of year $ 105,821 S 90,475 S 79,284 Nct Income . 55,086 56,082 52,722 Premium on Preferred Stock Redemption - Net 378 169 Dividends declared:

On cumulative preferred stock 3,230 3,230 4,903 On common stock ($ 2.135 per sharc 1997; $ 2.115 per share 1996;

$ 2.095 per sltare 1995) 37 137 37 128 36 459 Total Dividends Dcclarcd 40,367 40,358 41,362 Balance at end of year. $ 120,540 $ 105,821 $ 90,475 The Notes to Consolidated Financial Statements are an integral part hereof.

42 Central Hudson Gas & Electric Corporation

Consolidated Statement of Cash Flows Year Ended December 31, (In Thousands) 1997 1996 1995 Operating Activities Net Income $ 55,086 $ 56,082 $ 52,722 Adjustments to reconcile net income to net cash provided by operating activities:

Depreciation and amortization including nuclear fuel amortization. 48,348 47,073 45,388 Deferred income taxes, net. 14,077 17,848 14,146 Allowance for equity funds used during construction . (387) (466) (986)

Nine Mile 2 Plant deferred finance charges, net (4)855) (4,855) (4,855)

Provisions for uncollectibles ........ 3,493 4,336 3,220, Accrued pension costs (8,555) (6,757) (10,627)

Gain on sale of long-term investment. (2,104)

Deferred gas costs 3,475 (4,861) 5,302 Deferred gas refunds. 1,695 (1,556) (1,784)

Other - net 7/233 4,039 11,466 Changes in current assets and liabilities, net:

Accounts receivable and unbilled utility revenues . (4,420) (6,338) (3,300)

Materials and supplies ................................................ 3)995 (505) 5,799 Special deposits and prepayments (770) (781) (567)

Accounts payable (1,769) 1,704 (5,008)

Accrued taxes and interest (27107) (2,477) 995 Other current liabilities 61 602 944 Nct cash provided by operating activities. 114,478 103,088 110,751 Investing Activities Additions to plant . (43,868) (49,860) (50,269)

Allowance for equity funds used during construction 387 466 986 Net additions to plant (43,481) (49,394) (49,283)

Nine Mile 2 Plant decommissioning trust fund. (2,861) (1,734) (1,895)

Proceeds from sale of long-term investments . 2,879 Other - net. 2,389 200 (1,161)

Nct cash used in investing activities. (43,953) (50,928) (49,460)

I<'inancing Activities Proceeds from issuance of:

Long-term debt 2,000 3,090 1,000 Common stock. 1,817 7,064 Net borrowings (repayments) of short-term debt. (15,600) 15,600 (3,000)

Retirement and redemption of long-term debt (2,282) (30,779) (3,139)

Retirement and redemption of cumulative preferred stock . (13,000) (12,000)

Premium on preferred stock redemption . (378) (146)

Dividends paid on cumulative preferred and common stock (40,426) (40,489) (41,364)

Issuance and redemption costs. 736 (20)

Reacquired capital stock (9,398)

Nct cash used in financing activities. (65,706) (63,403) (51,605)

Net Change in Cash and Cash Equivalents. 4,819 (11,243) 9,686 Cash and Cash Equivalents at Beginning of Year . 4,235 15,478 5,792 Cash and Cash Equivalents at End of Year $ 9,054 $ 4,235 $ 15,478 Supplemental Disclosure of Cash Flow Information Interest paid $ 24,309 $ 25,184 $ 26,738 Federal income taxes paid .. 17,111 15,875 14,100 The Notes to Consolidated Financial Statements are an integral part hereof.

43 Central Hudson Gas & Electric Corporation

NOTES TO CONSOLIDATED FINANCIALSTATEN ENTS NOTE I - REGULATORY MATTERS Competitive Opportunities Proceeding In 1994, the Public Service Commission of the State of New York ("PSC") instituted the "Competitive Opportunities Proceeding," the overall objective of which is to identify regulatory and rate-making practices that will assist in the transition to a more competitive electric industry. On May 20, 1996, the PSC issued its Order ("Order" ) in this proceeding setting forth the PSC's vision and goals for the future of the electric industry in New York State. The Order called for implementation of a competitive wholesale power market, reducing rates for consumers, increasing customer choice, continuing reliability of service, continuing programs that are in the public interest, allaying concerns about market power, continuing customer protections and the obligation to serve.

The Order required the Company and certain other utilities to file a rate and restructuring plan with the PSC by October I, 1996. The Company was obligated to comply (and did so on October 1, 1996) with the provision of the Order.

On October 9, 1996, the PSC issued an order establishing procedures for a completion of discovery and settlement negotiations regarding the utilities'ctober 1, 1996 submissions, and, in the absence of settlement, for administrative litigation before a PSC Administrative Law Judge.

Amended Settlement Agreement On March 20, 1997, after months of negotiations, the Company entered into a Settlement Agreement with the Staff of the PSC

("Staff', the New York State Department of Economic Development and other parties ("Settlement Agreement" ) which addressed the Commission's Order by providing a (i) four-year basic electric rate freeze for all customers; (ii) economic development inducements to create and maintain jobs in the Mid-Hudson Valley; (iii) a reduction in prices for the largest industrial customers; (iv) a phased-in program to provide all customers with the opportunity to choose their energy supplier beginning in 1998; (v) a mechanism for the Company to recover all prudently incurred strandable costs and (vi) a proposal to structurally separate its generation assets by July 1, 2001 through thc creation of a holding company, divestiture or other option.

At its September 17, 1997 session, the PSC discussed the Settlement Agreement and indicated that further negotiations were needed on certain open issues related to the auctioning of the Company's fossil-fuel electric generating units, the provision of certain types of meters and environmental program funding.

On January 2, 1998, the Company concluded further negotiations with Staff and others resulting in an Amended Settlement Agreement between the Company, the PSC Staff, and several other interested parties ("Amended Settlement Agreement" ). The PSC approved the Amended Settlement Agreement at its February 4, 1998 session; however the PSC had not yet issued its final order at the time this document was filed with the Sccuritics and Exchange Commission. Among the most significant developments in the Amended Settlement Agreement is an agreement that the Company will auction its fossil-fueled electric generating units fi.e., the Company's interest in the Roseton Electric Generating Station ("Roseton Plant" ) and the Company's Danskammer Point Steam Electric Generating Station, ("Danskammer Plant")], with the sale and transfer to be completed by June 30, 2001. At December 31, 1997 the book value of those units represented approximately 20% of net utility plant. The Company has maintained the right to bid in the auction. The auction will also provide customer benefits if the auction results in the sale of assets in excess of their book value. The Amended Settlement Agreement does not contemplate the divestiture or transfer of the Company's share of Unit No. 2 of the Nine Mile Point Nuclear Station ("Nine Mile 2 Plant" ). As part of the Amended Settlement Agreement, the Company will have a reasonable opportunity to recover prudently incurred and appropriately mitigated investments.

The Company's potential strandable costs are those prior utility investments and commitments that may not be recoverable in a competitive energy market. Examples include any unrecovered cost of the Company's fossil-fueled generating plants (resulting from the auction process) and net generation related regulatory assets. During the transition, the Company will continue to recover its potential electric strandable costs in the rates it charges its transmission and distribution customers. Following the transition, the Company will be given a reasonable opportunity to recover, through a non-bypassable charge to customers, remaining electric strandable costs.

Other key components of the Amended Settlement Agreement include (i) a basic electric rate freeze through June 2001; (ii) phase-in of retail access through June 30, 2001 to residential, commercial and small industrial customers; (iii) a 10.6% return on equity cap with excess earnings deferred for stranded cost mitigation; (iv) provision to participate in a statewide program to support public policy initiatives such as energy efficiency and renewable sources for electricity production; (v) the creation of a mechanism for implementing retail transmission tariffs that will be limited to customers eligible during the transition period and (vi) a determination that customers participating in the Company's "Customer Choice Plan for Farmers and Food Processing Businesses" will do so under terms of the Amended Settlement Agreement.

The Amended Settlement Agreement also addresses options regarding a new corporate structure for the Company. On or before June 30, 2001, the Company, subject to shareholder and regulatory approvals, will establish a holding company. The holding company will include a regulated transmission and distribution company that will maintain the system of wires and pipelines which deliver electricity and natural gas to customers. The holding company will also include unregulated companies which will provide a, variety of new services to customers within and outside the Mid-Hudson Valley region and, possibly, fossil-fueled generating units retained or acquired.

44 Central Hudson Gas & Electric Corporation

Impact of Amended Settlement Agreement on Accounting Policies Thc Amended Settlement Agreement creates certain changes to the Company's accounting policies. The Company's accounting policies conform to generally accepted accounting principles, which, for regulated public utilities, include Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain Types of Regulation" ("SFAS 71"). Under SFAS 71, regulated companies defer costs and credits on the balance sheet as regulatory assets and liabilities when it is probable that those costs and credits will be allowed in the rate-making process in a period different from when they otherwise would have been rcflected in income. These deferred regulatory assets and liabilities are then reflected in the income statement in thc period in which thc same amounts are refiectcd in rates. Ifsome of an enterprise's operations are regulated and meet the appropriate criteria, SFAS 71 is applied only to thc regulated portion of the enterprise's operations.

As discussed above, the goal of the Amended Settlement Agreement is to deregulate and, ultimately, divest the Company's fossil-fueled generating assets. During 1997, the Financial Accounting Standards Board ("FASB") Emerging Issues Task Force concluded that an entity should discontinue application of SFAS 71 to any portion of its business when a deregulation transition plan is in place and the terms are known. The Amended Settlement Agreement was approved by the PSC on February 4, 1998, and on that date the Company applied the standards in Statement of Financial Accounting Standards No. 101, "Regulated Enterprises-Accounting for the Discontinuation of Application of FASH Statement No. 71" ("SFAS 101") to the fossil-fueled generating portion of its business. Therefore, the Company discontinued application of SFAS 71 to its fossil-fueled generation assets as of the date of such approval. The application of SFAS 101 to the fossil-fueled generating portion of the Company's business will not have a material adverse cffcct on thc Company's financial position or results of operations as of the date of such approval.

Statement of Financial Accounting Standards No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to bc Disposed Of," ("SFAS 121") requires that long-lived assets be reviewed for impairment if thc carrying value of thc asset may not bc recoverable. SFAS 121 also requires that long-lived assets to be disposed of be carried at the lower of net book value or fair value, and amends SFAS 71 to require that regulatory assets be charged against earnings ifrecovery of such assets is no longer considered probable. The Company will not recognize an impairment of its fossil-fueled generating assets because thc estimated cash flows from operations, the sale of such generating assets, and stranded cost recovery provisions of the Amended Settlement Agreement are not expected to be less than the net carrying amount of such generating assets.

Certain regulatory assets and liabilities have been created as a result of transactions relating to the Company's fossil-fueled generating assets. At December 31, 1997, net regulatory assets associated with the fossil-fueled generating assets totaled $ 7.6 million. Thc Company did not expense any of these net regulatory assets because recovery of such assets is considered probable under the Amended Settlement Agreement.

Summary of Regulatory Assets and Liabilities

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The following table sets forth the Company's regulatory assets and liabilities:

~

At December 31 1997 1996 Regulatory Assets (Debits): (In Thousands)

Defcrrcd finance charges - Nine Mile 2 Plant .... $ 68,470 S 69,615 Income taxes recoverable through future rates ... 49/20 55,791 Deferred energy efficiency costs ......................... 5,168 8,894 Other. 16378 17 126 Total Regulatory Assets $ 139/36 $ 151,426 Regulatory Liabilities (Credits):

Deferred finance charges - Nine Mile 2 Plant ... S 16%431 S 22,431 Income taxes refundable 28/16 29,077 Deferred Nine Mile 2 Plant costs ....................... 11/96 6/22 Deferred pension costs overcollection ............... 8@06 3997 Deferred OPEB costs overcollection ................. 6/24 4,778 Deferred unbilled gas revenues ........... 4/55 4357 Other. 5 643 3 625 Total Regulatory Liabilities . $ 81771 $ 74/87 Net Regulatory Assets. $ 57@65 $ 76,839 Some of the significant regulatory assets and liabilities include:

Deferred Finance Charges - Nine Mile 2 Plant: During the construction of the Nine Mile 2 Plant, the PSC authorized the nclusion in rate base of increasing amounts of the Company's investment in that Plant. The Company did not accrue an allowance for thc cost of funds used during construction ("AFDC") on any of thc Nine Mile 2 Plant construction work in progress ("CWIP") which was included in rate base and for which a cash return was being allowed; howcvcr, thc PSC ordered, effective January 1, 1983, 45 Central Hudson Gas & Electric Corporation

that amounts be accumulated in deferred debit and credit accounts equal to the amount of AFDC which was not being accrued on the CWIP included in rate base ("Mirror CWIP"). The balance in the-deferred credit account is available to reduce future revenue requirements by amortizing portions of the deferred credit to other income or by the elimination through writing off other deferred balances as directed by the PSC. The Company expects such application of the deferred credit will occur over a period substantially shorter than the life of the Nine Mile 2 Plant. When amounts of such deferred credit are applied in order to reduce revenue requirements, amortization is started for a corresponding amount of the deferred debit, which amortization continues on a level basis over the remaining life of the Nine Mile 2 Plant resulting in recovery of such corresponding amount through rates. Mirror CWIP is expected to be exhausted by the cnd of the useful life of the Nine Mile 2 Plant either through the amortization or write-off proccdurcs described above or through the write-off of the remaining debit and credit as directed by the PSC. The net effect of this procedure is that at the end of the amortization period for the deferred credit, the accounting and rate-making treatment will be the same as if the Nine Mile 2 Plant CWIP had not been included in rate base during the construction period.

Pursuant to a PSC Order issued and effective February 11, 1994, in an electric rate proceeding, the Company was authorized to amortize $ 6.0 million annually of the deferred credit beginning in December 1993.

The $ 6.0 million amortization of the deferred credit will be continued unless changed by a future PSC rate order or until it is exhausted. Under provisions of the Amended Settlement Agreement, this amortization will be replaced with other deferred credits to the extent necessary to provide for full replacement of the expiring mirror CWIP credits. The current level of the deferred debit amortization of $ 1.145 million is based on the level of deferred credits that have been utilized through the most recent rate year, which has ended. Credit amounts utilized subsequently are included in the deferred debit amortization level at the time of the next PSC rate order for the new rate year based on the then remaining life of the Nine Mile 2 Plant.

Income Taxes RccovcrabldRcfundablc: The adoption of Statement of Financial Accounting Standards 109, "Accounting for Income Taxes," ("SFAS 109") in 1993 increased the Company's net deferred tax obligation. As it is probable that the increase will be recovered from customers, the Company established a net regulatory asset.

Dcfcrrcd Nine Mile 2 Plant Costs: The existing rate-making for the Nine Mile 2 Plant, as directed by the PSC in its Order on Nine Mile 2 Operating and Capital Forecast for 1996 ("Supplement No. 5"), provides for the deferral of the difference between actual and authorized operating and maintenance expense. Supplement No. 5 continues in effect until changed by a subsequent rate order. For 1996 and 1997 the Nine Mile 2 Plant incurred less actual expense than authorized, and the Company's share has been rccordcd as a regulatory liability in accordance with Supplement No. 5.

Independent System Operator Thc Company is a member of the New York Power Pool ("NYPP") whose members, major investor-owned State electric utility companies and the Power Authority of the State of New York ("PASNY"), by agreement, provide for coordinated operation of their bulk power electric systems. In a filing with the Federal Energy Regulatory Commission ("FERC"), dated January 31, 1997, the member systems of the NYPP proposed a new market structure that would include as a key element the establishment of an Independent System Operator ("ISO"). The ISO's principal mission would be to maintain the reliability of the New York State bulk power systems and to provide transmission service on a comparable and non-discriminatory basis. The NYPP filed a supplemental filing with FERC in December 1997, which expanded the restructuring filing of January 31, 1997. The Company is unable to predict the outcome of these FERC filings.

NOTE 2 - SUNIvIARYOF SIGNIFICANT ACCOUNTING POLICIES Principles of Consolidation Thc consolidated financial statements include the accounts of the Company and its subsidiaries. Intercompany balances and transactions have been eliminated.

The Company's subsidiaries are each wholly owned and are comprised of landholding, cogeneration or energy'anagement companies. The net income of the Company's subsidiaries is reflected in the Consolidated Statement of Income as other non-operating income.

Rates, Revenues and Cost Adjustment Clauses Electric and gas retail rates, including fuel and gas cost adjustment clauses, applicable to intrastate service (other than contractually established rates for service to municipalities and governmental bodies) are regulated by the PSC. Transmission rates, facilities charges and rates for electricity sold for resale in interstate commerce are regulated by the FERC.

Revenues are rccognizcd on the basis of cycle billings rendered monthly or bimonthly. Estimated revenues are accrued for those customers billed bimonthly whose meters are not read in the current month.

The Company's tariff for retail electric service includes a fuel cost adjustment clause pursuant to which electric rates are adjusted to reflect changes in the average cost of fuels used for electric generation and in certain purchased power costs, from the average of such costs included in base rates. The Company's tariff for gas service contains a comparable clause to adjust gas rates for changes in thc price of purchased natural gas and certain costs of manufactured gas.

46 Central Hudson Gas & Electric Corporation

Utility Plant

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The costs of additions to utility plant and replacements of retired units of property are capitalized at original cost. The Company's share of the costs of the Nine Mile 2 Plant are capitalized at original cost, less the disallowed investment of $ 169.3 million which was recorded in 1987. Costs include labor, materials and supplies, indirect charges for such items as transportation,

~

certain taxes, pension and other employee benefits and AFDC. Replacement of minor items of property is included in maintenance expenses.

The original cost of property, together with removal cost, less salvage, is charged to accumulated depreciation at such time as the property is retired and removed from service.

Jointly Owned Facilities The Company has a 9%, or 103 MW, undivided interest in the 1,143 MW Nine Mile 2 Plant (see Note 3, hereof) and a 35%, or 420 MW, undivided interest in the 1,200 MW Roseton Plant.

The Company's share of the respective investments in the Nine Mile 2 Plant and the Roseton Plant, as included in its Consolidated Balance Sheet at December 31, 1997 and 1996, were:

(In Thousands)

Nine Mile 2 Plant Plant in service $ 316,123 $ 314,270 Accumulated depreciation .......... (70,202) (61,708)

Construction work in progress .... 1,032 1,894 Roseton Plant Plant in service $ 134,555 $ 135,026 Accumulated depreciation .......... (77,438) (74,963)

Construction work in progress .... 571 745 Allowance For Funds Used During Construction The Company includes in plant costs AFDC approximately equivalent to the cost of funds used to finance construction expenditures. The concurrent credit for the amount so capitalized is reported in the Consolidated Statement of Income as follows:

the portion applicable to borrowed funds is reported as a reduction of interest charges while the portion applicable to other funds (the equity component, a noncash item) is reported as other income. The AFDC rate was 8.0% in 1997, 7.5% in 1996 and 8.5% in 1995.

Depreciation and Amortization For financial statement purposes, thc Company's depreciation provisions are computed on the straight-line method using rates based on studies of the estimated useful lives and estimated net salvage value of properties, with the exception of the Nine Mile 2 Plant which is depreciated on a remaining life amortization method. The year 2026, which is the year in which the Nine Mile 2 Plant operating license expires, is used as the end date in the development of the remaining life amortization. Thc Company performs depreciation studies on a continuing basis and, upon approval by the PSC, periodically adjusts the rates of its various classes of depreciable property. The most recent study was performed in 1993.

The Company's composite rates for depreciation were 3.16% in 1997, 3.13% in 1996 and 3.14% in 1995 of the original cost of average depreciable property. The ratio of the amount of accumulated depreciation to the cost of depreciable property at December 31 was 38.2% in 1997, 36.5% in 1996 and 35.3% in 1995.

For fcdcral income tax purposes, the Company uses an accclcratcd method of depreciation and generally uses the shortest life permitted for each class of assets.

Amortization of Nuclear Fuel The cost of the Nine Mile 2 Plant nuclear fuel assemblies and components is amortized to operating expense based on thc quantity of heat produced for the generation of electric energy. Niagara Mohawk Power Corporation ("Niagara Mohawk"), on behalf of the Nine Mile 2 Plant cotenants, has entered into an agreemcnt with the U.S. Department of Energy ("DOE") for the ultimate disposal and storage of spent nuclear fuel. The cotenants are assessed a fee for such disposal based upon the kilowatthours generated by the Nine Mile 2 Plant. These costs are charged to operating expense and recovered from customers through base rates or through the electric fuel cost adjustment clause described herein. The Company cannot now determine whether such arrangements with the DOE will ultimately provide for the satisfactory pcrmancnt disposal of such waste products.

47 Central Hudson Gas & Electric Corporation

Cash and Cash Equivalents For purposes of the Consolidated Statement of Cash Flows, the Company considers temporary cash investments with a maturity when purchased of three months or less to be cash equivalents.

Federal Income Tax The Company and its wholly-owned subsidiaries file a consolidated federal income tax return. Federal income taxes are allocated to operating expenses and other income and deductions in the Consolidated Statement of Income. Federal income taxes are deferred under the liability method in accordance with Financial Accounting Standard No. 109, "Accounting for Income Taxes."

Under the liability method, deferred income taxes are provided for all differences between financial statement and tax basis of assets and liabilities. Additional deferred income taxes and offsetting regulatory assets or liabilities are recorded to recognize that income taxes will be recoverable or refundable through future revenues.

Use of Estimates Preparation of the financial statements in accordance with generally accepted accounting principles includes the use of estimates and assumptions by management that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and reported amount of revenues and expenses during the reporting period. Actual results may differ from those estimates.

New Accounting Standards and Other FASB Projects Segment Disclosures: In June 1997, the FASB issued Statement of Financial Accounting Standards No. 131, "Disclosures about Segments of an Enterprise and Related Information" ("SFAS 131"). This Statement establishes standards for reporting information about operating segments in annual and interim financial statements. It also establishes standards for related disclosures about products and services, geographic areas and major customers. In compliance with the requirements of this Statement, the Company expects to adopt SFAS 131 in 1998. The Company does not expect that the adoption of SFAS 131 will have a significant impact on the reporting requirements of the Company.

Plant Decommissioning: The FASB is considering when a liability for plant decommissioning or other long-lived asset retirement should be recognized, how any such liability should be measured, and whether a corresponding asset is created. In an exposure draft issued February 1996, FASB tentatively concluded that a liability should be recognized for legal or unavoidable constructive obligations for closure and removal of facilities, such as the Nine Mile 2 Plant, as the obligation is incurred. The liability recognized for those closure and removal obligations shall reflect thc present value of estimated future cash outflows currently expected to be required to satisfy those obligations. Initial recognition of a liability for closure and removal obligations increases the cost of the related asset because incurrence of the obligation is integral to or a prerequisite for operating the asset.

Further, any securities or other assets dedicated to future settlement of closure and removal obligations cannot bc offset to those liabilities for financial reporting purposes. The FASB is deliberating this issue and the resulting final pronouncement, which may be issued in 1998, could be different from that projected in the exposure draft. The Company docs not believe that such changes, if required, would have a significant adverse effect on results of operations due to its current belief that decommissioning costs will continue to be recovered in rates. However, future developments in the utility industry, including the effects of dcrcgulation and increasing competition, could change this conclusion.

NOTE 3 - NINE NILE 2 PLANT General The Nine Mile 2 Plant is located in Oswego County, New York, and is operated by Niagara Mohawk. The Nine Mile 2 Plant is owned as tenants in common by the Company (9% interest), Niagara Mohawk (41% interest), New York State Electric & Gas Corporation ("NYSE&G") (18% interest), Long Island Lighting Company ("LILCO")(18% interest), and Rochester Gas and Electric Corporation ("Rochester" ) (14% interest). The output of the Nine Mile 2 Plant, which has a rated net capability of 1,143 MW, is shared and the operating expenses of the Plant are allocated to the cotenants in the same proportions as the ownership interests. The Company's share of direct operating expense for the Nine Mile 2 Plant is included in the cotenants'espective appropriate expense classifications in the accompanying Consolidated Statement of Income.

Under the Operating Agreement entered into by the cotenants, Niagara Mohawk acts as operator of the Nine Mile 2 Plant, and all five cotenants share certain policy, budget and managerial oversight functions. The Operating Agreement remains in effect subject to termination on six months'otice.

48 Central Hudson Gas & Electric Corporation

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Radioactive Waste Niagara Mohawk has contracted with the DOE for disposal of high-level radioactive waste ("spent fuel") from the Nine Mile 2 Plant. Despite a court order reaffirming the DOE's obligation to accept spent nuclear fuel by January 31, 1998, the DOE has

~

forecasted the start of operations of its high-level radioactive waste repository to be no earlier than 2010. The Company has been advised by Niagara Mohawk that the Nine Mile 2 Plant spent fuel storage pool has a capacity for spent fuel that is adequate until 2012. IfDOE schedule slippage should occur, facilities that extend the on-site storage capability for spent fuel at the Nine Mile 2 Plant beyond 2012 would need to be acquired.

Nuclear Plant Decommissioning Costs The Company's 9% share of costs to decommission the Nine Mile 2 Plant is estimated to be approximately $ 209.6 million

($ 77.7 million in 1997 dollars) and assumes that decommissioning will begin in the year 2028. This estimate is based upon a site-specific study completed in December 1995.

In order to assist the Company in meeting this obligation, the Company makes annual contributions of $ 868,000 to a qualiTied external decommissioning trust fund. The total annual amount allowed in rates is $ 999,000, but the maximum annual tax deduction allowed is $ 868,000. Currently, the difference between the rate allowance ($ 999,000) and the amount contributed to the external qualified fund ($ 868,000) is recorded as an internal reserve ($ 131,000), and the funds are held by the Company.

Thc qualified external decommissioning trust fund at Dcccmbcr 31, 1997 and 1996 amounted to $ 11.0 million and $ 8.1 million, respectively, including net reinvested earnings to date of $ 4.3 million. The qualified external decommissioning trust fund is reflecte in the Company's Consolidated Balance Sheet in "Investments and Other Assets-Other." At December 31, 1997, the external decommissioning trust fund investments carrying value approximated fair market value. The amount of accumulated decommissioning costs recovered through rates and the nct earnings of the external decommissioning trust fund are reflected in accumulated depreciation in the Consolidated Balance Shcct and amount to $ 12.6 million and $ 9.6 million at December 31, 1997 and 1996, respectively.

Reference is made to the subcaption "New Accounting Standards and Other FASB Projects - Plant Decommissioning" in Note 2 hereof for details of the proposed changes in accounting for nuclear decommissioning costs.

The Company believes that if decommissioning costs are greater than currently estimated, such revised costs would be recovered in rates. However, future developments in the utility industry, including the effects of deregulation and increasing competition, could change this conclusion.

NOTE 4 - FEDERAL INCOME TAX Components of Federal Income Tax The following is a summary of the components of federal income tax as reported in the Consolidated Statement of Income:

1997 1996 1995 (In Thousands)

Charged to operating expense:

Fcdcral income tax ................................................. $ 19,004 $ 18,936 $ 19,245 Deferred income tax 10,186 13,764 9,795 Income tax charged to operating expense ..... 29,190 32,700 29,040 Charged (credited) to other income and deductions:

Federal income tax (6,844) (5,716) (4,704)

Deferred income tax 3,891 4,084 4,351 Income tax charged (credited) to other income and deductions. (2,953) (1,632) (353)

Total federal income tax . $ 26,237 $ 31,068 $ 28,687 49 Central Hudson Gas & Electric Corporation

Reconciliation: The following is a reconciliation between the amount of federal income tax computed on income before taxes at the statutory rate and the amount reported in the Consolidated Statement of Income:

1997 1996 1995 (In Thousands)

Net income ...................... $ 55,086 $ 56,082 $ 52,722 Federal income tax . 12,160 13/20 14/41 Deferred income tax 14 077 17 848 14 146 Income before taxes $ 81823 $ 87,150 $ 81,409 Computed tax I 35% statutory rate Increase (decrease) to computed tax due to:

$ 28/63 $ 30403 $ 28,493 Alternative minimum tax. (7@50) (2862) (2,958)

Tax depreciation (4/25) (10,499) (10,096)

Pension expense (2855) (2,424) (1,738)

Deferred storm costs . (2457)

Deferred finance charges - Nine Mile 2 Plant ... (1,699) (1,699) (1,701)

Nine Mile 2 settlement costs 1/67 1,043 843 Deferred gas costs ............................................... 1/16 (1,703) 2/86 Other (700) 261 588)

Federal income tax . 12,160 13/20 14/41 Dcferrcd income tax 14 077 17 848 14 146 Total fcdcral income tax $ 26/37 $ 31,068 $ 28,687 Effective tax rate 323% 35.6% 35.2%

The following is a summary of the components of defcrrcd taxes at Dcccmber 31, 1997 and 1996, as reported in the Consolidated Balance Sheet:

1997 1996 (In Thousands)

Accumulated Dcfcrrcd Income Tax Assets:

Future tax benefits on investmcnt tax credit basis difference $ 14/37 $ isyig Alternative minimum tax. 1,048 8@98 Unbilled revenues 5,675 5,654 Other. 29,047 26,891 Accumulated Dcfcrrcd Income Tax Assets $ 50,607 $ 56$ 61 Accumulated Deferred Income Tax Liabilities:

Tax dcprcciation $ 181P14 $ 176/22 Accumulated deferred investment tax credit ................. 27/55 28,448 Future revenues - recovery of plant basis differences ... 17,475 20,321 Other. 29 656 28 96 Accumulated Deferred Income Tax Liabilities .................. $ 256,000 $ 253/87 Net Accumulated Defencd Income Tax Liability ... $ 205493 $ 197@26 50 Central Hudson Gas & Electric Corporation

NOTE 5 - SHORT-TERN BORROWING ARRANGEIvIENTS The Company has in effect a revolving credit agreement with four commercial banks which allows it to borrow up to $ 50.0 million through October 23, 2001 ("Agreement" ). The Agreement gives the Company the option of borrowing at either the higher of the prime rate or the sum of the federal funds rate plus 1/2%, or three other money market rates, if such rates are lower.

Compensating balances are not required under the Agreement. In addition, the Company continues to maintain confirmed lines of credit totaling $ 1.5 million with two regional banks. There were no outstanding loans under the Agrecmcnt or the lines of credit at December 31, 1997 or 1996. In order to diversify its sources of short-term financing, the Company has entered into short-term credit facilities agreements with several commercial banks. The Company had no short-term debt outstanding at December 31, 1997. At December 31, 1996, the Company had outstanding short-term debt of $ 15.6 million under such facilities with a weighted average interest rate of 5.94%.

Authorization from the PSC limits the amount the Company may have outstanding, at any time, under all of its short-term borrowing arrangements to $ 52.0 million in the aggregate.

NOTE 6 - CAPITALIZATION- CAPITAL STOCK Common Stock, $5 par value; 30,000,000 shares authorized:

Reacquired Common Stock Paid-In Capital Shares Amount Capital Stock Outstanding ($ 000) ($ 000) ($ 000)

January 1, 1995 17438,464 $ 86,192 $ 277,205 $

Issued under dividend reinvestment plan ("DRP")(a) ... 218,610 1,093 4,897 Issued under customer stock purchase plan ("CSPP")(a) . 38,977 195 879 Redemption of preferred stock 39 December 31, 1995 . 17,496,051 87,480 282,942 Issued under DRP(a) . 49,023 245 1,278 Issued under CSPP(a) 913 0 245 December 31. 1996 . 17654,987 87,775 284,465 Rcpurchascd under common stock repurchase plan. 275200 9 398 December 31, 1997 . 17+79,787 $ 87,775 $ 284,465 $ (9/98)

(a) In hfay l996, the Company converted its DRP and its CSPP from original issue to open market purchase of common shares.

Cumulative Preferred Stock, $ 100 par value; 1,200,000 shares authorized:

Final Redemption Shares Outstandin Redemption Price December 31, Series Date 12/31/97 1997 1996 Not Subject to Mandatory Redemption:

4 1/2% $ 107.00 70,300 70/00 4.75% 106.75 20,000 20,000 4.35% 102.00 60)000 60,000 4.96% 101.00 60,000 60,000 210,300 210300 Subject to Mandatory Redemption:

6.20% 10/I/08 (a) 200,000 200,000 6.80% 10/1/27 (0) 150 000 150 000 350 000 350 000 Total 56)0 300 560 300 (a) Cannot be redeemed prior to October I, 2003.

51 Central Hudson Gas & Electric Corporation

The Company had no cumulative preferred stock redemptions or issuances during 1997; however on January I, 1996, the Company optionally redeemed its 7.72% Series Cumulative Preferred Stock (par value $ 100 per share) at a redemption price of

$ 101.00 per share. The $ 13.1 million redemption price paid and associated costs were funded through internal sources.

Expenses incurred on issuance of capital stock are accumulated and reported as a reduction in common stock equity. These expenses are not being amortized, except that, as directed by the PSC, certain issuance and redemption costs and unamortized expenses associated with certain issues of preferred stock that were redeemed have been deferred and are being amortized over the remaining lives of the issues subject to mandatory redemptions.

By Order, issued and effective December 4, 1996, the PSC authorized the issuance and sale of certain debt and equity securities of the Company.

That Order authorizes the Company, through December 31, 1999, to: I) issue and sell up to $ 40.0 million of new securities comprised of common stock and/or medium term notes, 2) acquire not more than 2.5 million shares of its issued and outstanding common stock of which the Company repurchased 275,200 shares during 1997, and 3) effective January I, 1997, combine its existing DRP, its CSPP and its Employee Stock Purchase Plan into a single plan called the Stock Purchase Plan. The Stock Purchase Plan became effective January I, 1997, superseded such other plans and operates as an original issue or open market purchase plan.

NOTE 7 - CAPITALIZATION- LONG-TERN DEBT Details of'ong-term debt are shown below:

December 31, (In Thousands)

Series Maturit Date First Mortgage Bonds (Nct of Sinking Fund Requirements):

6.10% (a) April 28, 2000 $ 10,000 $ 10,000 7.70% (a) June 12, 2000 25,000 25,000 7.97% (a) June 11, 2003 8,000 8,000 7.97% (a) Junc 13, 2003 8,000 8,000 6.46% (a) August 11, 2003 10,000 10,000 6 I/4% (b) June I, 2007 4@25 4,415 9 I/4% May I, 2021 70,000 70,000 8.12% (a) August 29, 2022 10,000 10,000 8.14% (a) August 29, 2022 10,000 10,000 8.375%(b) December I, 2028 16 700 16 700 172 025 172,115 Promissory Notes:

1984 Series A (7 3/8%)(c) October I, 2014 16,700 16,700 1984 Series B (7 3/8%)(c) October I, 2014 16,700 16,700 1985 Series A (Var. rate)(c) November I, 2020 36,250 36,250 1985 Series B (Var. rate)(c) November I, 2020 36,000 36,000 1987 Series A (Var. rate)(c) June I, 2027 33,700 33,700 1987 Series B (Var. rate)(c) June I, 2027 9,900 9,900 5.38% (a) January 15, 1999 20,000 20,000 7.85% (a) July 2, 2004 15.000 15.000 184,250 184,250 Secured Notes Payable of Subsidiary 6,152 6,299 Unamortized Discount on Debt (598) (624)

Total long-term debt $ 361,829 $ 362,040 (a) Issued under the Company's hfedium Term Note Program.

(b) First hiortgage Bonds issued in connection with the sale by tlte New York State Energy Research and Development Authority

("NYSERDA ") of tax-exempt pollution control revenue bonds.

(c) Prom!ssory Notes issued in connection with the sale by NYSERDA of tax.exempt pollution control revenue bonds.

52 Central Hudson Gas & Electric Corporation

First Mortgage Bonds The Company did not issue or redeem any first mortgage bonds during 1997; however, on May 1, 1996, the Company redeemed $ 30 million of its 8 3/4% Series due 2001 at a redemption price of 102.07% of the principal amount.

Medium Term Notes By Order, issued and effective December 4, 1996, the PSC authorized the Company to issue and sell not later than December 31, 1999, a combination of new debt securities and/or common stock totaling not more than $ 40.0 million in the aggregate.

Amended Settlement Agreement Under the terms of the Amended Settlement Agreement described in Note I hereof, the Company may transfer up to $ 100 million from its regulated utility business to its unregulated businesses prior to the formation of a holding company. The Company may, pursuant to this authorization, issue up to $ 100 million new securities in 1998 or 1999. The type of securities or timing of issuance is uncertain.

NYSERDA The NYSERDA Pollution Control Revenue Bonds issued in 1985 (Series A and B) and 1987 (Series A and B) (collectively, the "1985 and 1987 NYSERDA Bonds" ) are variable rate obligations subject to weekly repricing and investor tender. The Company has the right, exercisable independently with respect to each series of the 1985 and 1987 NYSERDA Bonds, to convert those Bonds of each such series to a fixed rate for the remainder of their term. In its rate orders, the PSC has authorized deferred accounting for the interest costs on the Company's 1985 and 1987 Series A and B Promissory Notes which were issued in connection with the sale of the 1985 and 1987 NYSERDA Bonds. The authorization provides for full recovery of the variance between that portion of the actual interest costs supporting utility operations and the interest costs allowed in rates. The percent of interest costs supporting utility operations represents approximately 95% of the total costs. The deferred balances under such accounting were $ 3.8 million and $ 2.4 million at December 31, 1997 and 1996, respectively, and were included in "Regulatory Assets" in the Company's Consolidated Balance Sheet.

Such dcferrcd balances are to be addressed in future rate cases. By Order, issued and effective December 4, 1996, the PSC authorized the Company to issue up to $ 132.55 million of tax-exempt NYSERDA Pollution Control Revenue Bonds for refunding purposes or for the purpose of refinancing, ifeconomical, a like amount of such bonds presently outstanding.

Letters of Credit The Company has in place irrevocable letters of credit which support certain payments required to be made on the 1985 and 1987 NYSERDA Bonds. Such letters of credit expire in 1999 and 2000. The Company anticipates being able to extend such letters of credit ifthe interest rate on the related series of such Bonds is not converted to a fixed interest rate. Ifthe Company were unable to extend the letter of credit that is related to a particular series of such Bonds, that series would have to be redeemed unless a fixed rate of interest became effective. Payments made under the letters of credit in connection with purchases of tendered 1985 and 1987 NYSERDA Bonds are repaid with the proceeds from the remarketing of such Bonds. To the extent the proceeds are not sufficient, the Company would be required to reimburse the bank that issued the letter of credit for the amount of any resulting draw under that letter prior to its expiration date.

Interest Rate Cap By Order, issued and effective December 4, 1996, the PSC authorized the Company to employ interest rate caps, collars and floors to manage interest rate risk associated with its variable rate 1985 and 1987 NYSERDA Bonds and to recognize the associated costs as interest expense for rate-making purposes. The Company entered into an interest rate cap agreement with a bank to manage exposure to upward changes in interest rates on the 1985 and 1987 NYSERDA Bonds. Under this agreement, in the event a nationally recognized tax-exempt bond interest rate index exceeds 8%, the Company will receive a payment from such bank equal to the amount by which the actual interest costs on such Bonds exceeds 8% per annum. This agreement has the effect of limiting the interest rate the Company must pay on such bonds (on a $ 115.9 million notional amount) to the lesser of their actual rate or 8% per annum. In the event such bank failed to make any required payment under such interest rate cap agreement, the Company's exposure would be limited to a maximum interest rate of 15% per annum under the terms of such Bonds. The interest rate cap agreement currently in effect expires on April 19, 1998. The Company intends to enter into a new agreement prior to such expiration date to provide similar risk management benefits for the remainder of 1998 and possibly beyond.

Debt Expense Expenses incurred on debt issues and any discount or premium on debt are deferred and amortized over the lives of the related issues. Expenses incurred on debt redemptions prior to maturity have been deferred and are generally being amortized over the shorter of the remaining lives of the related extinguished issues or the new issues as directed by thc PSC.

Debt Covenants Certain debt agreements require the maintenance by the Company of certain financial ratios and contain other restrictive covenants.

Mortgage Indenture Covenant Article XXIof the Company's First Mortgage Bond Indenture requires that the Company deposit, annually with the Indenture rustee cash in an amount equal to the difference between annual capital additions and depreciation charges, if such charges exceed capital additions, to the extent that such difference is not offset by credits from prior years. Though no cash deposit was rcquircd in 1997 or 1996, the Company anticipates that a deposit of cash of up to $ 4.0 million will be made pursuant to such Article by March 31, 1998. Such deposit may be withdrawn at a subsequent date to fund redemptions of outstanding mortgage bonds.

53 Central Hudson Gas 8c Electric Corporation

NOTE 8 - POSTENPLOYNENT BENEFITS Retirement Income Plan The Company has a non-contributory retirement income plan ("Retirement Plan" ) covering substantially all of its employees.

The Retirement Plan provides pension benefits that are based on the employee's compensation and years of service. It has been the Company's practice to provide periodic updates to the benefit formula stated in the Retirement Plan.

The Company's funding policy is to make annual contributions equal to the amount of net periodic pension cost, but not in excess of the maximum allowable tax-deductible contribution under the federal income tax law nor less than the minimum requirement under the Employee Retirement Income Security Act of 1974.

The return on plan assets has resulted in net periodic pension income of which 25% was allocated to capital projects in both 1997 and 1996 and 27% in 1995. This allocation follows the payroll distribution.

Net periodic pension income for 1997, 1996 and 1995 include the following components:

1997 1996 1995 (In Thousands)

Service cost - benefits earned during the period. $ 4,479 S 4,556 $ 3,877 Interest cost on projected benefit obligation 15@16 14,594 14,449 Actual return on Retirement Plan assets (60,760) (30,772) (38,849)

Net amortization and deferral 28,101 1,872 9,896 Net periodic pension (income) $ (12,864) S (9,750) $ (10,627)

The following table sets forth the Retirement Plan's funded status at October 1, 1997 and 1996 and amounts recognized in the Company's Consolidated Balance Sheet at December 31, 1997 and 1996:

1997 1996 (In Thousands)

Actuarial present value of benefit obligations:

Vested .. $ 192,410 $ 173,424 Nonvested. 3 455 3 207 Total. $ 195,865 $ 176,631 Projected benefit obligation ("PBO") for service rendered to date $ 222,250 $ 199,416 Retirement Plan assets at market value 316 852 268 615 Excess of Retirement Plan assets over PBO ... 94,602 69,199 Unrecognized nct gain . (74,326) (58,464)

Unrecognized prior service cost 5,960 3 273 Unrecognized net asset* 2 700 3 336 Prefunded Pension Cost. $ 23,536 S 10,672

~ Being amorrized over 15 years.

Assumptions used to determine actuarial valuations:

Discount rate used to determine PBO. 7.25% 7.75%

Rate of compensation increase used to determine PBO ... 4.50% 4.50%

Long-term rate of return on plan assets for net pension benefit. 9.25% 9.75%

Retirement Plan assets consist primarily of equities, real estate and fixed income securities. The Retirement Plan is deemed to bc fully funded for federal income tax purposes, therefore, the Company did not make any contributions to the Retirement Plan during 1997 or 1996.

The 1997 and 1996 accounting for pension benefits reflects adoption of PSC-prescribed provisions which, among other things, requires ten-year amortization of actuarial gains and losses and deferral of differences between actual costs and rate allowances.

54 Central Hudson Gas & Electric Corporation

Other Postretirernent Benefits The Company provides certain health care and life insurance benefits for retired employees through its postretircment benefit plan ("Benefit Plan" ). Substantially all of the Company's employees may become eligible for these benefits if they reach retirement age while working for the Company. These and similar benefits for active employees are provided through insurance companies whose premiums are based on the benefits paid during the year. In order to recover a portion of the costs of these benefits, the Company rcquircs employees who retired on or after October 1, 1994, to contribute toward the cost of such benefits.

The Company is fully recovering its net periodic postretircment costs in accordance with PSC guidelines. Under these guidelines, the difference between the amounts of postretirement benefits recoverable in rates and the amounts of postretiremcnt benefits determined by thc actuary under SFAS 106, "Employers Accounting for Postrctirement Benefits Other Than Pensions," are deferred as either a regulatory asset or liability, as appropriate.

Net periodic postrctirement benefit cost for 1997, 1996 and 1995 includes the following components:

1997 1996 1995 (In Thousands)

Service cost - benefits attributed to the period ............ $ 1,745 $ 1,875 $ 1,384 Intcrcst cost on accumulated postretiremcnt benefit obligation. 5/64 5,149 4,613 Actual return on Benefit Plan assets (1/86) (1/35) (875)

Amortization of Transition Obligation* ...................... 3,114 3,114 3,114 Net amortization and deferral (1/14) (784) (1,837)

Nct periodic postretirement benefit cost .................. $ 6,723 8,019 6,399

~ The Company is amortizing the unfunded accumulated postretirement benefit obligation ("Transition Obligation") at January l, 1993 over a 20-year period.

Thc Company has established a qualified funding vehicle for such retirement benefits for collective bargaining employees and a similar vehicle for management employees in the form of qualified Voluntary Employee Beneficiary Association ("VEBA")trusts.

Contributions to thc VEBA trusts are tax deductible, subject to limitations contained in the Internal Revenue Code and other egulations. Contributions to the VEBA trusts are made to fund employees'ostretirement health care and life insurance benefits, as well as benefits as they are paid to retirees. The VEBA trusts consists primarily of equities and fixed income securities.

Thc Benefit Plan's funded status reconciled with the Company's Consolidated Balance Sheet is as follows:

December 31, 1997 1996 (ln Thousands)

Accumulated postretircment benefit obligation ("APBO"):

Retirecs. $ (36@91) $ (33,427)

Fully eligible employees . (4P91) (4,632)

Other employees (37/71) (33,422)

(78853) (71,481)

Benefit Plan assets at fair value ... 45,109 31,402 Excess of APBO over Benefit Plan assets. (33/44) (40,079)

Unrecognized nct gain (14,716) (11,419)

Unrecognized prior service cost. (139) (149)

Unrecognized Transition Obligation 46,693 49,807 Postretiremcnt benefit liability . $ (2,006) $ (1,840)

Assumptions used to determine actuarial valuations:

Discount rate used to determine APBO . 7.25% 7.75%

Rate of compensation increase for applicable life insurance plans 450% 4.50%

Long-term rate of return on plan assets for periodic post retirement benefit costs. 6.80% 6.60%

55 Central Hudson Gas & Electric Corporation

The assumed health care cost trend is 11% in the early years and trends down to an ultimate rate of 5.5% by the year 2010.

1% increase in health care cost trend rate assumptions would produce an increase in the accumulated postretirements benefit obligation at December 31, 1997 and 1996 of $ 10.3 and $ 9.4 million, respectively, and an increase in the aggregate service and A ~

interest cost components of the net periodic postretirement benefit cost of $ 1 million for both 1997 and 1996, respectively.

NOTE 9 - COIvIIvIITIvIENTSAND CONTINGENCIES Nuclear Liability and tnsurance The Price-Anderson Act is a federal law which limits the public liability which can be imposed with respect to a nuclear incident at a licensed nuclear electric generating facility. Such Act also provides for assessment of owners of all licensed nuclear units in the United States for losses in excess of certain limits in the event of a nuclear incident at any such licensed unit. Under the provisions of the Price-Anderson Act, the Company's potential assessment (based on its 9% ownership interest in the Nine Mile 2 Plant and assuming that the other Nine Mile 2 Plant cotenants were to contribute their proportionate shares of the potential assessments) would be $ 6.8 million (subject to adjustment for inflation) and the Company could be assessed $ 339,800 (subject to adjustment for inflation) as an additional surcharge, but would be limited to a maximum assessment of $ 900,000 in any year with respect to any nuclear incident. The public liability insurance coverage of $ 200 million required under the Price-Anderson Act for the Nine Mile 2 Plant is provided through Niagara Mohawk.

The Company also carries insurance to cover the additional costs oF replacement power (under a Business Interruption and/or Extra Expense Insurance Policy) incurred by the Company in the event of a prolonged accidental outage of the Nine Mile 2 Plant.

This insurance arrangement provides for payments of up to $ 342,000 per week if the Nine Mile 2 Plant experiences a continuous accidental outage which extends beyond 21 weeks. Such payments will continue for 52 weeks after expiration of the 21-week deductible period, and thereafter the insurer shall pay 80% of the weekly indemnity for a second and third 52-week period. Subject to certain limitations, the Company may request prepayment, in a lump sum amount, of the insurance payments which would otherwise be paid to it with respect to said third 52-week period, calculated on a net present value basis.

'he Company is insured as to its respective interest in the Nine Mile 2 Plant under property damage insurance provided through Niagara Mohawk. The insurance coverage provides $ 500 million of primary property damage coverage for both Units of the Nine Mile Point Nuclear Station and $ 2.25 billion of excess property damage coverage solely for Unit 2 of that station. Such insurance covers decontamination costs, debris removal and repair and/or replacement of property.

The Company intends to maintain, or cause to be maintained, insurance against such risks at the Nine Mile 2 Plant, provided such coverage can be obtained at an acceptable cost.

Environmental Matters General: On an ongoing basis, the Company assesses environmental issues which could impact the Company and its customers.

Clean Water Act Compliance: In 1992 the Company filed renewal applications for the State Pollution Discharge Elimination System ("SPDES") permits for its Roseton and Danskammer Plants. Such permits are required to operate the Plants'ooling water systems and wastewater treatment systems. The Company is a party to an active proceeding before the New York State Department of Environmental Conservation ("NYSDEC") related to the processing of the application for the Roseton Plant. At this stage of the proceeding, the Company can make no determination as to the outcome of the proceeding or the impact, iF any, on the Company's financial position.

Clean Air Act Amendments: The Clean Air Act Amendments of 1990 ("CAA Amendments" ) added several new programs which address attainment and maintenance of national ambient air quality standards. These include control of emissions from fossil-fueled electric power plants that affect "acid rain" and ozone. At December 31, 1997, the Company believes it was in full compliance with regulations promulgated to date under the CAA Amendments. Ongoing federal and state clean air initiatives may require the Company to reduce its emissions in the future.

The Company's emissions of nitrogen oxides ("NOx") were subject to additional controls effective May 31, 1995 under Title I of the CAA Amendments. The Company has installed appropriate controls in compliance with this requirement. The Northeast Ozone Transport Commission, of which New York State is a member, has agreed that additional reductions of NOx emissions will be required in 1999 and, possibly, in the year 2003. Because regulations have not yet been promulgated by New York State to implement this agreement, the specific reductions required at the Company's facilities have not been determined.

In July 1997, the Environmental Protection Agency ("EPA") promulgated revisions to the National Ambient Air Quality Standards for ozone and particulates. These regulations may result in the need for additional reductions of sulfur dioxide and NOx emissions, depending on the results oF ongoing ambient air monitoring programs. Should monitoring determine that counties in the vicinity of the Company's electric generating stations exceed the new standards, emissions reductions could be required. However, ambient air monitoring for particulates will not be completed until 2002, at which time the EPA also intends to complete a reassessment of health risks associated with particulate emissions. Similarly, additional controls of NOx emissions that are 56 Central Hudson Gas 8c Electric Corporation

associated with ozone formation are unlikely until 2003. At that time the EPA will have completed its review of plans for meeting the new ozone standards that are to be submitted by the states.

While it is not presently possible to determine the additional emissions reductions, if any, required at the Company's facilities, the Company expects that it will have adequate financial resources to comply with the CAA Amendments requirements.

Former Manufactured Gas Plant: Facilities In May 1995, the City of Newburgh, New York ("City") filed suit against the Company in the United States District Court for the Southern District of New York ("District Court"). The City alleges that the Company has released certain allegedly hazardous substances without a permit from the site of the Company's former coal gasification plant ("Central Hudson Site" ) in Newburgh, New York into the ground at the Central Hudson Site and into adjacent and nearby property of the City, in violation of the federal Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"), the federal Resource Conservation and Recovery Act ("RCRA") and the federal Emergency Planning and Community Right to Know Act ("EPCRA"). The City also allcges a number of nuisance, trespass, damage and indemnification claims pursuant to New York State law.

The City seeks injunctive relief against such alleged disposal, storage or release of hazardous substances at the Central Hudson Site, remediation and abatement of the conditions alleged to lead to endangerment of the City's property, payment of restitution of clean-up costs and monetary damages of at least $ 70 million, assessmcnt of certain civil penalties under RCRA, CERCLA and EPCRA, and recovery of the City's costs and attorneys'ees in such action. The Company and the City continue to investigate this matter. A tentative schedule of proceeding has been applied by the District Court.

The Company and the NYSDEC have entered into an Order on Consent regarding the development and implementation of an investigation and remediation program for the Central Hudson Site, thc City's adjacent and nearby property and the adjoining areas of the Hudson River. Remedial investigations were completed in Scptcmber 1997. A draft report on the investigations was provided to the NYSDEC for its review and comment on October 31, 1997. The investigations revealed the presence of contaminants in the soil in portions of the study area. In the majority of the study area contaminants were found deep within the ground and are not a threat to the public. Contaminated ground water is associated with the contaminated soil but it is not used as a drinking water supply. Impacted sediments were also present within the Hudson River adjacent to the City's property which is the location of its sewage treatment plant. There are several possible sources of the contaminants due to the long industrial history and current uses of the area.

Following NYSDEC's approval of the report and its determination whether or not the contaminants found in the investigation may pose a significant threat to human health or the environment, a risk assessment will be completed by the Company, if required.

Remedial alternatives addressing any unacceptable risks identified in the risk assessment will be evaluated. It is currently anticipated that the risk assessment and remedial alternatives report will be completed in 1998.

At this time, the Company can make no prediction as to the outcome of this litigation, nor can it make reasonable estimates of the cost of the activities required under the Order on Consent. However, thc Company has put its insurance carriers on notice and intends to pursue reimbursement from them. The Company cannot predict thc extent of reimbursement that will be available from its carriers at this time.

By letter dated June 3, 1997, the Company received authorization from the PSC to defer costs related to this matter, including legal defense costs, but excluding the Company's labor, related to environmental site investigation and remediation actions. The Company has deferred costs expended to date that it expects to be recovered in future rates. The cumulative deferred costs for 1997 amounted to $ 2.2 million and were included in "Deferred Charges-Regulatory Assets" in the Company's Consolidated Balance Sheet.

Asbestos Litigation Since 1987, the Company, along with many other parties, has been joined as a defendant or third-party defendant in 1,212 asbestos lawsuits commenced in New York State and federal courts. The plaintiffs in these lawsuits have each sought millions of dollars in compensatory and punitive damages from all defendants. The cases were brought by or on behalf of individuals who have allegedly suffered injury from exposure to asbestos, including exposure which allegedly occurred at Company facilities.

As of December 31, 1997, of the 1,212 cases that had been brought against the Company, 596 remained pending against the Company. The 616 cases that were no longer pending against the Company as of December 31, 1997 were resolved as follows: (i) the Company negotiated voluntary dismissals in 372 cases and won summary judgcmcnt dismissals in 10 cases; (ii) 116 third-party claims were extinguished with respect to the Company when the third party plaintiff, Owens Corning Fiberglass settled the cases with the plaintiffs; and (iii) the Company settled 118 cases. The Company is presently unable to assess the validity of the remaining asbestos lawsuits; accordingly, it cannot determine the ultimate liability relating to these cases. Based on information known to the Company at this time, including its experience in settling asbestos cases and in obtaining dismissals of asbestos cases, the Company believes that the cost to be incurred in connection with the remaining lawsuits will not have a material adverse effect on the Company's financial position or results of operations.

The Company is insured under successive comprehensive general liability policics issued by a number of insurers, has put such insurers on notice of the asbestos lawsuits and has demanded rcimburscment for its defense costs and liability.

57 Central Hudson Gas & Electric Corporation

Purchased Power Commitments Under federal and New York State laws and regulations, the Company is required to purchase the electrical output of unregulated cogeneration facilities ("IPPs") which meet certain criteria for Qualifying Facilities, as such term is defined in the appropriate legislation. Purchases are made under long-term contracts which require payment at rates higher than what can be purchased on the wholesale market. These costs are currently fully recoverable through the Company's electric fuel adjustment clause. However, the PSC has indicated to the Company that it may not allow full recovery of onc such IPP contract. At December 31, 1997, thc Company has accrued a liability for its estimate of future payments under this IPP contract which will not be recovered through rates. IPPs with which the Company has contracts represent 4.6% of the Company's energy purchases in 1997.

Other Matters The Company is involved in various other legal and administrative proceedings incidental to its business which arc in various stages. While these matters collectively involve substantial amounts, it is the opinion of management that their ultimate resolution will not have a material adverse effect on thc Company's financial position or results of operations.

Included in such proceedings are lawsuits against the Company arising from a November 1992 explosion in a dwelling in Catskill, New York. These lawsuits include: one alleging personal injuries, the death of an occupant, and property damage and recovery of an unspecified amount of compensatory and punitive damages; and one alleging personal injuries and property damage and compensatory and punitive damages in the sum of $ 4.0 million.

In addition to the above, on February 12, 1994, a fire and an explosion destroyed a residence in the Village of Wappingers Falls, New York, in thc Company's service territory. A short time later, a second explosion and fire destroyed a nearby commercial facility. Lawsuits have bccn commcnccd against the Company arising out of the Wappingers Falls incident including: one alleging property damage and seeking recovery of $ 250,000 in compensatory damages and one alleging personal injuries and property damage and seeking an unspecified amount of damages against the Company.

The Company is investigating thc above claims and presently has insufficient information on which to predict their outcome.

The Company believes that it has adequate insurance to cover any compensatory damages that might be awarded. The Company's insurance, however, does not extend to punitive damages which, if awarded, could have a material adverse effect on the Company's financial position.

NOTE I 0 - DEPARTMENTAL INFORMATION The Company is engaged in the electric and natural gas utility businesses and serves the Mid-Hudson Valley region of New York State. Total revenues and operating income before income taxes (expressed as percentages), derived from electric and gas operations for each of the last three years, were as follows:

Percent of Percent of Operating Total Revenues Income Before Income Taxes Electric Gas Electric Gas 1 997 ~ eoteoooo 80% 20% 85% 15%

1 996 ................ 81% 19% 88% 12%

1 995 ................ 80% 20% 90% 10%

For the year ended December 31, 1997, the Company served an average of 266,471 electric and 61,402 gas customers. Of the Company's total electric revenues during that period, approximately 43% was dcrivcd from residential customers, 31% from commercial customers, 17% from industrial customers and 9% from other utilities and miscellaneous sources. Of thc Company's total gas revenues during that period, approximately 43% was derived from residential customers, 32% from commercial customers, 5% from industrial customers, 15% from interruptible customers and 5% from miscellaneous sources (including revenues from transportation of customer-owned gas).

The Company's largest customer is International Business Machines Corporation ("IBM"), which accounted for approximately 9% of the Company's total electric revcnucs and approximately 1% of its total gas revenues for the year ended December 31, 1997.

58 Central Hudson Gas & Electric Corporation

Certain additional information regarding these segments is set forth in the following table. General corporate expenses, property common to both segments and depreciation of such common property have been allocated to the segments in accordance with practice established for regulatory purposes.

1997 1996 1995 (In Thousands)

ELECTRIC Operating Revenues $ 416,429 $ 418 761 $ 409 445 Operating Expenses:

Fuel and purchased electricity 121,981 114,397 113,263 Depreciation and amortization. 39,480 38,401 37,503 Other, excluding income tax. 170 338 170 498 168 313 Total. 331,799 323,296 319,079 Operating Income before Income Tax. 84,630 95,465 90,366 Fcdcral income tax, including deferred income tax - net. 24 622 28 592 26 632 Operating Income. $ 60,008 S 66,873 S 63,734 Construction Expenditures $ 36,686 S 43,359 S 41,195 Identifiable Assets at December 31*

Net utility plant . $ 771,110 $ 784,582 $ 784,345 Construction work in progress.. 43 173 3 4 Total utility plant 814,283 823,928 823,323 Materials and supplies 18 695 22 668 23 167 Total . $ 832,978 $ 846,596 $ 846,490 GAS Operating Revcnucs . $ 103,848 $ 95,210 $ 102,770 Operating Expenses:

Purchased natural gas.. 61,514 50,636 62,339 Depreciation and amortization. 4,384 4,179 3,964 Other, excluding income tax. 23 334 27 331 26 899 Total .. 89,232 82,146 93,202 Operating Income before Income Tax. 14,616 13,064 9,568 Federal income tax, including defcrrcd income tax - net. 4 568 4 108 2 408 Operating Income $ 10,048 S 8,956 $ 7,160 Construction Expenditures .. $ 7,183 $ 6,501 $ 9,074 Identifiable Assets at December 31*

Net utility plant . $ 109,268 $ 106,348 $ 103,979 Construction work in progress.. 9 240 9 353 9 792 Total utility plant 118,508 115,701 113,771 Materials and supplies 5 405 5 427 4 423 Total . $ 123,913 $ 121,128 $ 118,194

~ Identifiable assets not included Irerein are considered to be corporate assets and have not been allocated benveen the electric and gas segments.

59 Central Hudson Gas & Electric Corporation

The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value:

Cash and Temporary Cash Investments: The carrying amount approximates fair value because of the short maturity of those instruments.

Cumulative Preferred Stock Subject to Mandatory Rcdcmptioni The fair value is estimated based on the quoted market price of similar instruments.

Long-Term Debt: The fair value is estimated based on the quoted market prices for the same or similar issues or on the current rates offered to the Company for debt of the same remaining maturities and quality.

Notes Payable: The carrying amount approximates fair value because of the short maturity of those instruments.

The estimated fair values of the Company's financial instruments are as follows:

December 31 1997 December 31 1996 Carrying Amount Fair Value Carrying Amount Fair Value (In Thousands)

Cumulative preferred stock subject to mandatory redemption ................................ $ (35,000) $ (39,100) $ (35,000) $ (33,950)

Long-term debt (including current maturities) ... (363,146) (382/37) (363,402) (380,875)

SELECTED QUARTERLY FINANCIALDATA (UNAUDITED)

Selected financial data for each quarterly period within 1997 and 1996 are presented below:

Earnings Per Income Average Available Share of for Common Operating Operating Common Stock Rcvcnues Income Stock Outstandin (In Thousands) (Dollars)

Quarter Ended:

1997 March 31. $ 151/75 $ 25/02 $ 20,677 $ 1.18 June 30. 118,604 14/42 9,656 55 September 30 .......... 123407 17@11 12/60 .72 December 31 ... 126/91 11/01 8/63 $2 1996 March 31 $ 153,846 $ 27,092 $ 21,014 $ 1.20 June 30............. 116,994 16,366 10,195 .58 September 30 ..... 117,684 18,000 12,857 .73 December 31. 125,447 14,371 8,407 .48 60 Central Hudson Gas & Electric Corporation

CHEDULE ll - Reserves Additions Payments Balance Balance at Charged to Charged to Charged at End Beginning Cost and Other to of Description of Period Expenses Accounts Reserves Period YEAR ENDED DECEMBER 31, 1997 Operating Reserves ... $ 4,755,264 $ 2,142,391 $ 334,700 $ 650,741 $ 6,581,614 Reserve for Uncollectible Accounts ..... $ 3,200,000 $ 3,493,405 $ - $ 3,893,405 $ 2,800,000 YEAR ENDED DECEMBER 31, 1996 Operating Reserves ............................... $ 6,024,101 $ 2,665,136 $ 195,608 $ 4.129.581 $ 4,755,264 Reserve for Uncollectible Accounts ..... $ 2,500,000 $ 4,335,676 $ - $ 3,635,676 $3,200,000 YEAR ENDED DECEMBER 31, 1995 Operating Reserves ... $ 5,663,407 $ 3,044,329 $ 1,091,388 $ 3,775,023 $ 6,024,101 Reserve for Uncollectible Accounts ..... $ 2,000,000 $ 3,220,608 $ - $ 2,720,608 $ 2,500,000 TEN 9 Changes In And Disagreements W'ith Accountants On Accounting And Financial Disclosure None.

PART III ITEN IO Directors And Executive Officers OfThe Company The information with respect to the Directors of the Company required hereunder is incorporated by reference to the caption "Election of Directors" in the Company's definitive proxy statement, to be dated March 2, 1998, and to be used in connection with its Annual Meeting of Shareholders to be held on April 7, 1998, which proxy statement will be submitted to the Securities and Exchange Commission pursuant to that Commission's Regulation S-T.

The information with respect to the executive officers of the Company required hereunder is incorporated by reference to Item I herein, under the caption "Executive Officers of the Company."

ITEN I I Executive Compensation The information required hereunder is incorporated by reference to the caption "Executive Compensation" in the Company's definitive proxy statement, to be dated March 2, 1998, and to be used in connection with its Annual Meeting of Shareholders to be ld on April 7, 1998.

61 Central Hudson Gas & Electric Corporation

ITEN l2 Security Ownership Of Certain Beneficial Owners And Nanagement The information required hereunder is incorporated by reference to the caption "Security Ownership" in the Company's definitive proxy statement, to be dated March 2, 1998, and to be used in connection with its Annual Meeting of Shareholders to be held on April 7, 1998.

ITEN I 3 Certain Relationships And RelatedTransactions There were no relationships or transactions of thc type required to be described by this Item.

PART IY ITEN l4 Exhibits, Financial Statement Schedule, And Reports On Form 8-K (a)

l. and 2. All Financial Statements and Financial Statement Schedules filed as part of this Report are included in Item 8 of this Form 10-K and refercncc is made thereto.

3. Exhibits Incorporated herein by reference to the Exhibit Index for this Rcport. Such Exhibits include the following management contracts or compensatory plans or arrangements required to be filed as an Exhibit pursuant to Item 14(c) hereof:

Directors'eferred Compensation Plan, effective October I, 1980. (Exhibit (10)(iii)1)

Trust Agreement between Registrant and Dutchess Bank & Trust Company, as trustee, dated as of January 1, 1984, pursuant to Registrant's Savings Incentive Plan. (Exhibit (10)(iii)2)

First Amcndmcnt, dated December 31, 1990, to Trust Agreement between Registrant and The Bank of New York, as successor trustee, dated as of January 1, 1984, pursuant to Registrant's Savings Incentive Plan. (Exhibit (10)(iii)3)

Agreement, made March 14, 1994 by and between Registrant and Mellon Bank, N.A., amending and restating, effective April I, 1994, Registrant's Savings Incentive Plan and related Trust Agreement with The Bank of New York, together with iamendments dated July 22, 1994 and December 16, 1994. (Exhibits (10)(iii)18, 19 and 20)

Executive Deferred Compensation Plan of thc Company, effective March I, 1992, together with Amendment thereto dated December 17, 1993. (Exhibits (10)(iii)8 and 15)

Retirement Benefit Restoration Plan of thc Company, cffectivc May 1, 1993, together with Amendment thereto dated July 23, 1993. (Exhibits (10)(iii)10 and 11)

Executive Incentive Compensation Plan of the Company, effective January 1, 1993, together with Amendment thereto dated April 4, 1995. (Exhibits (10)(iii)17 and 21)

Stock Plan for Outside Directors of the Company, dated November 17, 1995. (Exhibit (10)(iii)22)

Management Incentive Program of the Company, effective April 1, 1994, together with Amendment thereto dated July 25, 1997. (Exhibits (10)(iii)23 and 24) 4 62 Central Hudson Gas 8 Electric Corporation

During thc last quarter of the period covered by this Rcport and including the period to the date hereof, the following Reports on Form 8-K were filed by the Company:

(1) Report dated November 17, 1997 relating to the Company's former manufactured gas plant facilities described under the caption "Environmental Claims - Newburgh Manufactured Gas Site" in Item 3 of Part I of the Annual Report on Form 10-K for the fiscal year ending December 31, 1997, which in turn relates to the litigation filed against thc Company by thc City of Ncwburgh, New York, on May 26, 1995, in thc United States District Court, Southern District of New York. Pursuant to the October 1995 Order on Consent entered into between the Company and the NYSDEC, as referred to in said Item 3, the Company filed, on October 31, 1997, a Remedial Investigation report with the NYSDEC for the investigation and remediation progmm being conducted on the Company's former coal gasification plant site and the City of Newburgh's adjacent and nearby property. On October 31, 1997, the Company issued a related press release which was filed as Exhibit 99 and incorporated by reference to said Form 8-K.

(2) Rcport dated January 7, 1998 regarding the Company's execution of an Amended and Restated Settlement Agreement, dated January 2, 1998 with various parties, related to thc Competitive Opportunities Proceeding described in Note l.

(c) t I Incorporated herein by reference to subpart (a)-3 of Item 14, above.

Note to Shareholders: The copy of this Annual Rcport to the SEC, on Form 10-K for the fiscal year ended December 31, 1997, does not contain the list of exhibits contained in thc copy of the Rcport as filed with the SEC. Sliareholders who wish to obtain a copy of the list of exhibits may obtain it without charge by contacting: Ellen Ahcam, Secretary, Central Hudson Gas

& Electric Corporation,284 South Avenue, Poughkccpsie, NY 12601-4879, telephone (914) 486-5757; E-mail:http: //

www.ccnhud.corn. Copies of the exhibits can bc purchased from the Company for a specified fcc.

(d) w Not applicable, sce Item 8 hereof.

63 Central Hudson Gas & Electric Corporation

SIGNATURES itV Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Company has duly caused this.2 Report to be signed on its behalf by the undersigned, thereunto duly authorized. i CENTRAL HUDSON GAS & ELECTRIC CORPORATION By (John E. Mack, III, Chairman of the Board and Chief Executive Officer)

Dated: February 10, 1998 Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below by the following persons on behalf of the Company and in the capacities and on the date indicated:

BigtgItm (a) Principal Executive Officer or Officers

( hn E. Mack, III) Chairman of the Board and February 10, 1998 Chief Executive Officer (b) Principal Accounting Officer:

.r (Donna S. Doyle) Controller February 10, 1998 (c) Principal Financial Officer:

(Steven V. Lant) Treasurer and Assistant Secretary February 10, 1998 (d) A majority of Directors:

L. i~Vallace Cross*, Jack Effron*, Heinz K. Fridrich*, Edward F.X. Gallagher*,

Paul J. Ganci*, Charles LaForge*, John E. Mack, IIV and Edward P. Swyer*, Directors By:

(Jo i E. Mack, III) February 10, 1998

• John E. Mack, III, by signing his name hereto, does thereby sign this document for himself and on behalf of the persons named above after whose printed name an asterisk appears, pursuant to powers of attorney duly executed by such persons and filed with the Securities and Exchange Commission as Exhibit 24 hereof.

64 Central Hudson Gas 8c Electric Corporation

Qt ectors L Wallace Cross Edward P. Swyer Allan R. Page keepsie, NY Albany, NY Senior Vice President Corporate Services Executive Vice President and Chief President, The Swyer Companies; member Financial Officer of the Corporation; retired; of the Committee on Compensation and Ronald P. Brand member of the Committees on Audit and on Succession and the Rctiremcnt Committee

• 1990 Vice President Engineering Finance *1990 and Environmental Affairs

• Yearjoined tiic board Jack Effron Benon Budziak I'I Poughkeepsie, NY Vice President Production of President, EFCO Products, Inc.; Chairman the Committee on Compensation and Succession and member of the Executive Qfftcers of Joseph J. DeVirgilio, Jr.

Committee and the Committee on Finance The Board Vice President Human Resources

• 1987 and Administration Frances D. Fergusson John E. Mack III Ellen Abeam Chairman of the Board and Chief Executive Secretary Poughkeepsie, NY Officer; Chairman of the Executive, Finance President, Vassar College; member of thc and Retirement Comrnittecs Committees on Audit and on Compensation Donna S. Doyle and Succession *1993 Controller Jack Effron Cliairman of the Committee on Heinz K. Fridrich Compensation and Succession Steven V. Lant Fernandina Beach, FL Treasurer and Assistant Secretary Courtesy Professor, University of Florida, Gainsville, FL; Former Vice President Heinz K. Fridrich Chairman of thc Committee on Audit Gladys L. Cooper Manufacturing, International Business Assistant Vice President-Ma ines Corp.; Chairman of the Committee Govcrnmcntal Relations r t; member of the Executive tee *1988 James P. Lovette <'>

Assistant Vice President Edward F.X. Gallagher Fossil Production Newburgh, NY John E. Mack, III President and Owner, Gallagher Chairman of the Board and Chief Transportation Services; member of the Executive Officer Arthur R. Upright Committee on Finance *1984 Assistant Vice President Cost & Rate and Financial Planning Paul'J. Ganci Paul J. Ganci President and Chief Operating Officer William P. Reilly Poughkeepsie, NY President and Chief Operating Officer; Assistant Secretary and Assistant Treasurer Carl E. Meyer member of the Executive Committee and the Committee on Finance *1989 Senior Vice President Customer Services i'>> Retired effecti ve November i, 1997 u> Appointed effective October 20, 1997 Charles LaForge Affirmative Action Statement of Policy Rhinebeck, NY It is the policy of Central Hudson Gas 8c Electric Corporation to provide equal employment President of Wayfarer Inns and Owner of opportunities for all persons. Central Hudson is committed to recruit, hire, train and promote Beekman Arms; member of the Rctircmcnt persons in all positions, without regard to race, sex, color, creed, religion, age, national origin, Committee and thc Committee on Audit persons with a disability, disabled vctcran or Vietnam-cra vctcran status, except where sex is a

• 1987 bona fide occupational qualiTication. The Coinpany will base decisions on employment so as to further the principle of equal cmploymcnt opportunity. Central Hudson will insure that

, John E. Mack, III promotion decisions arc in accord wi(h principles of equal employment opportunity by imposing only valid requirements for promotional opportunities. Central Hudson will insure Poughkeepsie, NY

,I that all personnel actions such as compensation, bcncfits, transfers, layoffs, return from layoff,

', Chairman of the Board and Chief Executive employer sponsored training, education, tuition assistance, social and recreational programs, Oft " Chairman of the Executive, Finance t will be administered without regard to race, scx, color, creed, religion, age, national origin, ai ment Committees *1981 i

disability, disabled veteran or Vietnam-era veteran status.

A'lIll'GoI UdomOoA Your Energy Solutions Company QP Printed on recycled paper

S K C U R.I T I K S A N D K X 'C 8 AN 6 K C 0 MMIS S I0 N WASHINGTON, D.C. 20549 Form'10-K X ANNUALREPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED]

For the fiscal year ended March 31, 1998 0 TRANSITION REPORT PURSUA'NT TO SECTION'13 OR 15(tt)

OF THE SECURITIES EXCHANGE ACT OF 1934 fNO FEE REQUIRED]

Commission file number 1-3571 Long Island Lighting pursuant to the Laws ofNew York State Company'ncorporated Internal Revenue Service - Employer Identification, Number 11-1019782 175 East Old Country Road, Hicksville,'ew'York 11801 516-755-,6650 Securities registered pursuant to Section 12(b)-of the Act:.

Title ofeach class so registered:

Common Stock ($ 5 par)

Preferred Stock ($ 100 par, cumulative):

Series B, 5.00%

eries D, 4.25%, ... Series E, 4.35%,,

Series CC, 7.66%

Series I, 5 3/4%, Convertible Nl Preferred Stock ($ 25 par, cumulative):

Series AA, 7.95% Series GG, $ 1.67 Series QQ, 7.05 Po Series NN, $ 1.95 "l General and Refunding Bonds:

7.85% Series Due 1999 8.50% Series Due 2006 9 3/4% Series Due 2021 8 5/8% Series Due 2004 7.90% Series Due 2008 9 5/8% Series Due 2024, Debentures:

7.30% Series Due 1999 7.30% Series Due 2000 7.05%

7.00%

Series Series Due 2003,,

Due 2004 8.90% Series Due 2019 9'.00% Series Due 2022 6.25% Series Due 2001 7.125% Series Due 2005 8.20% Series Due 2023 7.50% Series Due 2007 Name of each exchange on which each class is registered: The New York Stock. Exchange and the Pacific Stock Exchange are the only exchanges on which the Common'Stock is registered. The New York Stock Exchange is the only exchange on which certain of the other securities listed above are registered. k li Securities register'ed pursuant to Section '12(g) of the Act: None' '

Indicate by check mark whether the registrant (I) has filed all reports required to be filed by Section 13:or 15(d) of the Securities Exchange Act ot 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such teports) and (2) has been subject to such filing requirements for the past 90 days.

Yes X NoQ I g Indicate by check mark ifdisclosure of delinquent filersyursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated of this Form 10-K or any amendment to this Form 10-K. K by reference in Part III

'aggregate market value of the Common Stock held by non-affiliates of the Company at March 31,1998 was $ 3,832,943,909.

Th te market value of Preferred Stock held by non-aAiliates of the Company at March 31, 1998, established Bro by Lehman ed on the average bid and asked price, was $ 735,033,360.

Common Stock ($ 5 par) - Shares outstanding at March 31, 1998: 121,680,759

TABLE OF CONTENTS Abbreviations..

Item 1. B usiness.

The Company.

Territory .

Business Segments.

PART I

'I 1

Employees.

Regulation and Accounting Controls.

Long Island Power Authority,Transaction.

KeySpan Energy Corporation Transaction. 4 Competitive Environment.. .6 Electric Operations. .6 General.. .6 System Requirements, Energy Available and Reliability .7 Fuel Mix .7 Energy Sources. "'...... .7 Oil.. .7 Natural Gas . .....8 Purchased Power .8 Nuclear". .9 Interconnections. .9 Conservation'Services .9 The 1989 Settlement .9 Electric Rates. .9 Gas Operations ...........................................,..............,................ ....10 General.. 10 Gas System Requirements................................................... 10 Peak Day Capability 11 Transportation 11 Storage Cogen/IPP Deliveries.

Peagk Shaving.....

Firm Gas Supply Gas Rates Recovery of Transition Costs Natural Gas Vehicles. 12 Environmental Matters. 12 General.. 12 Air. 13 Water 15 Land 16 Nuclear Waste ..........................................~........................... .....19 The Company's Securities. 20 General.. 20 The G&R Mortgage. 20 Unsecured Debt 21 Equity Securities. 21 Common Stock 21 Preferred Stock 22 Preference Stock 22, Executive Officers of the Company 23" Capital Requirements, Liquidity and Capital Provided. 28 Item 2, Properties 28 Item 3. Legal Proceedings '28 Shoreham 28 Environmental 29 Human Resources . .30 Other Matters 30

Item 4.~ 'ubmission of Matters to a Vote of Security Holders........

tItem 5.

Item 6.

Item 7.

Item S.

Management's Discussion and Analysis of Financial Condition and Results of Operations.

Financial Statements and Supplementary Data'.

Balance Sheet PART II Market for the Registrant's Common Equity and Related Stockholder Matter....'.........~......~...31 Selected Financial Data

~

~ , ... .. .....32

......33 55 55 '.",;......

Statement of Income ................ 57 Statement of Cash Flows. 58 Statement of Retained Earnings..',. 59,'

Statement of Capitalization. ' .....'...... 59 Notes to Financial Statements. .6I of Independent Auditors: 'eport 96 Item 9. Changes in and Disagreem'eritsrWith Ac'countants on Accounting '

and Financial Disclosures...:. 97 I

PART III Item 10. Directors and Executive Officers of. the Company .. ~ ~ 98 Item 11. Executive Compensation ~ ~

~ I Item 12. Security Ownership of Certain Beneficial Owners and Management. .............. 98 Item 13. Certain Relationships and Related Transactions...........................................

I PART IV, 'I, 4

tern 14. Exhibits, Financial Statement Schedules, arid Reports on

................... 98 List of Financial Statements., 98 List of Financial Statement Schedules '............. 98 List 'of Exhibits 98 R~eorts on Form 8-K.. .......,.........98

................... 99 fr SIGNATURES ~ ~ ~ ~ ~ ~ ~ ~ ~ l~~~~~~~~~~~~~~ ~~ ~~~~ ~~~ ~ ~ ~~ ~ ~~

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PART I Item 1. Business The Company ong Island Lighting Company (Company or LILCO) was incorporated in 1910 under the ransportation Corporations Law of the State of New. York and supplies electric and gas service in Nassau and Suffolk Counties and to the Rockaway Peninsula in Queens County, all on Long Island, New York. The mailing address of the Company is 175 East Old Country Road, Hicksville, New York 11801 and the general telephone number is (516) 755-6650.

I pl On April 11, 1997, the Company changed its year end from December 31 to March 3 1..

Accordingly, unless otherwise indicated, references to 1998 and 1997 represent the twelve month periods ended March 31, 1998 and March 31, 1997, respectively, while references to all other periods refer to-the respective calendar years ended December 31.

Territory The Company's service territory covers an area of approximately 1,230 square miles. The.

population of the service area, according to the Company's 1998 Long Island Population Survey, is 2.75 million persons, including, approximately'8,500 persons who reside in Queens County within the City of New York. The 1998 population survey reflects a 1.6% increase since the 1990 census.

ll Approximately 80% of all workers residing in Nassau and Suffolk Counties are employed within the two counties. During the year ended December 31, 1997 total non-agricultural employment in Nassau and Suffolk Counties increased by approximately 18,600 positions, an employment increase of 1.7%.

e Company serves approximately 1.04 million electric customers of which approximately 931,000 are residential. The Company receives approximately 49% of its electric revenues from, residential customers, 48%;-from commerciaVindustrial, customers and the balance from sales to other utilities and public authorities. The Company also serves approximately 467,000 gas customers, 417,000 of which are residential, accounting for about,f1% of its gas revenues, 17,000 of which are commercial/industrial, accounting for 23% of its gas revenues, 3,600 of which are firm transportation customers, accounting for 3% of its gas revenues, with the balance of the gas revenues derived from off-system sales.

Business Segments For information concerning the Company's electric and gas financial and operating results, see Item 7, "Management's Discussion and Analysis of Financial'Condition and Results of Operations" and Note 13 of Notes to Financial Statements.

E<mployees, As of March 31, 1998, the Company had 5,187 full-time employees, of which 2,149 belong to Local 1049 and 1,220 belong to Local 1381 of the International Brotherhood of Electrical Workers. Effective February 14, 1996, the Company and these unions agreed upon contracts which will expire on February 13, 2001. The contracts provide, among other things, for wage increases totaling 15.5% over the term of the agreements.

Regulation and Accounting Controls The Company is subject to regulation by the Public Service Commission of the State of New York (PSC) with respect to rates, issuances and sales of securities, adequacy and continuance of service, safety and siting of certain facilities, accounting, conservation of energy, management effectiveness and other matters. To ensure that its accounting controls and procedures are consistently maintained, the Company actively monitors these controls and procedures. The Audit Committee of the Company's Board of Directors, as part of its responsibilities, periodically reviews this monitoring program.

4 The Company is also subject, in certain of its activities, to the jurisdiction of the United States Department of Energy (DOE) and the Federal Energy Regulatory Commission (FERC). In addition to accounting jurisdiction, the FERC has jurisdiction over rates that the Company may charge for the sale of electric energy for resale in interstate commerce, including rates the Company charges for electricity sold to municipal electric systems within the Company's territory, and for the transmission, through the Company's system, of electric energy to other utilities or certain industrial customers. It is in the exercise of this jurisdiction over transmission that the FERC has issued two orders relating to the development of competitive wholesale electric markets. For a discussion of these FERC Orders, see Note 12 of Notes to Financial Statements.

The FERC also has some jurisdiction over a portion of the Company's gas supplies and substantial jurisdiction over transportation to the Company of its gas supplies.

Operation of Nine Mile Point Nuclear Power Station, Unit 2 (NMP2), a nuclear facility in which the Company has" an 18% interest, is subject to regulation by the Nuclear Regulatory Commission (NRC).

n Long Island Power Authority Transaction On June 26, 1997, the Company and Long Island Power Authority (LIPA) entered into definitive agreements pursuant to which, after the transfer of the Company's gas business unit assets, non-nuclear electric generating facility assets and certain other assets and liabilities to one or more newly-formed subsidiaries of a new holding company (HoldCo), formed in connection with the LIPA Transaction and KeySpan Transaction discussed below, the Company's common stock will be sold 'to LIPA for $ 2.4975 billion in cash.

In connection with this transaction, the principal assets to'be acquired by LIPA through its stock acquisition of LILCO include: (i) the net book value of LILCO's electric transmission and distribution system, which amounted to approximately $ 1.3 billion at March 31, 1998; (ii)

LILCO's net investment in NMP2, which amounted to approximately $ 0.7 billion at March 31, 1998; (iii) certain of LILCO's regulatory assets associated with its electric business;-and (iv) allocated accounts receivable and other assets. The regulatory assets to be acquired by LIPA amounted to approximately $ 6.6 billion at March 31, 1998, and primarily consist of the Base Financial Component (BFC), Rate Moderation Component (RMC), Shoreham post-settlement costs, Shoreham nuclear fuel, and the electric portion of the regulatory tax asset. For a further discussion of these regulatory assets, see Note 1 of Notes to Financial Statements.

LIPA is contractually responsible for reimbursing-HoldCo for postretirement benefits other than pension costs related to employees of LILCO's electric business. Accordingly, upon consummation of the transaction, HoldCo will reclassify the associated regulatory asset for postretirement benefits other than pensions to a contractual receivable.

The principal liabilities to be assumed by LIPA through its stock acquisition of LILCO include 2

I (i) LILCO's regulatory liabilities associated with its electric business; (ii) allocated accounts payable, customer deposits, other deferred credits and claims and damages; and (iii) certain series of long-term debt, a portion of which will be refinanced. The regulatory liabilities to be assumed by LIPA amounted to approximately $ 365 million at March 31, 1998, and primarily consist of the egulatory liability component, 1989 Settlement credits and the electric portion of the regulatory tax liability. For a further discussion of these regulatory, liabilities, see Note 1 of Notes to Financial Statements.

The long-term debt to be assumed by LIPA will consist of; (i) all amounts then outstanding under the General and Refunding (G&R) Indentures; (ii) all amounts then outstanding under the Debenture Indentures, except as noted below; and (iii) substantially all of the tax-exempt authority financing notes. HoldCo is required to assume the financial obligation associated with the 7.30/ty Debentures due July 15, 1999, with an aggregate principal amount currently outstanding of $ 397 million and 8.2010 Debentures due March 15, 2023, with an aggregate principal amount currently outstanding of $ 270 million. HoldCo will seek to exchange its Debentures, with identical terms, for these two series of Debentures and will issue a promissory note to LIPA in an amount equal to the unexchanged amount of such Debentures. HoldCo mill also issue a promissory note to LIPA for a portion of the tax-exempt debt borrowed to support LILCO's current gas operations, with terms identical to those currently outstanding. The Company currently estimates tge amount of this promissory note to be approximately $ 250 million.

In July 1997, in accordance with the provisions of the LIPA Transaction, the Company and The Brooklyn Union Gas Company (Brooklyn Union) formed a limited partnership and each Company invested $ 30 million in order to purchase an interest rate swap option instrument to protect LIPA against market risk associated with the municipal bonds expected to be issued by LIPA to finance e transaction. Upon the closing of the LIPA Transaction, each limited partner will receive. from PA $ 30 millio'n plus interest thereon, based on each partners'verage weighted cost of capital.

the event that the LIPA Transaction is not consummated, the maximum potential loss to the Company is the amount originally invested. In such event, the Company plans to defer any loss and petition the PSC to allow recovery from its customers.

As part of the LIPA Transaction, the definitive agreements contemplate that one or more of HoldCo will enter into agreements with LIPA, pursuant to which such subsidiaries

'ubsidiaries willprovide management and operations services to LIPA with'respect to the electric transmission and distribution system, deliver power generated by its power plants to LIPAand manage LIPA's fuel and electric purchases and any off-system electric'sales. In addition, three years aAer the LIPA Transaction is consummated, LIPA will have the right for a one-year period to acquire all of HoldCo's generating assets at the fair market value at the time of the exercise of the right, which value will be determined by independent appraisers.

In July 1997, the New York State Public Authorities Control Board (PACB), created pursuant fo the New York State Public Authorities Law and consisting of five members appointed by})hebq ~s,,

governor, unanimously approved the definitive agreements related to the LIPA Transaction'subject to the following conditions: (I) within one year of the effective date of the transaction,Ii,+rtp)n-;; ! it ttr establish a plan for open access to the electric distribution system; (ii) ifLIPA exercises its optiqn- .

to acquire the generation assets of HoldCo's generation subsidiary, LIPA may not purchase the g" generating facilities, as contemplated in the generation purchase right agreement, 'at a price "greater'han book value; (iii) HoldCo must agree to invest,'ver a ten-year period, at least $ 1.3 billidn in y-related and economic development projects, and natural gas infrastructure proJects on Long d; (iv) LIPA will guarantee that, over a ten-year period, average electric rates will be reduced 3

by no less than 14% when measured against the Company's rates today and no less than a 2% co's<<

savings to LIPA customers must result from the savings attributable to the merger of LILCO and KeySpan; and (v) LIPA will not increase average electric customer rates by more than 2.5% over a twelve-month period without approval from the PSC. LIPA has adopted the conditions set forth by the PACB. The holders of common and certain series ofpreferred stock of the Company eligible to vote approved the LIPA Transaction in August 1997.

In December 1997, the United States Nuclear Regulatory Commission (NRC) issued an order approving the indirect transfer of control of the Company's 18% ownership interest in NMP2 to LIPA. /

r In December 1997, the Company filed with the FERC a settlement agreement reached with LIPA in connection with a previous filing of the Company's proposed rates for the sale of capacity and energy to LIPA, as contemplated in the LIPA transaction agreements. The Company also had previously filed an application with the FERC seeking approval of the transfer of the Company's electric transmission and distribution system to LIPA in connection with L'IPA's purchase of the common stock of the Company. W In February 1998, the'FERC issued orders on both of the Company filings. Specifically, the FERC approved the Company's application to'trarisfer assets to LIPA in connection with LIPA's acquisition of the Company's common stock. In addition, the FERC accepted the Company's proposed rates for sale of capacity and energy to LIPA. Those rates may go into effect. on the date the service to LIPA begins, subject to refund, and final rates will be set after the FERC has completed its investigation of such rates, the timing of which cannot be determined at this time.

In January 1998, the Company filed an application with the PSC in connection with the proposed transfer of its gas business unit assets, non-nuclear generating facility assets and certain other assets and related liabilities to one or more subsidiaries of HoldCo to be formed as contemplated in the LIPA Transaction agreements. Op April 29, 1998, the PSG approved the transfer of the above-mentioned assets.

In July 1997, the Company, Brooklyn Union and LIPA filed requests for private letter rulings with the Internal Revenue Service (IRS) regarding certain federal income tax issues which require favorable rulings in order for the LIPA Transaction to be consummated. On March 4, 1998, the IRS issued a private letter ruling confirming that the sale of the Company's common stock to LIPA would not result in a corporate tax liability to the Company. In addition, the IRS ruled that, after the stock sale, the income of LIPA's electric utility business will not be subject to federal income tax. In a separate ruling on February 27, 1998, the IRS also ruled that the bonds to be issued by LIPA to finance the acquisition would be tax-exempt.

In January 1998, the Company filed an application with the SEC seeking an exception for most of the provisions of the Public Utilities Holding Company Act o'f 1935. In May 1998, the SEC issued an order approving the Company's application.

The Company currently anticipates that the LIPA transaction willbe consummated on or about May 28, 1998.

KeySpan Energy Corporation Transaction On December 29, 1996, The Brooklyn Union Gas Company (Brooklyn Union) and the Company entered-into an Agreement and Plan of Exchange and Merger (Share Exchange Agreement),

pursuant to which the companies will be merged in a transaction (KeySpan Transaction) that will result in the formation of HoldCo.

The Share Exchange Agreement was amended and restated to reflect certain technical changes as f February 7, 1997 and June 26, 1997. Effective September 29, 1997, Brooklyn Union reorganized into a holding company structure, with KeySpan, Energy Corporation (KeySpan) becoming its parent holding company. Accordingly, the parties entered into an Amendment, Assignment and Assumption Agreement, dated as of September 29, 1997, which among other things, amended the Share Exchange Agreement and related stock option agreements to reflect the assignment by Brooklyn Union to KeySpan and the assumption by KeySpan of all Brooklyn Union's rights and obligations under such agreements.

The KeySpan Transaction,'which has been approved by both c'ompanies'oards of directors and shareholders, would unite the resources of the Company with the resources of KeySpan. KeySpan, with approximately 3,300 employees, distribu'tes natural gas at retail, primarily in a territory of 187 square miles which includes the b'o<oughs of Brooklyn and Staten Island and 'pproximately two-thirds of the borough of Queens, all in New York City. KeySpan has energy-related investments in gas exploration,>production and.marketiitg'ih the United States and Northern Ireland, as well as energy services in the United States, including cogeneration projects, pipeline transportation and gas storage.

Under the terms of the KeySpan Transaction, the Company's common shareownbrs will receive 0.803 shares (the Ratio) of HoldCo's common stock for each share of the Compaq'ommon stock that they hold at the time of closing. KeySpan common shareowners will receive one share of common stock of HoldCo for each common share of KeySpan they hold at the time of closing.

Shareowners of the Company will own approximately 66/o of the common stock of HoldCo while ySpan shareowners will own approximately 34/o. In the event that the LIPA Transaction is nsummated, the Ratio will be 0.880 with Company shareowners owning approximately 68/o of the HoldCo common stock. Consummation of the Share'xchange Agreement is not conditioned upon the consummation of the LIPA Transaction and consummation of the LIPA Transaction is not conditioned upon consummation of the Share Exchange Agreement. Based on current facts and circumstances, it'is probable that the purchase'method of accounting will apply to the KeySpan Transaction, with the Company being the acquiring 'company for accounting purposes.,

In March 1997, the Company filed an application with the FERC seeking approval of the transfer of the Company's common equity and certain FERC-jurisdictional assets to HoldCo. In July 1997, the FERC granted such approval.

The Share Exchange Agreement contains certain covenants of the parties pending the consummation of the transaction. Generally, the parties must carry on their businesses in the ordinary course consistent with past practice, may not increase dividends on common stock beyond specified levels and may not issue capital stock beyond certain limits. The Share exchange Agreement also contains restrictions on, among other things, charter and by-law amendments, capital expenditures, acquisitions, dispositions, incurrence of indebtedness, certain increases in employee compensation and benefits, and affiliate transactions.

The Company and KeySpan expect to continue their respective current dividend policies until completion of the KeySpan Transaction. It is anticipated that HoldCo will set an initial annual

'dend rate of $ 1.78 per share for its commop stock.

Upon completion of the merger, Dr. William J. Catacosino's will become chairman and chief.

executive officer of HoldCo; Mr. Robert B. Catell, currently chairman and chief executive officer-of KeySpan, will become president and chief operating officer of HoldCo. One year after the closing, Mr. Catell will succeed Dr. Catacosinos as chi'ef executive officer, with Dr. Catacosinos continuing as chairman. The board of directors of HoldCo w'ill be comprised of 15 members, six from the Company, six from KeySpan and three additional persons previously unaffiliated with either company.

Effects ofLIPA and E'eySpan Transactions on Future Operations The future operations and financial position of the Company will be significantly affected by each of the proposed transactions with LIPA and KeySpari described "above. The discussion contained in this report and any analysis of financial condition an'd results of operations does not reflect, unless otherwise indicated, the potential effects of the transactions with LIPA and KeySpan.

Competitive Environment A discussion of the competitive issues the Company faces appears in Note 12 of Notes to Financial Statements.

Electric Operations t ~ 'jl I General The Company's system energy requirements are supplied from sources located both on and off Long Island. t The following table indicates the 1997 summer capacity of the Company's steam generation facilities, Internal Combustion (IC) Units and other, generation facilities as reported to the New York Power Pool (NYPP): ~ ~ i t Location of Units Description Fuel Units MW Company Owned: l Northport, L.I. Steam Turbine Dual*. 2 778, Oil 2 754 Port Jefferson, L.I. Steam Turbine Dual* 2 382 Glenwood, L.I. Steam Turbine Gas 2 218 Island Park, L.I. Steam Turbine Dual* 386'09 22 Far Rockaway, Steam Turbine Dual*

L.I.L.I.'hroughout IC Units 'ual*

279 Oil* 30 1,072 Jointly 0wned:

NMP2 (18% Share) Oswego, New York Steam Turbine Nuclear 1 205 Owned by the New York Power Authority Holtsville, L.I. Combined Cycle Dual*" 142 Total 55 4,325

• Dual - Oil or natural gas. E 1

r Additional generating facilities owned by others, such as indeperident power producers (IPPs) and cogenerators located on Long Island and investor-owned and public electric systems lochted off Long Island provide the balance of the Company's energy supplies.

The maximum demand on the Company's system was 4,"140 Megawatts (MW) on July 15, 1997, representing 84% of the total available capacity of 4,953 MW on that day, w'hich included 766 MW of firm capacity purchased from other sources. By agreement with the NYPP, the Company is required to maintain, on a monthly basis, an installed and contracted firm power reserve 6

generating capacity equal to at least 18% of its actual peak load. The Company continues to meet.

this NYPP requirement.

h stem Re uirements Ener -Available and Rel b'1 1r or the year ended March 31, 1998, system kilowatt hours (kWh) energy requirements on the Company's system were 1.0% higher than the corresponding 1997 period. The Company forecasts increases of 2.3% and 3.2%, for'the years ending March 1999 and 2000, respec'tively compared to that experienced for the year ended March 31, 1998. For the years ending March 31, 2001-2010, the Company forecasts an average annual growth rate in system energy requirements of 1.1%.

Due to the effects of price ela'sticity, the projected peak demand for electric power is expected to increase ifthe LIPA transaction is consummated. Base'd'on projecti'ons of peak'demand for electric power in the',absence of the LIPA Transaction, the Company believes it will'need to, acquire additional generating or demhand-side resources starting in 1998 in order to maintain electric supply reliability. In accordance with the Company's Integrated Electric Resource Plan (IERP), issued in 1996, the Comp'any intends to institute a combinati'on of a peak load reduction'emand-side management program and a capacity purchase to meet this need. Current projections are that new electric generating capacity will not need to be installed on Long Island to meet. peak demand until aAer 2002. It is anticipated that'such new. capacity would be acquired through a competitive bidding process.

Fuel Mix The megawatt hours'(MWh) and percentages of total energy available by, type of fuel for electric operations for the years ended March 3 1; 1998 and 1997, and-the years ended December 31, 1996 and 1995 were as follows:

Inthousands fMWh Ended , Year Ended

'ear March 31 December 31 1998 1997 '996 1995 MWh MWh  % MWh  % "1 MWh Oil 3,434 20% 3,278 - 19% 4,219 '24% 3 099 17%

Gas 6,212 35% 5 469 31% ',542 25%: 6,344 i 36%

Nuclear 1 545 9% 1,553 9%'" 558 9% 301 7%

'7 1 1 Purchased ower 6 412 36% 7 261 41 7 388 42% 7 143 40%

Total 17 603 100% 561 100% 17 707 100% 17 887 100%

Ii i i The total energy provided by oil and natural gas is generated by the Company's units located on Long Island, while the nuclear generation is provided through.NMP2, the Company's 18% owned>

nuclear power plant which is located near Oswego, New York. ~

h i'1 Osl The availability and cost of oil used by the Company is affected by factors such as the in'ternational.oil, m'arket, environmental regulations,,conservation measures and the availability of, alternative fuels. In order to reduce the impact of the above factors on-the Company's operations,,

. the Company, over the past several years, has,refitted the majority ofjts steam gen'eration units enabling them to burn oil or natural gas, whichever is more economical and consistent with seasonal environmental requirements.'he Company's fuel oil is supplied principally by three pliers.

Oil consumption in barrels was as follows:

Years Ended Consumption (in barrels)

~

March 31 1998 5.6 million March 31 1997, 5.5 million December 31 1996 7.1 million December 31 1995 5.2 million Natural Gas Nine of the Company's eleven steam generating units have the'capability of burning natural gas.

Seven of these units are capable of burning either oil o'r natural gas. This enables the Company to burn the most cost-efficient fuel, consisten't with seasonal environmental requir'ements, thereby reducing the Company's generation costs. In April 1996 and May 1997, the Company completed two planned conversions of oil-fired steam generating units at its Port Jefferson Power Station to dual-firing units.

Gas consumption for electric generation was as follows:

Years Ended Consumption (in million Dth)

March 31 1998 69.4 March 31 1997 63.6 December 31 1996 50.2 December 31'995 69.8 The percentage of energy generated by burning natural gas at the Company's steam and internal combustion units was as follows:

Years Ended Percent Generated March 31 1998 64%

March 31 1997 63%

December 31 1996 52%

December 31 1995 67%

Purchased Power The Company strives to provide its customers with the most economical energy available to keep electric rates as low as possible. Often, this energy is generated more economically at power plants within other electric systems and transmitted to the Company through its interconnections.

In addition, the Company is required to purchase energy from sources located within its service territory including the New York Power Authority (NYPA)'Holtsville facility, IPPs and cogenerators. IPPs and cogenerators located within the Company's service territory provided approximately 206 MW of capacity to the Company during the year ended March 31, 1998.

The percentage of the total energy made available to the Company by IPPs, cogenerators and the NYPA Holtsville facility was follows:

Years Ended Percent of Energy Available March 31 1998 17.2%

March 31 1997 16.1%

December 31 1996 December 31 1995 16 3%

8

Tile Company does not expect any new major IPPs or cogenerators to be built on Long Island in the near future. Among the reasons supporting this conclusion is the Company's belief that the market for IPPs and cogenerators to provide. power to the Company's remaining commercial and

~ ~

dustrial customers is small. Furthermore, under federal law, the Company is required to buy

~

nergy from qualified producers at the Company's long-range avoided costs. Current long-range "

avoided cost estimates for the Company have significantly reduced the economic advantage to entrepreneurs seeking to compete with the Com'pany and with existing IPPs. For additional information with respect to competitive'issues facing the Company, see Note 12 of Note's to Financial Statements.

1 8

Nuclear 4 The Company holds an 18% interest in NMP2, an 1,137 MW nuclear generating unit near Oswego, New York, which is operated by Niagara Mohawk Power Corporation (NMPC). The cotenants of NMP2,"in addition to the Company,'are NMPC (41%), New York- St'ate Electric &

Gas Corporation (18%), Rochester Gas and Electric Corporation (14%) and Central Hudson Gas &,

Electric Corporation (9%). For the year ended Mar'ch 31, 1998, NMP2 operated at 86.63% 'of its capacity. For a further discussion of NMP2, see Note 5 of Notes to Financial Statements.

ff Interconnections Five interconnections allow for the transfer of electricity between the Company and members of the NYPP and the New England Power Pool. Energy from these sources is transmitted pursuant to ',

transmission agreements with NMPC, NYPA, Northeast Utilities Service Company (NUSCO), a co-owner of one of these interconnections, and Consolidated Edison Company of New York, Inc.

(Con Edison) and displaces energy that would otherwise be generated on the Company's system at a higher cost. The capacity of these interconnections is utilized for Company'equirements eluding the transmission of the Company's share of power from NMP2, the requirements of Con ison, a co-owner with the Company of three of these interconnections, and the requirements on ong Island of NYPA, the owner of one of these interconnections.

Conservation Services A discussion of conservation services appears in'tem 7, "Management's Discussion and Analysis'f Financial Condition and Results of Operations."

The 1989 Settlement r

In February 1989, th'e Company and the State of New York entered into the 1989 Settlement resolving certain issues relating to the Company and pro9idin'g, among other matters, for the financial recovery of the Company and for the"transfer of the Shoreham'Nuclear Power Station (Shoreham) to LIPA for its subsequent decommission'ing.

II A discussion of the 1989 Settlement and Shoreham decommissioning appears in Note 10 of Notes to Financial Statements.

Electric Rates A discussion of electric rates appears in Note 4 of Notes to Financial Statements.

e Gas Operations S

q General '

The Company's gas supplies are transported by interstate pipelines from Canadian and domestic sources. On-.system peak shaving and IPP/Cogen peaking supplies are available to meet system requirements during winter periods.

During the past several years, the Company actively participated in proceedings before the FERC in an effort to mitigate any. adverse impact that filings by interstate pipeline companies might have.

on the Company's gas customers as well as to decrease upstream transportation costs and improve operational tariffs. The Company also actively participated in the proceedings before the PSC which established the framework for a.new competitive natural gas marketplace within the State of New York. g 1

In. response to changes in federal and state regulations that have "unbundled" traditional pipeline services in order to promote competition in the gas supply and gas services market, the Company implemented its NaturalChoice firm transportation program in April 1996. Under NaturalChoice, customers may purchase natural gas from qualified suppliers other than the Company. The Company continues to provide NaturalChoice customers with all gas services provided to traditional customers except for the procurement and sale of gas. These services include the local transportation of gas, meter reading and billing,,equipment maintenance and emergency response. The Company's profit margins have not been impacted by. this new program as the Company collects from these customers all costs associated with providing its service, including operating the gas system.

As of March 31, 1998, there were approximately 3,600 NaturalChoice customers with annual requirements of approximately 4,213,000 Dth or 7 percent of the Company's annual gas system requirements.

Gas S stem Re uirements The Company has 467,000 firm gas customers at March 31, 1998, including 295,000 gas space heating customers, an increase of more than 15,000 gas space heating customers over the past three years. The Company's penetration in the gas space heating market within its seryice territory is approximately 29%.

Total firm sales for the year ended March 31, 1998, when normalized for weather, decreased approximately 3.6% overthe comparable period in 199$ primarily due to customers switching to the NaturalChoice Program. The maximum daily sendout experienced on the Company's gas system was 585,227 Dth on January, 19, 1994, representing 83% of the Company's per day capability at that time. The forecasted maximum daily sendout for the 1998-1999 winter season (November 1 - March 31) is approximately 652,000 Dth, or 88% of the Company's peak-day capability.

10

Peak Da Ca abili The Company has firm gas peak day capability in excess of its projected requirements for firm gas customers for the 1998-1999 winter season (November 1-March 31). Firm capability is ummarized in the following table.' I i

Dth 'per da  % of Total Transportation 263,000 35

'torage 294,000 40

.'ogen/IPP Deliveries 85,000. , 11 Peak Shaving 103,000 14 Total 745,000 100%

l II I i Transportation The Company has available under firm contract 263,000 Dth per day,of year-r'ound and seasonal pipeline transportation capacity which is provided by four interstate pip'eline companies including the Iroquois Gas Transmission System. The Company, through its majority,, intei;est in a, subsidiary, LILCO Energy Systems, Inc., is a general partner in the Iroquois pipeline with an equity share of 1%.

Storage In order to meet higher winter demand, the Company also has long-term firm market area storage services in Pennsylvania and New York which provide a total maximum supply of 294,000 Dth per day, with a total. capacity of 22,534,000 Dth for the winter period.

• I

) ,g II In order to provide the Company with greater security, of supply and enhanced operational in meeti'ng peak-day requirements, the Company also contracts for production area . 'lexibility rage capacity in Louisiana and Mississippi. However, the Company has no jncremental firm eline transportation capacity for these supplies.

II Cogen/IPP Deliveries The Company has'contract rights with the Brooklyn Navy Yard Cogen facility to 576,000 Dth of peaking supplies during the winter period at'a rate of approximately receive'pproximately 30,000 Dth per day. Also, the Company has contract rights with the Nassau District Energy Corporation to receive 250,000 Dth of peaking supplies during the winter period at a'rate'of 12;500 Dth per day.

'he Company has contract rights with the NYPA IPP facility to receive 900,000 Dth of storage service during any'continuous 100-day period during each winter'season at a daily rate not to exceed 31,000 Dth'per day. In addition, the Company has contract righ'ts with Nissequogue Cogen facility to "receive up" to 330,000 Dth'of storage service for'30 days during each winter season at a' daily rate not'to exceed '11,000 Dth per day. The Company has the obligation to return these quantities in kind during the following summer period. In addition, the Company has the right 812,000 Dth in the winter season from the TBG Cogen facility with the obligation to return to'equest the quantities in kind during the following summer period. The daily quantity of 12,500 Dth is only available on warmer winter days.

Peak Shaving The Company has its own peak shaving supplies to meet its firm requirements on excessively cold nter days. They include a liquefied, natural gas plant with a storage capacity of approximately 000 Dth and vaporization facilities which provide approximately 103,000 Dth per day to the 11

IiiI peak-day capability S

of the Company's system.

The Company has approximately 161,000 Dth per day of firm gas supplies that are transported

'I under its firm pipeline transportation capacity. About 83,000 Dth per day is obtained from

'4

Canadian sources and 78,000 Dth per. day,is obtained from domestic sources. Included in the long-term firm Canadian gas is about'3,000 Dth per day'f gas contracted with Boundary Gas, Inc.

(Boundary). The Company owns 2.7% of the common stock of Boundary, a corporation formed with 14 other gas utility companies to act as a purchasing agent for the importation of natural gas "

Canada. 'rom The Company's 161,000 Dth per day of long-term supply contracts have commodity rates that are market-based. The Company has no fixed price supply contracts. Certain of these contracts'have minimum'annual'take or pay ar'rangements and/or associated demand charges".

The Company also'purchases various quantities of market-priced'gas in both the seasonal and spot'markets that is transported under firm and interruptible transpo'rtation agreements. 'onthly Gas Rates A discussion of gas rates appears in Note 4 of Notes to Financial Statements.

Recove of Transition Cos'ts

• Transition costs are the costs associated'with unbund/ing the pip'eline companies'erchant services in compliance with.FERC Order No. 636. They include pipeline companies'..unrecovered gas costs and the costs that pipelines incur as,"a result of modifying or terminating their gas supply contracts. In o'rder "to recover transition costs, pipelirie companies must demonstrate to the FERC that such costs were attributable to Order No. 636 and that they were prudently incurred. While the Company has challenged, on both eligibility and prudence grounds, its supplier'ipelines'fforts to recover their claimed transition costs, the Company estimates that it will be responsible.

for total transition costs of approximately $ 10 million. As of March 31, 1998, the Company has collected $ 8.7million of these transition costs, from its gas customers.,

I, Natural Gas Vehicles 'I II The Company continues to maintain a focus on promoting Natural Gas Vehicles (NGVs) and infrastructure development. Additional resources have been dedicated to the NGV program in 1997 and 1998 and an arrangement with a company named Fuelmaker has provided customers with a low risk, low cost. approach to refueling their NGVs. In addition, consistent with a Clean Cities designation, the Company has aggressively assisted customers in obtaining Congestion Mitigation Air Quality (CMAQ) grants and,other Department of Energy funds to help offset their, incremental NGV and refueling equipment costs. As a result of these efforts, NGVs consumed approximately130,000,Dth and resulted in $ 260,000 in revenue net of fuel for the year ended March 3,1, 1998.

II Matters '

1 I'nvironmental General The Company's ordinary business operations necessarily involve materials and activities which subject the Co'mpany to federal, state and local laws, rules and regulations dealing with the environment, including air, water and land quality. These environmental requirements may entail significant expenditures for capital improvements. or modifications and may expose the Company 12

to,potential liabilities which, in certain instances, may be imposed without,regard to fault or for historical activities which were lawful at the time they occurred.

Laws which may impose such potential liabilities include (but are not limited to) the federal, omprehensiye Environmental Response, Compensation and Liability Act (CERCLA, commonly own as Superfund), the federal Resource Conservation and Recovery Act, the federal Toxic Substances Control Act (TSCA), the federal Clean Water Act (CWA), and the federal Clean Air ~

Act (CAA).

Capital expenditures for environmental improvements and related studies amounted to approximately $ 9.2 million for the year ended March 31, 1998 and,,based on existing information, are expected to be $ 4.0 million for the year ended March 31, 1999. The expenditures in fiscal year 1998 and expected spending in fiscal year 1999 include a,total of $ 10.6 million for the completion of a gas-firing capability project at Northport Unit 1 and Port Jefferson Unit $ .

It is not possible if to ascertain with certainty or when the various required governmental approvals for which applications have been made will be issued, or whether, except as noted below additional facilities or modifications of existing or planned facilities will be required oi, generally, what effect existing or future controls may have upon Company operations. Except as set forth below and in Item 3 - "Legal Proceedings," no material proceedings have been commenced or, to the knowledge of the Company, are contemplated by any federal, state or local agency against the Company, nor is the Company a defendant in any material litigation with respect to any matter relating to the protection of the environment.

Recoverabili o Environmental Costs" The Company believes that none of the environmental matters, discussed below, will have a terial adverse impact on the Company's financial position, cash flows or results of operations...

addition, the Company believes that all significant costs incurred with respect to environmental

~ ~

investigation and remediation activities, not recoverable from insuiance carriers, will be recoverable from its customers.

lt \

I Air , 1 L

Federal, state and local regulations affecting new,and existing electric generating plants govern emissions of sulfur dioxide (SO,), nitrogen oxides (NO), particulate matter, and, potentially in the future, fine particulate matter (aerosols of SO,), ha'zardous air pollutants and carbon dioxide (CO,).,

Sulfur Dioxide Requirements The laws governing the sulfur content of the fuel oil being burned by the Company in compliance, with the United States Environmental Protection Agency (EPA) approved Air Quality State Implementation Plan (SIP) are administered by the New York State Department of Environmental Conservation (DEC). The Company does not expect to incur any costs to satisfy the 1990, amendments to the federal CAA with respect to the reduction of SO, emissions, as the Company already uses natural gas and oil with acceptably low levels of sulfur as boiler fuels. These fuels also result in reduced vulnerability to any future fine particulate standards implemented in the form of stringent sulfur dioxide emission limits. The Company's use of low sulfur fuels has resulted, and will continue to result, in approximately 70,000 excess SO, allowances per year through the year 1999. The Company presently applies the proceeds resulting from any sales of excess SO, allowances as a reduction to the RMC balance. ~

ompany entered into a voluntary Memorandum of Understanding with the DEC which 13

provides that the Company will not sell SO, allowances for use in 15 states in an effort to mitigate the transport of acid rain precursors into New York State from upwind states.

Nitrogen Oxides Requirements Due to the Company's program of cost-effective emission reductions, including the optimization of natural gas firing ability at almost all the steam electric generating stations, the Company had the lowest NOemissions rate of all the utilities in New York State for the years ended December 31, 1997, 1996 and 1995. 'Since the Company's generating facilities are located within a CAA

, Amendment-designated ozone non-attainment area, they are subject to NOreduction requirements which are being implemented in three phases. Phase I was completed in 1995; Phase II and Phase III will be completed in 1999 and 2003, respectively.

The Company is currently in compliance with Phase I NOreduction requirements. It is'estimated that additional expenditures of approximately $ 1 million will be required to'meet Phase II NO reduction requirements. Subject to requirements that are expected to be promulgated in forthcoming regulations, the Company estimates that it may be required to spend an additional $ 10 million to $ 34 million, excluding the Northport Unit 1 conversion, by the year 2003'o meet Phase NOreduction requirements. The completion of the project to add gas-firing'apability at

'II Northport Unit 1 (completed in May 1998 at a total cost of approximately $ 8.4 million) will also facilitate the Company's compliance with the anticipated Phase IIINoreduction requirements.

Continuous Emission Monitoring Additional sofbvare and equipment upgrades for Continuous Emissions Monito'rs of approximately

$ 2 million may be required through 1999 at all generating facilities in order to meet EPA requirements under development for the NOallowance tracking/trading program.

Hazardous Air Pollutants Utilityboilers are presently exempt from regulation as sources of hazardous air pollutants until the EPA completes a study of the risks, ifany, to public health reasonably anticipated to occur as a result of emissions by electric generating units. The EPA is expected to make a determination the need for control of hazardous air pollutants from utility facilities in 1998. Until 'oncerning such determination is made by the EPA, the Company cannot fully ascertain what, ifany, costs will be incurred for the control of hazardous air pollutants.

However, after the expenditure of approximately $ 1.5 million in fiscal 1998 and the planned spending of $ 0.5 million through March 31, 1999, for electrostatic precipitator upgrades and, with the maximization of clean burning natural gas as the primary fuel, hazardous air pollutant regulations, ifenacted, should not impose any additional control requirements for the Company's facilities.

m k

Carbon Dioxide Requirements CO, emissions from the Company's plants haze been reduced by approximately 23% since 1990, largely through greater reliance on the use of natural gas and through conservation programs. This makes the Company less vulnerable to future CO, reduction requirements.

'pacity Issues The DEC has proposed commencing enforcement actions'gainst all New York utilities for alleged opacity exceedences from steam electric generating facilities. Opacity is a measure of the relative level of light that is obscured from passing through a power plant stack emission plume. An exceedence occurs when the level of light passing through the plume is reduced by more than 20%

14 0

for six mihutes or mor'.'The Company has entered into an Adininistrative Consent Order (ACO) with the DEC which resolves all historical opacity exceedences, establishes an opacity reduction program to be undertaken by the Company, and sets a stipulated penalty schedule for future xceedences. The number of exceedences'experienced by the Company is relatively low, placing e Company among the best performers in New York State.

Electromagnetic Fields Electromagnetic fields (EMF) occur naturally and also are'produced wherever there is electricity.

These fields exist around power lines and other'utility equipment. The Company is in compliance with all applicable regulatory standards and requirements concerning EMF. "The Company also monitors scientific developments in the study of EMF, has contributed to funding for research efforts, and is actively involved in customer and employee outreach programs to inform the community of EMF developments as they occur. Although an extensive body of scientific literature has not shown an unsafe" exposure level or a causal relationship between EMF exposure and adverse health effects, concern over the potential for adverse health effects will likely continue without final resolution for some time. To date, four residential property owners have initiated separate'lawsuits against the Company alleging that the e'xistence of EMF has diminished the value of their homes. These actions are in the preliminary stages of discovery and are similar to actions brought against another New York State utility, which were dismissed by the New York State Court of Appeals. 'he Company is not involved in any active litigation that alleges a causal relationship between exposure to EMF and adverse health effects.

Water Under the federal CWA and the New York State Environmental Conservation Law, the Company is required to obtain a State Pollutant Discharge Elimination System permit'to make any discharge to the waters of the United States o'r New Yor'k State. The DEC has the jurisdiction to issue se permits and their renew'als arid has issued permits for the Compan'y's 'generating units. The permits allow the continued use of the circulating water systems which have been determined to be in compliance with state water quality standards. The permits also allow for the continued use of the chemical treatment systems and for the continued discharge of water'n accordance with applicable permit limits.

v V H F

. In fiscal year 1998, the Company spent approximately"$ 300;000 to upgrade its waste water treatment facilities and for other measures designed to pro'tect surface and ground water qu'ality and expects to spend an'additional $ 100,000 in the years 1998-2000.

Long Island Sound Transriiission Cables "

During 1996, the Connecticut Departm'ent ofEnvironment'al Protection (DEP) issued a modification to an Administrative Consent Order (ACO) previously issued in connection with an investigation of an electric transmissio'n cable system located under the Long Island Sound (Sound Cable) that is jointly owned by the Company and'the'onnecticut Light and Power Company (Owners). The mbdified ACO requires the Owners to submit to the DEP and DEC a series of reports and studies de'scribing cable system condition, operation and r'epair practices, alternatives for cable improvements or r'eplacement and environmental impacts associated with leaks of fluid into the Long Island Sound which h'ave occurred fr'om time to time. The Company continues to compile required information and coordinate the'activities necessary to perform these studies and at the present time, is unable to determine the 'costs it will incur to'complete the requirements of odified ACO or to,comply with any additional requirements.

15

The Owners have also entered into an ACO with the DEC.as a result of leaks of dielectric fluid' from the Sound Cable, The ACO formalizes the DEC's,authority to participate in and separately approve the reports and studies being prepared pursuant to the ACO issued by the,DEP. In addition, the ACO settles any DEC claim for natural resource damages in connection with historical releases of dielectric fluid from the Sound Cable.

In October 1995, the U.S. Attorney for the District of Connecticut had commenced an investigation regarding occasional releases of fluid from the Sound Cable, as well as associated operating and maintenance practices. The Owners have provided the U.S. Attorney with all requested documentation. The Company believes that all activities associated with the response to occasional releases from the Sound Cable were consistent with legal and regulatory requirements.

I E

In December 1996, a barge, owned and operated by a third party, dropped anchor which then dragged over and damaged the, Sound Cable, resulting in the release of dielectric fluid into Long.

Island Sound. Temporary clamps and leak abaters were, installed on the cables to stop the leaks.

Permanent repairs were completed in June 1997. The cost to repair the Sound Cable vyas approximately. $ 17.8 million, for which there was $ 15 million of insurance coverage. The Owners filed a claim and answer, in response. to,the maritime limitation proceeding instituted by the barge owner in the United States District Court, Eastern District of New York. The claim seeks recovery of the amounts paid, by insurance carriers and recovery of the costs incurred for which there was no, insurance coverage. Any costs to repair the Sound, Cable which are not reimbursed by a third party or covered by insurance will be shared equally by the Owners.

Land U Superfund imposes joint,and several liability, regardless, of fault, upon generators of hazardous substances for,costs associated with environmental cleanup activities. Superfund also imposes, liability for remediation of pollution caused by historical acts which were. lawful at the time they occurred. i

, I In the course of the Co'mpany's ordinary busiriess'operations, the Company is involved in th' handling of materials"that are deemed to be hazardous subsfa'nc'es under Superfund. These materials include asbestos, metals, certain flammable and organic compounds and dielectric fluids containing polychlorinated biphenyls (PCBs)..Other hazardous substances, may be handled in the Company's,operations or may be present at Company. locations as a result of historical practices by the Company or its predecessors in interest.,The Company has,received notice concerning possible claims under Superfund or analogous state la'ws relating to a number of sites at which it is alleged that hazardous substances generated by the Company and other, potentially. responsible, parties (PRPs) were deposited. A discussion of these sites is set forth below.

J, Estimates'of the Compa'ny's allocated shar'e of c'osts'for'investigative, removal and remedial activities at these sites range from preli'minary to refined and are updated as new information becomes available. In De'cember 1996, the Company filed a complaint in'he United States District Court for the Southern District of New York agaIrist 1$ of the Company's insurers which general comprehensive lIability (GCL) policies to the Company. In'January 1998, the .

'ssued a similar action against the same,and certain additional insurer defendants'ompany,"commenced in New York State Supreme Court,'irst Department; the federal court action was subsequently dismissed in March 1998. The Company is seeking recovery, under the GCL policies'for the costs incurred to date and future costs associated with the clean-up of the Company's former manufactured gas plant (MGP) sites and Superfund sites for.which the Company has been named a PRP. The Company is seeking a declaratory judgment that the defendant insurers are'bound by the 16 0

terms of the GCL policies, subject to the stated coverage limits, to reimburse the Company for the clean up costs. The outcome of this proceeding cannot yet be determined.

Su er und Sites, etal Bank The EPA has notified, the Company that, it is one of many PRPs that may. be liable for the remediation of a licensed disposal site located in, Philadelphia, Pennsylvania, and operated by.",

Metal Bank of America. The Company and nine other PRPs, all of which are public utilities, completed performance of a Remedial Investigation and Feasibility, Study (RI/FS), which was .

conducted under an.ACO with the ZPA. In December 1997, the EPA issued its Record of Decision (ROD), setting forth the final remedial action selected for the site. In the ROD, the.EPA estimated that'the present cost of the selected remedy for the site is $ 17.3 million. At this time, the Company cannot predict with reasonable certainty the actual cost of the selected remedy, who will implement the remedy,1 or the cost, ifany, to the Company. Under a PRP "participation agreement, the Company previously was responsible for 8.2% of the'costs ass'ociated with the RI/FS. The Company.'s allocable share of liability for the remediation activities has not yet been determined.

,E' The Company has recorded a liability of approximately $ 1 million representing'ts estimated share of the additional cost to remediate this site based upon its 8.2% responsibility under the RI/FS.

E'E Syosset The Company 'and nine other PRPs have be'en named in'a lawsuit where the Town of Oyster Bay (Town) is seeking indemnification for'emediation'nd investigation costs that have, been or will be incurred for a feder'al Superfund site in Syos'set,-New York. For a further discussion on this matter, see It'em 3,'Le'gal Proceedings Environm'ental.

B Treatment, Inc.

e Company has also been named a PRP for disposal sites in Kansas City, Kansas', and Kan'sas City, Missouri. The two sites w'ere'used'by'a company named PQB Treatment, Inc. from 1982 until 1987 for the storage, 'processing, and treatment'of electric equipment, dielectric oils and materials contaihing PCBs. According to the EPA, the buildings'and certain soil ar'eas outside the buildings are contaminated with'PCBs.

II 1 F 1 11 Certain of the PRPs, including the Company and several other utilities, formed a PRP group, signed an ACO, and have developed a workplan for investigating environmental conditions at the sites. Documentation c'onnecting the Company to the sites in'dicates that the Compa'ny was for less. tHan 1% of tHe materials that were shipped to the Missouri site; 'fhe EPA has

'esponsible "'.

not yet corn'pleted compiling'the~documents for the Kansas site.

1', 1 E', 1' 1

Osage The EPA has notified the'Company'that it is a PRP at the Osage Metals Site, a former scrap metal "

recycling facility located in-Kansas City, Kanshs. Under Section 107(a) of CERCLA, parties who arranged for disposal ofhazardous substances are liable for costs incurred by the'EPA'in responding to a release or threat of release of the hazardous substances. Osage had purchased capacitor scrap metal from PCB Treatment, Inc. Through the arrangements that the Company made with PCB Treatment, Inc. to dispose of capacitors, the Company is alleged to'have arranged for disposal<within the'meaning of the federal Superfund law: A similar letter was sent to 861 ..

ies who sent capacitors to PCB Treatment, Inc.'The EPA is seeking to recover. approximately million dollars it expended to conduct a removal action at the site. The Company is currently lE V

17

unable to determine its share of the $ 1.1 million expenditure.

Port Refinery The Company has been notified that it is a PRP at the Port Refinery'uperfund site located in Westchester County, New York. Port Refinery was engaged in the business of purchasing, selling, refining and processing mercury and the Company may have shipped a small amount:of waste products containing mercury to this site. Tests conducted by. the EPA indicated that the site and certain adjacent properties were contaminated with mercury. As a result, the EPA has performed a response action at'he site and seeks to recover its costs, currently totaling approximately $ 4.4 million, plus interest, from the PRPs. The Company does not believe its portion of these costs, if any, willbe material.

Port 0'ashington In 1989, the EPA notified the Company that it was"a PRP for a landfill in Port Washington, New York. The Company does not believe that it sent any materials to the site that contributed to the contamination which requires remediation and has therefore declined the EPA's requests to participate in funding the investigation and remediation activities at the property. The Company has not received further communications regarding this site.

Liberty The EPA has notified the Company that it is a PRP in a Superfund site located in Farmingdale, New York. Industrial operations took place at this site for at least fiAyyears. The PRP group has claimed that the Company should absorb remediation expenses in the amount of approximately

$ 100,000 associated with removing PCB-contaminated soils from a portion of the site which formerly contained electric transformers. The Company is currently unable to determine its share of costs of remediation at this site.

Huntington/East Northport The DEC has notified the Company, pursuant to the State Superfund program, that its records indicate the Company may be responsible for the disposal of waste at this municipal landfill property. The Company conducted a search of its corporate records and did not locate any documents concerning waste disposal practices associated with this landfill. The Company is currently unable to determine its share, ifany, of the costs to investigate and remediate this site.

Blydenburgh The New York State Office of the Attorney General has notified the Company that it may be responsible for the disposal of wastes and/or for the generation of hazardous substances which may have been disposed of at the Blydenburgh Superfund site, a municipal sanitary landfill located in the Town of Islip, Suffolk County. The State has incurred approximately $ 15 million in costs for the investigation and remediation of environmental conditions at the landfill. In connection with this notification, the Company conducted a review of its corporate records and did not locate any documents concerning waste disposal practices associated with this landfill. The Company is currently unable to determine its share, ifany, of the costs to investigate and remediate this site.

Other Sites Manufactured Gas Plant Sites The DEC has required the Company and other New York State utilities to investigate and, where necessary, remediate their former MGP sites. Currently, the Company is the owner of six pieces of property on which the Company or certain of-its predecessor companies produced manufactured gas. Operations at these facilities in the late 1800's and early 1900's may have resulted in the 18

disposal of certain waste products located at these sites.

The Company has entered into discussions with the DEC which pre expected to lead to the issuance of one or more ACOs regarding the management of environmental activities at these six roperties. Although the exact amount of the Company's cleanup costs cannot yet be determined, based on the findings of preliminary investigations conducted at each of these six sites, current estimates indicate that it'may cost 'approximately $ 54 to $ 92 million to investigate and remediate all of these sites. Considering the range of possible remediation estimates, the Company felt it appropriate to record a $ 54 million liabilityreflecting the present value of the future stream of payments amounting to $ 70 million to investigate and remediate these sites. The Company used a risk-free rate of 6.0/o to discount this obligation. The Company believes that the PSC will provide for future recovery of these costs and has recorded a $ 54 million regulatory asset. The Company's rate settlement which the PSC approved February 4, 1998 as discussed in Note 3 of Notes to Financial Statements, allows for the recovery of MGP expenditures from gas customers.-

The Company is also evaluating its responsibilities with respect to several other former MGP sites that existed in its territory which it does not presently own. Research is underway to determine the existence and nature of operations and relationship, ifany, to the Company or its predecessor companies.

North Hills Leak The Company has undertak'en remediation of certain soil locations in North Hills, New York that were impacted by a release of insulating fluid from an electrical cable in August 1994. The Company estimates that any additional cleanup costs will not exceed $ 0.5 million. The Company has initiated cost recovery actions against the third parties it believes are responsible for causing e cable leak, the outcome of which are uncertain.

torage Facilities As:a result of petroleum leaks from underground storage facilities and other historical occurrences, the Company is required to investigate and, in certain cases, remediate aQected soil and groundwater conditions at several facilities within its service'territory. The aggregate costs of such remediation work could be between $ 3 million and $ 5 milli'on. 'To the extent that these costs are not recoverable through insurance carriers, the Company believes such costs will be recoverable from its customers.

Nuclear Waste LoivLevel Radioactive 5'aste The federal Low Level Radioactive Waste Policy Amendment Act of 1985, requires states for the disposal of all low level radioactive waste generated within the s'tate or, in the to'rrange alternative, to contract for. their disposal at an operating facility outside the state. As a result, New York State has stated its intentions of dev'eloping an in-state disposal facility due to the large volume of low level radioactive waste generated within the"state and has committed to develop a plan for the management of such waste during the interim period until a disposal facility is New York'State is still developing a disposal methodology and acceptance criteria for a 'vailable.

disposal facility. The latest New York State low level radioactive waste site development schedule now assumes two possible siting scenarios,,a volunteer approach and a non-volunteer approach, either of which would not begin operation until at least 2001. Low'evel radioactive waste rated at NMP2 is currently being disposed of at the Barnwell, South Carolina waste disposal ity which reopened in July 1995 to out-,of-state low level waste generators.

19

In the event that off-site storage becomes unavailable prior to 2001, NMPC has implemented a low level radioactive waste management program that will properly handle interim on-site storage of low level radioactive waste for NMP2 for at least ten years. The Company's share of the costs associated with temporary storage and ultimate disposal are currently recovered in-rates.

C Spent Nuclear Fuel NMPC, on behalf of the NMP2 cotenants, has entered into a contract with the DOE for the permanent storage of NMP2 spent nuclear fuel. The Company reimburses NMPC for its 18%

share of the cost under the contract at a rate of $ 1.00 per megawatt hour of net generation less a factor to account for transmission line losses. The Company is collecting its portion of this fee from its electric customers. It is anticipated that the DOE facility may not be available for permanent storage until at least 2010. Currently, all spent nuclear fuel from NMP2 is stored at the NMPC site, and.existing facilities are sufficient to handle all spent nuclear fuel generated at NMP2 through the year 2012.

For information concerning environmental litigation; see Item 3 "Legal Proceedings" under the heading Environmental.

II The Company's Securities General The Company's securities are rated by Moody's Investors Service, Inc., Standard and Poor's, Fitch IBCA, Inc. and Duff& Phelps Credit Rating Co. For information relating to the ratings of the Company's securities, see Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations."

The G&R Mort a e The Company's General and Refunding Indenture dated June 1, 1975 (G&R Mortgage) is a lien upon. substantially all of the Company's properties. Outstanding at March 31, 1998 and 1997 were approximately $ 1.3 billion of G&R Bonds.

Under the G&R Mortgage, the Company may issue G&R Bonds on the basis of either matured or redeemed G&R Bonds or on the basis of the Bondable Value of Property Additions (BVPA).

Generally, when issuing G&R Bonds, the Company must satisfy a mortgage interest coverage requirement, known as the G&R Mortgage Interest Coverage. The G&R Mortgage Interest Coverage requires that the net earnings as defined in the G&R Indenture, available for interest for, any 12 consecutive calendar months within the 15 consecutive calendar months preceding the issuance of any G&R Bonds must be equal to at least two times the stated annual interest payable on outstanding G&R Bonds, including any new G&R Bonds. Under the G&R Mortgage Interest Coverage, the Company would, currently be able to issue approximately $ 5.2 billion of additional G&R Bonds based upon net earnings for the year ended March 31, 1998 and an assumed interest rate of 7.75% for such additional G&R Bonds. A change of I/8-of 1% in the assumed interest rate of such G&R Bonds would result in a change of approximately $ 82 million in the amount of such G&R Bonds that the Company could issue. The maximum amount of additional G&R Bonds which the Company is currently able to.issue on the basis of either matured or retired G&R Bonds and on the basis of the BVPA is approximately $ 1.5 billion.

Under the pro'visions of the G&R Mortgage, the Company must also satisfy by June 30 of each year a Sinking Fund requirement, which for the year ended December 31, 1997 is $ 25 million.

The Company believes that, based upon currently scheduled redemptions and maturities, it will 20 0

have sufficient retired G&R Bonds for the foreseeable future to satisfy the requirements of the G&R Sinking Fund.

he G&R Mortgage also contains a Maintenance Fund covenant which requires that the aggregate ount of property additions added subsequent to December 31, 1974 must be, as of the end of eac h calendar year subsequent to 1974, at least equal to the cumulative provision for depreciation (as defined in the G&R Mortgage) from December 31, 1974. The G&R Mortgage requires cash (or retired G&R Bonds) to be deposited to satisfy the Maintenance Fund requirem'ent only when such cumulative provision for depreciation exceeds such aggregate amount of property additions.

As of December 31, 1997, the amount of such cumulative property additions calculated pursuant to the G&R Mortgage was approximately $ 10.4 billion, including approximately $ 5.5 billion of property additions attributable to Shoreham. Also, as of December 31; 1997; the amount of the cumulative provision for depreciation, similarly calculated, was approximately $ 2.0 billion. The Company anticipates that the aggregate amount of property additions will continue to exceed the cumulative provision for depreciation.

For a discussion of the effect the LIPA Transaction will have on Company debt outstanding, see Long Island Power Authority Transaction, above.

Unsecured Debt The Company's G&R Mortgage and its Restated Certificate of Incorporation do not contain any limitations upon the issuance of unsecured debt. The Company's unsecured debt consists of debentures and certain tax-exempt securities.

The Company's Debenture Indenture, dated as of November 1, 1986, as supplemented, and its ebenture Indenture, dated as of November 1, 1992, as supplemented, each provide for the uance of an unlimited amount of Debentures to be issued in amounts that may be authorized rom time to time in one or more series. The debentures are unsecured and rank~err nssu with all other unsecured indebtedness of the Company subordinate to the obligations secured by the Company's G&R Mortgage. At March 31, 1998 and 1997, there were'pproximately $ 2.3 billion of debentures outstanding. For a discussion of the effect that the LIPA Transaction will have on the Company's G&R Bonds and Debentures, see "Long Island Power Authority Transaction,"

above.

As of March 31, 1998, the Company had outstanding approximately $ 941 million principal amount of promissory notes, comprised of: (i) $ 2 million of tax-exempt Industrial Development Revenue Bonds (IDRBs); (ii) approximately $ 214 million of tax-exempt Pollution Control Revenue Bonds (PCRBs); and (iii) $ 725 million of tax-exempt Electric Facilities Revenue Bonds (EFRBs). Of these amounts, certain series are subject to periodic tenders. For a discussion of the effect that the LIPA Transaction will have on the Company's tax-exempt authority financing notes, see "Long Island Power Authority Transaction," above.

For additional information respecting tender provisions and other information on the Company's outstanding debt, see Note 7 of Notes to Financial Statements.

E uit Securities Common Stock e Company's common stock is listed on the New York and Pacific Stock Exchanges, and is ed under the symbol "LIL." The Board of Directors'urrent policy is to pay cash dividends on common stock on a quarterly basis. However, before declaring any dividends, the Company's 21

Board of Directors considers, among other factors, the Company's financial condition, its ability'te comply with provisions of the Company's Restated Certificate of Incorporation and the availability of retained earnings, future earnings and cash. For additional information with respect to the Company's common stock, see Note 6 of Notes to Financial Statements.

1 Preferred Stock The Company's Restated Certificate of Incorporation provides that the Company may not issue additional preferred stock unless, for any 12 consecutive calendar months within the 15 calendar months immediately preceding the calendar month within which such additional shares shall be issued, the net earnings of the Company available for the payment of interest charges on the

. Company's interest-bearing indebtedness, determined aAer provision for depreciation and all taxes, and in accordance with sound accounting practice, shall have been at least one and one-half times the aggregate of the annual interest charges on the interest-bearing indebtedness of the Company and annual dividend requirements on all shares of. preferred stock to be outstanding immediately after the proposed issue of such shares of the preferred stock (Earnings Ratio). At March 31, 1998, the Company satisfied the Earnings Ratio and could issue up to approximately $ 1,076 million of preferred stock at an assumed dividend rate of 8.25%. When the proceeds from the sale of the ,

preferred stock to be issued are used to redeem outstanding preferred stock, the requirement to satisfy the Earnings Ratio is not applicable ifthe dividend requirement and the requirements for redemption in a voluntary liquidation of the preferred stock to be issued do not exceed the respective amounts for the preferred stock which is to be retired. Additional preferred stock may also be issued beyond amounts permitted under the Earnings Ratio with the approval of at least I

two-thirds of the votes entitled to be cast by the holders of the total number of shares of outstanding preferred stock. For additional information with respect to the Company's preferred stock, see Note 6 of Notes to Financial Statements.

Preference Stock Issuance of preference stock, which is subordinate to the Company's preferred stock but senior to its common stock, with respect to declaration and payment of dividends and the right to receive amounts payable on, any dissolution,'oes not require satisfaction of a net earnings test or any other coverage requirement, unless established by the Board of Directors for one or more series of preference stock, prior to the issuance of such series. No preference stock has been issued by the Company, nor does the Company currently plan to issue any.

22

Executive Officers of the Company Current information regarding the Company's Executive Officers, all of whom serve at the will of the Board of Directors, follows:

illiam J.'atacosinos: Dr. Catacosinos has served as Chairman of the Board of Directors and Chief Executive Officer of the Company since January 1984, and as a Director since December 1978. He currently chairs the Executive Committee of the Company's Board of Directors. Dr.

Catacosinos also served as President of the Company from March 1984 to January 1987 and from March 1994 to December 1996. Dr. Catacosinos, 68, a resident of MillNeck, Long Island, earned a bachelor of science degree, a masters degree in business administration and a doctoral degree in economics from New York University. Dr. Catacosinos is a member of the Boards of Atlantic Bank of New Yo'rk, the Long Island Association and the Empire State Business Alliance, and is a member of the Advisory Committee of the Huntington Township Chamber Foundation. He is the former Chairman and Chief Executive Officer of Appli'ed Digital Data Systems, Inc., Hauppauge, New York; served as Chairman of the Board and Treasurer of Corometric Systems, Inc. of ~

Wallingford, Connecticut; and served as Assistant Diiector at Brookhaven National Laboratory, Upton, New York.

Theodore A. Babcock: Vice President since January 1997, Treasurer since February 1994 and Assistant Corporate Secretary since January 1996, Mr. Babcock joined the Company in July 1992 as Assistant Treasurer. He previously spent five years with the AMBASE Corporation as an Assistant Vice President and was promoted in 1988 to Vice President and Treasurer. Prior to AMBASE, Mr. Babcock spent 11 years with the Associated Dry Goods Corporation where he was promoted to Assistant Treasurer and Director of Corporate Treasury Operations in 1984. Mr.

Babcock, 43, received a bachelor of science degree in accounting from Manhattan College and a

~

asters degree in finance from Iona College. Mr. Babcock is a member of the board of the

~

ntington Township Chamber Foundation.

~ ~

Michael E. Bray: Senior Vice President of the Electric Business Unit since joining the Company in

~

March 1997. Prior to joining the Company Mr. Bray was President and CEO of DB Riley Consolidated in Worcester, Massachusetts. From 1987-1994 Mr. Bray was with ABB Power Generation, Inc. in Windsor, Connecticut holding the positions of Senior Vice President Sales &

Marketing for ABB Power Generation and President of ABB's Resource Recovery Systems organization. Prior to that, he spent 17 years with General Electric Company beginning as a in the power equipment service organization and ultimately managing Gen'eral Electric's field'ngineer cogeneration development, construction and operating organization. Mr. Bray, 50, holds a bachelor of science degree in mechanical engineering from the University of Missouri at Rolla and '

masters degree in Business Administration from Washington University. Mr. Bray is a member of the American Academy of Mechanical Engineers, past Board of Director/member of American Boiler Manufacturer's Association and the Greater Hartford Chamber of Commerce. He is also a charter member of the'Academy of Mechanical Engineers at the University of Missouri at Rolla.

Charles A. Daverio: Vice President of The Energy Exchange Group since December 1996, Mr.

Daverio, 48, holds a bachelor of engineering degree in mechanical engineering from Manhattan College, a master of science degree in industrial engineering from New York'niversity and a =

master of business administration from New York Institute of Technology. He joined the Company in 1976 as an Associate Engineer. He held various supervisory and managerial positions the Nuclear Engineering Department from 1979 through 1989. In 1990, he was assigned ager of Gas Supply and Planning and was given the additional responsibility for Gas perations in 1993. Mr. Daverio is the Company's representative on the Iroquois Gas 23

Transmission System's Management Committee and is on the Board of the Iroquois Pipeline, Operating Company. Mr. Daverio is a member of the board of the Huntington Arts Council.

Jane A. Fernandez: Vice President of Human Resources since May 1997, Ms. Fernandez joined the Company in 1973 and has.held various positions in the Employee Relations/Human Resources organization since, that time. She was Director of Human Resource Planning from 1988 to 1990, -,.

Director of Human Resource Services from,1990 to 19/4; Director, of Corporate Training aqd Human Resources in 1994, and Assistant Vice President of Human Resources from 1994 to 1997.

Ms. Fernandez, 48, is a graduate ofC. W. Post, College and holds an MBA in Management from Hofstra University., ~

4 James T. Flynn: President and member of the Company's Board of Directors since December 1996 and Chief Operating Officer since March .1994, Mr.,Flynn joined the Company in October 1986 as Vice President of Fossil Production. He also geld the positions of Group Vice President, Engineering and Operations,and Executive Vice President. before joining the Company, Mr.

Flynn, 64, was General Manager-Easter'ervice Department for General Electric. His career began as a member of General Electric's Technical Marketing Program in 1957. He holds a, bachelor of science degree in mechanical engineering from Bucknell University and is a Licensed Professional Engineer in the State of Pennsylvania.

'l ll H Joseph E. Fontana: .Vice President since January 1997 and Controller since October 1994, Mr.

Fontana joined the Company in December 1992 as Diiector of Accounting Services. He held the position of Assistant Controller from February 1994 through September 1994. In his capacity as Controller, Mr. Fontana serves as the Company's Chief Accounting Officer. Mr. Fontana is a member of the American Institute of Certified Public Accountants and the New York State Society of CPAs. Before joining the Company, Mr. Fontana was a Senior Manager at the international accounting firm of Ernst A Young, LLP. Mr. Fontana, 40, holds a bachelor of science degree in accounting from Westchester State College and is a Certified Public Accountant.

'I George B. Jongeling: Vice President of Special Projects since April 1998. Prior to joining the .

Company, Mr. Jongeling was President and Chief Operating Officer of Smith Cogeneration Company, an Independent Power. Development Company with active independent power development in Asia and operating plants in the U.S. Previous assignments jncluded Vice President of Operations and Member of the Board of Directors of DB Riley, President of PACE Construction Company, Vice President of Service and Spare Parts for EBB Gas Turbine, Business and Vice President of Business Development for ABB waste t'o energy business. He started his career in'1966,as a field engineer for the General Electric Company and spent 24,years working in the power generation business in domestic and foreign management positions. His last General Electric assignmentwas as Manager of the Eastern Region of the U.S. for the Systems Marketing Group supporting the cogeneration, construction, development and OEcM businesses for General, Electric. Mr. Jongelin'g, 54, received a Bachelor of Science degree in Mechanical Engineeiing from the South Dakota School of Mines and Technology and is a licensed professional engineer in Illinois and Missouri.,

I Robert X Kelleher: Senior Vice President of Humangesources since, May 1997, Mr. Kelleher joined the Company in 1959 and has held various managerial positions in the Finance, Accounting, Purchasing, Stores, and EmployeeRelations organizations. He was Industrial Relations Manager from,1975 to 1979, Manager of the Employee, Relations Department from 1979, to 1985, Assistant Vice President of the Employee Relations Department from 1985 to 1986, and Vice President of Human Resources from.1986 to 1997. Mr. Kelleher, 61, is a graduate of St.

24

Francis College and,the Human Resources Management and Executive Management Programs of Pennsylvania State University. Mr. Kelleher is a member. of the American Compensation Association,"Personnel Directors Council, Industrial Relations Research Institute and The Edison lectric Institute's L'abor Relations Committee.

John D. Leonard, Jr.: Vice President of Special Projects since April 1997, Mr. Leonard joined. the .

Company in 1984 as Vice President of Nuclear Operations. He continues.to be responsible for nuclear issues. Mr. Leonard served as Vice President of Engineering and Construction from March 1994 through March 1997, and previously served as Vice President of Corporate Services from ~

July 1989 through March 1994., From'1980 to 1984, Mr. Leonard was the Vice President and Assistant Chief Engineer for Design and Analysis at the New York Power Authority. Prior to this position, he served ah a Resident Manager of the Fitzpatrick Nuclear Power Plant.,for...

approximately five years. Before accepting a position at the New York Power Authority, Mr.

Leonard served as. Corporate Supervisor of Operational Quality Assurance of the Virginia Electric Power Company from 1974 to 1976. In 1974, Mr.'eonard:retired with the rank of Commander, from the United States Navy, having commanded two nuclear-powered submarines in a.career that spanned 20 years. He holds a bachelor of science degree from Duke University and a master of science degree from the Naval Post Graduate School. He is 65 and.a Licensed Professional Engineer in the State of New York. i v

Adam M. Madsen: Senior Vice President of Corporate and Strategic Planning since 1984,'r.

Madsen, 61, holds a bachelors degree in electrical engineering from Manhattan College and a master of science degree. in nuclear engineering from Long Island University. He has been with the Company since 1961;" serving in various engineering positions including Manager of Engineering from 1978 to '1984. Prior to that time, he held the. position" of Manager'of the "

arming Department. Since. 1978, Mr. Madsen has been the Company's representative to the- ~

ing Committee of the New York Power Pool. He is a member of the. Northeast Power Council',s Executive Committee and the Council's Reliability Coordinating, . 'oordinating Committee. He also serves on the Board of Directors of the Empire State Electric Energy Research Company. Mr. Madsen is a Licensed Professional Engineer in the State of New York.

1 4

Kathleen A. Marion: 'Vice President of CorporateiServices since April 1994 and Corporate Secretary since April,1992, Ms.'Marion has served as Assistant,to the Chairman since April 1987.

She was Assistant Corporate Secretary from April 3990 to April 1992. Ms. Marion; 43, has a .

bachelor of science degree in business and finance from the State University of New York at Old.

Westbury.

Brian R. McCafPey: Vice President of Communications since February.$ 997,"Mr. McCaffrey, joined the Company in 1973. Mr. McCaffrey, 52, holds a bachelor of science, degree in aerospace engineering from, the University of Notre Dame; He alamo received. a master of science degree in aerospace engineering from Pennsylvania State University and a master of. science degree in, nuclear engineering from Polytechnic University. He is a Licensed Professional Engineer in the State of New York. Prior to his present assignment, Mr. McCaffrey was Vice President of Administration since 1987. Previously, Mr. McCaffrey served in manypositions in the, nuclear organizations of the Company and positions in engineering'capacities associated with gas turbine and fossil power station projects. Mr. McCaffrey is a member of the Executive Board of the Suffolk County'Council B'oy Scouts of America. "

1 v

ph P'. McDonnell: Senior Vice President of Marketing and, External Affairs since December 6, Dr. McDonnell joined the Company in 1984. Dr. McDonnell was Assistant to the Chairman 25

from 1984 through 1987 when he was named Vice President of Communications. In'July 1992 h6 was named Vice President of External Affairs. Prior to joining the Company, he was the Director of Strategic Planning and Business Administration for Applied Digital Data Systems, Inc. and Associate Director of the University Hospital at the State University of New York at Stony Brook.

Dr. McDonnell, 46, holds bachelor of arts and master of arts degrees in philosophy from the State University of New York at Stony Brook and a doctoral degree in communications from the University of Southern California.

Leonard P. Novello Senior Vice President since December 1996, and General Counsel since he joined the Company in April 1995. Before joining the Company, Mr. Novello was General Counsel at the international accounting firm of KPMG Peat Marwick, where he advised senior management on a variety of litigation and corporate issues and was responsible for all legal J matters arising out of the firm's operations and its audit, tax and management'consulting engagements. Prior to joining Peat Marwick in 1975 as an Associate General Counsel, Mr.

Novello was associated with the New York law firm of Cravath, Swaine and Moore. Mr. Novello is active in professional associations and is a member of the Executive Committee of the Litigation Commercial and Federal Section of the New York State Bar Association and the Association of the Bar of the City of New York..He is also a member of the Executive Committee of the CPR Institute for Dispute Resolution. Mr. Novello, 57, has a bachelors degree from the College of the Holy Cross and a juris doctorate from Fordham University.

Anthony Nozzolillo: Senior Vice President of Finance and Chief Financial Officer of the Company since February 1994, Mr. Nozzolillo served as the Company's Treasurer from July 1992 to February 1994. He has been with the Company since 1972 serving in various positions including Manager of Financial. Planning and Manager of Systems Planning. Mr. Nozzolillo, 49, holds a bachelor of science degree in electrical engineering from the Polytechnic Institute of Brooklyn and a master of business administration degree from Long Island University, C.W. Post Campus. Mr.

Nozzolillo is chairman of the Community Advisory Board of Lawrence Public Schools'School to Career Initiative."

Richard Reichler: Deputy General Counsel and Vice President of Tax Planning and Services since January 1997. Mr. Reichler held the positions of Deputy General Counsel and Vice President of Financial Planning and Taxation from January 1995 through December 1996 and Assistant Vice President for Tax and Benefits Planning from October 1992 through December 1994. Prior to joining the'Company, he was a partner in the international accounting firm of Ernst & Young LLP for 23 years. Mr. Reichler, 63, holds a bachelor of arts degree from Columbia College and a bachelor of law degree from Columbia University School of Law. Since 1989, he has taught various courses at Baruch College, including state and local taxation,'corporate taxation and real estate taxation. He has authored several publications on tax and employee benefit topics and has served as a member of the Executive Committee of the Tax Section of the New York State Bar Association and as an Advisor to the Urban Development Corporation High Technology Advisory Council.

,1 8'illiam G. Schiffmacher: Senior Vice President of Customer Relations and Information Systems and Technology since December 1996, Mr. Schiffmacher held the positions of Vice President of Customer Relations from April 1994 through November 1996 and Vice President of Electric Operations from July 1990 through March 1994. He joined the Company in 1965 after receiving a bachelor of electrical engineering degree from Manhattan College. Mr. Schiffmacher, 54, also holds a master of science degree in management engineering from Long Island University. He has held a variety of positions in the Company, including Manager'of Electric System Operations, 26

Manager of Electrical Engineering and Vice President ofEngineering and Construction..

8'erner J. Schweiger: Vice President of Electric Operations since December 1996, Mr. Schweiger

'oined the Company in 1981 and has held a number of positions in Electric Operations, as well as Engineering. Most recently, he was Manager of Electric Systems Engineering from October 1995 through November 1996. Mr. Schweiger, 38, received his bachelors degree in electrical engineering from Manhattan College and also holds a masters degree in Energy Management from the New York Institute of Technology.

Richard M. Siegel: Vice President of Information Systems and Technology since December 1996, Mr. Siegel held the position of Director of Information Systems and Technology from June 1995 to December 1996. Mr. Siegel, 51, joined'the Company in 1969 as an Associate Engineer and has held progressive management positions in Electric Operations and Engineering, including of Electric System Engineering and Manager of Electric System Operations. Mr. Siegel'anager holds a bachelor of electrical engineering degree from the City College of New York and a master of science degree in Industrial Management from the State University of New York at Stony Brook. Mr. Siegel is a Licensed Professional Engineer in the State of New York.

Robert B. Steger: Senior Vice President of Gas Business Unit since December 1996, Mr. Steger held the positions of Vice President of Electric Operations from April 1994 through November 1996 and Vice President of Fossil Production from February 1990 through March 1994. He joined the Company in 1963 and held progressive operating and engineering positions including Manager of Electric Production-Fossil from 1985 through 1989. Mr. Steger, 61, holds a bachelor of, mechanical engineering degree from Pratt Institute and is a Licensed Professional Engineer in the State of New York.

'lliam E. Steiger, Jr.:. Vice President of Facilities and Real Estate since February,1997, Mr.

eiger, 54, held the positions of Vice President of Fossil Production, from April 1994 through February 1997 and Vice President of Engineering and Construction from July 1990 through March 1994. During his career with the Company, which began in 1968, he has served, among other positions, as Lead Nuclear Engineer for Shoreham, Chief Operations Engineer for Shoreham, Plant Manager for Shoreham as well as Assistant Vice President of Nuclear Operations. Mr. Steiger received a bachelor of science degree in marine engineering from the United States Merchant Marine Academy and a master of science degree in nuclear engineering from Long Island University.

Edward J. Youngling: Senior Vice President of Engineering Bc Construction since February 1997, .

Mr. Youngling joined the Company in 1968 and has held various positions in the offices of Fossil Production, Engineering and Nuclear Operations including service as Department Manager of Nuclear Engineering. In 1988, Mr. Youngling was named Vice President of Conservation and Load Management. In 1990, he became Vice President of Customer Relations, and from March 1993 through March 1994, he was Vice President of Customer Relations and Conservation. In April 1994 he was named Senior Vice President of the Electric Business Unit. Mr. Youngling, 53, holds a bachelor of science degree in mechanical engineering from Lehigh,University. Mr.

Youngling serves on the board of the Empire State Electric Energy Research Company and is a member of the Executive Committee of the New York Power Pool. Mr. Youngling also serves on the Eastern Advisory Board of the Protection Mutual Insurance Company.

27

Capital Requirements, Liquidity and Capital Provided Information as to "Capital Requirements," "Liquidity"and "Capital Provided" appears in Item 7, "Management's Discu'ssion and Analysis of Financial Condition and Results of Operations."

Item 2. 'roperties The location and general character of the principal properties of the Company are described in Item 1, "Business"'under the'headings "Electric Operations" and "Gas Operations."

Item 3. Legal Proceedings P Shoreham Pursuant to the LIPA Act, LIPA is required to make payments-in-lieu-of-taxes (PILOTs) to the municipalities'that impose real property taxes on Shoreham. Pursuant to the 1989 Settlement, the Company agreed to fund LIPA's obligation to make Shoreham PILOTs. The timing and duration of PILOTs under the LIPA Act were the subject of, litigation entitled LIPA et al. v. Shoreham-Wadin River Central School District et al., brought in Nassau County Supreme Court by LIPA against, among others, Suffolk County, the Town of Brookhaven and the Shoreham-Wading River Central School District. The Company was permitted to intervene in the lawsuit. In June 1996, the New York State Court of Appeals rendered its opinion on the cross-appeals filed by the parties regarding the timing, duration and refundability of PILOTs under the LIPA Act. The Court affirmed portions of a prior rulin'g by the Appellate Division, Second Department by holding that (a) LIPA's PILOT obligation is perpetual, (b) PILOTs, like taxes, are subject to refund ifthe assessment upon which the PILOTs were based is determined to be excessive, and (c) PILOTs phase down by ten percent of the prior year's amount, rather than ten percent of the first PILOT year amount, until PILOTs reach a level that equals the taxes that would have been levied on the plant in a non-operative state. Additionally, the Court modified the Appellate Division's ruling by finding that PILOTs commence, not at the time the Company transferred Shoreham to LIPA in February 1992, but rather on December 1, 1992, the beginning of the next tax year.

I Unless otherwise agreed by the parties, the proper assessment of Shoreham for purposes of determining the proper amount of PILOTs is to be determined in a proceeding challenging the Shoreham assessment for the 1992-93 tax year. Ifthat determination results in PILOTs that are less than the amount of PILOTs that have already been paid, LIPA, and therefore the Company, should be entitled to refunds of excessive PILOTs already made.

The costs of Shoreham included real property taxes imposed by, among others, the Town of Brookhaven, and.were capitalized by the Company during construction. The Company sought judicial review in New York Supreme Court, Suffolk County Lon Island Li htin Com an v.

The Assessor of the Town of Brookhaven et al. of the assessments upon which those taxes were based for the years 1976 through 1992 (excluding 1979 which had been settled). The Supreme Court consolidated the review of the tax years at issue into two phases: 1976 through 1983 (Phase I); and 1984 through 1992 (Phase II). In January 1996, the Company received approximately $ 81 million, including interest,'rom Suffolk County pursuant to ruling by the Supreme Court, upheld on appeal, that found that Shoreham had been overvalued for real property tax purposes in Phase I.

28 0

In November 1996, the Supreme Court ruled that Shoreham had also been over-assessed for real tax purposes for'Phase IL A judgment was entered on March 26, 1997 in the amount of 'roperty

$ 868,478,912 which includes interest to November 4, 1996. Suffolk County, the Town of rookhaven and the Shoreham Wading-River Central School District have appealed the judgment o the Appellate Division, Second Department. All briefs have been filed and oral argument occurred on May 6, 1998. The Court reserved decision. Ifthe assessment for the 1991-92 tax year is used to determine the proper'amount of PILOTs this ruling should also result in a refund of

$ 260 million plus interest for PILOTs for the years 1992-1996. 'pproximately II The refund of any real property taxes, PILOTs, and interest thereon, net of litigation costs; will be used to reduce electric rates in the future. However, the court's ruling is subject to appeal and, as a result, the Company is unable to determine the amount and timing of any additional real property tax and PILOT refunds.

Environmental In February 1994, a lawsuit was filed in the United States District Court for the Eastern District of New York by the Town of Oyster Bay (Town),'gainst the Company and nine other PRPs. The is seeking indemnification for remediation and investigation costs that have been or will be 'own for a federal Superfund site in Syosset, New York, which served as a Town-owned and 'ncurred operated landfill between 1933 and 1975. In a Record of Decision issued in September 1990,'the EPA set forth a remedial design plan; the cost of which was estimated at $ 27 million and is reflected in the Town's lawsuit. In an Administrative Consent Decree entered into between the EPA and the Town in Dec'ember 1990, the Town agreed to undertake remediation at the site. The Company is participating in a joint PRP defense effort with several other defendants.'iability, if imposed, would be joint and sev'eral. An agreement in principal has been reached betwee'n the ompany, certain other defendants, the State of New York and the Town; any settlement is subject court approval and ifapproved would not have a material adverse effect on its financial position, cash flows or results o'f operatioris.

In March 1996, the Village of Asharoken filed a lawsuit against the Company in the New York Supreme Court,SuffolkCounty Inco orated Villa eofAsharoken New York etal.v.Lon Island Li htin Com an . The Village is seeking monetary damages and injunctive relief based upon theories of negligence, gross negligence and nuisance in connection with the Company's design and construction of the Northport Power Plant which the Village alleges upset the littoral'rift, thereby causing beach erosion. In November 1996, the Court decided the Company's motion to dismiss the lawsuit, dismissing two of the three causes of action. The Court limited monetary damages on the surviving continuous nuisance claim to three years prior to the commencement of the action. The Company's liability, ifany, resulting from this proceeding cannot y'et be determined. However, the Company does not believe that this proceeding willhave a material adverse effect on its financial position, cash flows or results of operations.

In June 1996, a lawsuit was commenced against the Company in the New York Supreme Court, Suffolk County Town of Riverhead et al. v. Lon Island Li htin Com an, in which the plaintiffs seek monetary damages and injunctive relief based upon theories of nuisance, breach of contract, and breach of the Public Trust in connection with the Company's construction of the Shoreham Nuclear Power Station and the Company's diversion and maintenance of the Wading River Creek. The plaintiffs allege that the diversion of the Wading River Creek and the struction of the Shoreham Nuclear Power Station have caused negative environmental impacts urrounding areas. The plaintiffs also allege that the Company has contractual obligations to 29

perform annual maintenance dredging of the Wading River Creek and beach replenishment of ~,

certain beach front property. In September 1996, the Company filed a motion to dismiss the complaint on numerous grounds. In January 1997, the plaintiffs cross-moved for an order seeking partial summary judgment. The Court issued an Order dated August 26, 1997 which denied both motions except that it dismissed Plaintiffs'ause of action alleging violation of the Public Trust Doctrine and prohibited the Town of Riverhead from suing in its sovereign capacity. The parties have filed notices of intent to appeal this order and discovery has commenced. The Company's liability, ifany, resulting from this proceeding cannot yet be determined. However, the Company does not believe that this proceeding will have a material adverse effect on its financial position, cash flows or results of operations.,

Human Resources Pending before federal and state courts, the federal Equal Employment Opportunity, Commission and the New York State Division of Human Rights are charges by several individuals alleging, in separate actions, that the Compariy discriminated against them, or that they were the subject of harassment, on various grounds. The Company has estimated that any costs to the Company resulting from these matters will not have a material adverse effect on its financial position, cash flows or results of operations.

In May 1995, eight participants of the Company's Retirement Income Plan (RIP)'filed.a lawsuit against the Company, the RIP and Robert X. Kelleher, the Plan Administrator, in the United States District Court for the Eastern District of New York Becher et al. v. Lon Island Li htin C~l.).t JV1996,I Cd*dhUi action. This proceeding arose in connection with the i b" i i d plaintiffs'ithdrawal, approximately 25 years ago, of contributions made to the RIP, thereby resulting in a reduction of their pension benefits. The plaintiffs are now seeking, among other things, to have these reduced benefits if restored to their pension accounts. The Company's liability, any, resulting from this proceeding cannot yet be determined. In November 1997, the Company filed a motion for partial summary judgment with the District Court. On April 28, 1998, the Court denied the Company's motion and permitted the Company to file a further motion for partial summary judgement on additional grounds. The Company maintains that the plaintiff's claims are without merit and intends to defend against said claims.

Other Matters II A discussion of legal proceedings related to competitive issues facing the Company appears in Note 12 of Notes to Financial Statements.

Item 4. Submission of Matters to a Vote of Security Holders None 30

PART II Item 5. Market for the Registrant's Common Equity and Related Stockholder Matters

~

~ ~

t March 31, 1998, the Company had 78,314 registered holders of record of common stock.

The common stock of the Company is traded on the New York Stock Exchange and the Pacific Stock Exchange. Certain of the Company's preferred stock series are traded on the New York

~

Stock Exchange.

The high and low market prices of the Company's common stock and dividends per common share for 1996, 1997 and the first quarter of calendar 1998 is set forth on the table below.

Fiscal Year Ended March 31, 1998 3 Months Ended 3/31/97 6/30/97 9/30/97 12/31/97, 3/31/98 Market price of common stock High 24 '/, 24 '/g 26 30*'/, 31 s/s Low 21 s/, 22 229 24 '/s 27 l5/

Dividends per common share .445 ,445, .445 .445 .445 Calendar Year Ended December 31, 1996 3 Months Ended 3/31/96 6/30/96 9/30/96 12/31/96 Market price of common stock High 18 17 7/s 179, 22'/,

Low 15 r/g 16 i/s 6 s/z 17 '/,

Dividends per common sharc .445 .445 .445 .445 31

Item 6. Selected FinaricialfData (in thousands of dollars except pcr sharo amounts)

March 31

" ' h{arch31 December 31 Dcccmbcr 31 December 31 For the car ended 1998 1997 '995 1994 Revenues Electric ,S 2,478,435 S 2;464>957 2,466,43$ $ ',484,014 $ 2,481,637 S 2,352,109 Gas 645,659 672 70$ 684 260 591 114 $ 8$ 670 528 886 Total Rcvcnucs 3 124,094 3 131,662 3,150,695 3 075 128 3 067 307 880 995 Operating Expenses Operations - fuel and purchased power 957,807 954,848 963,251 ~

834,979 847>986 827,S91 Operations - other * '400,045 >>

.372,880 381,076 383,238 406,014 387,808 h{aintcnsncc 111,120 116,988 118,13$ 128,155 134,640 133,852 Dcprcciation and amortization 1$ 8,S37 1$ 4,921 153,92$ 1 45>357 130,664 122,471 Base financial component amortization 100>971 100>971 100,971 100,971 100,971 100>971 Rate moderation coinponent amortization (3$ ,079) (2,999) (24>232) ZIP33 191,656 88,667 Regulatory liabilitycomponent amortization (79,359) (79,359) (79,359) (79,359) (79,359) (79@59) 1989 Sct tlcmcnt credits amortization (9,213) (9>213) (9,214) (9,214) (9>214) (9,214)

Other regulatory amortization 47,272 112,294 127,288 161>605 4,328 (18,044)

Operating taxes 466,326 469,S61 472,076 447,507 406>895 385,847 Federal income tax - current 86,388 S2,737 42,191 14,$ 96 10,784 6,324 Fcdcral income tax - defcircd and other 150 983 1$ 7 873 168 000 193 742 170 997 178 $ 30 Total tin $ 5,798 2,401,502 2,414 114 2,343 $ 10 362 125444 tin income 768 296 736,160 736,581 731 618 744,94$ 7$ $ $ $ 1 Other Income and (Deductions) 25,259

'5,279 Rate moderation component canying charges 23,632 25,274 32,321 40,004 Other incomo and deductions, net '. (18,156) 13>921 19>197 34>400 3$ ,343 38>997 Class Scttlcmcnt (15,623) (19,89$ ) (20,772) (21,669) (22,730) (23,178)

Allowance for other funds used during construction 3,846 2,886 2,888 2,898 2,716 2,473 income tax - current 594

"'ederal Federal income tax - dcfcncd and other 4 124 723 940 800 5 069 1 578 Total Other Income and ductions 1 $ 83 21 468 27 512 43 703 5 719 0 874 l corno e ore crea r cs Interest Charges Interest on Iong.term debt 351,261 372,108 384,198 412,S12 437,751 466,S38 Other intcrcst 57,805 66,818 67,130 63,461 62,345 67,534 Allowanco for bonowcd funds used duiin construction 4,593 3,70 3 699 3,938 4 284 4 210 Total Intcrcst Cha 404 473 435,219 447,629 47 035 495 812 529 862 Net Income 362,240 322,409 316,464 303,286 301,8$ 2 296,563 Prcfcned stock dividend rc uircments" 51,813 52,113 52,216 5 620 53 020 56 108 Earnln s for Common Stock S 310,427 S 270,296 S 264,248 S 250 666 $ 248 832 S 240 455 Avera e Common Shares Outstandin 000 121 415 120 620 '120,360 119,195 115880 11 057 Basic and Diluted Earnin s er Cominon Share S 2.56 S 2.24 S 2.20 S 2.10 S 2.15 $ 2.1$

Common stock dividends declared pcr share $ 1.78 $ 1.78 S 1.78 $ 1.78 S 1.78 S 1.76 Common stock dividends paid pcr sham $ 1.78 $ 1.78 $ 1.78 S ',1.78 S 1,78 S 1,75 Book vsluo pcr conunon share at S 21.88 S 21.07 S 20.89 S, 20;$ 0 S 20.21 S 19.88 Common shares outstanding at (000) 121,681 120,987 120,781 119,65$ 118,417 112@32 Conuuon sharcowners of record at 78 314 77 691 86,607 93 088 96,491 94 877 Total Assets $ 11,900,725 $ 11,849>574 12,209>67$ S 12,S27,597 S 12,419,289 $ 12,4 $ 3,771 Long-Term Debt $ 4,381,949 S 4>457,047, 4,456,772 $ 4,706,600 S 5,145,397 S 4,870,340 Preferred Stock- redemption required $ S62,600 $ 638,$ 00 638>$ 00 S 639>$ 50 S 644,350 S 649,150 Preferred Stock- no redemption required S S 63,598 63,664 S 63,934 $ 63,9$ 7 $ 64,038 Common Shareowners'quity S 2,662,447 $ 2,$ 49>049 2,523>369 $ 2,452,953 $ 2,393,628 S 2,232/SO 32

'anagement's t

Item7; Discussion and Analysis of Financial Condition and- Results of Operations N

On April 11, 1997, the Company changed its year end from December 31 to March 31. Accordingly, unless otherwise indicated, references to 1998 and 1997 represent the twelve month periods ended March 31, 1998 and March 31, 1997, respectively, while references to all other periods refer.to the respective calendar years ended December 31.

Effects ofLIPA and KeySpan Transactions on Future Operations

• The future operations and financial position of the Company will be significantly affected by each of the proposed transactions with LIPA and KeySpan described below. The discussion contained in this management's discussion and analysis of financial condition and results of operations does not reflect, unless otherwise indicated, the potential effects of the transactions with LIPA and KeySpan.

Results of Operations Earnings Earnings for the years ended March 31, 1998 and March 31, 1997 were as follows:

(In millions ofdollars and shares except earnings per share) 1998 1997 Net income $362.2 $ 322.4 Preferred stock dividend r uirements 51.8 52.1 Eamin s for common stock $ 310.4 $ 270.3 Avera e common shares outstandin 121.4 120.6 Basic and diluted eamin s er common share $ 2.56 $ 2.24 or the year ended March 31, 1998 the Company had higher earnings in the electric business partially ffset by lower earnings in the gas business compared to the year ended March 31, 1997.

In the electric'-business, the increase in earnings for the year ended March 31, 1998, was primarily due to a change in the method of amortizing the Rate Moderation Component (RMC) to eliminate the effects of seasonality on monthly operating income, as more fully discussed in the section titled "Rate Moderation Component." This positive contributor to earnings more than offset the effects of lower short-term interest income and the accruals for certain obligations for key employees, as more fully discussed in Note 8 of Notes to Financial Statements.

V The decrease in earnings in the gas business for the year ended March 31, 1998 resulted from lower short-term interest income and the accruals, noted above, partially offset by lower operations and maintenance expenses.

Earnings for the years ended December 31, 1996 and December 31, 1995 were as follows:

(In millions ofdollars and shares except earnings per share) 1996 1995 Net income $ 316.5 $ 303.3 Preferred stock dividend re uirements 52.2 52.6 Eamin s for common stock $ 264.3 $ 250.7 Avera e common shares outstandin " 120.4 119.2 Basic and diluted eamin s er common share $ 2.20 $ 2.10 33

The Company's 1996 earnings were higher for both its electric and gas businesses as compared to 1995. While the Company's allowed rate of return in 1996 was the same as 1995, the higher earnings for the electric business were the result of the Company's increased investment in electric plant in 1996, as compared to 1995. Also contributing to the increase in electric business earnings were the Company's continued efforts to reduce operations and maintenance expenses and the efficient use of cash generated by operations to retire maturing deb't.

J The increase in earnings in the gas business was the result of additional revenues due to the continued growth in the number of gas space heating customers. Also contributing to the increase in gas business earnings was a 3.2% rate increase which became effective December 1, 1995, and an increase in off-system gas sales.

I Revenues Electric Revenues The table below provides a summary of the Company's electric revenues, sales and customers.

Years Ended Ivlarch 31, Years Ended 1)ecember 31, Revenues (000) 1998 1997 1996 1995 Residential $ 1,206,640 $ 1,199,976 $ 1,205,133 $ 1,204,987 Commercial and industrial 1,194,725 1,178,471 1,174,499 1,194,014 Other system revenues 47,832 50,499 50,513 52,472 Total system revenues 2,449,197 2,428,946 2,430,145 2,451,473 Other revenues 29,238 36,011 36,290 32,541 Total Revenues $ 2,478,435 ., $ 2,464,957 $ 2,466,435 $ 2,484,014 Sales - millions of kwh Residential 7,170 7,121 7,203 7,156 Commercial and industrial 8,375 8,209 8,242 8,336 Other system sales 415 437 441 460 Total system sales 15,960 15,767 15,886 15,952 Customers - monthly average Residential 928,580 922,330 915,162 920,930'04,488 Commercial and industrial 105,795 104,703 103,669 Years Ended March 31 1998 and 1997" The Company's electric revenu'es fluctuate mainly as a result of system growth,'ariations in weather and fuel costs, as electric base rates have remained unchanged since December 1993. However, these variations, have no impact on earnings due to the current electric rate structure which includes a revenue reconciliation mechanism to eliminate the impact on earnings caused by sales volumes that are above or below adjudicated levels. The slight increase in revenues for the year ended March 31, 1998, when compared to the year ended March 31, 1997, was primarily due to higher system sales volumes -.

resulting in part from the addition of approximately 8,000 new electric customers and higher fuel expense recoveries, partially offset by lower sales to other utilities.

Years Ended December 31 1996 and 1995 The Company experienced a growth in electric system sales in 1996 on a weather-normalized basis compared to 1995. This growth is primarily attributable to the addition of new electric customers.

34

Zor a further discussion on electric rates, see Note 4 of Notes'to Financial Statements.

Gas Revenues a The table below provides a summary Revenues (000) of the Company's 1998 gas revenues, sales and customers.

Years Enced March 31, 1997 I

Year> Ended l)eccmber 31, 1996 '995 Residential $ 390>990 . $ 396,143 $ 414,749,, $ 365,775 Commercial and industrial 145,861 163,824 ~, 181>356 165,257 Total firm revenues 536,851 559,967 596,105 531,032 Interruptible revenues 37,565 42,584 37,927 32,837 Total system revenues 574,416 602,551 634,032 563,869 Other revenues 71,243 70,154 50,228 27,245 Total Revenues $ 645,659 $ 672,705 $ 684,260 $ 591,114 Sales - thousands of Dth Residential 37,417 39,286 40,850 38,265 Commercial and industrial 17,168 19,341 21,054 20,439 Total firm sales 54,585 58,627 61,904 58,704 Interruptible sales 9,130 8,399 7,869 9,176 Ofr-system sales 10,372 10>036 7,457 7,743 Total Sales 74>087 77,062 77,230 75,623 Customers - monthly average U Residential 415>369 41 1,734 410,922 407,566 Commercial and industrial 44,917 45,684 45,887 45,340 Total firm customers 460,286 457,418 456,809 452,906 Interruptible customers 688 659 651 623 Firm transportation customers 3,589 833 349 Years Ended March 31 1998 and 1997 Despite an increase of approximately 5,600 gas space heating customers, gas revenues decreased primarily as a result of lower sales volumes due to warmer weather experienced during the year ended March 31, 1998 when compared to the year ended March 31, 1997.

In 1998 and 1997, other gas revenues totaled $ 71 million and $ 70 million, respectively. Included in other gas revenues is off-system gas sales which totaled $ 34 million and $ 43 million, for 1998 and 1997, respectively. Profits generated from off-system gas sales are allocated 85% to firm gas customers and 15% to the shareowners, in accordance with PSC mandates..Off-system gas sales decreased as the demand for natural gas declined as a direct result of the warmer weather experienced in this region during this period.

Years Ended December 31 1996 and 1995 The increase in 1996 gas revenues when compared to 1995 is attributable to a 3.2% gas rate increase which became effective on December 1, 1995, higher sales volumes, an increase in gas fuel expense recoveries driven by higher sales volumes, and revenues generated through non-traditional services, including off-system gas sales., The recovery of gas fuel expenses in 1996 when compared to 1995 increased approximately $ 31 million as a result of higher average gas prices and increased per customer usage due to colder weather than experienced in the prior year. In 1996 and 1995, other gas 35

revenues totaled $ 50 million and $ 27 million, respectively. Included in other gas revenues is Off-system gas sales which totaled $ 37 million and $ 24 million for 1996 and 1995, respectively.

Operating Expenses Fuel and Purchased Power Electric System Fuel and purchased p'ower expenses for the years ended March 31, 1998 and 1997, and for the years

'nded December 31, 1996 and 1995 were as follows:

(In millions ofdollars),

Years Ended Years Ended March 31 December31 1998 1997 1996 1998 Fuel for Electric Operations Oil $ 123 $ 128 $ 158 $ 98 Gas 197 170 138 149 Nuclear 15 15 15 14 Purchased ower 324 333 329 310 Total $ 659 $ 646 $ 640 $ 571 Variations in fuel and purchased power costs have no impact on operating results as the Company's current electric rate structure includes a-mechanism that provides for the recovery of fuel costs which are greater than the costs collected in base rates. Ifthe actual fuel costs are less than the amounts included in base rates, the difference is credited to the RMC balance.

Electric fuel and purchased power mix for the years ended March 31, 1998 and 1997, and years ended December 31, 1996 and 1995 were as follows:

In thousands of MWh Years Ended Years Ended March 31 December 31 1998 1997 1996 1995 MWh MWh MWh MWh Oil 3,434 20% 3,278 19%,4,219 24% 3,099 17%

6 344 36%

'7 Gas 6 212 35% 5 469 31% 4 542 25%

Nuclear 1 545 9% 1,553 9% 1,558 9% 1,301 Purchased ower 6 412 36% 7 261 41% 7 388 42% 7 143 40%

Total 17 603 100% 17 561 100% 707 100% 17 887 100%

In May 1997, the Company completed the second of two planned conversions of oil-fired steam generating units at its Port Jefferson Power Station to dual firing units, bringing the total number of steam units capable of burning natural gas to nine. As a result, seven of the Company's nine steam generating units are currently dual-fired, providing the Company with the ability to burn the most cost-efficient fuel available, consistent with seasonal environmental requirements.

Years Ended March 31 1998 and 1997 Electric fuel costs increased as a result of higher system sales volumes. During 1998, the'price per kWh of power purchased increased over 1997. As a result,'the Company changed the mix of generation and purchased power in 1998 when compared to 1997'by generating more electricity using gas and oil rather than purchasing the equivalent energy from off-system.

36

Years Eitded December 31 1996 and 1995,

• As a result of a sharp increase in the cost of natural'gas'n 1996, generation with oil became more economical than generation with gas. The total barrels of oil consumed for electric operations'ere 7.1 million and 5.2 millio'n for the years 1996 and 1995; respectively.

I Gas System

'I Variations in gas fuel costs. have no impact on operating results, as the Company's current gas rate, structure includes a fuel adjustment clause whereby variations between actual fuel'costs and fuel costs included in base rates are deferred and subsequently returned to or collected from customers. Effective February 5, 1998, in accordance with the Stipulation, discussed in Note 3 of Notes to Financial Statements, total gas fuel costs are recovered through the gas fuel adjustment clause.

Years Ended March 31 1998 and 1997 Gas" system fuel expense totaled $ 299 millio'n and $ 309 million'for the year's ended March 31," 1998 and 1997, respectively. The decrease is due to lower firm sales volumes and lower off-system gas sales resulting from warmer weather experienced in this region" during this period.

Years Ended December 31 1996 and 1995 8 For the years ended December 31, 1996 and 1995, gas system fuel expense totaled $ 323 million and

$ 264 million, respectively. The increase of $ 59 million was due to higher firm sales'volumes, an increase in the Company's average price of gas and higher off-system'gas sales.'

f /

Operations and Maintenarice Expenses Years Ended March 31 1998 and 1997 perations and Maintenance (O&M) expenses, excluding fuel and pur'chased'power, were $ 511 million and $ 490 million, for the years ended March 31, 1998 and 1997, respectively. This increase in O&Mwas primarily due to the recognition of higher performance'-based employee incentives and certain, other, charges for employee benefits related,to the KeySpan/LILCO merger.,

II II I Years Ended December 31 1996 and'1995,

'&M expenses, exclu'ding fuel and purchased power, were $ 499 million and $ 511 million, for the years ended December 31, 1996 and 1995, respectively..This decrease in 0&M'was primarily due to the Company's cost containment'program which 'resulted in lower plant maintenance expenses; lower distribution expenses and lower administrative and general expenses. '

Rate Moderation Component The Rate Moderation Component (RMC) represents the difference between the Company's revenue requirements under conventional ratemaking and the revenues provi'ded oy its electric'te structure. 'n addition, the RMC:is also adjusted for the operation of'the Company's Fuel Moderation Component" (FMC) mechanism and the difference between the Comp'any's share of actual operating costs at-'Nine Point Nuclear Power Station,'Uriit 2 (NMP2) and amounts provided for in electric rates.

"'ile 37

t In April 1998, the PSC authorized a revision to the Company's method for recording its monthly RMC amortization. Prior to this revision, the amortization of the annual level of RMC was recorded monthly on a straight-line, levelized basis over the Company's rate year which runs from December 1 to November 30. However, revenue requirements fluctuate from month to month b'ased upon consumption, which is greatly impacted by the effects of weather. Under this revised method, effective December 1, 1997, the monthly amortization of the annual RMC level varies based upon each month's forecasted revenue requirements, which more closely aligns such amortization with the Company's cost of service. As a result of this change, for the'iscal year ended March 31, 1998, the Company recorded approximately $ 65.1 million more of non-cash RMC credits to income (representing accretion of the RMC balance), or $ 42.5 million net of tax, representing $ .35 per share more than it would have under the previous method. However, the total RMC amortization for the rate year ended November 30, 1998, will be equal to the amount that would have been provided for under the previous method.

The Company continues to believe that the full amortization and recovery of the RMC balance, which at March 31, 1998, was approximately $ 434 million, willtake place within the time frame established by the Rate Moderation Agreement (RMA), in accordance with the rate plans submitted to the Public Service Commission of the State of New York (PSC) for the single rate year 1997 and the three year rate period 1997 through 1999. In December 1997, the Company received PSC approval to continue the RMC mechanism and the LILCO Ratemaking and Performance Plan (LRPP) ratemaking mechanisms and incentives for the electric rate year ending November 30, 1997. In the event that the LIPA Transaction is not consummated, the Company expects that the PSC will issue an order providing for, among other things, the continuing recovery, through rates, of the RMC balance, one of the Shoreham-related regulatory assets. Ifsuch an electric rate order is not obtained or does not provide for the continuing recovery of the RMC balance, the Company may be required to write-off the amount not expected to be provided for in rates. For a further discussion of the LIPA Transaction, see Note 2 of Notes to Financial Statements.

Years Ended March 31 1998 and 1997 For the years ended March 31, 1998 and March 31, 1997, the Company recorded non-cash credits to income of approximately $ 52 million and $ 30 million, respectively, representing the amount by which revenue requirements exceeded revenues provided for under the current electric rate structure.

Partially offsetting these accretions were the effects of the FMC mechanism and the differences between actual and adjudicated operating costs for NMP2, as discussed above. The adjustments to the accretion of the RMC totaled $ 17 million and $ 27 million, respectively, of which $ 12 million and $ 23 .

million, respectively, were derived from the operation of the FMC mechanism.

Years Ended December 31 1996 and 1995 For the year ended December 31, 1996, the Company recorded a non-cash credit to income of approximately $ 50 million, representing the amount by which revenue requirements exceeded revenues provided for under the current electric rate structure. Partially offsetting this accretion were the effects of the FMC mechanism and the differences between actual and adjudicated operating costs for NMP2. The adjustments to the accretion of the RMC totaled $ 26 million, of which $ 24 million, derived from the operation of the FMC mechanism.

'as 38

t

,For the year ended December 31, 1995, the Company recorded a non-cash charge to income of approximately $ 22 million, after giving effect to the credits generated. principally by the operation of the FMC mechanism. FMC credits for 1995 totaled approximately $ 87 million.

1 For a further discussion of the RMC, see Note 4 of Notes to Financial Statements.

Other Regulatory Amortization The significant components of other regulatory amortization are the following:

In millions o dollars Income Ex ense Years Ended Years Ended March 31 December 31 1998 1997 1996 1995 Net Margin $2 $ (5) $ 3 $ 64 LRPP Amortization 42 59 53 Excess Earnings - Electric (3) 21 10 3 Excess Earnings - Gas 10 10 10 1 Shoreham Post Settlement Costs 31 30 29 27 Other 7 14 16 14

$ 47 $ 112 $ 127 $ 162 Net Margin- An electric business unit revenue reconciliation mechanism, established under the LRPP, which eliminates the impact on earnings of experiencing sales that are above or below adjudicated levels by providing a fixed annual net margin level (defined as sales revenue, net of fuel and gross receipts taxes). Variations in electric revenue resulting from differences between actual and t adjudicated net margin sales levels are deferred on a monthly basis during the rate year through a charge or credit to other regulatory amortization. These deferrals are then refunded to or recovered from ratepayers as explained below under "LRPP Amortization."

LRPP Amortization- As established under the LRPP, deferred balances resulting from the net margin, electric property tax expense reconciliation, earned performance incentives, and associated carrying charges are accumulated during each rate year. The first $ 15 million of the total deferral is recovered from or credited to electric ratepayers by increasing or decreasing the RMC balance. Amounts deferred in excess of $ 15 million, upon approval by the PSC," are refunded to or recovered from ratepayers through the Fuel Cost Adjustment (FCA) mechanism over a subsequent 12-month period, with the offset being recorded in other regulatory amortization.

For the rate years ended November 30, 1997 and 1996, the total amount deferred under the LRPP was

$ 4.0 and $ 15.0 million, respectively. Such amounts were credited against the RMC balance.

Years Ended March 31 1998 and 1997 For the year ended March 31, 1998, there was no LRPP amortization, as the Company has not yet received approval from the PSC to begin refunding $ 26 million of the remaining deferred LRPP balance in excess of $ 15 million for the rate year ended November 30, 1995. For the year ended March 31, 1997, the Company recognized $ 42.4 million of non-cash charges to income representing the amortization of the deferred LRPP balance related to the rate year ended November 30, 1994.

39

Years Ended December 31 1996 and 1995 For the year ended December,3'1, 1996, the Company recognized $ 58.7 million of non-cash charges to income representing the amortization of the deferred LRPP balance related to the rate year ended November 30, 1994.

For the year ended December 31, 1995, the Company recognized $ 52.9 million of non-cash charges to income representing the amortization of the deferred LRPP.balance related to the rate year ended November 30, 1993..

For a further discussion'of the LRPP, see'Note 4 of Notes to Financial Statements.

Excess Earnings - Also recorded in other regulat'ory amortization, ifapplicable, are non-cash charges representing: (a) 100% of electric earnings generated by the Company in excess of amounts provided for in electric rates, which is returned to the electric customer,,through a reduction to the RMC balance; and (b) 50% of the gas earnings generated by the Company in excess of amounts provident foi in gas rates, which will be'returned to the firm gas customers. Effective February 5, 1998, the'Company,-in accordance'with the Stipulation, discussed in Note 3 of Notes to Financial Statements, established a gas balancing account in order to defer excess gas earnings for future disposition. For the rate year ended November 30, 1997, the electric business earned $ 4.8 million in excess of its allowed return on common equity'and'the firm gas customers'ortion of the gas business earnings was $ 6.3 million.

t Shoreham'Pos't Settlement Cosfs Represents the amortization of-Shoreham decommissioning costs,

=-fuel disposal costs, payments'-in-lieu-'of-taxes, carrying charges and other costs over a forty-year period on a straight line remaining'life basis.

'l l 1 P'

'I t,

Years Ended March 31 1998 and 1997 p Other regulatory amortization was a non-"cash charge to income. of $ 47 million and $ 112,million for th s ended March 31,'1998 and 1997.; respectively. For, the year ended March 31,,1997; the Company recognized a'pproximately $ 42 million of charges representing the amortization of the deferred LRPP balance associated with the rate year ended'Noveinber 30;~1994., For the year ended March 31, 1998, there was no, LRPP amortizatio'n, as.the;Compariy has not yet" received approval. from the PSC;to begin. refunding $ 26 million of the. remaining deferred LRPP balance in excess of $ 15 millionfor.the rate'year'ended November 30, 1995.

Also contributing to the decrease in other, regulatory, amortization.was the timing of the recognition of electric excess earnings for the rate years en/ed November 30, 1997 and 1996.

p Years Ended December 31 1996 and 1995 Other regulatory amortization was a non-cash charge to income of$ 127 million and $ 162;million.for the years ended December 31, 1996 and 1995, respectively. This decrease is primarily attributable to the operation of the net margin; discussed above. For the year ended December 31, 1995, the amount deferred related to the net margin amounted to $ 64 million compare'd to $ 3:million for the year ended December 31, .1 996.

V 1 It' gH 40

t Dperdting Taxes Operating taxes were $ 466 million and $ 470 million for the years ended March 31, 1998 and 1,997 respectively. The decrease in 1998 is primarily attributable to the expiration of the Corporate Tax Surcharge and lower gross receipts taxes related to lower gas revenues. For the years ended December 31, 1996 and 1995, operating taxes were $ 472 million and $448 million, respectively. The increase in 1996 compared to 1995 is primarily relatecl to higher property taxes and higher gross receipts taxes, due to increased revenues.

Federal Income Tax Federal income tax was $ 233 million and $ 211 million for the years ended March 311998 and 1997, respectively. For the years ended December 31, 1996 and December 31, 1995, federal income tax was

$ 209 million and $ 206 million, respectively. The increase in federal income tax for both periods was primarily attributable to higher pre-tax earnings partially offset by the utilization of investment tax credits.

4 Other Income and Deductions, Net Years Ended March 31 1998 and 1997 Other income and 'deductions was a $ 18 million charge to income. for the year ended March.31, 1998, compared to a $ 14 million credit to income for the same period in 1997. The difference, which amounts to approximately $ 32 million, relates primarily to a charge of approximately $ 31 million with respect to certain benefits earned by its officers recorded in 1998. For a further discussion of this t matter, see Note 8 of Notes to Financial Statements.

Years Ended December 31 1996 and 1995 Other income and deductions totaled $ 19 million for the year ended December 31, 1996, compared to

$ 34 million for the same period in 1995. The decrease in 1996 when compared to 1995 is primarily attributable to the recognition of non-recurring expenditures associated with one of the Company's wholly-owned subsidiaries, a decrease in non-cash carrying charge income associated with regulatory assets not currently in rate base and the recognition in 1995 of certain litigation proceeds related to the construction of the Shoreham Nuclear Power Station.

Interest'Expense Ended March 31 1998 and 1997

'ears Interest expense for the year ended March 31, 1998 totaled $ 409 million compared to $ 439 million for the year ended March 31, 1997. This decrease is primarily attributable to lower outstanding debt levels as the Company retired $ 250 million of G&R Bonds in February 1997.

Years Ended December 31 1996 and 1995 Interest expense for the year ended December 31, 1996 totaled $ 451 million compared to $ 476 million for the year ended December 31, 1995. This decrease is primarily attributable to lower outstanding debt levels, partially offset by higher letter of credit and commitment fees associated with the change in the Company's credit ratin'g in 1996.

II I 41

Liquidity and Capital Resources Liquidity For the year ended March 31, 1998, cash generated from operations exceeded the Company's operating, construction and dividend requirements. This positive cash flow is the result of, among other things: (i) the Company's continuing efforts to control both O&M expenses and construction expenditures; (ii) lower interest payments resulting from lower debt levels; and (iii) lower fuel expenditures.

At March 31, 1998, the Company's cash and cash equivalents amounted to approximately $ 181 million, compared to $ 65 million at March 31, 1997. In addition, the'Company has available for its use a revolving line of credit through October 1, 1998, provided by its 1989 Revolving Credit Agreement (1989 RCA). This line of credit is secured by a first lien upon the Company's accounts receivable and fuel oil inventories. In July 1997, the Company utilized $ 40 million in interim financing under the RCA, which was repaid in August 1997. The Company will, in order to satisfy short-term cash requirements, continue to avail itself of interim financing through the RCA, as necessary. For a further discussion of the 1989 RCA, see Note 7 of Notes to Financial Statements.

The Company does not intend to access the financial markets during 1998 to meet any of its ongoing operating, construction or refunding requirements. However, the Company will avail itself of any tax-exempt financing made available to it by the New York State Energy Research and Development Authority (NYSERDA). The Company used cash on hand to satisfy the retirement of $ 100 million of G&R Bonds which matured on April 15, 1998.

In December 1997, the Company received $ 24.5 million in net proceeds from the sale of Electric Facilities Revenue Bonds (EFRBs) issued by NYSERDA. The proceeds from this offering were used, to reimburse the Company's treasury for amounts previously expended on electric non-nuclear generation projects.

L With respect to the repayment of $ 454 million of maturing debt and $ 22 million of maturing preferred stock in 1999 and the repayment of $ 37 million of maturing, debt and $ 363 million of maturing preferred stock in 2000, should the LIPA Transaction not close, the Company intends to use cash generated from operations to the maximum extent practicable.

Pursuant to the terms of the LIPA Transaction, each issued and outstanding share of the Company's preferred stock that is subject to optional redemption will be called for redemption at or before closing of the LIPA Transaction. The LIPA Transaction provides for repayment to the Company, at closing, for the principal amount of the preferred stock to be redeemed., Accordingly, on April 17, 1998, the Company exercised its option and called for redemption on May ]9, 1998, all the outstanding shares of its Preferred Stock Series B, D, E, F, H, I, L, and NN. The redemption of these Preferred Stock Series amounted to $ 122 million which included approximately $ 5 million of redemption premiums. The Company used cash generated from operations and the utilization of interim financing through its 1989 RCA to finance the redemption. In the event the LIPA Transaction is not consummated, the Company may elect to access the capital markets for permanent financing to replace the Preferred Stock redeemed.

In 1990 and 1992, the Company received Revenue Agents'eports disallowing certain deductions and credits claimed by the Company on its federal income tax returns for the years 1981 through 1989.

A settlement resolving all audit issues was reached between the Company and the Internal Revenue 42

Service in May 1998. The settlement provided for the payment of taxes and interest of approximately

$9 million and $ 35 million, respectively, which the Company made in May 1998.

In May 1998, the Company funded certain of its obligations for postretirement benefits other than pensions in order to take a current tax deduction. The Company secured a bridge loan of $ 250 million to fund Voluntary Employee's Beneficiary Association trusts. The Company intends.to repay this bridge loan upon the closing of the LIPA Transaction.

Capitalization The Company's capitalization, including current maturities of long-term debt and current redemption requirements of preferred stock, at March 31, 1998 and 1997 and December 31, 1996 and 1995, was

$ 7.8 billion, $ 7.7 billion, $ 7.9 billion and $ 8.3 billion, respectively.

At March 31, 1998 and 1997 and at, December 31, 1996 and 1995, the Company's capitalization ratios were as follows:

March 31 December 31 1998 1997 1996 1995 Long term debt 57.3% 57 8% 59 3% 61.8%

Preferred stock 9.0 9.1 8.9 8.6 Common shareowners'quity 33.7 33.1 31.8 29.6 IPP P% IPP P% 100.0% 1PP P In support of the Company's continuing goal to reduce its debt ratio, the Company, in February 1997, retired at maturity $ 250 million of G&R Bonds with cash on hand and by utilizing interim financing of

$ 30 million, which was repaid. in March 1997. The Company used cash on hand to satisfy the $ 100 million of G&R Bonds which matured in April 1998.

~

~

nvestment Rating The Company's securities are rated by Standard and Poor's (S&P), Moody's Investors Service, Inc.

(Mo'ody's), Fitch IBCA, Inc. (Fitch) and Duff& Phelps Credit Rating Co. (D&P).

At March 31, 1998, the ratings for each of the Company's principal securities were as follows:

G&R Bonds S&P, Moody's Fitch D&P BBB Baa3 BBB- BBB Debentures BB+ Bal BB+ BB+

Preferred Stock BB+ bal BB- BB Minimum Investment Grade BBB- Baa3 BBB- BBB-Boldface indicates securities that meet or erceed minimum investment grade During March 1998, following the announcement that the Company received favorable tax rulings from the IRS with respect to the LIPA Transaction, Moody's raised the ratings of the Company's G&R Bonds to Baa3 from Bal; its debentures to Bal from Ba3 and its preferred stock to bal from ba3.

During October 1997, S&P announced that it raised the Company's G&R Bonds ratings one notch to BBB from BBB-. The upgrade resulted from S&P incorporating into its ratings of corporate issues a more vigorous analysis of ultimate recovery potential to supplement the analysis of default risk. The 0

43

incorporation of ultimate recovery risk is particularly important for ratings of elect'ric, gas; and'water" ~

utility senior secured debt. If, in~S&P.'s analytical. conclusion, full recovery of principal can be anticipated in a post-default scenario, an issue's rating may be enhanced above the corporate credit rating or default rating.

U U

Capital Requirements and Capital Provided . ~

Ul Capital requirements and capital provided. for the year ended March 31, 1998, the three months ended March 31, 1997 and the year ended December 31, 1996, were as follows:

(In Millions of Dollars)

-'U . Year Ended, Three Months Ended Year Ended March 31, 1998 March 31, 1997 December 31, 1996 Capital Requirements Construction ' '$257 $ 50 $ 240 Redemptions and Dividends Long-term debt I ,

, 250 . 415 Preferred stock I 5 Preferred stock dividends 52 13 52'16 Common stock dividends ,54 214 Total Redemption and Dividends 270 317 686 Shoreham post-settlement costs, 40 12, 52 Investment in interest rate hedge 30 Total Capital Requircmcnts $ 597 $ 379 . "$978 Capital Provided Cash from operations , $ 674 $ 160 $892 (Increase) Decrease in cash balances (116) 215 71 Long term debt issued 25 Common stock issued 18 19 Other investing and financing activities (4) (I) . (4 )

, ~ ,

Total Capital Provided $ 597 ~ $ 379 $978 Excludes non-cash allowance for other fitnds used during construction.

For further information, see the Statement of Cash Flows.

For the year ended March 31, 1999, total capital requirements (excluding'common stock. dividends) are estimated to be $ 589 million, of which maturing debt is $ 101 million, construction requirements are

$ 266 million, preferred stock dividends are $ 45 million, redemptions of preferred stock are $ 144 and Shoreham post-settlement costs are $ 33 million (including $ 31 million for payments-in- 'illion lieu-of-taxes). The Company believes that 'cash generated from operations coupled with cash balances will be sufficient to meet all capital requirements during this period.

I e

Other Matters Long Island Power Authority Transaction For a discussion of the Long Island Power Authority Transaction, see Note.2 of Notes,to Financial'tatements, Ul

't i' il 'I II I it KeySpan Energy Corporation Transaction For a discussion of the KeySpan Energy Corporatio'n Transaction, see Note 3 of Notes to Financial Statements..' 'i ji 44

R'ate M'atters For a discussion of Rate Matters, see Note 4 of Notes to Financial Statements...

' 'I Competitive Environment For a discussion of Competitive issues facing the Company, see Note 12 of Notes to Financial Statements.

I Environmental Matters II

'i'I, General ~ r I

The Company's ordinary business operations necessarily involve materials and activities which subject the Company to federal, state and local laws,'rules and regulations dealing with the environment, including air, water and land quality. These environmental requirements may entail significant expenditures for capital improvements or modifications and may expose the Company to potential liabilities which;in certain instances,'ay be imposed without regard to fault or for historical activities which were lawful at the time th'ey occurred

}!

Laws which may impose such potential liabilities include (but are not limited to) the federal Comprehensive Environmental Response, Compensation and Liability Act (CERCLA', commonly known as Superfund), the federal Resource Conservation and Recovery Act, the federal Toxic Control Act (TSCA), the federal Clean Water Act (CWA), and the federal Clean Air Act 'ubstances (CAA).

'I expenditures for environmental improvements and related studies amounted to approximately 'apital

$ 9.2 million for the year ended March 31, 1998 and, based on existing information, are expected to be

$ 4.0 million for the year ended March 31, 1999. The expenditures in fiscal year 1998 and expected .

spending in fiscal year 1999 include a total of $ 10.6 million for the completion of a gas-firing capability project at Northport Unit 1 and Port Jefferson Unit 4.

I I I It is not possible if to ascertain with certainty or when the various required governmental approvals for, which applications have been made wIlf be issued, or whether, except as noted below, additional facilities or modifications of existing or planned facilities will be required or, generally, what effect existing or future controls may have upon Company operations. Except as set forth below and in Item 3 - "Legal Proceedings," no material proceedings have been commenced or, to the knowledge of the Company, are contemplated by any federal, state or local agency against the Company, nor is the Company a defendant in any material litigation with respect to any matter relating to the protection of the environment.

Recoverabili o Environmental Costs' The Company believes that none of the environmental matters, discussed below, will have a material adverse impact on the Company's financial position, cash flows or results of operations. In addition, the Company believes that all significant costs incurred with respect to environmental investigation and remediation activities, not recoverable from insurance carriers, will be recoverable from its customers.

Air II I

state and local regulations affecting new and existing. electric generating, plants govern I'ederal, emissions of sulfur dioxide (SO2), nitrogen oxides (NOx), particulate matter, and, potentially in the future, fine particulate matter (aerosols of SO2), hazardous air pollutants and carbon dioxide (CO>).

45

Sulfur Dioxide Requirements ~

~ ) ~

The laws governing the sulfur content of the fuel-oil being burned by the Company in compliance with the United States Environmental Protection Agency (EPA) approved Air Quality State Implementation Plan (SIP) are administered by the New York State Department of Environmental'Conservation The. Company does not expect to incur an/'costs to satisfy the 1990 amendments to the federal 'DEC).

CAA with respect to the reduction of SO2 emissions, as the Company already uses natural gas and oil" with acceptably low levels of sulfur as boiler fuels. These fuels also result in reduced vulnerability to any future fine particulate standards implemented in the form of stringent sulfur dioxide emission limits. The Company's use of low sulfur fuels has resulted, and will continue to result, in approximately 70,000.excess SOz allowances per year through the year 1999. The Company presently applies the proceeds resulting from any sales of excess S02 allowances as a reduction.to the RMC balance." I 4'

The Company entered into a voluntary Memorandum of Understanding with the DEC which provides that the Company will not sell SO2 allowances for use in 15 states in an effort to, mitigate the transport of acid rain precursors into New York State from upwind states.

I Nitrogen Oxides Requirements.

Due to the Company's pr'oIgram of cost-'effective emission'reductions, including the optimization of natural gas firing ability at almost all the steam electric generating'tations, the Company had the NOx emissions rate of all the utilities in New York State for the years ended December 31, 'owest 1997, 1996 and 1995. Since the Company's generating facilities are located within a CAA Amendment-designated ozone non-attainment area, they're subjec't to NOreduction requirements which are being implemented in'three phases. Phase I was completed in 1995; Phase II and Phase III will be completed in 1999 and 2003', respectively.

4 The Company is currently in compliance with Phase I NOreduction requirements. It is estimated that additional expenditures of approximately $ 1 million will be required to meet Phase II NOreduction I

~

requirements. Subject to'requirements that are expected to be promulgated in forthcoming regulations, the Company estimates that it may be required to spend an additional $ 10 million to $ 34 million, excluding the Northport Unit 1'conversion, by the year 2003 to meet Phase IIINOreduction requirements. 'The completion of the project to add gas-firing capability at Northport'Unit 1 (completed in May 1998 at a,total'cost of approximately $ 8.4'million) will also facilitate the complian'ce with the anticipated Phase IIINoreduction requirements. 'ompany's Continuous Emission Monitoring Additional software and equipment upgrades for Continuous Emissions Monitors of approximately $ 2 million may be required through 1999 at all generating facilities in order to meet EPA requirements under development for the NO'llowance tracking/trading program.

14 4

Hazardous Air Pollutants Utilityboilers are presently exempt from regulation as sources of hazardous air pollutants until the EPA completes a study of the risks, ifany, to public health reasonably anticipated to occur as a result of emissions by electric generating units. The EPA is expected to make a determination concerning the need for control of hazardous air pollutants from utility facilities in 1998. Until such determinatio'n I I I I

46

. is 'made by the EPA, the:.Company cannot fully ascertain what,. ifany, costs will'be incurred for the control of hazardous air pollutants.

l

' However, after the expenditure of approximately $ 1.5 million in fiscal,1998 and the planned spending 'f

$ 0.5 million through March,31,:1999, for electrostatic precipitator upgrades and, with the maximization of clean burning natural gas as the primary fuel, hazardous'ir pollritant regulations, if enacted, should not impose any additional control requirements for the Company's facilities.

Carbon Dioxide Requirements, CO2 emissions from the. Company.'s plants have been reduced by approximately 23% since 1990, largely through greater reliance on the use of natural gas and through conservation programs. This makes the Company less vulnerable to future CO2 reduction requirements. i" ff rt Opacity Issues v 8~ 4 f The DEC has proposed commencing enforcement actions against'all New'ork utilities"for=alle'ged opacity exceedences from steam electric generating fa'cilities."'Op'acity is'a measure of the:relative level of light that is'obscured from passing thr6ugh a power plant stack emission plume. An'"

exceedence occurs wh'en the level of light passing through the plume is reduced bymore than 20% for six minutes or more. The Company has entered into an Administrative Consent Order (ACO) with the DEC which resolves all historical opacity exceedences, establishes an opacity reduction program to be undertaken by the Company, and sets a stipulated penalty, schedule for future exceedences. The number of exceedences 'experienced by the Company is relatively,low', placing the Company among best performers in New'York State.

'he lectromagnetic Fields lectromagnetic fields (EMF) occur naturally and also are produced wherever there is electricity.

hese fields exist around power lines and other utilityiequipment. The Company is in compliance with all applicable regulatory standards and..requirements concerning EMF. The Company also monitors scientific developments ig the study of EMF, has contributed to funding for research efforts, and is actively involved in customer and employee outreach programs to inform the community of.EMF developments as they occur. Although an extensive body of scientific literature has not shown an unsafe exposure level or a causal relationship between EMF exposure and adverse health effects, concern'over the potential for adverse health effects will likely continue without final resolution for'ome time. To date, four residential property owners have initiated separate lawsuits against the Compan'y alleging that the existence of EMF has diminished the value'of their homes, These actions are in the preliminary stages of discovery and are'similar to actions brought against another New York State utility, which were dismissed by the New'York State Court of Appeals. The Company is not in any active litigation that alleges a causal relationship betw'een exposure to EMF and "'nvolved adveise health effects.

'I N t

Water Under the federal CWA and the New York State Environmental Conservation Law, the Company is required to obtain a State Pollutant Discharge Elimination System permit to make any discharge into the waters of the United States or New York State. The DEC has the jurisdiction to issue these permits and their renewals and has issued permits for the Company's generating units: The permits allow the continued use of the circulating 'water systems which have been determined to be in compliance with 47

state water quality standards. The permits also allow for the continued use of the chemical treatment" ~

systems and for the continued discharge of water in accordance with applicable permit limits.

In fiscal year 1998, th'e Company spent approximately $ 300,000 to upgrade its waste water treatment facilities and for other measures designed to protect surface and ground water quality and.expects to spend an additional $ 100,000 in the years 1998-2000. rr r k I

Long Island Sound Transmission Cables During 1996, the Connecticut Department of Environmental Protection (DEP) issued a modification to an Administrative Consent Order (ACO) previously issued in connection with an investigation of an electric transmission cable system located under the Long Island Sound (Sound Cable) that is jointly owned by the Company and the Connecticut Light and Power Company (Owners). The modified ACO requires the Owners to submit to the DEP and DEC a series of reports and studies describing cable system condition, operation and repair practices, alternatives for cable improvements or replacement and environmental impacts associated with leaks of fluid into the Long Island. Sound which have occurred from time, to time. The Company continues to compile required information and coordinate the activities, necessary to perform these studies and, at the present time, is unable to determine the costs it will incur to complete the requirements of the modified ACO or to comply with any additional requirements.

'I The Owners have also entered into an ACO with the DEC as a result of leaks of dielectric fluid from the Sound Cable. The ACO formalizes the DEC's authority, to participate in and separately approve the report's and studies being prepared pursuant to the ACO issued by the DEP. In addition, the ACO settles any DEC claim for natural resource damages in connection with historical releases of dielectric fluid from the Sound Cable.

In October 1995, the U.S. Attorney for the District of Connecticut had commenced an investigation regarding occasional releases of fluid from the Sound Cable, as well as associated operating and maintenance practices. The Owners have provided the U.S. Attorney with all requested documentation. The Company believes that all activities associated Kith the response to occasional releases from the Sound Cable were consistent with le'gal and regulatory requirements.

r r

In December 1996, a barge, owned and operated by a third party, dropped anchor which then dragged over and damaged the Sound Cable, resulting in the release of dielectric fluid into. Long Island Sound.

Temporary clamps and leak abaters were installed on the cables to stop the leaks. Permanent repairs were completed in June 1997. The cost to repair the Sound Cable was approximately $ 17.8 million, for which there was $ 15 million of insurance, coverage. The Owners filed a claim and answer in response to the maritime limitation proceeding instituted by the barge owner in the United States District Cou~r Eastern District of New York. The claim seeks recovery of the amounts paid by insurance carriers and recovery of the costs incurred for which there was no insurance coverage. Any costs to repair the Sound Cable which are not reimbursed by a third party or covered by insurance will be shared equally by the Owners.

Land r Superfund imposes joint and several liability, regardless of fault, upon generators of hazardous substances foi costs associated with environmental, cleanup activities. Superfund also imposes liability for remediation of pollution caused by historical acts which were lawful at the time they occurred.

48

.In the 'course of the Company's ordinary business operations, the'Company is involved in the handling of materials that are deemed to be hazardous substances under Superfund. These-materials include asbestos, metals, certain flammable and organic compounds and dielectric fluids containing

~

polychlorinated biphenyls (PCBs). Other hazardous substances may be handled in the Compa'ny's '

operations or may, be present at Company locations as a result of historical practices by the Company or its predecessors in interest. The Company has,received notice concerning possible claims under; or analogous state laws relating to a number, of sites at whichjt is alleged that hazardous ~'uperfund substances generated, by the Company and otherpotentially. responsible parties (PRPs).were deposited:

A discussion of these sites is set forth below.

Estimates of the Company,'s allocated share'of costs for investigative, removal and remedial actiyIties at these sites~range Porn,preliminary to refined and are updated as new information becomes available.

In December 1996, the Company filed a complaint in the United States District Court for, the Southern District of New York against 14 of the Company's insurers,which issued general comprehensive,.

liability (GCL) policies to the Company. In January 1998,.the Company commenced a similar,action against the same and certain additional insurer defendants in New York State Supreme Court, First Department; the federal court action was subsequently dismissed in March 1998. The Company is; ..

seeking recovery under the GCL policies for the costs incurred to date and future, costs associated with the clean-up of the Company's former manufactured gas plant (MGP) sites and Superfund sites for which the Company,has been named a PRP. The Company is seeking a declaratory judgment'that the defendant insurersare bound by the terms of the GCL policies, subject to the stated cove'r'age'limits, to reimburse the Company for the.'clean up costs., The outcome of this proceeding cannot yet be..

,,'etermined.

S~ZS V Metal Bank The EPA has notified the Company that it is one of many PRPs that may be liable for the remediation of a licensed disposal site located in Philadelphia, Pennsylvania, and operated by Metal Bank of America. The Company and nine other PRPs, all of which are public utilities, completed performan'ce of a Remedial Investigation and Feasibility Study (Rl/FS), which was conducted under'an AGO with' the EPA. In December 1997, the EPA issued its Record of Decision (ROD), setting forth the:.final ' ~

remedial action selected for the site. In the ROD, the EPA estimated that the present'cost of the-selected remedy for'the'site is $ 17.3 million. At this time, the Company can'not predict with'reasonable certainty the actual cost of the selected r'emedy, who will implement the remedy,'r the cost; ifany",to the Company. Under a PRP participatiori agreement,"'the Company previously was responsible'for of the costs associated with the RI/FS Tlie Company's'allocable share of liability for the

"'.2%

remediation activities has not yet been determined. II The Company has recorded a liability of approximately $ ] million representing its estimated share of the additional cost to remediate this site based upon its 8.2% responsibility under the RI/FS.

w Syosset The Company and nine other PRPs have been named in'a lawsuit where the Town of,Oyster Bay (Town) is seeking indemnification for remediation and investigation costs that have been, or will be

'49

incurred for a federal Superfund site in Syosset, New York. For a further discussion on this matter, see.

Item 3, Legal Proceedings Environmental.

PCB Treatment, Inc.

The Company has also been named a PRP for disposal sites in Kansas City, Kansas, and Kansas City, Missouri. The two "sites were used by a company named PCB Treatment, Inc. from 1982 until 1987 for the storage, processing, and tr'eatment of electric equipment, dielectric oils and materials containing PCBs. According to the EPA, the buildings and certain soil areas outside the buildings are with PCBs. 'ontaminated Certain of the PRPs, including the Company and several other utilities, formed a PRP group, signed an ACO, and have developed a workplan for investigating environmental conditions at the sites'.

Documentation connecting the Company to the sites indicates that the Company was responsible for less than 1% of the materials that were shipped to the Missouri site. The EPA has not yet completed compiling the documents for the Kansas site. H

'J Osage The EPA has notified the Compa'ny that it is a PRP at the Osage Metals Site, a former'scrap metal recycling facility located in Kansas City, Kans'as. Under Section 107(a) of CERCLA, parties who arranged for disposal of hazardous substances are'liable for costs incurred by the EPA in responding to a'release or threat of release of the hazardous'ubstances. Osage had"purchased capacitor'scrap metal from PCB Treatment, Inc. Through the arrangements that the Company made with PCB Treatment, Inc. to dispose of capacitors, the Company is alleged to have arranged for disposal within the meaning of the federal Superfund law. A similar letter was sent to 861 parties who sent capacitors to PCB Treatment, Inc. The EPA is seeking to recover approximately $ 1.1 million dollars it expended a removal action at the site. The Company is currently unable to determine its share ofthe, to'onduct

$ 1 1 million expenditure.

~

Port Refinery The Company has been notified that it is a PRP at the Port Refinery Superfund site located in Westchester County, New York:,Port Refinery was engaged in the business of purchasing, selling, refining and processing mercury and the Company may have shipped a small amount of waste products containing mercury to this site. Tests conducted by the EPA indicated that the site and certain adjacent properties were contaminated with mercury. As a result, the EPA has performed a response action at the site and seeks to recover its costs, currently totaling approximately $ 4.4 million, plus interest, from the PRPs. The Company does not believe its portion of these costs, ifany, will be material.

Port 8'ashington In 1989, the EPA notified the Company that it was a PRP for'a landfill in Port Washington, New York.

The Company does not believe that it sent any materials to the site that contributed to the contamination which requires remediation and has therefore declined the EPA's requests to participate in funding the investigation and remediation activities at the property. The Company has not received further communications regarding this site.

50

t Liberty'he EPA has notified the Company'hat it is a PRP in a Superfund site located in Farmingdale, New York. Industrial'operations took place at this site for at least fiftyyears. The PRP group has 'claimed that the Company should absorb remediation expenses in the amount of approximately $ 100,000 associated with removing PCB-contaminated soils from a portion of the site which formerly contained electric transformers. The Company is currently unable to determine its share of costs of remediation at this site. t Huntington/East 1Vorthport, The DEC has notified the Company, pursuant to the State Supeifund program, that its records indicate the Company may be responsible for the disposal of waste at this municipal landfill property. The Company conducted a search of its corporate records and did not locate any documents concerning waste disposal practices associated with this landfill. The Company is currently unable to determine its share, ifany, of the costs to investigate and remediate this site.

Blyden burgh The New York State Office of the Attorney General has notified the Company that it may be responsible for the disposal of wastes and/or for the generation of hazardous substances which may, have been disposed of at the Blydenburgh Superfund site, a municipal sanitary landfill located in the Town of Islip, Suffolk County. The State has incurred approximately $ 15 million in costs for the investigation and remediation of environmental conditions at the landfill. In connection with this notification, the Company conducted a review of its corporate records and did not locate any documents concerning waste disposal practices associated with this landfill. The Company is currently unable to determine its-share, ifany, of the costs to investigate and remediate this site.

ther Sites 4

anufactured Gas Plant Sites The DEC has required the Company and other New York State utilities to investigate and, where necessary, remediate their former MGP sites. Currently, the Company is the owner of six pieces of property on which the Company or certain of its predecessor companies produced manufactured gas.

Operations at these facilities in the late 1800's and early 1900's may have resulted in the disposal of certain waste products located at these sites.

The Company has entered into discussions with the DEC which is expected to lead to the issuance of one or more ACOs regarding the management of environmental activities at these six properties.

Although the exact amount'of the Company's cleanup costs cannot yet be, determined, based on the findings of preliminary investigations conducted at each of these six sites, current estimates indicate that it may cost approximately $ 54 to $ 92 million to investigate and remediate all of these sites.

Considering the range, of possible reinediation estimates, the Company felt it appropriate to record a

$ 54 million liability reflecting the present value of the future stream of payments amounting to $ 70 million to investigate and remediate these sites. The Company used,a risk-free rate of 6.0% to discount this obligation. The Company believes that the PSC willprovide for future recovery of these costs and has recorded a $ 54 million regulatory asset. The Company's rate settlement which the PSC approved February 4, 1998 as discussed in Note 3 of Notes to Financial Statements, allows for the recovery of MGP expenditures from gas customers.

51

The Company is also evaluating its responsibilities with respect to several other former MGP sites, that, existed in its territory which it,does not presently own. Research is underway to determine the existence and nature of operations and relationship, ifany, to the Company or its predecessor companies.

North Hills Leak The Company has undertaken remediation of certain soil locations in North Hills, New York that were impacted by a release of insulating fluid from an electrical cable in August 1994. The Company estimates that any additional cleanup costs will not exceed $ 0.5 million. The Company has,initiated cost recovery actions against the third parties it,believes pre responsible for causing the, cable leak, the outcome, of which are uncertain.

4 Storage Facilities, "

As a result of petroleum leaks from undergro'und storage facilities and other historical occurrences, the" Company is required to investigate and, in certain cases, remediate affected soil and groundwater conditions at several facilities within its service territory. The aggregate costs of such reme'diation work could be between $ 3 million and $ 5'million. To the extent-that these costs are not recoverable through insurance carriers, the'Company believes such costs will be recoverable from its customers.

I I Nuclear Waste d N

Low Level Radioactive'Waste The federal Low-Level Radioactive Waste Policy Amendment Act of 1985; requires states to arrange for the disposal, of all low level radioactive, waste generated within the state or, in the, alternative, to contract for their disposal at an operating facility outside the state. As a result, New York State has stated its intentions of developing an in-state disposal facility due to the large volume of low level radioactive waste generated within the state and has committed to develop a plan for the management of such waste during the, interim period until a disposal facility is available. New York State is still developing a disposal methodology and acceptance criteria for a ~

disposal facility. The latest New York State low level radioactive waste site development schedule now assumes two possible siting scenarios, a volunteer approach and a non-volunteer approach, either of which would not begin operation until at least 2001..Low level radioactive waste ~

generated at NMP2 is currently being disposed of at the Barnwell, South Carolina waste disposal facility which reopened in July 1995 to out-of-state low level waste generators.

In the event that off-site storage becomes unavailable. prior to 2001, NMPC has implemented a low "

level radioactive waste management program that';will properly handle interim on-site., storage of low level radioactive waste for NMP2 for at least ten.years." The Company's share of the costs, associated with temporary storage and ultimate disposal. are currently recovered in rates. I

'l Spent Nuclear Fuel NMPC, on'behalf of the NMP2 cotenants, has 'entered into a contract with the DOE for the permanent storage of NMP2 spent nuclear fuel. The Company reimburses NMPC for its 18% share of the cost under the contract at a rate'of $ 1.'00 per megawatt hour'o'f net'generation less a factor to account for transmission line losses. The Company is collecting its portion of this fee from its electric customers. It is anticipated that the DOE facility may not be available for permanent 52

t

.storage until at least 2010. Currently, all spent nuclear fuel from NMP2 is stored at the NMPC site, and existing facilities are, sufficient to handle all spent nuclear fuel generated at NMP2 through the year 2012.

For information concerning environmental litigation, see Item 3 "Legal Proceedings" under the heading Environmental.

Impact of Year 2000 Some of the Company's older computer programs were written using two digits rather than four to define the applicable, year. As a result, those computer programs have time-sensitive software that recognizes a date using "00" as the year 1900 rather than the year 2000. This could cause a system failure or miscalculations causing disruptions of operations, including, among other things, a temporary inability to process transactions, or engage in normal business activities.

The Company embarked on a program in 1996 to complete Year 2000 compliance by December 31, 1998. A corporate-wide program has been established to review all software, h'ardware and" associated compliance plans. The readiness of suppliers an'd vendor systems is also under review. Contingency and business continuation plans are being prepared "and will be reviewed per'iodically.

The Company expects to spend approximately $ 10 million to address the'ear 2000 issue over a three-year period (1997-1999) consisting of $ 7 million to test and modify application'systems and $ 3 million to test and modify nori-information technology systems, All costs will be expensed as incurred. As of March 31, 1998, $ 4.53 million has been expended in investigating and modifying software. This effort is scheduled to be completed in 1998 and testing will continue into early 1999.

The Company believes that, with modifications to existing software and conversions to new software, the Year 2000 Issue will riot pose significant operational problems for its computer systems. However, ifsuch modifications and conversions are not made, or are not completed'on time, the Year 2000 Issue could have a material adverse impact on the operations of the Company.

The costs of the project and the date on which the Company believes it will complete the Year 2000 modifications are based on management's best estimates, which were derived utilizing numerous assumptions of future events, including the continued availability of certain resources and other factors. However, actual results could differ materially from those anticipated. Specific factors that might cause such material differences include, but are not limited to, the availability and cost of personnel trained in this area, the ability to locate and correct all relevant computer codes and similar uncertainties. J Recent Accounting Pronouncements Comprehensive Income In June 1997, the Financial Accounting Standards Board (FASB) issued Statement of Standards (SFAS) No. 130. SFAS No. 130 establishes standards for reporting Financial'ccountirig comprehensive income. Comprehensive income is the change'in the equity of a company, not including those changes that result from shareholder tran'sactions. 'All components of comprehensive income are required to be reported in a new financial statement that is displayed with equal" 53

prominence as existing financial statements. The Company will'be required to adopt SFAS No. 130 for the year ending March 31, 1999. The Company does not expect that the adoption of SFAS No. 130 willhave a significant impact on its reporting and disclosure requirements.

Segment Disclosures Also in June 1997, FASB issued SFAS No. 131. SFAS No. 131 establishes standards for additional

. ~

disclosure about operating segments for interim and annual financial statements. More specifically, it requires financial information to be disclosed for segments whose operating results are reviewed by the chief decision maker for decisions on resource allocation. It also requires related disclosures about products and services, geographic areas'and major customers. The Company will be required to adopt SFAS No. 131 for the year ending March 31, 1999. The Company does not expect that the adoption of SFAS No. 131 will have a significant impact on its reporting and disclosure requirements.

Conservation Services The Company's 1997 Demand Side Management (DSM) Plan focused on the. pursuit of energy efficiency and peak load reduction in a way that had minimal impact on, electric rate increases. To assure the success of this strategy, >he Company implemented a balanced and cost-effective mix of DSM programs that continued to represent a limited reliance on broad-based rebates and a concentrated emphasis on programs that provided education and information, targeted business development, provided financing for energy efficiency, induced market transformation and improved the efficiency of LILCO facilities. The Company was successful in meeting the PSC Energy Penalty Threshold by obtaining energy savings of approximately 24.4 GWh at a cost less than that provided for in electric rates.

In 1998, the Company plans to continue to follow the aforementioned strategy while introducing several new initiatives. These include a program targeted at increasing the energy efficiency of residences of low income customers, the introduction of a peak load curtailment program constructed to help the Company meet its peak supply side requirements and an increased emphasis on programs that induce market transformation. Overall, the 1998 Plan targets an annualized energy savings of 18.6 GWh at a budget of $ 10.7 million.

N Cautionary Statement Regarding Forward-Looking Statements This report contains statements which, to the extent they are not recitations of historical fact, constitute "forward-looking statements" within the meaning of the Securities Litigation Reform Act of 1995 (Reform Act). In this respect, the words "estimate," "project," "anticipate," "expect," "intend,"

"believe" and similar expressions are intended to identify forward-looking statements. All such forward-looking statements are intended to be subject to the safe harbor protection provided by the Reform Act. A number of important factors affecting the Company's business and financial results could cause actual results to differ materially from those stated in the forward-looking statements.

Those factors include the proposed transactions with The KeySpan Energy Corporation and LIPA as, discussed under the heading "KeySpan Energy Corporation Transaction" and "Long Island Power Authority Transaction" state and federal regulatory rate proceedings, competition, and certain environmental matters each as discussed herein, in the Joint Proxy Statement/Prospectus filed June 30, 1997, or in other reports filed by the Company with the Securities and Exchange Commission.

54

FINANCIALSTATEMENTS Balance Sheet tIn thousands ofdollars)

'etsat March31,1998 March31,1997 December31,1996 tilityPlant Electric 4,031,510 $ 3,900,264 $ 3,882,297 Gas 1,233,281 1,'171,183 1,154,543 Common 290,221 263,267 260,268 Construction work in progress 118,808 108,850 112,184 Nuclear fuel in rocess and in reactor 18,119 15,454

-'5,503 5,691,939 5,459,067 5,424,746 Less - Accumulated dc reciation and amortization 1,877;858 1,759,110 1,729,576 Total Net Utili Plant 3,814,081 3,699,957 3,695,170 Regulatory Assets Base financial component (less accumulated amortization of $ 883,496, $ 782,525 and $ 757,282) 3,155,334 3,256,305 3,281,548 Rate moderation component 434,004 409,512 402,213 Shoreham'post-settlement costs 1,005,316 '96,270 991,795 Shoreham nuclear fuel 66,455 68,581 69,113 Unamortized cost of issuing securities 159,941 187,309 194,151 Postretirement benefits other than pensions 340,109 357,668 360,842 Regulatoiy tax asset 1,737,932 1,767,164 1,772,778 Other 192,763 200,137 199,879 Total Re lato Assets 7,091,854 7,242,946 7,272,319 nutilit Pro crt and"OthcrInvcstmcnts 50,816 18 870 18 597 rent Assets sh and cash equivalents 180,919 64,539 279,993 Special deposits 95,790 37,631 38,266 Customer accounts receivable (less allowance 'r for doubtful accounts of $ 23,483, $ 23,675 and $ 25,000) 297,889 305,436 255,801 Other accounts receivable 43,744 42,946 65,764 Accrued unbilled revenues r 124,464 141,389 '69,712 Materials and supplies at average cost 54,883 55,454 55,789 Fuel oil at average cost 32,142 49,703 53,'941 Gas in storage at average cost 14,634 10,893 73,562 Defcrrcd tax asset - net operating loss 93,349 145,205 Pre a ments and other current assets 13,807 8,805 8,569 Total Current Assets 858,272 810,145 1,146,602 Deferred Char es 85,702 77,656 76,991 Tofal Assets 11,900,725 $ 11,849,574 $ 12,209,679 See )Votes to Financial Statements.

55

Pn thousands o dollars)

Ca italtzation and Liabilities at March 31, 1998 March 31, 1997 December 31, 199 Capitalization Long-term debt 4,395,555 4,471,675 $ 4,471,675 Unamortized discount on debt (13,606) (14,628) 14,903) 4,381,949 4,457,047 4,456,772 Preferred stock - redemption required F

562,600 638,500 638,500 Prcfencd stock - no redem tion uired 63,598 63,664 Total Preferred Stock 562,600 702,098 702,164 Common stock 608,635 605,022 603,921 Premium on capital stock 1,146,425 1,131,576 1,127,971 Capital stock expense (47,501) (48,915) (49,330)

Retained earnings 956,092 861,751 840,867 Trcasu stock, at cost (1,204) (385) (60)

Total Common Shareoivners'i 2,662,447 2,549,049 2,523,369 Total Ca italization 7,606,996 7,708,194 7,682,305 Regulatory Liabilities Regulatory liability component 99,199 178,558 198,398 1989 Settlement credits 59,397 125,138 127,442 Regulatory tax liability 78,913 100,377 102,887 Other 151,922 158,660 139,510 T 1R I t Liabilities 389,431 562,733 568,237 Current Liabilities Current maturities of long-term debt 101,000 1,000 251,00 Current redemption requirements of preferred stock 139,374 1,050 1,050 Accounts payable and accrued expenses 228,583 230,189 289,141 LRPP payable 30,118 40,499 40,499 Accrued taxes (including federal income tax of $ 28,308, $ 49,262 and $ 25,884) 34,753 51,157 63,640 Accrued interest 146,607 143,983 160,615 Dividends payable if 58,748 58,474 58,378 Class Settlement 60,000 58,333 55,833 Customer de sits 28,627 29,173 29,471 Total Current Liabilities 827,810 613,858 949,627 Deferred Credits Deferred federal income tax - net 2,539,364 2,420,443 2,442,606 Class Settlement 46,940 89,487 98,497 Other 22,529 20,889 39,447 Total Deferred Credits 2,608,833 2,530,819 2,580,550 Operating Reserves Pensions and other postretirement benefits 401,401 387,048 381,996 Claims and dama cs 66,254 46,922 46,964 Total 0 ratin Reserves 467,655 433,970 428,960 Commitments and Contin encies Total Ca italization and Liabilities $ '1,900,725 11,849,574 $ 12,209, See Notes to Financial Statements.

56

Statement of income (in thousands of dollars cx t

, Thee Months Year Ended Ended Year Ended Year Ended March 31, 1998 March 31, 1997 December 31, 1996 December 31, 1995 Revenues Elcctnc $ 2,478,435 557,791 $ 2,466,435 $ 2,484,014 Gas 645,659 293,391 684,260 591,114 Total Rcvcnues 3,124,094 851,182 3,150,695 3,075,128 Operating Expenses Operations - fuel and purchased power 957,807 301,867 963,251 834,979 Operations - other 400,045 95,673 381,076 383,238 Maintcnancc , 111,120 29,340 118,135 128,155 Depreciation and amortization 158,537 38,561 153,925 145,357 Base Iinancial component amortization 100,971 25,243 100,971 100,971 Rate moderation component amortization (35,079) 5,907 (24,232) 21,933 Rcgu!atoty liabilitycomponent amortization (79,359) (19,840) (79,359) (79,359) 1989 Settlemcnt credits amortization (9,213) (2,303) (9,214) (9,214)

Other regulatory amortization 47,272 12,218 127p288 161,605 Operating taxes 466,326 117,513 472,076 447,507 Fcdcral income tax - current 86,388 23,378 42,197 14,596 Federal income tax - deferred and other 150,983 33,624 168,000 193,742 Total ratin Ex nscs 2,355,798 661,181 2,414,114 2,343,510 0 ratin Income 768,296 190,001 736,581 731,618 Other Income and (Deductions)

Rate moderation component carrying charges 23,632 5,919 25,259 25,274 Other income and deductions, nct (18,156) 645 19,197 34,400 Class Scttlcment (15,623) (4,496) (20,772) (21,669) for other funds used during construction 3,846 717 2,888 2,898 F mc tax - current 594 F e tncome tax-deferred an'd other 4,124 789 "'940 2,800 Total Other Income and Deductions 1,583 3,574 27,512 43,703 Income Bcforc Interest Char cs 766,713 193,575 764,093 775,321 Interest Charges Interest'on long-term debt 351,261 90,168 3&4,198 412,512 Other intcrcst 57,805 16,659 67,130 63,461 Allowance for borrowed funds used durin construction 4,593 949 3,699 3 938 Total Interest Cha es 404,473 105,878 447,629 472,035 Net Income 362,240 87,697 316,464 303,286 Preferred stock dividend r uircments 51,813 12,969 52,216 52,620 Earnin for Common Stock 310,427 74,728 $ 264 248 $ 250,666 Avcra e Common Shares Outstandin 000 121,415 120,995 120,360 119,195 Basic and Diluted Earnin er Common Share 2.56 0.62 $ 2.20 $ 2.10 Dividends Declared cr Common Sharc 1.78 0.45 $ 1.78 $ 1.78 See"¹les ro Financtal Slarensenrs.

57

Statement of Cash Flows (fn thousands ofdollars)

Year Thtce Year Year Ended Months Ended Ended Ended.

March 31 March 31 December 31 Decein 1998 1997 1996 199 Operating Activities Net Income $ 362,240 $ 87,697 $ 316,464 $ 303,286 Adjustmcnts to reconcile net income to net cash provided by operating, activities Provision for doubtful accounts 23,239 4,821 23,119 17,751 Depreciation and amortization 158,537 38,561 153,925 145,357 Base financial component amortization 100,971 25,243 100,971 '100,971 Rate moderation component amorhzation (35,079) ',907 (24,232) 21,'933 Regulatory liabilitycomponent amortization (79,359) (19,840) (79,359) (79,359) 1989 Settlement credits amortization (9,213) (2,303) (9,214) (9,214)

Other regulatory amortization 47,272 12,218 127,288 161,605 Rate moderation component carrying charges (23,632) (5,919) (25,259) (25,274)

Class Settlement 15,623 4,496 20,772 21,669 Amortization of cost of issuing and redeeming securities 30,823 8,087 34,611 39,589 Federal income tax - deferred and other 146,859 32,835 167,060 190,942 Pensions and Other Post Retirement Benefits 48,512 13,496 14,952 4,900 Other 87,618 2,381 51,671 56,675 Changes in operating assets and liabilities Accounts receivable (14,905) (31,638) 69,215 (67;213)

Materials and supplies, fuel oil and gas in storage 14,391 67,242 (34,531) 21,986 Accounts payable and accrued expenses 1,668 (58,952) 28,258 19,100 Class Settlement (56,503) (11,006) (42,084) '33,464)

Special deposits (58,159) 635 25,146 (35,798)

Other (86,819) 14,394 26,460 83,442 N 'd b 0 tin Activities 674,084 159,567 892,313 772 000 Investing Activuies Construction and nuclear fuel expenditures (257,402) (50,375) (239,896) ( 6)

Shoreham post-settlement costs (39,828) (12,104) (51,722) (70,589)

Investment in interest rate hedge (30,000)

Otlier (1.987) 160 (4,806 8,019 Net Cash Used in Investin Activities 329,217) (62,319 296,424 306,156 Financing Activities Proceeds from issuance of securities 43,218 4,640 18,837 68,726 Redemption of securities (2,050) (250,000) (419,800) (104,800)

Common stock dividends paid (215,790) (53,749) (213,753) (211,630)

Ptefetred stock dividends paid (51,833) (12,969) (52,264) (52,667)

Other 2,032) (624) (369) , 529 Net Cash Used hi Financin Activities (228,487) (312,702 (667,349 299,842 Nct Increase (Decrease) In Cash and Cash Equivalents $ 116,380 ($215,454) ($ 71,460) $ 166,002 Cash and cash equivalents at beginning of period $ 64,539 $ 279,993 $ 351,453 $ 185,451 Net hicrease (decrease) in cash and cash e uivalents 116,380 215,454 71,460 '66,002.

Cash and Cash Equivalents at end of period $ 180,919 $ 64,539 $ 279,993 Interest pai, ote reduchon or ie allowance '351,453'427,988 for borrowed funds used during construction $ 364,864 $ 112,981 $ 404,663 Federal income tax paid $ 108,980 $ 45,050 $ 14,200 See Ptotes to Financial Statements.

58

Statement of Retained Earnin

~

s Pn thousands ofdolkws)

Dcocmber 31 ~ 1995 st of period $ 861,751 8 840,867 8 790,919 8 752.480 Nct income for the period 362.240 87,697 316,464 303~

),223 P91 928,564 1,107/83 1,055,766 II Deductions Cash dividends declared on common stock 216,086 $ 3,844 214,255 212,181 Cash dividends dcclarcd on preferred stock 51,812 12.969 52,240 52,647 Other t 1 21 19 Balance st end of rlod $ 956,092 5 861,751 $ 840.867 $ 790,919 Sre Notes to Finandol Staternerus.

Statement of Ca italization ShanesIssued (fn thousands ofdollars)

March 31, 1998 March 31, 1997 Deccmbcr 31, 1996 March 31, 1998 r March 31, 1997 December 31, 1996 Common Shareovrncrs'quity Common stock, $ 5.00 per value 121,727,040 12L00431$ 120,784,277 $ 608,635 $ ' 605,022 $ 603P21 Premium on capital stock ~ 146,425 V3 1476 1,127P71 Capital stock expense (47,501) (48.915) (49@30)

Rctaincd comings 956,092 861,751 840,867 Treasury stock, st cost 16,985 3,485 (1,204) (385) (60)

Total Common Shsreovrners'quity 2,549,049 2,523369 Preferred Stock- Redemption Required Par vsluo $ 100 pcr share

/v Sensa L 150,$ 00 161,000 161,000 15,050 '6,100 16,100 v Scrics CC $ 70,000 570,000 570,000 57,000 57,000 $ 7,000 es called for redemption 15.050 1,0$ 0 1,0$ 0 57.0CN. 72.0$ 0 '2,050 Par value $25 per share 7.95% Series AA 14/20,000 14,520,000 14,$ 20.000 363,000 t 363,000 363,000

$ 1.67 Series GG 880,000 880,000 880,000 22,000 22,000 22,000

$ 1.95 Series NN 1/$ 4,000 1,554,000 1,554,000 38,850 38,850 38,8$ 0 7.05% Series QQ 3,464,000 3,464,000 3,464.000 86,600 86,600 86,600 6.875% Sensa UU 2,~,000 2,~000 ',240,000 56,000 56,000 56,000 Less - Series called for redemption 38,850 Less redemption ofpreferred stock 505.600 i 566.450 566,4$ 0 Total Prefcrrcd Stock - Redem 'on Requirel Preferred Stock- No Redemption Required Par value $ 100 per sharo

$ .00/i Series B 100,000 100,000 )00,000 10,000 10,000 10,000

.4.25% Series D 70,000 70,000 70,000 7P~ 7,000 ~ 7,000 435% Scrics B 200,000 200,000 20,000 20,000 20,000 4.35% Series F 50,000 50,000 50.000 5,000 5.000 5,000 5 1/8/e Scrics H, 200,000 200,000 200,000 ,

20,000 20,000 20.000 5 3/4% Series 1 - Convertible 14,743 15,978 16,637 1,474 1,598 lr664 Less - Scncs celled lbr rcdcmptien 63.474 1 Total Preferred Stock- No Redemption Required 63,598 63.664 Tots referred Stock 562 600 $ 702,098 S 59

grithourrurr/s o dollorr) 31 I General and Refunding Borids Fehuary IS, 1997 8 3/4% $ $ 250,000 April 15, 1998 7 5/SYi 100,000 100,000 100,000 Msy 15, 1999 7.85% 56,000 56,000 56,000 April 15, 2004 8 5/SYi 185,000 185,000 'SS,000 Msy 1$ , 2006 8.50Yi 75.000 75,000 75,000 July IS, 2008 7.pter/i 80,000 80,000 80,000 May 1,2021 9 3/4% 415,000 '15,000 415,000 July I, 2024 9 5/8/i 375,000 375.000 375,000 Total General and Retbnding Bonds 1,286.000 1,286,000 Dcbcntures July IS, 1999 7.30Yi 397,000 397,000 January 1$ , 2000 7.30Yi 36,000 36,000 36,000 July 15. 2001 6.25% 145,000 145,000 145,000 March IS. 2003 7.05% 150,000 1$ 0,000 150,000 Mach I, 2004 7.00Yi 59,000 59,000 59,000 Juno I, 2OOS 7.125% 200,000 200,000 March I, 2007 7.50/i 142,000 142,000 July 1$ ,2019 8.90Yi 420.000 420,000 November I, 2022 9.00Yi 451,000 451,000 451,000 March 15, 2023 8.20Yi 270.000 270.000 270,000 Total Dcbcnturcs 2,270,000 2,270,000 Authority Flnanclng Notes Industriai Development Revenue Bonds Dcccmber I, 2006 7.50Yi 1976 AB Poliurion Control Revenue Bonds December I, 2006 7.50/i 1976 A 2737$ 28/75 2837$

Deccmbcr I, 2009 7.80Yi I 979 B 19,100 19,100 19,100 October I, 2012 8 I/4% 1982 17,200 17,200 17,200 Mach I, 201 6 3.58/i, 1985 AB 150.000 150,000 ISO,000 Elcctrio Faeilitics Rcvcnue Bends Sq¹cmber I, 2019 7.15% 1989 AB, 100,000 100,000 100,000 June I, 2020 7.15% . 1990 A 100,000 100,000 100,000 December I, 2020 7.15% 1991 A 100,000 100.000 100,000 Fchuary I, 2022 7.15% 1992 iEB 100,000 100,000 100.000 August I, 2022 6.90/i 1992 CiD 100,000 100,000 100,000 November I ~ 2023 3.70/i 1993 A 50.000 50,000 November I, 2023 3.70/i 1993 B S0,000 50,000 October I, 2024 3.70Yi 1994 A 50,000 50,000 -50,000 August I, 202S 3.70Yi 199S A S0,000 50,000 December I, 2027 3.55% 1997 A 24,880 Total Authority Financing Notes 940355 916,675 916.675 Unamortized Discount on Debt (13,606) (14.628) 4,482@49 4,4SS,OI7 4,707,772 101.000 1,000 2S1,000 Total Long-Term Debt 4,381,949 4.457.047 4.45(c772 Total Ca Italhatlon $ 7.6069K $ 7.708.194 $ 7,682305 Sce No/rs ro Finmrdol $/a/eaten/a 60

NOTES TO FINANCIALSTATEMENTS

~ ~

Note 1. Summary of Significant Accounting Policies

~

~

asis of Presentation

~

On April 11, 1997, the Company changed its year end from December 31 to March 31. Accordingly, unless otherwise indicated, references to 1998 and 1997 represent the twelve month period ended March 31, 1998 and March 31, 1997, while references to all other periods'refer to the respective calendar years ended December 31.

's further discussed in Note 2, on June 26, 1997, the Company and the Long Island Power Authority (LIPA) entered into definitive agreements pursuant to which, afler the transfer of the Company's gas business unit assets, non-nuclear electric generating facility assets and certain other assets and liabilities to one or more newly-formed subsidiaries of a new holding company, the Company's common stock will be sold to LIPA for approximately $ 2.4975 billion in cash. No adjustments have been made to the Company's financial statements to reflect this proposed transaction.

II Nature of Operations The Company was incorporated in 1910 under the Transportation Corporations Law of the State of New York and supplies electric and gas service in Nassau and Suffolk Counties and to the Rockaway Peninsula in Queens County, all on Long Island, New York. The Company's service territory covers an area of approximately 1,230 square miles. The population of the service area, according to the Company's 1998 Long Island Population Survey estimate, is about 2.75 million persons, including approximately 98,500 persons who reside in Queens County within the City of New York.

e Company serves approximately 1.04 million electric customers of which approximately 93 1,000 are sidential. The Company receives approximately 49'/0 of its electric revenues from residential customers, 48/0 from commercial/industrial customers and the balance from sales to other utilities and public authorities. The Company also serves approximately 467,000 gas customers, 417,000 of which are residential, accounting for about 610/0 of its gas revenues, 17,000 of which are commercialiindustrial,:

accounting for 23/o of its gas revenues, 3,600 of which are firm transportation customers, accounting for 30/0 of its gas revenues, with the balance of the gas revenues made up by off-system sales.

The Company's geographic location and the limited electrical interconnections to Long Island serve to limit the accessibility of the transmission grid to potential competitors from offthe system. In addition, the Company does not expect any new major independent power producers (IPPs) or cogenerators to be built on Long Island in the foreseeable future. One of the reasons supporting this conclusion is based on the Company's belief that the composition and distribution of the Company's remaining commercial and industrial customers would make it difficult for large electric projects to operate economically.

Furthermore, under federal law, the Company is required to buy energy from qualified producers at the Company's avoided cost. Current long-range avoided cost estimates for the Company have significantly reduced the economic advantage to entrepreneurs seeking to compete with the Company and with existing IPPs. For a further discussion of the competitive issues facing the Company, see Note 12.

Regulation The Company's accounting records are maintained in accordance with the Uniform Systems of Accounts cribed by the Public Service Commission of the State of New York (PSC) and the Federal Energy ulatory Commission (FERC). Its financial statements reflect the ratemaking policies and actions of 61

these commissions in conformity with generally accepted accounting principles for rate-regulated-enterprises.

Accounting for the Effects of Rate Regulation General The Company is subject, to the provisions of Statement of Financial Accounting Standards (SFAS) No.

"Accounting for the Ef'fects of Certain Types of Regulation." This statement recognizes the economic

'1, ability of regulators, through the ratemaking process, to create future economic benefits and obligations affecting rate-regulated companies. Accordingly, the Company records these future economic benefits and obligations as regulatory assets and regulatory liabilities, respectively.

Regulatory assets represent pr'ob'able future revenues associated with previously incurred costs that are expected to be recovered from customers. Regulatory liabilities represent probable future reductions in associated with amounts that are expected to be refunded to customers through the ratemaking 'evenues process. Regulatory assets net of regulatory liabilities amo'unted to approximatefy $ 6.7 billion at March 31, 1998, March 31, 1997 and December 31, 199'6.

In order for a rate-regulated entity to continue to apply the provisions of SFAS No. 71, it must continue to meet the following three'criteria: (i) the enterprise's rates for regulated services provided to its customers must be established by an independent third-party regulator; (ii) the regulated rates must be designed to recover the specific enterprise's costs of providing the regulated services; and (iii) in view of the demand for the regulated services and the level of competition, it is reasonable to assume that rates set at levels that will recover the enterprise's costs can be charged to and collected from customers.

Based upon the Company's evaluation of the three criteria discussed above in relation to its operations, the effect of'competition on its ability to recover its costs, including its allowed return on comrrion equity an the regulatory environment in which the Company operates, the Company believes that SFAS No. 71 continues to apply td the Company's electric and gas operations. The Company formed its conclusion based upon several factors including: (i) the Company's continuing ability to earn its allowed return on common equity for both its electric and gas operations; and (ii) the PSC's continued commitment to the Company's full recovery of the Shoreham Nuclear Power Station (Shoreham) related assets and all other prudently incurred costs.

Notwithstandirig the above, rate'regulation is undergoing significant change as regulators and'customers seek lower prices for electric and gas service. In the event that regulation sig'nificantly changes the opportunity for the Company to recover its costs in the future, all or a portion of the Company's operations may no longer meet the'criteria discussed above. In that event, a significant write-down of all a portion of the Company's existing regulatory assets and liabilities co1rld result. Ifthe Company had

'r been unable to continue to apply the provisions of SFAS 71 at March 31, 1998, the Company would apply the provisions of SFAS 101 "Regulated Enterprises Accounting for the Discontinuation of Application of PASB Statement No. 71." IfSFAS'101 were implement'ed, the charge to earnings could be as high as

$ 4.5 billion, net of tax. For additional information respecting the Company's Shoreham-related assets, see below and Notes 4 and 10.

SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of'equires that costs which were capitalized in accordance with regulatory practices, because it was probable that future recovery would be allowed by the regulator, must be charged against current period earnings ifit appears that the criterion for capitalization no longer applies. The carrying amount such assets would be reduced by amounts for which recovery is unlikely. SFAS No. 121 also provides for 62

t the restoration of previously disallowed costs that are subsequently allowed by a regulator. No impairment losses have been recognized by the Company with respect to regulatory or other long-lived assets.

lh Discussed below are the Company's significant regulatory assets and regulatory liabilities.

I Base Financial Component and Rate Moderation, Component, h

Pursuant to the 19S9 Settlement, the Company recorded a regulatory asset known as the Financial Resource Asset (FRA). The FRA is designed to provide the Company with sufficient cash flows to assure its financial recovery. The FRA has two components, the Base Financial Component (BFC) and the Rate Moderation Component (RMC).,

The BFC represents the present value of the future net-after-tax cash,,flows which the Rate Moderation Agreement (RMA), one of the constituent documents of the 1989 Settlement, provided the Company, for its financial recovery. The BFC was granted rate base treatment under the terms of the RMA and is included in the Company's revenue requirements through an amortization included in rates over a forty-year period on a straight-line basis which began July 1, 19S9.

'h The RMC reflects the difference between the Company's revenue requirements under conventional ratemakirig and the revenues resulting from the implementation of the rate moderation plan provided for in the. RMA. The RMC is currently adjusted, on a monthly basis, for the Company's share of certain NMP2 operations and mainten'ance expenses, fuel credits resulting from the Company's electric fuel cost adjustment clause and gross receipts tax adjustinents related to the FRA.

In April 1998, the PSC authorized a revision to the Company's method for recording its monthly RMC amortization. Prior to this revision, the amortization of the annual level of RMC was recorded monthly on a traight-line, levelized basis over the Company's rate year which runs from December 1 to November 30.

owever, revenue requirements fluctuate from month to month based upon consumptionwhich is greatly impacted by the effects of weather. Under this revised method, effective December 1, 1997, the monthly amortization of the annual RMC level varies based upon each month's forecasted revenue requirements, which more. closely aligns such amortization with the Company's cost of service. As a result of this change, for the fiscal year'ended March 31, 1998, the Company recorded approximately $ 65.1 million more of non-cash RMC credits to income (representing accretion of the RMC balance),,or $ 42.5 million net of tax, representing $ .35 per share more than it would have under the previous method. However, the total RMC amortization for the rate year ending November 30, 1998, will be equal to the amount that would have been provided for under the previous method. As discussed in Note 2, the RMC will be acquired by LIPA as part of the LIPA Transaction. h For a further discussion of the 1989 Settlement and FRA, see Notes 4 and 10.

Shoreham Post-Settlement Costs Shoreham post-settlement costs consist of Sh'oreham decommissioning costs, fuel disposal costs, payments-in-lieu-of-taxes, carrying charges and other costs. These costs are being capitalized and amortized and recovered through rates over a forty-year period on a straight-line remaining life basis which began July 1, 1989. For a further discussion of Shoreham post-settlement costs, see Note 10.

h Shoreham Nuclear Fuel horeham nuclear fuel principally reflects the unamortized portion of Shoreham nuclear fuel which was lassified from Nuclear Fuel in Process and in Reactor at the time of the 1989 Settlement. This amount is eing amortized and recovered through rates over a forty-year period on a straight-line remaining life basis which began July 1, 1989.

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Unamortized Cost ofIssuing Securities Unamortized cost of issuing securities represents the unamortized premiums or discounts and expenses related to the issues of long-term debt that have been retired prior to maturity and the costs associated with the early redemption of those issues. In addition, this balance includes the unamortized capital stock expense and redemption costs related to certain series of preferred stock that have been refinanced. These costs are amortized and recovered through rates, as provided by the PSC, over the shorter of the life of the redeemed issue or the new issue.

Postretirement Benefits Other Than Pensions The Company defers as a regulatory asset the difference between postretirement benefit expense recorded in accordance with SFAS No. 106, "Employers'ccounting for Postretirement Benefits Other Than Pensions," and postretirement benefit expense reflected in current rates. Pursuant to a PSC order, the ongoing annual SFAS No. 106 benefit expense was phased into and fully reflected in rates by November 30, 1997, with the accumulated deferred asset to be recovered in rates over the fifteen-year period which began December 1, 1997. For a further discussion of SFAS No. 106, see Note 8.

Regulatory Tax Asset and Regulatory Tax Liability The Company has recorded a regulatory tax asset for amounts that it will collect in future rates for the portion of its deferred tax liability that has not yet been recognized for ratemaking purposes.

tax asset is comprised principally of the tax effect of the difference in the cost basis of the BFC The'egulatory for financial and tax reporting purposes, depreciation differences not normalized and the allowance for equity funds used during construction.

The regulatory tax liability is primarily attributable to deferred taxes previously recognized at rates higher than current enacted tax law, unamortized investment'tax credits and tax credit carryforwards.

Regulatory LiabilityComponent Pursuant to the 1989 Settlement, certain tax benefits attributable to the Shoreham abandonment are to be shared between electric customers and shareowners. A regulatory liability ofapproximately $ 794 million was recorded in June 1989 to preserve an amount equivalent to the customer tax benefits attributable to the Shoreham abandonment. This amount is being amortized over a ten-year period on a straight-line basis which began July 1, 1989.

1989 Settlement Credits t

Represents the unamortized portion of an adjustment of the 'book write-offto the negotiated 1989 Settlement amount. A portion of this amount is being amortized over a ten-year period which began on July 1, 1989. The remaining portion is not currently being recognized for;ratemaking purposes.

UtilityPlant Additions to and replacements of utility plant are capitalized at original cost, which includes material, labor, indirect costs associated with an addition or replacement and an allowance for the cost of funds used during construction. The cost of renewals and betterments relating to units of property is added to utility plant. The cost of property replaced, retired or otherwise disposed of is deducted from utilityplant and, generally, together with dismantling costs less any salvage, is charged to accumulated depreciation.

The cost of repairs and minor renewals is charged to maintenance expense. Mass properties (such as poles, wire and meters) are accounted for on an average unit cost basis by year of installation.

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t Allowance for Funds Used During Construction The Uniform Systems of Accounts as prescribed by the PSC, defines the Allowance, For Funds Used During Construction (AFC) as the net cost of borrowed funds used for construction purposes and a, reasonable rate of return upon the utility's.equity'when so used. AFC is not an item of current cash income. AFC is computed monthly using a rate permitted by the FERC on a portion of construction work in progress. The average AFC rate, without giving effect to compounding, was as follows:

Periods 'AFC Rate 12 Months Ended 3/31/98 9.29/o 3 Months Ended 3/31/97 2.26/o 12 Months Ended 12/31/96 9.02/o 12 Months Ended 12/31/95 9.36/o Depreciation The provisions for depreciation result from the application of straight-line rates to the original cost, by groups, of depreciable properties in service. The rates are determined by age-life studies performed annually on depreciable properties. The average depreciation rate as a percentage of respective average depreciable plant costs was as follows:

Periods Electric Gas 12 Months Ended 3/31/98 3.07o/o 2.04o/o 3 Months Ended 3/31/97 78o/o '51o/o 12 Months Ended 12/31/96 3.00/o 2 00o/o 12 Months Ended 12/31/95 3.00o/o 2 00o/o Cash and Cash Equivalents Cash equivalents are highly liquid investments with maturities of three months or less when purchased.

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he carrying amount approximates fair value because of the short maturity of these investments.

LRPP Payable Represents the current portion of amounts due to ratepayers that result from the revenue and expense reconciliations, performance-based incentives and associated carrying charges'as established un'der the LILCO Ratemaking and Performance Plan (LRPP). For further discussion of the LRPP, see Note 4.

Fair Values of Financial Instruments The fair values for the Company's long-term debt and redeemable preferred stock are based on quoted market prices, where available. The fair values for all other long-term debt and redeemable preferred stock are estimated using discounted cash flow analyses based upon the Company's current incremental borrowing rate for similar types of securities.

Revenues Revenues are comprised of cycle billings rendered to customers and the accrual of electric and gas revenues for services rendered to customers not billed at month-end.

The Company's electric rate structure provides fear a revenue reconciliation mechanism which eliminates the impact on earnings of experiencing electric sales that are above or below the levels reflected in rates.

The Company's gas rate structure provides for a weather normalization clause which reduces the impact revenues of experiencing weather which is warmer or colder than normal.

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Fuel Cost Adjustments h The Company's electric.and gas tariffs include fuel cost adjustment (FCA) clauses which provide for the of the difference between actual fuel costs and the fuel costs allowed in the Company's base 'isposition tariffrates(base fuel costs). The. Company defers these differences to future periods in which they will be billed or credited to'customers, except for base'electric fuel costs in excess of actual electric fuel 'costs,'hich are currently credited to the RMC as incurred. "Purs'uant'to the Stipulation,'as described in Note 3, gas fuel costs are excluded from base fuel costs and recovered through the gas fuel adjustment clause.

Federal Income Tax The Company provides deferred federal income tax with respect to certain items of income and expense that are reported in different periods for federal income tax purposes than for financial statement purposes.

Additionally, the Company provides deferred federal income tax with respect to items with different bases for financial and tax reporting purposes, as discussed in Note 9.

The Company 'defers the benefit of,60/0 of pre-1982 gas and pre-.1983 electric and 100/o of all tax credits, with respect to regulated properties, when realized on its tax returns. Accumulated other,'nvestment deferred investment tax credits are amortized ratably over the lives of the related properties.

'1 II For ratemaking purposes, the Company provides deferred federal income tax with respect to certain differences between income before income tax for financial reporting purposes and taxable income for federal income tax purposes. Also, certain accumulated deferred federal income tax is deducted from rate base and amortized or otherwise applied as a reduction in'federal inc'ome tax expense in 'future years.

Reserves for Claims and Damages Losses arising from claims against, the Company, including workers', compensation claims, property...

damage, extraordinary storm'costs and general liability claims, are partially self-insured. -Reserves for these claims and damages are based on, among other things, experience, risk of loss and the ratemaking practices of the PSC. Extraordinary storm losses incurred by the Company are partially insured by various, commercial insurance carriers.-, These"insurance carriers provide partial insurancecoverage for indivjdual storm losses to,the Company',s transmission and distribution system between $ 15 million and

$ 25 million.. Storm losses which,are outside of this range are self-insured by the Company.

Recent Accounting Pronouncements " V'I Earnings I'er Share At December 31, 1997, the Company adopted SFAS No; 128, "Earnings Per Share." This statement replaced the calculation of.primary and fully diluted earnings per share with basic and diluted earnings per share. Unlike primary earnings per share, basic earnings per share excludes'any dilutive effects of options, warrants and convertible securities. Diluted earnings per share are very similar to the previously reported fully diluted earnings per share. None of the earnings per share amounts for periods presented were effected by, the adoption of.,SFAS No. 128: .,'

Comprehensive Income In June 1997, the Financial Accounting'Standards Board'(FASB) issued Statement of Financial Accounting. Standards (SFAS) No. 130. "SFAS No." 130 establish'tandards for reporting comprehensive income. Comprehensive income is the change in the equity of a company, not including those changes that re'suit from 'sh'areholder tran'sactions'. All components of comprehensive income are required to be reported in a new financial statement that is displayed with equal prominence'as existing financial statements. The Company will be required to adopt SFAS No. 130 for the year ending March 31, 1999.

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The Company does'n'ot expect that the adoption of SFAS No. 130 will have a significant impact on its" and disclosure requirements'. 'eporting

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In June 1997, FASB issued SFAS No. 131 rr"Disclosures about Segments of an Enterprise and Related

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Information." SFAS No. 131 establishes standards for additional disclosure about operafing segments for

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interim and'annual financial statem'ents. More specifically, it, requires financial inform'ation to be disclosed for segments whose operating results are reviewed by the chief oper'ating decision maker for decisions on resource allocation. It also requires related disclosures about products and services," " "

geographic areas and major custom'ers. The Company will be required to adopt SFAS No. 131 for the fiscal year ending March 31, 1999. The Company does"not expect that the adoption of SFAS No. 131 will have a significant'impact on its reporting and disclosure requirements.

Estimates'l

'I Use of The prepar'ation of the'financial statements in confo'rmity with generally accepted accounting principles requires management to make estimates and assumptions that affect the'amounts reported'in the financial statements and accompanying notes. Actual results could differ from those estimates.

V Reclassifications "

V year amounts have b'een reclassified in the financial statements to conform'with the current

'ertain'prior year presentation.

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2. 'Long Island Power Authority Transaction V'ote On June 26, 1997, the Company and Long Island Power Authority (LIPA) e'ntered'into definitive agreements purs'uant to which, after the transfer of the Company's gas business unit assets, non-nuclear'ectric generating facility assets and certain other assets and liabilities to one or more newly-foimed of a new holding company (HoldCo), formed in connection with the LIPA Transaction and 'ubsidiaries Key'Span'Transaction discussed below, the Co'mpany's common stock will be s'old'to LIPA for $ 2.4975 billion in cash.

In connection with this transacti'on", the principal'assets to be acquired by LIPA through its ofLIL'CO include: (i) the net book value of LILCO's electric transmission and distribution stock'cquisition system', which amounted to'pproximately $ 1.3 billion at March 31; 1998; (ii) LILCO s'et investment in NMP2, which amounted to approximately $ 0.7 billion at March 31, 1998 (as more fully discus'sed in Note 5); (iii) certain of LILCO's regulatory assets associated with its electric business; and (iv) allocated'ccounts receivable and other assets. The regulatory assets to be acquired by LIPA amounted to approximately $ 6.6 billion at March 31, 1998, arid p'rimarily consist of the Base Financial Component (BFC), Rate Moderation Component (RMC),'Shoreham post-settlement costs, Shoreham nuclearfuel, and the electric portion of the regulatory tax asset. For a further discussion of these regulatory assets, see Note V

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V II LIPA is contractually re'sponsible for reimbursing HoldCo for postretirement b'enefits other than pension costs related to employees of LILCO's'electric business. 'Accordingly, upon coinsurnmationiof the HoldCo will reclassify the associated regulatory asset for po'stretirement benefits other than 'ransaction, pensions to a contractual receivable. I V

e principal liabilities to be assumed by LIPA through its stock acquisition of LILCO include:: (i)

LCO's regulatory liabilities associated with its electric business; (ii) allocated accounts payable, ustomer deposits, other de'ferred'credits and claims and damages; and (iii) certain series of long-term 67

debt. The regulatory liabilities to be assumed by LIPA amounted to approximately $ 365 million at March 31, 1998, and primarily consist of the regulatory liability component, 1989 Settlement, credits and the electric portion of the regulatory tax liability. For a further discussion of these regulatory liabilities, see Note 1 of Notes to Financial Statements.

The long-term debt to be assumed by LIPA will consist of: (i) all amounts then outstanding under the General and Refunding (G&R) Indentures; (ii) all amounts then outstanding under the Debenture Indentures, except as noted below; and (iii).substantially all of the tax-exempt authority financing notes.

HoldCo is required to assume the, financial obligation associated with the 7.30'/0 Debentures due July 15, 1999, with an aggregate principal amount currently outstanding of $ 397 million and 8.20/0 Debentures due March 15, 2023, with an aggregate principal amount currently outstanding of $ 270 million. HoldCo will seek to exchange its Debentures, with identical terms, for these two series of Debentures and will issue a promissory note to LIPA in an amount equal to the unexchanged amount of such Debentures.

HoldCo will also issue a promissory note to LIPA for a portion of the tax-exempt debt borrowed to support LILCO's current gas operations, with terms identical to those currently outstanding. The Company currently estimates the amount of this promissory note to be approximately $ 250 million.

l In July 1997, in accordance with the provisions of the LIPA Transaction, the Company and The Brooklyn Union Gas Company (Brooklyn Union) formed a limited partnership and each Company invested $ 30 million in order to purchase an interest rate swap option instrument to protect LIPA against market risk associated with the municipal bonds expected to be issued by LIPA to finance the transaction. Upon the closing of the LIPA Transaction, each limited partner will receive from LIPA $ 30 million plus interest thereon, based on each partners'verage weighted cost of capital. In the event that the LIPA Transaction is not consummated, the maximum potential loss to the Company is the amount originally invested. In such event, the Company plans to defer any loss and petition the PSC to allow recovery from its customers.

As part of the LIPA Transaction, the definitiy'e agreements contemplate that one or more subsidiaries of HoldCo will enter into agreements with LIPA, pursuant to which such subsidiaries willprovide management and operations services to LIPA with respect to the electric transmission and distribution system, deliver power generated by its power plants to LIPA, and manage LIPA's fuel and electric purchases and any off-system electric sales. In addition, three years aAer the LIPA Transaction is consummated, LIPA willhave the right for a one-year period to acquire all of HoldCo's generating assets at the fair market value at the time of the exercise of the right, which value will,be determined by independent appraisers. 1I 4

In July 1997, the New York State Public Authorities Control Board (PACB), created pursuant to the Neq York State Public Authorities Law and consisting of five members appointed by the governor, unanimously approved the definitive agreements related to the LIPA Transaction subject to the following conditions: (i) within one year of the effective date of the transaction, LIPA must establish a plan for open access to the electric distribution system; (ii) ifLIPA exercises its option to acquire the generation assets of HoldCo's generation subsidiary, LIPA may not purchase the generating facilities, as contemplated in the generation purchase right agreement, at,a price greater than book value< (iii) HoldCo must agree to invest, over a ten-year period, at least $ 1.3 billion in energy-related and economic development projects, and natural gas infrastructure projects on Long Island; (iv) LIPA will guarantee that, over a ten-year period, average electric rates willbe reduced by no less than 14/o when measured against the Company's rates today and no less than a 2/o'cost savings to LIPA customers must result from the savings attributab to the merger of LILCO and KeySpan; and (v) LIPA will not increase average electric customer rates'b more than 2.50/0 over a twelve-month period without approval from the PSC. LIPA has adopted the conditions set forth by the PACB.

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~the I'I T'e holders of common and certain.s'eries LIPA Transaction in August 1997. "-'

h of preferred stock of the Company eligible'to vote'approved indirect transfer of control of the Co'mpany's 18 lo ownership interest in NMP2 to LIPA.

II December 1997, the United States'Nuclear Regulatory Commission'(NRC) is'sued an order approving.

In December 1997, the Company filed with the FERC a settlement agreement reached with'LIPA in connection with a prev'ious filing of the Company's proposed rates for the sale of capacity and energy to LIPA, as contemplated in the LIPA transaction'agreements. The Company'lso had previously file'd an" application with the FERC seeking approval of the transfer of the Company's electric tr'ansmission and distribution system to LIPA in connection with LIPA's pur'chase of the common stock of the Company.

In February 1998, the FERC issued orders on both of the Company filings. Specifically, the FERC approved the Company's application to transfer assets to LIPA in connection with LIPA's acquisition. of the Company's common stock. In addition, the FERC accepted the Compariy's pro'posed rates for sale"of capacity and energy to LIPA. Those rates may go into effect on. the date the service to LIPAegins, the subject to refund, and final rates will be "set after the FERC has completed its investigation of such rates,:"

the timing of which cannot'be determined at this time.

In January 1998, the Company filed an application with the PSC in connection with the proposed transfer of its gas business unit assets, non-nuclear generating facility assets and certain other assets and related to one ormore subsidiaries of HoldCo to be formed as'contemplated.,in'the LIPA Transaction agreements. On April 29, 1998, the PSC approved the transfer of the above-mentioned assets..

In July 1997, the Company, Brooklyn Union and LIPA filed requests for private letter. rulings with the ternal Revenue Service (IRS) regarding certain federal income tax issues which require favorable lings in order for the LIPA Transaction to be consummated. On March 4, 1998, the IRS issued a private letter ruling confirming that the sale of the Company's common stock to LIPA would not result in a corporate tax liability to the Company. In addition, the IRS'ruled that, aAer the stock sale, the income of LIPA's electric utility business will not be subject to fede'ral income tax'. In'a'separate ruling on February 27, 1998, the IRS also ruled that the bonds to be issued by LIPA to finance the acquisition would be tax-exempt. C approving the Company's application

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In January 1998, the Company filed an application with the SEC seeking an exception'or most of the provisions of the Public Utilities Holding Company Act of 1935. In'May 1998, the'SEC issued an order The Company currently anticipates that the LIPA transaction will be consummated by June 30, 1998.

.'iabilities Note 3. KeySpan Energy Corporation Transaction On December 29, 1996, The-Brooklyn, Union Gas Company"(Brookl)n Union) and the Company entered into an Agreement and Plan of Exchange and Merger (Share Exchange Agreemen't), pursuant to which the companies will be merged in a transaction (KeySpan Transaction) that will'result in the formation of' HoldCo.

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'4 The Share Exchange Agreement was amended and restated to reflect certain technical changes'as of February 7, 1997 and June 26, 1997. Effective September 29, 1997, Brooklyn Union reorganized into a 69

t holding company structure, with KeySpan Energy Corporation (KeySpan) becoming its parent holding company. Accordingly, the parties entered into an Amendment, Assignment and Assumption Agreement, dated as of September 29, 1997, which among other things, amended the Share Exchange Agreement and related stock option agreements to reflect the assignment by Brooklyn Union to KeySpan and the assumption by KeySpan of all Brooklyn Union's rights'and obligations under such agreements.

The KeySpan Transaction, which has been approved by both companies'oards of directors and, shareholders, would unite the resources of the Company with the resources of KeySpan. KeySpan, with approximately 3,300 employees, distributes natural gas at retail, primarily in a territory of approximately 187 square miles which includes the boroughs of Brooklyn and Staten Island and two-thirds of the borough of Queens, all in New York City. KeySpan has energy-related investments in gas exploration, production and marketing in the United States and Northern Ireland, as well as energy services in the United States, including cogeneration projects, pipeline transportation and gas storage.

Under the terms of the KeySpan Transaction, the Company's common shareowners will receive .803 shares (the Ratio) of HoldCo's common stock for each share of the Company's common stock that they currently hold. KeySpan common shareowners will receive one share of common stock of HoldCo for.

each common share of KeySpan they currently hold. Shareowners of the Company will own approximately 66% of the common stock of HoldCo while KeySpan shareowners will own approximately 34%. In the event that the LIPA Transaction is consummated, the Ratio will be 0.880 with Company shareowners owning approximately 68% of the HoldCo common stock. Based on current facts and circumstances, it is probable that the purchase method of accounting will apply to the KeySpan with the Company being the acquiring company for accounting purposes; 'ransaction, Consummation of the Share Exchange Agreement is not conditioned upon the consummation of the LIPA Transaction and consummation of the LIPA Transaction is not conditioned upon consummation of the Share Exchange Agreement.

In March 1997, the Company filed an application with the FERC seeking approval of the transfer of the Company's common equity and certain FERC-jurisdictional assets to HoldCo. On July 17, 1997, the FERC granted such approval.

The Share Exchange Agreement contains certain covenants of the parties pending the consummation of the transaction. Generally, the parties must carry on their businesses in the ordinary course consistent with past practice, may not increase dividends. on, common stock beyond specified levels and may not ~

issue capital stock beyond certain limits. The Share Exchange Agreement also contains restrictions on, among other things, charter and by-law amendmerits, capital expenditures, acquisitions, dispositions, incurrence of indebtedness, certain increases in employee compensation and benefits, and affiliate transactions.

Upon completion of the merger, Dr. William J. Catacosinos will become chairman and chief executive officer of HoldCo; Mr. Robert B. Catell, currently chairman and chief executive offiicer of KeySpan, will, become president and chief operating officer of HoldCo. One year after the closing, Mr. Catell will succeed Dr. Catacosinos as chief. executive officer, with Dr. Catacosinos continuing as chairman. The board of directors of HoldCo will be comprised of 15 members, six from the Company, six from KeySpan and three additional persons previously unaffiliated with either company.

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In March -1997, the Company and the Brooklyn Union Gas Company (Brooklyn Union) filed a joint petition with the PSC seeking approval, under section 70 of the New York Public Ser'vice Law, of the KeySpan Agreement by which the Company and KeySpan each would become subsidiaries of HoldCo through an exchange of shares of common stock with HoldCo. In addition, the petition called for approximately $ 1.0 billion of savings attributable to operating synergies that are expected to be realized over the 10-year period following the combination to be allocated to'customers, net of transaction costs for the combination. On December 10, 1997, Brooklyn Union, the Company, the Staff of the PSC and three other parties entered into a Settlement Agreement (Stipulation) resolving all issues among them in the proceeding. Hearings on the Stipulation were held in early January 1998 and, on February 4, 1998, the PSC approved, effective February 5, 1998, the Stipulation, modiflied'only to reduce Brooklyn Union's earnings cap for the remaining years of its rate plan.

r Under the Stipulation, a three-year gas rate plan covering the period December 1, 1997 through November 30, 2000 will be implemented by the Company which provides for, among other things, an estimated reduction in customers'ills of approximately 3.9%, including fuel savings, through at least November 30, 2000. This gas rate reduction will occur in three phases as follows: (i) a reduction in base rates of approximately $ 12.2'"million to reflect decreases in the Company's gas cost of service effective on February 5, 1998; (ii) a base rate reduction of approximately $ 6.2 million associated with non-fuel savings related to the KeySpan Transaction to become effective on the closing date of the transaction; and (iii) an expected reduction in the Gas Adjustment Clause (GAC) to reflect annual fuel savings associated with the transaction estimated at approximately $ 4.0 million, the actual level of which will be reflected in rates if and when they actually materialize.'he Company will be subject to an earnings sharing provision pursuant to which it will be required to credit to core/firm customers 60% of any utility earnings up to 100 basis points above 11.10% and 50% of any utility earnings in excess of 12.10% of the allowed return on common equity. Both a customer service and a safety and reliability incentive performance program will e implemented effective December 1, 1997, with maximum pre-tax return on equity penalties of 40 and 12 basis points, respectively, ifthe Company fails 'to achieve certain performance standards in these areas.

The Stipulation, which obligates the Company to reduce electric customers'ills by approximately 2.5%

resulting from the savings in operating and fuel costs, related to synergy savings, also defers the time within which the PSC must act on the Company's pending electric rate plan until July 1, 1998. However, any reduction in customers'ills would not become effective until the PSC sets the Company's electric rates.

For Brooklyn Union, effective on the date of the consummation of the KeySpan Transaction, Brooklyn Union'.s base rates to core/firm customers will be reduced by $ 23.9 million annually. In addition, effective in the fiscal year in which the KeySpan Transaction is consummated, Brooklyn Union will be subject to an earnings sharing provision pursuant to which it will be required to credit to core/firm customers 60% of any utility earnings up to 100 basis points above certain threshold equity return levels over the term of the rate plan (other than any earnings associated with discrete incentives) and 50% of any utility earnings in excess of 100 basis points above such threshold levels. The threshold levels, as modified by the February 5, 1998 Order, are 13.75% for fiscal year 1998,-13.50% for fiscal years 1999,

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2000, and 2001; and 13.25'/0 for, fiscal~year 2002. A safety and reliability incentive mechanism will'be implemented effective on the consummation date of the KeySpan Transaction, with a maximum 12 basis point pre.-tax penalty return.-on common equity ifBrooklyn Union fails to achieve certain safety and

reliability.performance standards. With the exception of the simplification of the customer service performance standards, the current Brooklyn Union rate plan approved by the PSC in 1996 remains unchanged. Any gas cost savings allocable to Brooklyn Union resulting from the KeySyan Transaction will be, reflected in rates to utility customers through the GAC.as those savings are realized.

I The Stipulation adopts. certain affiliate,transaction restrictionscost allocation and financial integrity conditions, and a competitive code of conduct. These restrictions and conditions eliminate or relax many restrictions currently applicable to Brooklyn Union in such areas as affiliate transactions, use of the name and reputation of Brooklyn Union by unregulated affiliates, common officers of HoldCo, the utility subsidiaries and unregulatedlsubsidiaries, dividend payment restrictions, and the composition of the Board of Directors of Brooklyn Union.

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The Stipulation also enables, the utilities to form, one or more shared services subsidiaries to perform functions common to both utilities and their affiliates, such as accounting, finance, human resources, legal

. and information systems and.technology to realize synergy savings, I R Note 4. Rate Matters, R l Electric In April 1996, the PSC issued an order directing the, Company to file financial and.other information

. sufficient to provide a legal basis for setting new rates for the three-year period 1997 through 1999, In compliance with the order, the Company submitted a multi-year, rate plan (Plan) in September 1996.

Major elements of the Plan include: (i) a base rate freeze for the three-year period December 1, 1996 through November,30, 1999;, (ii) an allowed return on common equity of 11.0/0 through the term'of the Plan with the Company fully retaining.all earnings up,to 12.66/o, and sharing with the customer any earnings above 12.66/0, (iii) the continuation of existing LRPP revenue and expense reconciliation mechanisms and performance incentive programs; (iv) crediting all net proceeds from the Shoreham, property tax litigation to the RMC to reduce its balance; and (v) a.mechanism to fully recover any outstanding. RMC balance. at the end of the 1999 rate. yea'r throughRinclusion in the FCA, over a two-year period. Pursuant to'theprovisions of the Stipulation discussed above, under the heading KeySpan Energy Corporation Transaction, the PSC has until July 1, 1998 to render a decision 'on this filing.

As an. interim measure, pending the consummation of the LIPA.Transaction or the adjudication of its =

electric rate filing;the Company submitted petitionsinkfay 1997 and,December:1997 requesting PSC approval to extend, through the rate years ending November 30, 1996 a'nd 1997, respectively, the provisions of its 1995 electric rate order (1995 Order). These petitionswere appioved by the PSC in December 1997 and, April;1998; respectively.

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~ R R.

1995 Electric Rate Order ,

The basis. of the 1995 Order included minimizing future electric rate increases while continuing to provide for the recovery of the Company's regulatory assets and retaining consistency with the RMA's objective of restoring the Company to financial health. The 1995 Order, which became effective December 1, 1994, froze base electric rates, reduced the Company's allowed return on common equity from 11.6/0 to 11.0/0 and modified or eliminated certain performance-based incentives, as discussed below.

The LRPP, originally approved by the PSC in November 1991, contained three major components: (i) revenue reconciliation; (ii) expense attrition and reconciliation; and, (iii) performance-based incentives.

72

In the 1995 Order, the PSC continued the three major components of the LRPP with modifications to the expense attrition and reconciliation mechanism and the performance-based incentives. The revenue reconciliation mechanism remains unchanged.

I evenue reconciliation provides a mechanism that eliminates the impact of experiencing sales that are above or below adjudicated levels by providing a fixed annual net margin level (defined as sales revenues, net of fuel expenses and gross receipts taxes). The difference between actual and adjudicated net margin levels are deferred on a monthly basis during the rate year.

1 The expense attrition and reconciliation component permits the Company to make adjustments for certain expenses recognizing that these cost increases are unavoidable due to inflation and changes outside the control of the Company. Pursuant to the 1995 Order, the Company is permitted to reconcile expenses for property taxes only, whereas under the original LRPP the Company was able to reconcile expenses for wage rates; property taxes, interest costs and demand side management (DSM) costs.

The original LRPP had also provided for the deferral and amortization of certain cost variances for enhanced reliability, production operations and maintenance expenses and the application of an inflation index to other expenses. Under the 1995 Order, these deferrals have'been eliminated and any. unamortized balances were credited to the RMC during 1995.

The modified performance-based incentive programs include the DSM program, the customer service performance program and the transmission and distribution reliability program. Under these revised programs, the Company was subject to a maximum penalty of 38 basis points of the allowed return on common equity and could earn up to 4 basis points under the customer service program. Pursuant to the Stipulation, the Company's customer service incentive program was further modified to eliminate the 4 is point reward and increased the maximum penalty which can be incurred under the these programs om 38 to 62 basis points.

The partial pass-through fuel incentive program remains unchanged. Under this incentive, the Company can earn or forfeit up to 20 basis points of the allowed return on common equity.

For the rate year ended November 30, 1997, the Company earned 12.7 basis points, or approximately

$ 2.9 million, net of tax effects, as a result of its performance under all incentive programs. For the rate years ended November 30, 1996 and 1995, the Company earned 20 and 19 basis points, respectively, or approximately $ 4.3 million and $ 4.0 million, respectively, net of tax effects, under the incentive programs in effect at those times.

The deferred balances resulting from the net margin and expense reconciliations, and earned performance-based incentives are netted at the end of each rate year, as established under the LRPP and continued under the 1995 Order. The first $ 15 million of the total deferral is recovered from or credited to ratepayers by increasing or decreasing the RMC balance. Deferrals in excess of the $ 15 million, upon approval of the PSC, are refunded to or recovered from the customers through tPe FCA mechanism over a 12-month period.

For the rate year ended November 30, 1997, the amount to be returned to customers resulting from the revenue and expense reconciliations, performance-based incentive programs and associated carrying charges totaled $ 4.1 million. Consistent with the mechanics of the LRPP,'it is anticipated that the entire nce of the deferral will be used to reduce the RMC balance upon approval by the PSC of the pany's reconciliation filing which was submitted to the PSC in March 1998. For the rate year ended November 30, 1996, the Company recorded a net deferred LRPP credit of approximately $ 14.5 million 73

which was subsequently applied as a reduction to the RMC upon the PSCls approval. of the Company's ~

reconciliation filing in December 1996. For the rate year ended November 301995, the Company recorded a net deferred credit of approximately $ 41 million. The first $ 15 million of the deferral was applied as a reduction to the RMC while the remaining portion of the deferral of $ 26 million will be returned to customers through the FCA when approved by the PSC.

'I Another mechanism of the LRPP, provides that earnings in excess of the allowed return on common 0

equity, excluding the impacts of the various incentive and/or penalty programs, are used to reduce the RMC. For the rate years ended November 30, 1997, 1996 and 1995, the Company earned $ 4.8 million,

$ 9.1 million, and $ 6.2 million, respectively, in excess of its allowed return on common equity. These excess earnings were applied as reductions to the RMC.

hl In the event that the LIPA Transaction is not consummated," the Company is currently unable to predict the outcome of the electric rate proceeding currently before. the PSC and its effect, ifany, on the Company's financial position, cash flows or results of operations.

. Gas In May 1997, the Company submitted a petition requesting PSC approval to extend through the rate year ending November 30, 1997, the gas excess earnings sharing mechanism established in its prior three-year gas rate settlement agreement which expired on November 30, 1996. Pursuant to this request, earnings in excess of a return on common equity of 11.0/0 are to be allocated equally between customers and shareowners with the customers'hare of excess earnings credited to the regulatory asset created as a result of costs associated with manufactured gas plant (MGP) site investigation and remediation costs.

This request was approved by the PSC in December 1997. As a result of this mechanism, the customer' allocation of excess earnings amounted to $ 6.3 million for the rate year ended November 30, 1997, and will be applied to offset costs incurred to investigate and remediate MGP sites. The prior gas rate settlement provided that earnings in excess of a 10.6/0 return on common equity be shared equally between the Company's firm gas customers and its shareowners. For the rate years ended November 30, 1996 and 1995, the firm gas customers'ortion of gas excess earnings totaled approximately $ 10 million and $ 1 million, respectively. In 1997, the Company was granted permission by the PSC to apply the customers'ortion of the gas excess earnings and associated carrying charges for the 1996 and 1995 rate years to the recovery of deferred costs associated with post-retirement benefits other than pensions and costs incurred for investigation and remediation of MGP sites. 4 Note 5. Nine Mile Point Nuclear Power Station, Unit 2 The Company has an undivided 18/0 interest in NMP2, located near Oswego, New York which is operated by Niagara Mohawk Power Corporation (NMPC). The owners of NMP2 and their respective percentage ownership are as follows: the Company (18/0), NMPC (41/0), New York State Electric & Gas Corporation (18/0),'ochester Gas and Electric Corporation (14/0) and Central Hudson Gas & Electric Corporation (9/0). The Company's share of the rated capability is approximately 205 MW. The Company's net utility plant investment, excluding nuclear fuel, was approximately $ 689 million at March 31, 1998, $ 710 million at March 31, 1997 and $ 715 million at December 31, 1996. The accumulated provision for depreciation, excluding decommissioning costs, was approximately $ 196 million and $ 175 million at March 31, 1998 and 1997, respectively, and $ 169 million at December 31, 1996, Generation from NMP2 and operating expenses incurred by NMP2 are shared in the same proportions as the cotenants'espective ownership interests. The Company is required to provide its respective share of financing for any capital additions to NMP2. Nuclear fuel costs associated with NMP2 are being amortized on the basis of the quantity of heat produced for the generation of electricity.

74

NMPC has contracted with the United States Department of Energy for the disposal of spent nuclear fuel.

The Company reimburses NMPC for its 18'/o share, of the cost under the contract at a rate of $ 1.00 per megawatt hour of net generation less a factor to account for transmission line losses. For the year ended arch 31, 1998 and for the three months ended March 31, 1997, this totaled $ 1.4 million and $ 0.4 illion, respectively. For the years ended December 31, 1996 and 1995, this totaled $ 1.4 million and $ 1.2 million, respectively. As discussed in Note 2, the LIPA Transaction contemplates that LIPA will acquire the Company's 18/0 interest in NMP2.

Nuclear Plant Decommissioning NMPC expects to commence the decommissioning of NMP2 in 2026, shortly after the cessation of plant operations, using a method which provides for the removal of all equipment and structures and the release of the property for unrestricted use: The Company's share of decommissioning costs, based upon a "Site-Specific" 1995 study (1995 study), is estimated to be $ 309 million in 2026dollars ($ 155 million in 1998 dollars). The Company's share of the estimated decommissioning costs is currently being provided for in electric rates and is being charged to operations as depreciation expense over the service life of NMP2.

The amount of decommissioning costs recorded as depreciation expense for the year ended March 31, and the three months ended March 31, 1997, totaled $ 2.2 million and $ 0.5 million, respectively,,and

'998

$ 3.9 million and $ 2.3 million for the years ended December 31, 1996 and 1,995, respectively. The accumulated decommissioning costs collected in rates through March 31, 1998 and 1997 and December 31,'1996 amounted to $ 17.7 million, $ 15.5 million and $ 14.9 million, respectively.

The Company has established trust funds for the decommissioning of the contaminated portion of the NMP2 plant. It is currently estimated that the cost to decommission the contaminated portion of the plant will be approximately 76/o of the total decommissioning costs. These. funds comply with regulations

'ssued by the NRC and the FERC governing the funding of nuclear plant decommissioning costs. The mpany's policy is to make quarterly contributions to the funds based upon the amount of ecommissioning costs reflected in rates. As of March 31, 1998, the balance in these funds, including reinvested net earnings, was approximately $ 17.9 million. use amounts are included on the Company's Balance Sheet in Nonutility Property and Other Investments. The trust funds investment consists of U.S.

Treasury debt securities and cash equivalents. Thecarrying amounts of these instruments approximate fair market value.

'I I The FASB issued an exposure draft in 1996,entitled "Accounting for Certain Liabilities Related to Closure or Removal of Long-Lived Assets." Under the provisions of the exposure draft, the Company would be required to change its current accounting practices for decommissioning costs as follows; (i) the Company's share of the total estimated decommissioning costs would be accounted for as a liability, based on discounted future cash flows; (ii) the recognition of the liability for decommissioning costs would result in a corresponding increase to the cost of the nuclear plant rather than as depreciation expense; and (iii) investment earnings on the assets dedicated to the external decommissioning trust fund would bb recorded as investment income rather than as an increase to accumulated depreciation. Discussions of the issues expressed in the exposure draft are ongoing. Ifthe Company was required to record the present value of its share of NMP2 decommissioning costs on its Balance Sheet as of March 31, 1998, the Company would have to recognize a liability and corresponding increase to nuclear plant of approximately $ 62 million. Upon consummation of the LIPA Transactiori,'LIPA will acquire the Company's interest in NMP2 as well as the trusts referred to above. " '

clear Plant Insurance PC procures public liability and prop'erty insurance for NMP2, and the Company reimburses NMPC for its 18/0 share of those costs.

75

The Price-Anderson Amendments Act mandates that nuclear power plants secure financial protection in event of a nuclear accident. This protection must consist of two levels. The primary level provides

'he liability insurance coverage of $ 200 million (the maximum amount available) in the event of a nuclear accident. Ifclaims exceed that amount, a second level of protection is provided through a retrospective assessment of all licensed operating reactors. Currently, this "secondary financial protection" subjects each of the 110 presently licensed nuclear reactors in the Unit'ed States to a retrospective assessment of up to $ 76 million for each nuclear incident, payable at a rate not to exceed $ 10 million per year. The interest in NMP2 could expose it to a maximum potential loss of $ 13.6 million, per incident,

'ompany's through assessments of $ 1.8 million per year in the event of a serious nuclear accident at NMP2 or another licensed U.S; commercial nuclear reactor. These assessments are subject to periodic inflation indexing and to a 5'/0 surcharge iffunds prove insufficient to pay claims..

4 II NMPC has also procured $ 500 million primary nuclear property insurance with the Nuclear Insurance Pools and approximately $ 2.3 billion of additional protection (including decontamination costs) in excess of the prim'ary layer through Nuclear Electric Insurance Limited (NEIL). Each member of NEIL, including the Company,'s also subject to retrospective premium adjustments in the event losses exceed accumulated reserves. -For its share of NMP2, the Company could be assessed up to approximately $ 1.6 million per loss. This level of insurance is in excess of the NRC required $ 1.06 billion of coverage.

The Company has obtained insurance coverage from NEIL for the extra expense incurred in purchasing replacement power during prolonged accidental outages. Under this program, should losses exceed the accumulated reserves of NEIL, each member, including the Company, would be liable for ifs share of deficiency. The Company's maximum liability per incident under the replacement power coverage, in the event of a deficiency, is approximately $ 0.7 million.

Note 6. Capital Stock Common Stock Currently the Company has 150,000,000 shares of authorized common stock, of which 121,727,040 were issued and 46,281 shares were held in Treasury at March 31, 1998. The Company has 1,644,865 shares reserved for sale through its Employee Stock Purchase Plan, 2,829,968 shares committed to the Investor Common Stock Plan and 86,099 shares reserved for conversion of the Series I Convertible Preferred Stock at a rate of $ 17.15 per share. In addition, in connection with the Share Exchange Agreement, as discussed'in Note 3, thb Company has granted KeySpan the option to purchase, under certain circumstances, 23,981,964 shares of common stock at a pr'ice of $ 19.725 per share. In connection with such option, the Company has received shareowner approval to increase the authorized shares of common stock to 160,000,000.

Stock A C'referred The Company has 7,000,000 authorized shares, cumulative preferred stock, par value $ 100 per share and .,

3P,000,000 authorized shares, cumulative preferred stock, par value $ 25 per share. Dividends on preferred stock are paid in preference to dividends on common stock or any other stock ranking junior to preferred stock.

Preferred Stock Subject to Mandatory Redemption The aggregate fair value of redeemable preferred stock with mandatory redemptions at March 31, 1998 and 1997 and December 31, 1996 amounted to approximately $ 675, $ 643 and $ 637 million, respectively, compared to their carrying amounts of $ 639, $ 640 and $ 640 million, respectively. For a further discussion on the basis of the fair value of the securities discussed above, see Note 1.

76

Each year tlie Company is required'to redeem certain series of preferred stock through the operation of sinking fund provisions'as follows: "

Series Redem lion Provision Number ofShares Redemplion Amounts Beginning Ending 6.875% Series UU... 10/15/99,,10/15/19 ~

112,000,, h $ 2,800,000 lt 1 aggregate par valu'e of preferred stock required to be redeemed through sinking funds during the Il'he fiscal year ended March 31, is $ 2.8 million'in each of the years 2000, 2001, 2002 and 2003. The Company also,has the non-cumulative option to double the number of shares to be, redeemed pursuant to the sinking fund provisions in any year for, the preferred;stock series UU.

The Company is also required to redeem all shares of certain series'of preferred stock which are not subject to sinking fund requirements. The mandatory redemption requirements for these series are as follows:

Series

,$ 1.67 Ser'ies'GG.

7.95% Series AA ...

Redemption Dale 3/1/99 6/1/00'

'Numb'er ofSitares 880,000 14,520,000 Redemption Amounts

$ 22,000,000

'63,000,000 7.05% Series QQ 5/1/01 3,464,000 86,600,000 7.66% Series CC 8/1/02 570,000 57,000,000 Preferred StockSubject to Optional Redemption

Company,has the option to redeem certain series of its preferred, stock. For the series subject to

'he optional redemption ', "

at, March 31,,1998,,the call prices were as'olio'ws:

tl

~h g h 'h Series CalpPrice - 'edemption Amounts

.00/0 Senes B $ 101.00, $ 10,100,000 4.25% Series D 102.00 7,140,000 4.35% Series E 102.00 ' '

~

20,400,000 4.35% Series F E 102.00 ~

5,100,000 L,, '102.07 '1 5 '/,% Series H 102.00 ., 20,400,000 5 '/,% Series 1- Convertible 100.00 1,474,300

~,

7.40% Series

$ 1'.95 'Serie's NN J

tl a

'6.95 15,361,535 880 300 On'April 17, 1998, the'Company exeicised its option to redeem its callable preferred stock and 'called for redemption on May 19, 1998 all of the outstanding shares of the preferred stock series noted above'or a total of $ 122 million including approximately $ 5 million of call premiums.

't h

Preference Stock.

At March 31, 1998, none of the authorized 7,500,000 shares of nonparticipating preference stock, par value $ 1 per share, which ranks junior to preferred stock, were outstanding. >>

Note 7. Long-Term Debt G&R Mortgage The General and Refunding l'G&R) Bonds are the Company's only outstanding secured indebtedness., The

. G&R Mortgage is a lien on'substantially all of the Company's properties.

The annual G&R Mortgage, sinking fund requirement for 1997, due not later than June 30, 1998, is ated at $ 25 million. It is anticipated that this requirement wi11 be satisfied with retired G&R Bonds, erty 'additions,'r 'ahny combination'hereof.

77

Upon consummation,.of the LIPA Transaction, all of the Company's series of G&R Bonds will be, by LIPA. LIPA has indicated that it intends to redeem all such G&R Bonds as soon as 'ssumed practicable after the closing of the LIPA Transaction.

1 989 Revolving Credit Agreement The Company has available through October 1, 1998, $ 250 million under its 1989 Revolving Credit Agreement (1989 RCA). This line of credit is secured by a first lien upon the Company'.s accounts receivable and fuel oil inventories. In February 1997, the Company utilized $ 30 million in interim financing under the 1989 RCA, whichwas repaid in March 1997, and $ 40 million in July'1997, which was repaid in August 1997. At March 31, 1998, no amounts were outstanding under the 1989 RCA.,The Company has filed, with the lending institutions, the documentation necessary to terminate the 1989 RCA effective upon the closing of the,LIPA and KeySpan Transactions.

Authority Financing Notes Authority Financing Notes are issued by the Company to the New York State Energy Research and Development Authority (NYSERDA) to secure certain tax-exeinpt Industrial Development Revenue Bonds, Pollution Control Revenue Bonds (PCRBs) and Electric Facilities Revenue Bonds (EFRBs) issued by NYSERDA. Certain of these bonds are subject to periodic tender, at which time their interest rates may be subject to redetermination.

Tender requirements of Authority Financing Notes at March 31, 1998 were as follows:

(In thousands ofdollars)

Interest Rate Series Principal Tendered PCRBs 8 '/% 1982 $ 17,200 Tendered every three years, next tender October 2000 3.58% 1985 A,B 150,000 Tendered annually on March 1 EFRBs 3.70% 1993 A 50,000 Tendered weekly 3.70% 1993 B 50,000 Tendered weekly 3.70% 1994 A 50,000 Tendered weekly 3.70% 1995 A 50,000 Tendered weekly 3.55% 1997 A 24,880 Tendered weekly I

The 1997, 1995, 1994 and 1993 EFRBs and the 1985 PCRBs are supported by letters of credit pursuant to which the letter of credit banks have agreed to pay the principal, interest and premium, ifapplicable, in the aggregate, up to approximately $ 408 million in the event of default. The obligation of the Company, to reimburse the, letter of credit banks is unsecured.

The expiration dates for these letters of credit are as follows:

Series Ex iralion Dale PCRBs 1985 A,B 3/16/99 EFRBs 1993 A,B 11/17/99 1994 A 10/26/00 1995 A 8/24/98 1997 A 12/30/98 Prior to expiration, the Company is required to obtain either an extension of the letters of credit or a substitute credit facility. Ifneither can be obtained, the authority financing notes supported by letters of credit must be redeemed.

In accordance with the LIPA Agreement, LIPA will assume substantially all of the tax-exempt authoritr financing notes. HoldCo will issue a promissory note to LIPA for a portion of the tax-exempt debt borrowed to support LILCO's current gas operations, with terms identical to those currently outstanding.

The Company currently estimates the amount of this promissory note to be approximately $ 250 million.

78

Fair Valu'es of Long-Term Debt 8 The carrying amounts and fair values of the Company's long-term debt at March 31, 1998 and 1997 and December 31, 1996 were as follows:

air l ,.

(In thousands ofdollars)

March 31, 1998 March 31, 1997 December 31, 1996 General and Refunding Bonds $ 1,288,470 $ 1,314,273 $ 1,571,745 Debentures 2,407,178 2,256,573 2,271,095 Financing Notes

'uthority 987,646 959,092 950,758 Total $ 4,683,294 $ 4,529,938 $ 4,793,598 Carrying Amount (In thousands ofdollars)

'arch 31, 1998 March 31, 1997 December 31, 1996 Gen'eral and Refunding Bonds $ 1,286,000 =-

$ 1,286,000 $ 1,536,000 Debentures 2,270,000 ,2,270,000 2,270,000 Authority Financing Notes 940,555 916,675 916,675 Total $ 4,496,555 $ 4,472,675 $ 4,722,675 For a further discussion on the basis of the fair value of the securities listed above, see Note 1.

Debt Maturity Schedule The total long-term debt maturing in each of the next five years ending March 31 is as follows: 1999,

$ 10.1 million; 2000, $ 490 million; 2001, $ 1 million; 2002, $ 146 million; and 2003, $ 154 million.

, Note S. Retirement Benefit Plans Pension Plans The Company maintains a defined benefit pension plan which covers substantially all employees (Primary n), a supplemental plan which covers officers and certain key executives (Supplemental Plan) and a tirement plan which covers the Board of Directors (Directors'lan). The Company also maintains

$ 401(k) plans for its union and non-union employees to which it does not contribute. ~

Primary Plan, The Company's funding policy is to contribute annually to the Primary Plan a minimum amount consistent with the requirements of the. Employee Retirement Income Security Act of 1974, plus such additional amounts, if any, as the Company may determine to be appropriate from time to time. Pension benefits are based upon years of participation in the Primary Plan and compensation.

The Primary Plan's funded status and amounts recognized, on the Balance Sheet at March 31, 1998 and March 31, 1997 and December 31, 1996 were as follows:

(In thousands ofdollars)

March 31, 1998 March 31, 1997 December 31, 1996 Actuarial present value of benefit obligation Vested benefits $ 661,075 $ 642,392 $ 547,002 Nonvested benefits 59,268 57,960 55,157 Accumulated Benefit Obligation $ 720,343 $ 700,352 $ 602,159 Plan assets at fair value $ 919,100 $ 744,400 $ 746,400 Actuarial present value of projected benefit obligation 825,159 '07,703 689,661 Projected benefit o'bligation less (greater) than lan assets 93,941 (63,303) 56,739 recognized net obligation 62,652 <<. 69;399 ,

71,085 recognized net (gam) (163 034) '1,605) (123,759)

Net (Accrued) Prepaid Pension Cost $ ( 6,441) $ 4,491 $ 4,06 79

The increase in the present value of the accrued benefit at March 31, 1997 compared to December 31, 1996, is due primarily to the change in the discount rate from 7.25% to 7.00% and the use of updated actuarial assumptions, relating to mortality.

Periodic pension cost for the Primary Plan and the significant assumptions consisted of the following:

(In thousands ofdollars)

Year Ended Three Months Ended Year Ended Year Ended March 31, 1998 March 31, 1997 December 31, 1996 December 31, 1995 Service cost benefits earned during the period $ 21,1 1'4 $ 4,645 $ 17,384 $ 15,385 Interest cost on projected benefits obligation and service cost 56,379 12,494 47,927 45,987 Actual return 'on 'plan assets (200,025) (3,694) (81,165) (102,099)

Net amortization and deferral 151,438 (9,446) 33,541 57,665 Net Periodic Pension Cost $ 28,906 $ 3,999 $ 17,687 $ 16,938 March 31, 1998 . March 31, 1997 December 31, 1996 December 31, 1995 Discount rate for obligation 7.00% 7.00% 7 25% 7.25%

Discount rate for expense 7.00% 7.25% 7.25% 7.25%

Rate of future compensation increases 4.50% 5 PP% 5.00% 5 00%

Long-term rate of return on assets 8 5P% 7.50% 7.50% 7 50%

The Primary Plan assets at fair value include cash, cash equivalents, group annuity contracts, bonds and equity securities.

In 1993, the PSC issued an Order which addressed the accounting and ratemaking treatment of pension costs in accordance with SFAS No. 87, "Employers'ccounting for Pensions." Under the Order, the Company. is required to recognize any deferred net gains or losses over a ten-year period rather than using the corridor approach method. The Company believes that this method of accounting for financial reporting purposes results in a better matching of revenues and the Company's pension cost. The Company defers differences between pension rate allowance and pension expense under the Order. In addition, the PSC requires the Company to measure and pay a carrying charge on amounts in excess of the pension rate allowance and the annual pension contributions contributed into the pension fund.

I'n addition, effective December 1, 1997, in accordance with the Stipulation, the Company defers the difference between the sum of gas pension and gas postretirement benefit costs other than pension and the amounts provided for in rates, to the extent that such differences are in excess of or below three percent of the Company's pretax net income from its gas operations. Such excess will be transferred to a gas balancing account. For a further discussion of the Stipulation, see Note 3.

Supplemental Plan The Supplemental Plan provides supplemental death and retirement benefits for officers and other key executives without contribution from such employees. The Supplemental Plan is a non-qualified plan under the Internal Revenue Code. The provision for plan benefits totaled approximately $ 0.7 million for the three months ended March 31, 1997 and $ 2.7 million and $ 2.3 million for the years ended December 31, 1996 and 1995, respectively. For the year ended March 31, 1998, the Company recorded a charge of approximately $ 31 million relating to certain ben'efits earned by its officers relating to the termination of their annuity benefits earned through the supplemental retirement plan and other executive retirement benefits. These charges, the cost of which are borne by the Company's shareowners, result from provisions of the officers'mployment contracts, including the Chairman's employment contract, and the pending transactions with LIPA and KeySpan which affect the timing of when these costs are recorde i'0

Directors'Plan The Directors'Plan provides benefits to directors who are not officers of the Company. Directors who have served in that capacity for more than five years qualify as participants under the plan. The Directors'an is a non-qualified plan under the Internal Revenue Code. The provision for retirement benefits, hich are unfunded, totaled approximately $ 132,000 for the year ended March 31, 1998, $ 34,000 for the three months ended March 31, 1997 and $ 127,000 and $ 114,000 for the years ended December 31, 1996 and 1995, respectively.

Postretirement Benefits Other Than Pensions In addition to providing pension benefits, the Company provides certain medical and life insurance benefits to retired employees. Substantially all of the Company,'s employees may become eligible for these benefits ifthey reach retirement age after working for the Company for a minimum of five years.

These and similar benefits for active employees are provided by the Company or by insurance companies whose premiums are based on the benefits paid during the year. Effective January 1, 1993, the Company adopted the provisions of SFAS No. 106, "Employers'ccounting for Postretirement Benefits Other Than Pensions," which requires the Company to recognize the expected cost of providing postretirement benefits when employee services are rendered rather than when paid. As a result, the Company, in 1993, recorded an'accumulated,postretirement benefit obligation and a corresponding regulatory asset of approximately $ 376 million.

The PSC requires the Company to defer as a re'gulatory asset the difference between postretirement benefit expense recorded for accounting purposes in accordance with SFAS No. 106 and the postretirement benefit expense reflected in rates. The ongoing annual postretirement benefit expense was phased into and fully reflected in rates beginning December 1, 1996 with the accumulated regulatory asset to be recovered in rates over a 15-year period, beginning December 1, 1997. In addition, the Company is quired to recognize any deferred net gains or losses over a ten-year period.

In addition, effective December 1, 1997, in accordance with the Stipulation, the Company defers the difference between the sum of gas pension and gas postretirement benefit costs other than pension and the amounts provided for in rates, to the extent that such differences are in excess of or below three percent of the Company's pretax net income from its gas operations. Such excess will be transferred to a gas balancing account. For a further discussion of the Stipulation, see Note 3.

V In 1994, the Company established Voluntary Employee's Beneficiary Association trusts for'union and non-union employees for the funding of incremental costs collected in rates for postretirement benefits.

The Company funded the trusts with approximately $ 21 million for the year ended March 31, 1998, $ 5 million for the three months ended March'31, 1997 and $ 18 million and $ 50 million for the years ended December 31, 1996 and 1995, respectively. In May 1998, the Company funded an additional $ 250 million into the trusts, representing obligations related to the electric business unit employees. The Company secured a bridge loan to fund these trusts.

81

Accumulated postretirement benefit obligation other than pensions at March 31, 1998, March 31;1997 ~

and December 31, 1996 was as follows: v March 31, 1998 March 31, 1997 f

(In thousands o dollars)

December 31, 1996 Retirees $ 157,380 $ 169,655 $ 156,181 Fully eligible plan participants 60,711 62,491 56,950 Other active plan participants 140,850 183,526 152,627 Accumulated postretirement benefit obligation $ 358,941 $ 415,672 $ 365,758 Plan assets 108,165 80,533 74,692 Accumulated postretirement benefit obligation in excess of plan assets 250,776 335,139 291,066 Unrecognized prior, service costs (175) (185)'8,563 (188)

Unrecognized net gain 102,346 75,309 Accrued Postretirement Benefit Cost $ 352,947 $ 363,517 $ 366,187 The increase in the present value of the accrued benefit at March 31, 1997 compared to December 31, 1996 is due to the change in the discount rate from 7.25% to 7.00% and the use of updated actuarial assumptions relating to mortality.

The change in the accumulated postretirement benefit obligation from March 31, 1997 to March 31; 1998 reflects a decrease in the healthcare cost trend rate based on the Company's review of the medical plan cost experience and also revised assumptions with respect to future compensation increases, mortality and the percentage of employees who are assumed to be married at the time of retirement.

At March 31, 1998, March 31, 1997 and December 31, 1996 the Plan assets,'which are recoided at fair value, include cash and cash"equivalents, fixed income investments and approximately $ 100,000 of listed equity securities of the Company.

Periodic postretirement benefit cost other than pensions and the'significant assumptions consisted of the following:

f (In thousands ofdollars)

Year Ended Three Months Ended Year Ended Year Ended March 31, 1998 March 31, 1997 December 31, 1996 December 31, 1995 Service cost - benefits

=

earned during the period $ 12,204 $ 2,821 $ 10,690 $ 9,082 Interest cost on projected benefits obligation and service cost 27,328 6,642 25,030 22,412 Actual return on plan assets (6,632) (591) (3,046) (1,034)

Net amortization and deferral (10,000) (3,446) (12,175) (14,699)

Net Periodic Pension Cost $ 22,900 $ 5,426 $ 20,499 $ 15,761 March 31, 1998 March 31, 1997 December 31, 1996 December 31, 1995 Discount rate for obligation 7.00% 7.00% 7 25% 7.25%

Discount rate for expense 7.00% 7.2 7.25% 7.25%

Rate of future compensation increases 4 50% 5 PP% 5 PP% 5P0 Long-term rate of return on assets 8 50% 7.50% 7 50% 7.50%

The actuarial assumptions used for postretirement benefit plans are:

(In Ihousands ofdollars) March31,1998 March31,1997 December3l, 1996 Health care cost trend 5 00%(a) 8.00%(b) 8.00%(b)

Effect of one percent increase in health care cost trend rate:

On cost components $ 7 $ 1 $5 On accumulated benefit obligation $ 42 $59 $ 43 (a) Per year indefinitely (b) Gradually declining to 6.0% in 2001 and thereafter.

82

Note 9. Federal Income Tax The significant components of the Company's deferred tax assets and liabilities calculated under the provisions of SFAS No. 109, "Accounting for Income Taxes," were as follows:

(In thousands ofdollars) 3/31/98 3/31/97 12/31/96 Deferred Tax Assets Net operating loss carryforwards $ 93,349 $ 145,205 Reserves not currently deductible 39,667 56,749 58,981 Tax depreciable basis in excess of book 10,559 33,848 34,314 Nondiscretionary excess credits 24,858 27,037 '7,700 Credit carryforwards 40,318 128,469 135,902 Other 261,729 225,885 186,907 Total Deferred Tax Assets $ 377,131 $ 565,337 $ 589,009 Deferred Tax Liabilities 1989 Settlement $ 2,169,909 $ 2,165,462 $ 2,163,239 Accelerated depreciation 650,562 642,656 642,702 Call premiums 38,698 43,617 44,846 Rate case defer'rais 564 2,579 2,127 Other 56,762 38,117 33,496 Total Deferred Tax Liabilities 2,916,495 '2,892,431 2,886,410 Net Deferred Tax Liability '2,539,364

$ 2,327,094 $ 2,297,401 SFAS No. 109 requires utilities to establish regulatory assets and liabilities for the portion of its deferred tax assets and liabilities that have not yet been recognized for ratemaking,purposes. The major components of these regulatory assets and liabilities are as follows:

(In tltousands ofdollars) 3/31/98 3/31/97 12/31/96 Regulatory Assets 1989 Settlement $ 1,652,412 $ 1,659,065 $ 1,660>871 lant items 100,661 120,460 125,976 ther (15 141) (12,361) (14,069)

, Total Regulatory Assets $ 1,737,932 $ 1,767,164 $ 1,772,778 Regulatory Liabilities Carryforward credits Other Total Regulatory Liabilities f

'78,913 $ 38,720 40,193

$ 64,548 35,829

$ 100,377

$ 68,421 34,466

$ 102,887 The federal income tax amounts included in the Statement of Income differ from the amounts which result from applying the statutory federal income tax rate to income before income tax.

The'table below sets forth the reasons for such differences.

. IN I (In thousands ofdollars)

Year Ended Three Months Ended " Year Ended Year Ended March 31, 1998 March 31, 1997 December 31, 1996 December 31, 1995 Income before federal income tax $ 594,893 $ ,I43,910 $ 525,721 $ 508,824 Statutory federal income tax rate 35% 35% 35% 35%

Statutory federal income tax $ 208,213 $ 50,369 $ 184,002 $ I78,088 Additions (reductions) tn jegeral income tax Excess ofbook over tax depreciation 17,912 4,356 18,339 18,588 1989 Settlement 4,212 1,053 4,212 4,213 Interest capitalized 2,962 588 2,270 2,218 Tax credits (2,464) (940) (4,383) (1,025)

Tax rate change amortization h 2 223 815 3,686 3,752 AIIowancc for funds used during construction (2,953) (583) (2,305) (2,392)

Other items 2,549 555 3,436 2,096 otal Federal Income Tax Expense $ 232,654 $ 56,2I3 $ 209,257 ~

$ 205,538 ctlve Federal Income Tax Rate 39.1% 39,1% 39 8% 40 4%

83

The Company currently has tax credit carryforwards of approximately $ 40 million.- This balance is composed of investment tax credit (ITC) carryforwards, net of the 35/o reduction required by the Tax Reform Act of 1986, totaling approximately $ 31 million and research and development credits totaling approximately $ 9 million.

In 1990 and 1992, the Company received Revenue Agents'eports disallowing certain deductions and credits claimed by the Company on its federal income tax returns for the years 1981 through 1989. A settlement resolving all audit issues was reached between the Company and the Internal Revenue Service in May 1998. The settlement provided for the payment of taxes and interest of approximately $ 9 million and $ 35 million, respectively, which the Company made in May 1998. The Company had previously provided reserves adequate to cover such taxes and interest.

Note 10. The 1989 Settlement In February 1989, the Company and the State of New York entered into the 1989 Settlement resolving certain issues relating to the Company and providing, among other matters, for the financial recovery of the Company and for the transfer of Shoreham to LIPA, an agency of the State of New York, for its subsequent decommissioning. In February 1992, the Company transferred ownership of Shoreham to LIPA. In May 1995, the NRC terminated LIPA's possession-only license for Shoreham which signified the NRC's approval that decommissioning was complete and that the site is suitable for unrestricted use.

Upon the effectiveness of the 1989 Settlement, in June 1989, the Company recorded the FRA on its Balance Sheet and the retirement of its investment of approximately $ 4.2 billion, principally in Shoreham.'or a further discussion of the FRA, see Note 1.

Pursuant to the 1989 Settlement, the Company was required to reimburse LIPA for all of its costs associated with the decommissioning of Shoreham. The PSC has determined that all costs associated wi Shoreham which are prudently incurred by the Company subsequent to the effectiveness of the 1989 Settlement are decommissioning costs. The RMA provides for the recovery of such costs through electric rates over the balance of a forty-year period ending 2029. At March 31, 1998, Shoreham post-settlement costs totaled approximately $ 1.2 billion, consisting of $ 587 million of property taxes and payments-in-lieu-of-taxes, and $ 568 million of decommissioning costs, fuel disposal costs and all other costs incurred at Shoreham after June 30, 1989.

Note 11. The Class Settlement The Class Settlement, which became effective in June 1989, resolved a civil lawsuit against the Company brought under the federal Racketeer Influenced and Corrupt Organizations Act. The lawsuit, which the Class Settlement resolved, had alleged that the Company made inadequate disclosures before the PSC concerning the construction and completion of nuclear generatmg facilities.

e The Class Settlement provides the Company's electric customers 'with rate reductions aggregating $ 390 million that are being reflected as adjustments to their monthly electric bills over a ten-year period'which began on June 1, 1990. Upon its effectiveness, the Company recorded its liabilityfo'r the Class Settlement on a present value basis at $ 170 million. The Class Settlement obligation at March 31, 1998 reflects the present value of the remaining reductions to be refunded to customers. The remaining reductions to customers bills, amounting to approximately $ 130 million as of March 31, 1998, consists of approximately $ 10 million for the two-month period beginning April 1, 1998, and $ 60 million for each of the 12-month periods beginning June 1, 1998 and 1999.

84

Npte 12. Commitments and Contingencies Electric,.

The Company has entered into contracts with numerous Independent Power Producers (IPPs) and the New York Power Authority (NYPA) for electric generating capacity. Under the terms of the agreement with .,

YPA, which is set to expire in May 2014, the Company may purchase up to 100% of the electric energy.

produced at the NYPA facility located within the Company's service territory at Holtsville, NY. The Company is required to reimburse PYPA for the minimum debt service payments, and to make, fixed non-energy payments and expenses associated with operating and maintaining the plant.

With respect to contracts entered into with the IPPs, the, Company js ob]igated to purchase all the energy they make available,to the Company at prices that often exceed current market prices. However, the Company has no obligation to the IPPs ifthey fail to deliver energy, For, purposes of the table below, the Company has assumed full performance by the

• IPPs, as no event has occurred to suggest anything less than full performance by these parties. ~,

The Company also has contracted with NYPA for firm transmission (wheeling) capacity in connection with a transmission cable which'was constructed, in part, for'he b'enefit of the Company. In accordance with'the provisions of this agreement, which expir'e's'in 2020,'he Company is required to reimburse NYPA for debt service payments and the cost 'of operating and'maintaining the cables. The cost of such contracts is included in electric fuel expense and, is recoverable through rates.

I The following table represents the Company's commitments under purchased power contracts.

4

, Electric Operations (In millions ofdollars)

NYPA Holtsville l9 'ther Fixed~ Firm Total For the fiscal years ended Debt Serin'ceC/barges -. Energy~... Transmission IPPsi B 9 $ 14.7 $ 6.7 $ 25.7 $ 127.6 $ 196.4 000 , 21.7 13.7, 6.7, 26.0, , 132.7 200.8 2001 2002'003 21.8 21.9 22.0 "

14.6 16.3 16.7, 7.2 8.7 27.8 27.8 ' '

135.8 139.5 207.2 214.2

", 9.0 27.9 137.9,, '13.5 Subsequent Years 232.4, 217.1 ., 119.8, 474,0 .. 957.5', 2 ,000.8 Total $ 341.5 $ 293.1 $ 158.1 $ 609.2, ~ $ 1,631.0 $ 3,032.9 Less: lmpu'te'd Interest

$ 166.8 $ 154.1 $ 85.3

$ 381.9

'805.2' $ 1,593.3 Present Value of Payments $ 174.7 $ 139.0'72.8 " $ 227.3' $ 825.8 " ~ ~

$ 1,439.6

'Assumes fullperformance by the IPPs and JIYPA.

- Gas H

In order to provide for sufficient supplies of g'as'for'the Company's gas cust'omers, 'the Company has entered into long-term firm gas transportation, storage and supply contracts which co'ntain provision's that require the Company to make fixed payments (demand charges) even ifthe services are not fully utilized.

The cost of such contracts is, included. in gasfuel,expense and is recoverable through rates. The. table below sets forth the Company's aggregate obligation under these commitments which extend through, 2014.

Gas 0 erations In millions of dollars For the fiscal years ended 2002,,: '1.69 1999 $ 111.73

'71.20 2000 110.37 2001 '

i,101.33, ,

97.81 2003 Subse uent Years Total ~

$ 884.'13 Less: Im uted Interest. 258.45 Present Value of Pa ments $ 625.68 85

Competitive Environment The electric industry continues to undergo fundamental changes as regulators, elected officials and customers seek lower energy prices. These changes, which may have a significant impact on future financial performance of electric utilities, are being driven by a number of factors including a regulatory environment in which traditional cost-based regulation is seen as a barrier to lower energy prices. In 199 and 1998, both the PSC and the FERC continued their separate, but m some cases parallel, initiatives with respect to developing a framework for a competitive electric marketplace.

The Electric Industry - State Regulatory Issues In 1994, the PSC began the seco'nd phase of its Competitive Opportunities Proceedings to investigate issues related to the future of the regulatory proces's in an industry which is moving toward competition.

The PSC's overall objective was to identify regulatory and ratemaking practices that would assist New York State utilities in the transition to a more competitive environment designed to increase efficiency in providing electricity while maintaining safe, affordable and reliable service.

As a result of the Competitive Opportunities Proceedings, in May 1996, the PSC issued an order (Order) which stated its belief that introducing competition to the electric industry in New York has the potential to reduce electric rates over time, increase customer choice and encourage economic growth. The Order called for a competitive wholesale power market to be in place by early 1997 to be followed by the introduction of retail access for all customers by early 1998.

The PSC stated that competition should be transitioned on an individual company basis, due to differences in individual service territories, the level and type of strandable investments (i.e., costs that utilities would have otherwise recovered through rates under traditional cost of service regulation that, under market competition, would not be recoverable) and utility specific financial conditions.

The Order contemplates that implementation of competition will proceed on two tracks. The Order requires that each major electric utility (except the Company and Niagara Mohawk Power Corporation) file a rate/restructuring plan which is consistent with the PSC's policy and vision for increased competition. Those plans were submitted by October 1, 1996, in compliance with the Order. However, the Company was exempted from:this requirement due to the PSC's separate investigation of the Company's rates and LIPA's examination of the Company's structure. The PSC has now approved settlement agreements with each of the five New York utilities that were required Io file restructuring plans in the Competitive Opportunities Proceeding. LILCO and Niagara Mohawk were exempt however, on February 18,1998 the PSC also approved a settlement agreement on the Niagara Mohawk PowerChoice restructuring proposal that had been filed in October 1995.

In general, the term's of the agreements vary from three to'five years with all agreements calling for some rate reductions, structural separation of the generation and power delivery function, divestiture of fossil generation, full retail access in two to four years, and the imposition of a system benefits charge to cover the costs of research and development (R&D), conservation, low-income and environmental programs. In each case, the PSC is giving the utility a reasonable opportunity to recover all prudently-incurred stranded costs.

The PSC Order also anticipated that certain other filings would be made on October 1, 1996, by all New York State utilities, to both the PSC and the FERC. The filings were to address the delineation of transmission and distribution facilities jurisdiction between the FERC or the PSC, a pricing of each company's transmission services, and a joint filing by all the utilities to address the formation of an Independent System Operator (ISO) and the creation of a market exchange that will establish spot mark 86

prices. Although there were extensive collaborative meetings among the parties, it was not possible for the additional filings to be completed by October 1, 1996. Ori December 31, 1996, the New York Power Pool members submitted a compliance filing to the FERC which provides open membership and omparable services to eligible entities in accordance with FERC Order 888, discussed below. The New ork State utilities submitted the full ISO/Power Exchange filing to the FERG in January 1997, which proposes to establish a competitive wholesale marketplace in New York State for electric energy and transmission pricing at market-based rates. Subsequent to the FERC filing in January 1997, the New York State utilities made three relating filings with the FERC: (i) a supplemental filing, providing additional details regarding the creation of a New York State Reliability Council, in May 1997; (ii) a request for market-based rate authority, by six of the New York utilities, in August 1997; and (iii) a supplemental filing with the FERC on December 19, 1997 which expands upon and provides additional details with respect to the January 1997 filing.

The PSC has taken the position that a fully operational wholesale competitive structure will foster movement to full retail competition. The PSC's vision of the retail competitive structure, the'xpeditious known as the Flexible Retail Poolco Model, consists of: (i) the creation of an ISO to coordinate the safe and reliable operation of electric generation and transmission; (ii) open access to the transmission system, which would be regulated by the FERC; (iii) the continuation of a regulated distribution company to operate and maintain the distribution system; (iv) the deregulation of energy/customer services such as meter reading and customer billing; (v) the ability of customers to choose among suppliers of electricity; and (vi) the allowance of customers to acquire electricity either by long-term contracts, purchases on the spot market, or,a combination of the two.

One issue discussed in the Order that could affect the Company is strandable investments. The PSC stated in its Order that it is not required to allow recovery of all prudently-incurred investments, that, it has nsiderable discretion to set rates that balance ratepayer and shareholder interests, and that the amount of andable investments that a utility will be permitted to recover will depend on the particular circumstances of each utility. Additionally, the Order provided that every effort should be made by utilities to mitigate these costs prior to seeking recovery.

h Certain aspects of the restructuring envisioned by the PSC -particularly the PSC's apparent determinations that it may deny the utilities recovery of prudent investments made on behalf of the public, order retail wheeling, require divestiture of generation assets, and deregulate certain sectors of the energy market could, ifimplemented, have a negative impact on the operations and financial conditions of New, York's investor-owned electric utilities, including. the Company.

The Company is party to a lawsuit commenced in September 1996 by the Energy Association ofNew York State and the state's other investor-owned electric utilities (collectively, Petitioners) against the PSC in New York Supreme Court, Albany County The Ener Association of New York State et al. v. Public Service Commission of the State of New York et al.. The Petitioners have requested that the Court declare that the Order is unlawful or, in the alternative, that the Court clarify that the PSC's statements in the Order constitute simply a policy statement with no binding legal effect. In November 1996, the, Court issued a Decision and Order denying the Petitioners'equest to invalidate the Order. Although the Court stated that most of the Order is a non-binding statement of policy, the Court rejected the challenges to the Order. In December 1996, the Petitioners filed a notice of appeal with the Petitioners'ubstantive Third Department of the Appellate Division of the New York State Supreme Court; The litigation is oing and the Company is unable at this time to predict the likelihood of success or the impact of the ation on the Company's financial position, cash flows or results of operations. At the request of the I

87

Energy Association and Public UtilityLaw Project of New York (PULP), the Court has extendeddhe tirade in which the Energy Association and PULP must perfect their appeals until July 6, 1998.

The Electric Industry - Federal Regulatory Issues In April 1996, in response to its Notice of Proposed Rulemaking issued in March 1995, the FERC issued Orders 8S8 and 889 relating to the development of competitive wholesale electric markets.

Order 888 is a final rule on open transmission access and stranded cost recovery and provides that the

'ERC has exclusive jurisdiction over interstate wholesale wheeling and that utility transmission systems must now be open to qualifying sellers and purchasers of power on a non-discriminatory basis.

Order 888 allows utilities to recover legitimate, prudent and verifiable stranded costs associated with wholesale transmission, including the circumstances where full requirements customers become wholesale transmission customers, such as where a municipality establishes its own electric system.

With respect to retail wheeling, the FERC concluded that it has jurisdiction over rates, terms and conditions of service, but would leave the issue of recovery of the costs stranded by retail wheeling to the states.

Order 888 required utilities to file open access tariffs under'which they would provide transmission services, comparable t'o those which they'rovide to themselves and to third parties on a non-discriminatory basis. Additionally, utilities must use these same tariffs for their own wholesale sales.

Order 8SS-A, issued in March 1997, generally reaffirmed the FERC's basic determination in Order 888.

One pertinent change made in S88-A, however, was that the FERC, as opposed to the states, will be the primary forum for determining stranded costs in cases involving municipal annexation. Order SSS-B, issued November 1997, reaffirmed 888-A's findings.

The Company filed its open access tariffin July 1996. In September 1996, the FERC ordered Rate Hearings on 28 utility transmission tariffs, including the Company's. On the basis of a preliminary review, the FERC was not satisfied that the tariffrates were just and reasonable. Settlement discussions have been held between the Company and various intervenors concerning the Company's transmission rates. In December 1996, the parties reached a tentative settlement on the rate issues.

On May 14, 1997, the FERC approved the settlement agreement that the Company filed (with five other entities) concerning the rates for the Company's open access electric tariff. The effective date for those rates was July 9, 1996. The Company and four other New York'utilities are seeking review of certain non-rate aspects of the FERC's open access transmission tarifforders in the U.S. Court of Appeals for the D.C. Circuit.

Order 889,'hich'is a final rule on a transmission pricing bulletin board, addresses the rules and technical standards for operation of an electronic bulletin board that will make available, on a real-time basis, the price, availability and other pertinent information concerning each transmission utility's services. It also addresses standards of conduct to ensure that transmission utilities functionally separate their transmission and wholesale power merchant functions to prevent discriminatory self-dealing. In December 1996, the Company filed its standards of conduct in accordance with the Order.

Order 889-A and 889-B, issued in March and November 1997, respectively, generally reaffirmed and clarified the original Order 889. Order 889-A implemented new discounting policies and required that negotiations between a transmission provider and a potential customer take place on the transmission pricing bulletin board and be visible to all.

88

It is not possible to predict the ultimate outcome of these proceedings, the timing thereof, or the'amount, jf

'l any, of stranded costs that the. Company would recover in a comp'etitive environment. The outcome of the state and federal regulatory proceedings could adversely affect the Company's ability to apply SFAS No.

1, "Accounting for the Effects of Certain Types of Regulation," which, pursuant to SFAS No. 101, ccounting for Discontinuation of Application of SFAS No. 71," could then require a significant write-down of all or a portion of the Company's net regulatory assets.

The Company's Service Territory The Company's geographic location and the limited electrical interconnections to Long Island serve to limit the. accessibility of its transmission grid to potential competitors from offthe system. However, the changing utility regulatory environment has affected the Company by requiring the Company to co-exist with state'and federally mandated competitors, non-utility generators (NUGs).

The Public UtilityRegulatory Policies Act of 1978 (PURPA), the goals of which are to reduce the United States'ependency on foreign oil, to encourage energy conservation and to promote diversification of the =

fuel supply, has negatively impacted the'Company through the encouragement of the NUG industry. The PURPA provides for the development of a new class of electric generators which rely on either cogeneration technology or alternate fuels. Utilities are obligated under the PURPA to purchase the output of certain of these generators, which are known as qualified facilities (QFs).

For the years ended March 31, 1998 and 1997, the Company. lost sales to NUGs totaling 447 and 422 gigawatt hours (GWh) representing a loss in electric revenues net of fuel (net revenues) of approximately

$ 36 million and $ 34 million, respectively or 2.0/o and 1.9/0 of the Company's net revenue's, respectively.

For the year ended December 31, 1996, the Company lost sales to NUGs totaling 422 GWh~epresenting a s in electric net revenues of approximately $ 34 million, or 1.9/0 of the Company's net revenues. For year ended December 31, 1995, the Company lost sales to NUGs totaling 366 GWh or approximately 28 million or 1.5'/0 of the Company's net revenues.

The increase in lost net revenues'esulted principally from the completion of seven facilities that became commercially operational during 1996 and the full year operation of the IPP located at the State University of New York at Stony Brook, NY. The Company estimates that in 1999 sales losses to NUGs will be 447 GWh, or approximately 1.8/0 of projected net revenues, ' '

The Company believes that load losses due to NUGs have stabilized. This belief is based on the fact that the Company's customer load characteristics, which lack a significant industrial base and related large thermal load, willmitigate load loss and thereby make cogeneration economically, unattractive.

Additionally, as mentioned above, the Company is required to purchase all the power offered by QFs, which for the years ended March 31, 19)8 and 1997, approximated 220 megawatts (MW) and 226 MW, respectively. The Company estimates that purchases from QFs required by federal and state law cost the Company $ 71 million and $ 64 million in 1998 and 1997, respectively, more than it would have cost had the Company purchased the power in the open market or generated it.

For the years ended December 31, 1996 and 1995, QFs offered approximately 218 MW and 205 MW, respectively. The Company estimates that purchases from QFs required by federal and state law cost the Company $ 63 million and $ 5$ million for the years ended December 31, 1996 and 1995, respectively, than it would have cost had the Company purchased the power in, the open market"or generated it.

89

QFs have the choice of pricing sales to the Company at either the PSC's published estimates of the Company's long-range avoided costs (LRAC) or the Company's tariffrates, which are modified from time to time, reflecting the Company's actual avoided costs. Additionally, until repealed in 1992, New York State law set a minimum price of six cents per kilowatt-hour,(kWh) for utility purchases of power from certain categories of QFs, considerably above the Company's avoided cost. The six cent minimum continues to apply to contracts entered into before June 1992. The Company believes that the repeal of six cent minimum, coupled with recent PSC updates which resulted in lower LRAC estimates, has

'he significantly reduced the economic benefits of constructing new QFs within its service territory.

The Company has also experienced a revenue loss as a result of its policy of voluntarily providing wheeling of New York Power Authority (NYPA) power for economic development. The Company estimates that for the years ended March 31, 1998 and 1997, NYPA power displaced approximately 373 GWh and 424 GWh of annual energy sales, respectively. Net revenue loss associated with these volumes of sales is approximately $ 23 million, or 1.2~/o of the Company's 1998 net revenues, and $ 27 million, or 1.5/o of the Company's 1997 net revenues. Currently, the potential loss of additional load is limited by conditions in the'Company's transmission agreements with NYPA.

The Company estimates that for the years ended December 31, 1996 and 1995, NYPA power displaced approximately 417 GWh and 429 GWh of annual energy sales, respectively, Net revenue loss associated with these volumes of sales is approximately $ 26 million, or 1.4~/o of the Company's 1996 net revenues, and $ 30 million, or 1.6o/o of the Company's 1995 net revenues.

A number of customer groups are seeking;to hasten consideration and implementation of full retail competition. For example, an energy consultant has petitioned the PSC, seeking alternate sources of power for Long Island school districts. The County of Nassau has also petitioned the PSC to authorize retail wheeling for all classes of electric customers in the county.,

In addition, several towns and villages on Long Island are investigating municipalization, in which customers form a government-sponsored electric supply company. This is one form of competition that is likely to increase as a result of the National Energy, Policy Act of 1992 (NEPA). NEPA sought to increase economic efficiency in the creation and distribution of power by relaxing restrictions on the entry of new competitors to the wholesale electric. power market. NEPA does so by creating exempt wholesale generators that can sell power in wholesale markets without the regulatory constraint placed on utility generators such as on the Company. NEPA also expanded the FERC's authority to grant access to utility transmission systems to all parties who seek wholesale wheeling for wholesale competition. While it should be noted that the FERC's position favoring stranded cost recovery from retail turned wholesale customers will reduce utility risk from municipalization, significa'nt issues associated with the removal of restrictions on wholesale transmission system access have yet to be resolved.

There are numerous towns and villages in the Company's service territory that are considering the formation of a municipally-owned and operated electric authority to replace the services currently provided by the Company.

t r, s In 1995, Suffolk County issued a request for proposal from suppliers for up to 300 MW of power which the County would then sell to its residential and commercial customer'. The County has awarded the bid to two off-Long Island suppliers:and has requested the Company to deliver the power. After the Company challenged Suffolk County's eligibility-forsuch service, the County petitioned the FERC to order the Company to provide the requested transmission service. ~

90

In DhcemB'er 1996, the'FERC ordered the Company to provide transmission services to'Suffolk County to the extent necessary to accommodate proposed. sales to customers to which it was providing service on the date of enactment of NEPA (this Order could provide Suffolk County with the ability to import up to 200 W of power on a daily basis). The FERC reserved decision on the remaining.100 MW of Suffolk ounty's request until the County identifies the ownership or control of distribution facilities that it alleges qualifies it for a wheeling order to Suffolk County customers who were not receiving service on the date of NEPA's enactment. The Company may ask the FERC to reconsider its decision once that decision becomes final; which is not expected fox several months. The Company and Suffolk County submitted briefs in July 1997 addressing the pricing for the 200 MW of power. The FERC has yet to determine the pricing of. that service. As previously noted; FERC'Order 888 allows 'utilities to recover legitimate, pruderit and verifiable stranded costs associated" with wholesale transmission,'ncluding the circumstances where full requirements customers'.become wholesale transmission customers, such'as where a municipality establishes its own elec'tric system'.'t tt I t' t )

The matters discussed above involve substantial social; economic, legal, environmental'and financial issues. The Company;is,opposed to any proposal. that merely shiAs costs from one group of customers to another, that fails to enhance the provision of least-cost, efficiently-generated electricity or that fails to provide the Company's shareowners with an adequate return on and recovery of their investment. The Company is unable to predict what action, ifany, the PSC or the FERC may take regarding any of these matters, or the impact on the Company's financial position, c'ash flows or'esults of operations ifsome or all of these matters are approved or implemented by the appropriate regul'atory authority'.

Notwithstanding the outcome of the state or federal regulatory proceedings, or any other state action, the Company believes that, among other obligations, the State has a contractual obligation to allow the Company to recover'its Shoreham-related ass'ets.

F lh

)

gt t Ak vironmental Matters The Company is subject to federal, state and local laws and regulations'dealing with 'air and water quality and other environmental matters. Environmental matte'rs may expose the Company to potential liabilities which, in certain instances, may be imposed'without regard to fault or for historical activities whikh were" lawful at the'time they occurred. 'he Compan'y continually monitors its activities in order to determine the impact of its activities on the environment and to ensure compli'ance with various'environmental laws.

Except as set forth below, no mater'ial proceedings have been commenced or, to the knowledge of the Company, are contemplated against the Company with respect to a'y matter relating-to the protection of the environment.

v 4

The New York State Department of Environmental Conservation (DEC) has required the Company and other New York State utilities'to investigate and, where'necessary, 're'mediate their former manufactured gas plant (MGP) sites. -Currently, the Company is the 'owner of six pieces of property on which the Company or certain of its predecessor companies are believed to have produce'd manufactured gas.

Operations at these facilities'in the late 1800's and early 1900's may have resulted in the'disposal of certainwasteproductsonthese sites. '

' 't

\

The Company has entered into discussions with the DEC which is expected to lead to the issuance of one or more ACOs regarding the management of environmental activities at these six properties., Although the exact amount of the Company's cleanup costs cannot'yet be determined, based'on the findings of investigations conducted at each of these six sites, current estimates indicate that it may cost'inary ximately $ 54 to $ 92 million to investigate and remediate all of these sites. In considering the range o ossible remediation estimates, the Company'felt it a'ppropriate to record a $ 54 million liability t

t 1 91

reflecting the, present value-of the, future stream of payments amounting to $ 70 million to investigate and.

remediate these sites." The, Company used.a risk-free, rate of 6.0/o to discount. this obligation. The Company. believes that, the PSC w'ill provide for future recovery of these costs and has recorded a $ 54 million regulatory'ass'et. The.Company's rate settleinent which'the PSC approved'February 4,: 1998 as '

discussed in,Note 3:o'f Notes'to Financial Statements, allows for the recovery of MGP expenditures from~

gas customers. ~

r r r h' r In December,1996, the Company fileda complaint in the, United States District Court for the Southern,,

District of New York against,14 of the Company,'s insureds which issued general comprehensive liability (GCL) policies to the Company." In January 1998; the Company commenced a similar action against the same and certain additional insurer defendants in New York State Supreme Court, First33epartment; the-federal court action was subsequently dismissed in March 1998.. The,Company is seeking recovery. under.

the GCL policies for the costs incurred to date and future costs associated with the clean-up of the Company's former manufactured gas plant (MGP) sites and Superfund sites for which the Company has been named a,PRP: The Company is seeking a declaratory judgment that the defendant insurers are" bound. by the. terms of the, GCL policies, subject to the stated coverage limits, to reimburse the Company'or the clean up costs. The'outcome of this proceeding cannot yet be determined.

r rt' r i The Company has been notified by the United States Environmental Protection Agency (EPA) that it-is one of many+/Ps that may be liable for the remediation of three licensed treatment, storage and disposal sites to which the Company may have shipped waste products and.which. have subsequently become environmentally contaminated. I I, r At one site, locatl;d in Philadelphia, Pennsylvania, and operated by Metal. Bank of America,.the Company.

and nine other PRPs, all of which are public utilities, completed performance of a Remedial Ipvestigation and Feasibility Study (RI/FS), which was conducted under an ACO with the EPA. In December 1997, EPA issued its Record of Decision (ROD), setting forth the final remedial action selected'or this site.

the ROD, the;EPA e'gtimated that, the present cost of the selected remedy for the site is $ 17.3 million.. At this time; the Companycannot predict. with, reasonable certainty, the. actual. cost of the selected remedy, if will,implement the remedy, or the cost, any, to the Company.,Under a PRP participation

'ho agreement, the~Company previously was responsible for 8.2/o of the costs associated with the RI/FS. The ~

Company,'s,allocable share of liability for.the remediation activities has not'yet been:determined; The Company, has recorded a liability of approximately. $ 1 million representing its estimated share of the cost to remediate,this site;-based upon its 8.2'/0 responsibility under the RI/FS; The Company has also been named a PRP for disposal sites in Kansas City, Kansas, and Kansas City, Missouri. The two sites were used by a company named PCB, Inc. from 1982 until 1987 for the storage,'

processing, and,treatment of electric equipment, dielectric oils and materials containing PCBs. According to the EPA,'the buildings and certain soil areas outside the buildings are contaminated withe'CBs.

Certain of the PRPs, including the Company and,several other utilities formed a, PRP group, signed an.

ACO, and have developed a workplan for investigating environmental conditions at the sites.

Documentation connecting the Company to the sites indicates that the Company was responsible for less than 1/0 of the materials that were shipped to the Missouri site. The EPA has not yet completed .

' .. i compiling the documents for the Kansas site.

t W I In additiqn, ttie Company was;notified that it js a, PRP, at a $ uperfund site, located in Farmingdale, New York.. Industrial operations, took place at this site for at least fifty years. The PRP group has claimed t the Companyshould absorb remediation expenses-in the amount of approximately.$ 100,000 associat with removing PCB-'contaminated soils from a portion of the site which formerly contained electric transformers. The Company is currently unable to determine its share of costs of remediation at this site.

92

Dur'ing 1996, the Connecticut Department of Environmental Protection (DEP) issued a modification to an ACO previously, issued in'connection with an investi'gation. of an electric'transmission cable located under the Long Island Sound (Sound Cable) that is jointly owned by th'e Company and the Connecticut Light.

d Power Company (Owners). The 'modified ACO requires the Owners to'submit to the DEP and DEC a ries of reports and studies describing cable system condition, operation and repair practices, alternatives for cable improvements or replacement and environmental impacts associated with leaks of fluid into the Long Island Sound, which have occurred from time to time. The Company continues to compile required information and coordinate the.activities necessary to perform these studies and, at the present time, is unable to determine the costs it will incur to complete the requirements of the modified ACO or to comply with any additional requirements.

'he Owners have also entered into an ACO with the DEC as a result of leaks of dielectric fluid from the Sound Cable. The ACO formalizes the DEC's authority to participate in and separately, approve the reports and studies being prepared pursuant to the ACO issued by the DEP. In addition, the ACO settles any DEC claim for natural resource damages in connection with historical releases of dielectric fluid from the Sound Cable.

In October 1995, the U.S. Attorney for the District of Connecticut had commenced an investigation regarding occasional releases of fluid from the Sound. Cable, as well.as associated operating and maintenance practices. The Owners have provided the U.S. Attorney with all requested documentation.

The Company believes that all activities associated with the response to occasional releases from the Sound Cable were consistent with legal and regulatory requirements.

In December 1996, a barge, owned and operated-by a third party, dropped anchor which then dragged over d damaged the Sound Cable, resulting in the release of dielectric fluid into Long Island Soun'd.

porary clamps and leak abaters were installed on the cables to stop the leaks. Permanent repairs were pleted in June 1997. The'cost to repair the Sound Cable was approximately $ 17.8 million, for which there was $ 15 million of insurance coverage. The Owners filed a claim and answer in response to the maritime limitation proceeding instituted by the barge owner in the United States District Court, Easte'rn District of New York. The claim seeks recovery of the amounts paid by insurance carriers and recovery of the costs incurred for..which there was no insurance coverage. Any costs to repair the Sound Cable which are not reimbursed by a third party or covered by insurance 'will be shared equally by the Owners.

The Company believes that. none of the environmental matters, discussed above, will have a material adverse impact on the Company's financial position, cash flows or results of operations. In addition, the Company believes that all significant costs incurred with respect to environmental investigation and remediation activities, not recoverable from insurance carriers, will be recoverable through rates.

93

Note 13. Business Segments Identifiable assets by segment include net utility plant, regulatory assets, materials and supplies, accrued unbilled revenues, gas in storage; fuel and deferred charges. Assets utilized for overall Company operations consist primarily'fcash and cash equivalents, accounts receivable, common net utility plant unamortized cost of issuing securities.

'nd (In millions ofdollars)

Year Ended Three Months Ended Year Ended Year Ended March 31, 1998 March 31, 1997 December 31, 1996 December 31, 1995 Operating revenues Electric $ 2,478 $ 558 $ 2,467 $ 2,484 Gas 646 293 684 591

'otal

$ 3,124 $ 851 $ 3,151 $ 3,075 Operating expenses (excludes federal income tax)

Electric 1,595 $ 400 $ 1,644 $ 1,657 Gas 523 204 560 478 Total $ 2,118 $ 604 $ 2,204 $ 2,135 Operating income (before federal income tax)

Electric $ 883 $ 158 $ 823 $ 827

'as 123 89 124 113 Total operating income $ 1,006 $ 247 $ 947 $ 940 AFC $ (8) (2) $ (6) (7)

Other income and deductions 10 (2)" (23) (38)

Interest charges 409 107 451 476 Federal income tax 233 56 209 206 Net Income $ 362 $ 88 $ 316 $ 303 Depreciation and Amortization Electric $ 131 $ 32 $ 129 Gas "28 7 25 Total $ 159 $ .39 $ 154 Construction and nuclear fuel expenditures*

Electric Gas Total fl

$ 181 80

$ 261

~'6 '

35

51

$ 243 165 78

$ 162

$ 246 84

~ Includes non-cash allowance for other funds used during construction and excludes Shoreham post-settlement costs.

March 31, 1998 March 31, 1997 December 31, 1996 December 31, 1995 Identifiable Assets Electric $ 9,553 $ 10,048 $ 9,835 $ 10,020

'as 1,219 1,134 I)232 1,181 Total Identifiable Assets 10,772 11,182 11,067 11,201 Assets Utilized for Overall 1,129 668 1,143 1,326 Company Operations Total Assets $ 11,901 $ 11,850 $ 12,210 $ 12,527 94

Note'14. 0'isaggregated Condensed Balance Sheet (Unaudited),

Set forth below is the Company's condensed balance sheet at March 3l, 1998 which has been disaggregated pursuant to the terms of the LIPA Agreement to give effect to the proposed LIPA ansaction as ifit had occurred on March 3 1; 1998. The assets;- capitalization and liabilities attributable HoldCo Subsidiary represent the,Company's transfer of its gas and generation business to such subsidiary. The assets, capitalization and liabilities attributable'to LIPA represent those items that will be acquired or assumed by LIPA through its acquisition of the Company's common stock. All such amounts exclude'the proceeds from the sale of common stock to LIPA. The disaggregated condensed balance sheet was prepared by'management o'f the Com'pany, and is subject to adjustment. For a further discussion of the LIPA Transaction, see Note 2.

(In millions tofdollars)

ASSETS LILCO HoldCo Subsidiary LIPA Total Net UtilityPlant $ 3,814.1 $ 1,777.8 $ 2,036.3 Regulatory Assets Shoreham related 4,661.1 4,661.1 Regulatory tax asset 1,737.9'92.8 21.0 1,716.9 Other 430,1 262,7 Total Regulatory Assets Nonutility Property and Other Investments .,

Total Current Assets

=

7,091.8 50.8 858.3, 451.1 32.9 494.2,,

, 6,640.7

'7.9 364.1 Deferred Charges 85.7 38.0 47.7 Total Assets $ 11,900.7 $ 2,794.0 $ 9,106.7 CAPITALIZATIONAND, LIABILITIES Long term debt, including current maturities $ 4,482.9 $ 1,130.5 $ 3,352.4 Preferred t

stock, including current maturities 702.0 363.0 339.0 ommon Shareowner's Equity 2,662.5 161.7 25008 1 $ 7,847.4 $ 1,655.2 $ 6,192.2

latory Liabilities 389.4 24.2 365.2 Current Liabilities 587.4 ., 433.0 154.4 Deferred Credits, 2,608.8, 211.2 2,397.6, Operating Reserves 467.7 . 470.4 -

(2.7)

'; '2,794.0

'ommitments and Contingencies Total Capitalization and Liabilities $ 11,900.7 $ 9,106.7 c k k k It kt t 'I ~

k tt' t k

f Pk" t

t kt 95

Note 15. Quarterly Financial Information (Unaudited)

Summarized 'quarterly financial'data for 1998,"1997 and 1996 is. as follows:

(In'ihousands ofdollars except earnings per common share) isca ear 3 Months Ended" Operating Revenues ~

3/31/97

$ 851,182 190,001 6/30/97

$ 664,488" 144,079,",,

9/30/97

'852,408

'42,611,

', 12/31/97

$ 779,622 171,969

" 3/31/98

$ 827,576 209,637 Operating Income. '

45)16) ', 1144)384

,-i 56,756 115,939

'et Income 87,697 Earnings for common stock, Basic and diluted earnings per common sfiare '62 74,728, 32,193

.26 131,435 1.09

. 43,807

.36

,. 102,992

.85 Calendar Year Ended December 31, 1996 3 Months Ende'iI 3/31/96 6/30/96 9/30/96 12/31/96 Operating Revenues $ 864,214 $ 694,602 $ 849,775 $ 742;104 Operating Income 190,421 141,065 235,402 169,693 Net Income 81,753 40,524 130,023 '4,164 Earnings'for common stock 68,682 27,453 116,972 51,141 Basic and diluted earnings per common share .57 .23 .97 .43 Report of Ernst &, Young LLP, Independent Auditors, as evaluating the overall financial statement To the Shareowners and Board of Directors of Long presentation. We believe that our audits provide a Island Lighting Company reasonable basis for our opinion.-

We have audited the accompanying balance sheet of In. our'pinion", the financial statements referred to.

Long Island Lighting Company and the related above present fairly,'in all'material respec'ts,'the statement of capitalization as of March 31, 1998 and financial position of Long Island Lighting Company 1997, and December 31, 1996 and the related at March 31, 1998 and 1997, and December 31, statements of income, retained earnings and cash 1996, and the results of its operations and its c flows for the year ended March 31, 1998, the flows for the year ended March 31, 1998, the q transition period from January 1, 1997 to March 31, transition period from January 1, 1997 to March 31, 1997 and'each of the two years in the period ended 1997 and each of the two years in the period ended December 31, 1996. Our audits also included the December 31, 1996, in conformity with generally financial statement schedule listed in the index at accounting principles. Also,"in our opinion, 'ccepted Item 14(a). These financial statements and schedule the related financial statement schedule, when are the responsibility of the Company's management. considered in relation to the basic financial Our responsibility is to express an opinion on these statements taken as a whole, presents fairly in all financial statements and schedule based on our material respects the information set forth therein.

audits. As discussed in Note 1 to the financial statements, We conducted our audits in accordance with during the year ended March 31, 1998 the Company generally accepted auditing standards. Those changed its method of accounting for revenues standards require that we plan and perform the audit provided for under the Rate Moderation Component.

to obtain reasonable assurance about whether the financial statements are free of material Melville, New York misstatement. An audit includes examining, on a test May 22, 1998 basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well 96

Item 9. ' Changes in and Disagreements With Accountants on Accounting and Financial Disclosures fl V Not applicable.

h tt I J t

V g 97

PART III ~

in the SEC filing of May 28, 1998. 'ncluded Item 10. Directors and Executive Officers of the Company ll Item 11. Executive Compensation Item 12. Security Ownership of Certain Beneficial Owners and Management 1

Item 13. Certain Relationships and Related Transactions PART IV Item 1'4. Exhibits, Financial Statement Schedules, and Reports on Form 8-K (a)(1) List of Financial Statements Statement of Income for the year ended March 31, 1998, the three months ended March 31, 1997 and the years ended December 31, 1996 and 1995.

Balance Sheet at March 31, 1998 and 1997 and December 31, 1996.

Statement of Retained Earnings at March 31, 1998'and 1997 and December 31, 1996 and 1995.

Statement of Capitalization at March 31, 1998 and 1997 and December 31, 1996.

Statement of Cash Flows for the year ended March 31, 1998, the three months ended March 1997 and the years ended December 31, 1996 and 1995.

Notes to Financial Statements (2) List of Financial Statement Schedules Valuation and Qualifying Accounts (Schedule II)

(3) List of Exhibits To be provided by the Legal Department and included in the filing copy.

98

SCHEDULE II - VALUATIONAND QUALIFYINGACCOUNTS (Thousands ofDollars)

Column A Column B Column C Column D Column E Additions Balance at Charged to Charged Balance at Description beginning costs and to other Deductions- end of of period expenses accounts- describe period describe Year ended March 31, 1998 Deducted from asset accounts:

Allowance for doubtful accounts $ 23,675 $ 23,239 $ 23,431to $ 23,483 Three Months Ended March 31, 1997 Deducted from asset accounts:

Allowance for doubtful accounts $ 25,000 $ 4,821 $ 6,146<0 $ 23,675 Year ended December 31, 1996 Deducted from asset accounts:

Allowance for doubtful accounts $ 24,676 $ 23,119 $ 22,795 re $ 25,000 ar ended December 31, 1995 ducted from asset accounts:

Allowance for doubtful accounts $ 23,365 $ 17,751 $ 16,44000 $ 24,676 (I) Uncollectible accounts written og net ofrecoveries.

99

t

". (',i ", '~ 'ignatures,,

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Date Si nature and Title WILLIAMJ. CATACOSINOS4

'. Willia'm J. Catacosinos, Principal Executiye Otic'er and Chairman of the Board, of Directors

. JAMES T."FLYNN*

James T. Flynn, President,

', Chief Operating Officer, Director

" /s/ JOSEPH E. FONTANA Joseph E. Fontana, Vice President, Controller, Principal Accounting Officer A. JAMES BARNES* I, f A. James Barnes, Director GEORGE BUGLIARELLO*

George Bugliarello, Director May 28, 1998 RENSO L. CAPORALI*.,

Renso L. Caporali, Director VICKIL. FULLER*

Vicki L. Fuller, Director KATHERINED. ORTEGA*

Katherine D. Ortega, Director BASIL A. PATERSON*

Basil A. Paterson, Director RICHARD L. SCHMALENSEE*

Richard L. Schmalensee, Director GEORGE J. SIDERIS*

George J. Sideris, Director JOHN H. TALMAGE*

John H. Talmage, Director

/s/ ANTHONYNOZZOLILLO Anthony Nozzolillo (Individually, as Senior Vice President and Principal Financial Officer and as attorney-in-fact for each of the persons indicated) 100

SIGNATURES, P 11 Pursuant to the requirements of Section 13 or.15(d) of the Securities Exchange Act of 1934, the registrant has duly caused, this report to be signed on its behalf by the undersigned,,thereunto duly authprized.

LONG ISLAND LIGHTINGCOMPANY V

I Date: May 28, 1998: By =

i

/s/ ANTHONYNOZZOLILLO ANTHONYNOZZOLILLO 4q lt Principal Financial Officer Original powers of attorney, authorizing Kathleen A. Marion and Anthony Nozzolillo, and each of them; to sign this report and any amendments thereto, as attorney-in-fact for each of the Directors and Officers of the Company, and a certified copy of the resolution of the Board of Directors of the Company authorizing said persons and each of them to sign this report and~,,

thereto as attorney-in-fact for any Officers signing on behalf of the Company, have 'mendments been, are being filed or will be filed with the Securities and Exchange Commission.

101

Consent of Inde endent Auditors We consent to the incorporation by reference in the Post-Effective Amendment No. 3 to Registration Statement (No. 33-16238) on Form S-8 relating to Long Island Lighting Company's Employee Stock'Purchase Plan, Post"-Effective Amendment No. 1 to Registration Statement (No.

2-87427) on Form S-3 relating to Long Island Lighting Company's Automatic Dividend Reinvestment Plan and in the related Prospectus, Registration Statement (No. 2-88578) on Form S-3 relating to the issuance of Common Stock and in the related Prospectus and Registration Statement (No. 33-52963) on Form S-3 relating to the issuance of General and Refunding Bonds, Debentures, Preferred Stock or Common Stock and in the related Prospectus, of our report dated May 22, 1998, with respect to the financial statements and schedule of Long Island Lighting" Company included in'this Annual Report on Form 10-K for the year ended March 31, 1998.

/s/ERNST & YOUNG 'LLP i

Melville, New York May 26, 1998 102