OR

Commission file number 1-14766

Registrant's telephone number, including area code: (518) 434-3049

Securities registered pursuant to Section 12(b) of the Act:

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes     X        No           

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of Registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [   X   ]

The aggregate market value as of March 15, 2000, of the common stock held by non-affiliates of the Registrant was $2,334,692,694.

Common stock - 117,465,645 shares outstanding as of March 15, 2000

DOCUMENTS INCORPORATED BY REFERENCE

PART I

PART II

TABLE OF CONTENTS (Cont'd)

PART III

PART IV

Item 1.  Business

(a)  General development of business

Energy East Corporation is a holding company that was organized under the laws of the State of New York in 1997. It is a super-regional energy services and delivery company with operations in New York, Connecticut, Massachusetts, Maine, New Hampshire and New Jersey and offices in New York and Connecticut. On May 1, 1998, the company became the parent of New York State Electric & Gas Corporation. Because Energy East did not become the holding company for NYSEG until May 1, 1998, the January through April 1998 and the 1997 consolidated financial statements represent the accounts of NYSEG on a consolidated basis as predecessor of Energy East.

On February 8, 2000, the company completed its merger with Connecticut Energy Corporation (CNE). CNE is a holding company primarily engaged in the retail distribution of natural gas through its wholly-owned subsidiary, The Southern Connecticut Gas Company. The company accounted for the acquisition using the purchase method; consequently its consolidated financial statements will include CNE's results beginning with February 2000.

The following general developments have occurred in the company's business since January 1, 1999:

(b)  Financial information about segments
(See Item 8 - Note 14 to the Consolidated Financial Statements.)

(c)  Narrative description of business
(See Item 7 - Merger Agreements, and Energy Delivery Business.)

Disposition of Assets
(See Item 7 - Energy Delivery Business, Sale of Coal-fired Generation Assets, Nine Mile Point 2 and Item 8 - Notes 7 and 8 to the Consolidated Financial Statements.)

     (i)  Principal business

The company's principal energy delivery business is purchasing, transmitting and distributing electricity and purchasing, transporting and distributing natural gas in New York. After completing its merger with CNE in February 2000, the company began purchasing, transporting and distributing natural gas in Connecticut. The company also generates electricity from its nuclear and hydroelectric stations.

The company's New York service territory, 99% of which is located outside the corporate limits of cities, is in the central, eastern and western parts of the state. It has an area of approximately 19,900 square miles and a population of 2,500,000. The company's Connecticut service territory extends along the southern Connecticut coast from Westport to Old Saybrook. It has an area of approximately 488 square miles and a population of 776,000. The larger cities in New York in which the company serves both electricity and natural gas are Binghamton, Elmira, Auburn, Geneva, Ithaca and Lockport. In Connecticut the larger cities in which it serves natural gas are Bridgeport and New Haven. The company provides delivery service to approximately 825,000 electricity customers and 408,000 natural gas customers. The service territories reflect diversified economies, including high-tech firms, light industry, colleges and universities, agriculture and recreational facilities. No customer accounts for 5% or more of either electric or natural gas revenues. The company's operating revenues derived from electricity deliveries were 83% in 1999, 87% in 1998 and 83% in 1997. Its operating revenues derived from natural gas deliveries were 14% in 1999, 12% in 1998 and 15% in 1997.

The 1999 peak load of 2,431 megawatts (mw) was set on January 14, 1999. This is 92 mw more than the previous year peak of 2,339 mw set on December 30, 1998.

The 1999 maximum peak daily sendout for natural gas of 400,713 dekatherms was set on January 13, 1999. This is 37,209 dekatherms more than the previous year peak of 363,504 dekatherms set on December 30, 1998.

     (ii)  Other operations

XENERGY Enterprises includes the following businesses:

• XENERGY provides energy services, information systems and energy consulting nationwide.
• Energy East Solutions sells electricity and natural gas in wholesale and retail markets in the Northeast and mid-Atlantic regions.
• Cayuga Energy generates and sells electricity in the wholesale market at times of high demand.
• Energy East Telecommunications operates a fiber optic network in Central New York.

Energy East Enterprises includes the following businesses:

• CMP Natural Gas delivers natural gas in southern and central Maine.
• New Hampshire Gas operates a propane air distribution system in Keene, New Hampshire.
• Seneca Lake Storage, Inc. is developing high deliverability gas storage in New York State.

CNE's non-utility operations include the following businesses:

• CNE Energy Services Group, Inc. provides energy commodities and services to business customers throughout New England.
• CNE Development Corporation participates in a natural gas purchasing cooperative.
• CNE Venture-Tech, Inc. invests in technologically advanced energy-related products.

     (iii)  New product or segment
     (See (ii) Other operations.)

     (iv)  Sources and availability of raw materials

Electric
(See Item 7 - Energy Delivery Business, Sale of Coal-fired Generation Assets and Nine Mile Point 2.)

After completing the sale of its coal-fired generation assets, the company satisfied the majority of its power requirements for 1999 through generation from its nuclear and hydroelectric stations and by purchases under long-term contracts from non-utility generators (NUGs) and the New York Power Authority. For its remaining power requirements, the company has assumed the risk of market prices that fluctuate and uses electricity contracts, both physical and financial, to manage its exposure to fluctuations in the market price of electricity.

Natural Gas
(See Item 7 - Energy Delivery Business.)

The company's natural gas supply mix includes long-term, short-term and spot natural gas purchases transported under both firm and interruptible transportation contracts. During 1999 about 60% of the company's New York natural gas supply was purchased from various suppliers under long-term and short-term sales contracts and 40% was purchased in the monthly or daily spot natural gas market. About 84% of the 1999 Connecticut natural gas supply was purchased from various suppliers under long-term and short-term sales contracts and 16% was purchased in the monthly or daily spot natural gas market. The company expects to purchase its New York and Connecticut natural gas supplies for 2000 in similar proportions as were purchased in 1999. The company uses natural gas futures and options contracts to manage its exposure to fluctuations in natural gas commodity prices.

     (v)  Franchises

The company has, with minor exceptions, valid franchises from the municipalities in which it renders service to the public. In 1999 the company obtained authorization from the Public Service Commission of the State of New York for natural gas distribution service in the town of Skaneateles.

     (vi)  Seasonal business

Sales of electricity are highest during the winter months primarily due to space heating usage and fewer daylight hours. Sales of natural gas are highest during the winter months primarily due to space heating usage.

     (vii)  Working capital items

The company has been granted, through the ratemaking process, an allowance for working capital to operate its ongoing electric and natural gas utility services.

     (viii)  Single customer - Not applicable

     (ix)  Backlog of orders - Not applicable

     (x)  Business subject to renegotiation - Not applicable

     (xi)  Competitive conditions

     (See Item 7 - Energy Delivery Business and Accounting Issues.)

     (xii)  Research and development

Expenditures on research and development were $5 million in 1999, $6 million in 1998 and $11 million in 1997, principally for internal research programs and for contributions to research administered by the Electric Power Research Institute, the Empire State Electric Energy Research Corporation (prior to 1999), the New York Gas Group and the New York State Energy Research and Development Authority. These expenditures are designed to improve existing technologies and to develop new technologies for the production, delivery and customer use of energy.

     (xiii)  Environmental matters
     (See Item 3 - Legal proceedings, Item 7 - Energy Delivery Business, Sale of Coal-fired Generation Assets and Item 8 - Notes 8, 9 and 13 to the Consolidated Financial Statements.)

The company is subject to regulation by the federal government and by state and local governments with respect to environmental matters and is also subject to the New York State Public Service Law requiring environmental approval and certification of proposed major transmission facilities.

From time to time environmental laws, regulations and compliance programs may require changes in the company's operations and facilities and may increase the cost of energy delivery service. Historically, rate recovery has been authorized for environmental compliance costs.

Capital additions to meet environmental requirements during the three years ended December 31, 1999, were approximately $23 million, primarily for the company's coal-fired generation plants, which were sold in 1999. As a result, future capital additions to meet environmental requirements are not expected to be material.

The company is required to comply with federal and state water and air quality statutes and regulations including the Clean Water Act. The Water Act requires that generating stations be in compliance with federally issued National Pollutant Discharge Elimination System Permits or state issued State Pollutant Discharge Elimination System (SPDES) Permits, which reflect water quality considerations for the protection of the environment. Nine Mile Point 2 has a SPDES Permit. The company owns two natural gas-fired peaking generating stations, which have the required federal or state operating permits and are in compliance with the permits.

Niagara Mohawk has contracted with the U.S. Department of Energy for disposal of high level radioactive waste (spent fuel) from Nine Mile Point 2. The company is reimbursing Niagara Mohawk for its 18% share of the costs under the contract (currently approximately $1 per megawatt hour of net generation). The DOE's schedule for start of operations of their high level radioactive waste repository will be no sooner than 2010. The company has been advised by Niagara Mohawk that the Nine Mile Point 2 Spent Fuel Storage Pool has a capacity for spent fuel that is adequate until 2014. If further DOE schedule slippage should occur, construction of pre-licensed dry storage facilities would extend the on-site storage capability for spent fuel at Nine Mile Point 2 beyond 2014.

     (xiv)  Number of employees  The company had 3,838 employees as of February 29, 2000.

(d) Financial information about geographic areas  Not applicable

Item 2.  Properties
(See Item 7 - Energy Delivery Business, Sale of Coal-fired Generation Stations and Nine Mile Point 2.)

The company's electric system includes nuclear, hydroelectric and internal combustion generating stations, substations and transmission and distribution lines, all of which are located in the State of New York. Generating facilities are:

(1)  The company's 18% share of the generating capability. The company has agreed to sell its 18% interest in Nine Mile Point 2.

The company also owns two natural gas-fired peaking generating stations, Carthage and South Glens Falls, which are operated by Cayuga Energy and located in the State of New York. Each station has a generating capability of 63 mw.

The company owns 430 substations in New York having an aggregate transformer capacity of 13,436,948 kilovolt-amperes. The transmission system consists of 4,384 circuit miles of line. The distribution system consists of 33,891 pole miles of overhead lines and 2,153 miles of underground lines.

The company's New York natural gas system consists of 74 miles of transmission pipeline and 7,056 miles of distribution pipeline. Its Connecticut natural gas system consists of 3,573 miles of distribution pipeline.

NYSEG's and Southern's first mortgage bond indentures constitute direct first mortgage liens on substantially all of their respective properties.

Item 3.  Legal proceedings
(See Item 7 - Energy Delivery Business.)

Since the Public Service Commission of the State of New York has allowed the company to recover in rates remediation costs for certain of the sites referred to in the next sentence, there is a reasonable basis to conclude that the company will be permitted to recover in rates any remediation costs that it may incur for all of the sites referred to in the next sentence. Therefore, the company believes that the ultimate disposition of the matters referred to below in (b), (d), (e), (f), (g), the first paragraph in (a) and the first two paragraphs in (c) will not have a material adverse effect on its results of operations or financial position.

As a result of the company's merger with CNE on February 8, 2000, the matters referred to in (j) below now relate to the company. All costs identified as recorded and deferred in (j) below are reflected in the company's financial records beginning in February 2000. Since the Connecticut Department of Public Utility Control has allowed recovery in rates of certain remediation costs of the type referred to below in (j), the company believes that the ultimate disposition of the matters referred to below in (j) will not have a material adverse effect on its results of operations or financial position.

(a)  In June 1991 the New York State Department of Environmental Conservation (NYSDEC) notified the company that it had been identified as a potentially responsible party (PRP) at the Pfohl Brothers Landfill, an inactive hazardous waste disposal site in Cheektowaga, New York. The Pfohl Site is listed on the National Priorities List and the New York State Registry of Inactive Hazardous Waste Disposal Sites. The expected remediation costs at the Pfohl Site are estimated to be $37 million to $55 million. In May 1995 the company agreed to participate in a process for allocating remedial costs at the Pfohl Site with other PRPs. In October 1997 the PRPs agreed upon an allocation formula under which the company would be responsible for approximately $296,000 to $440,000.

Five actions were commenced against the company and approximately 24 other defendants in the New York State Supreme Court, Erie County (State Court) (in January 1995, April 1995, June 1995, January 1997 and October 1997), claiming $103.5 million in damages for personal injuries, wrongful death and loss of companionship allegedly caused by exposure to hazardous chemicals from the Pfohl Site. In December 1997 the action commenced in October 1997 was removed to the United States District Court for the Western District of New York (District Court). The company believes that the actions against it are without merit and will defend them vigorously.

In November 1997 a class action was commenced in the State Court against the company and approximately 23 other defendants claiming unspecified damages for personal injuries allegedly caused by exposure to hazardous chemicals from the Pfohl Site. This action was transferred to the District Court. The company believes this action against it is without merit and will defend it vigorously.

In 1995 four actions were commenced against approximately 11 defendants, and in 1996, an action was commenced against 13 defendants for personal injuries, wrongful death and loss of companionship allegedly caused by exposure to hazardous chemicals from the Pfohl Site. The company was not named as a defendant in those actions. However, the defendants in those actions consequently commenced actions against the company and certain other parties in the District Court at various times in 1995 and 1996, alleging that the company and such other parties are liable for all or a part of any damages recovered by the plaintiffs. Recovery in the actions against the company and such other parties depends on, among other things, whether the plaintiffs recover money damages against the defendants. The company believes that the actions against it are without merit and will defend them vigorously.

In October 1998 an action was commenced against the company and approximately 24 other defendants in the State Court claiming damages due to the lost use, value, and enjoyment of their property as a result of contamination from the Pfohl Site. The plaintiffs seek damages that total $6.4 million in the aggregate. The company believes that the action against it is without merit and will defend it vigorously.

In September 1999 the District Court granted a motion by the defendants to dismiss the claims of 26 plaintiffs based on the statute of limitations in the actions referred to in the four prior paragraphs.

(b)  In January 1992 the NYSDEC notified the company that it had been identified as a PRP at the Peter Cooper Corporation's Landfill Site (Peter Cooper Site) in the village of Gowanda, New York. The Peter Cooper Site is listed on the National Priorities List and the New York State Registry. Three other PRPs were identified in the NYSDEC letter. The company believes that remediation costs at the Peter Cooper Site might rise to $16 million. In May 1992 the company notified the NYSDEC that it believed it had no responsibility for the alleged contamination at the Peter Cooper Site, and it declined to conduct remediation or finance remediation costs.

In June 1999 the U.S. Environmental Protection Agency (EPA) notified the company and 18 other companies that they are PRPs with respect to the Peter Cooper Site, and offered them the opportunity to perform a remedial investigation and feasibility study at the site. Along with approximately 12 other companies, the company indicated to EPA its willingness to consider performing the study for a portion of the Peter Cooper Site. Although the company is still discussing the possibility of performing the study with the EPA and the other parties, the company believes that the ultimate disposition of this matter will not have a material adverse effect on its financial position or results of operations.

(c)  In July 1992 the NYSDEC notified the company that it had been identified as a PRP at the Bern Metals Removal Site in Buffalo, New York, which the NYSDEC defined to include an adjacent property known as the Universal Iron & Metal Site. The Bern Metals/Universal Iron Site is listed on the New York State Registry. The NYSDEC also identified eight other PRPs for the site. In December 1992 the company declined to negotiate with NYSDEC to finance or conduct a Remedial Investigation and Feasibility Study (RI/FS) for the site.

The total cost of remediation is estimated to be $2.7 million. Without admitting any liability or responsibility, the company, in October 1997, entered into an Order on Consent with NYSDEC and four other PRPs pursuant to which it and such PRPs will, subject to NYSDEC approval, design the remedy for the Bern Metal/Universal Iron Site. The NYSDEC subsequently inquired whether the company and 15 other PRPs were willing to implement the remedy. In December 1998 the company and six other PRPs, who completed the remedial design, responded that the NYSDEC should first look to the other PRPs who have yet to finance any work at the site.

In September 1996 the company and 55 other parties were named as third-party defendants by Niagara Frontier Transportation Authority (NFTA) claiming contributions for costs that might be recovered against NFTA in an action filed by EPA in the District Court. NFTA is seeking contributions for response costs incurred by EPA at the Universal Iron Site. The company believes that the action against it is without merit and will defend it vigorously.

(d)  In April 1992 the EPA notified the company that the EPA had reason to believe that the company was a PRP for the Clinton-Bender Removal Site (Clinton-Bender Site) in Buffalo, New York. Five other PRPs have been identified by the EPA. Nine private residential lots and one commercial property at the Clinton-Bender Site were contaminated with lead, allegedly due to run-off from the adjacent Bern Metals Site. The company and four other PRPs performed removal actions at the Clinton-Bender Site at a cost of approximately $3.2 million. The company along with the other participating parties are seeking to recover from other PRPs, not participating in the remedial action at the Clinton-Bender Site, costs that the company and other participating parties have incurred or will incur.

(e)  In February 1993 NYSDEC notified the company and 19 other parties that they had been identified as PRPs for remediation of hazardous wastes at the Booth Oil Site in North Tonawanda, New York. The Booth Oil Site is listed on the New York State Registry. According to NYSDEC, the Booth Oil Site is contaminated with polychlorinated biphenyls (PCBs), lead, and other substances. The company estimates that the present value of costs for remedial alternatives range from $10.0 million to $21.7 million. The company and more than 20 other PRPs have tentatively agreed on an allocation under which the company's share of a cleanup settlement will be between $160,000 and $700,000.

(f)  In June 1994 the company was served with a summons and complaint joining it as a defendant in an action that was filed in the United States District Court for the Northern District of New York. The plaintiffs are five companies that have been required by the EPA to conduct remedial activities at the Rosen Brothers Site in the City of Cortland, New York. The Rosen Site is allegedly contaminated with hazardous substances including heavy metals, solvents and PCBs. The Rosen Site is listed on the National Priorities List and the New York State Registry. The plaintiffs allege that the company was a contributor of transformers that may have contained PCBs.

In August 1994 the EPA notified the company that the EPA had reason to believe that the company was a PRP for the Rosen Site and requested that it participate in the RI/FS then being prepared for the Rosen Site by other named PRPs.

The company received an order from the EPA in March 1998 ordering the company and 15 other parties to perform certain removal actions at the Rosen Site. The company contributed approximately $45,000 toward the $730,000 total cost of the removal actions.

In September 1998 the company, along with approximately 12 other parties, entered into a consent decree with the EPA under which the company and the other settling parties will perform the selected remedy and reimburse the EPA for approximately $692,000 of past costs. The estimated total present worth cost of the remedy is $3,140,000. The company's share of the remediation costs is still being negotiated.

(g)  The company responded in October 1995 to a request for information by the EPA concerning alleged disposal of PCBs at facilities owned or operated by PCB Treatment, Inc. in Kansas City, Kansas and Kansas City, Missouri. In September 1996 the company entered into an Order on Consent with the EPA under which the company and at least nine other companies will perform the first phase of remedial activity, a Removal Site Evaluation and Engineering Evaluation/Cost Analysis, at the two facilities operated by PCB Treatment, Inc. The company's obligation under this Order on Consent has been completed at a cost of $90,000. In September 1997 the EPA notified 1,251 entities, including the company, of their potential remediation liability at the two facilities. The company's share of remediation costs at the two facilities is likely to be less than $250,000.

(h)  In August 1997 the company was notified by the NYSDEC that they were contemplating enforcement action against the company with respect to violations of regulations concerning opacity of air emissions at all of its New York coal-fired stations. The company is in the process of negotiating a consent order with NYSDEC to resolve the NYSDEC's demand for a penalty of approximately $650,000. The company sold its New York coal-fired stations in 1999 and has notified the buyer of its responsibility for any such penalty.

(i)  The company received a letter in October 1999 from the Office of the Attorney General of New York State alleging that the company may have constructed and operated major modifications to certain emission sources at the Goudey and Greenidge generating stations, which it formerly owned, without obtaining the required prevention of significant deterioration or new source review permits. The Goudey and Greenidge plants were sold to The AES Corporation in May 1999. The letter requested that the company and AES provide the Attorney General's Office with a large number of documents relating to this allegation. On January 13, 2000, the company received a subpoena from the NYSDEC ordering production of similar documents.

The company furnished documents pursuant to such requests. The company believes it has complied with the applicable rules and regulations and there is no basis for the Attorney General's allegation.

(j)  The company has identified coal tar residue at three sites in Connecticut where gas was manufactured in the past. In September 1997 the company received a letter from the Connecticut Department of Environmental Protection (DEP) informing it that the three sites had been entered on the Connecticut inventory of hazardous waste sites.

The company and the DEP have entered into a Consent Order with respect to one of the sites. Pursuant to the Consent Order, the company has agreed to undertake an investigation of the site and its immediate surrounding area to determine potential sources of contamination and to remediate contamination that may be found to have emanated or be emanating from the site as a result of the company's activities at the site. As a result of this Consent Order, the company has recorded and deferred $405,000 for costs related to the site investigation. Since the investigation has not yet been completed, the company cannot predict the cost, if any, of any remediation for the site.

The company has also elected to proceed with the rehabilitation of a bulkhead located at the site at an estimated cost of $2 million. In addition, the company estimates it will incur approximately $905,000 in the next 12 months, which has been recorded and deferred, for pilot studies, remediation design work and legal fees associated with the site and the Consent Order. The company anticipates that additional costs for this rehabilitation will be incurred, but cannot estimate such costs at this time.

Although the company cannot estimate the cost to investigate and remediate the remaining two sites, it does not expect that such costs will have a material adverse effect on its results of operations or financial position.

Item 4.  Submission of matters to a vote of security holders - Not applicable

* * * * * * * * * * * *

The company has entered into employment agreements with Wesley W. von Schack and Kenneth M. Jasinski each for a term ending April 22, 2003, and the company and NYSEG have entered into an employment agreement with Michael I. German for a term ending February 28, 2003. Mr. von Schack's agreement provides for his employment as Chairman, President and Chief Executive Officer of the company, Mr. Jasinski's agreement provides for his employment as Executive Vice President and General Counsel of the company and Mr. German's agreement provides for his employment as Senior Vice President of the company and President and Chief Operating Officer of NYSEG. Each agreement provides for automatic one-year extensions unless either party to an agreement gives notice that such agreement is not to be extended.

Each officer holds office for the term for which he is elected or appointed, and until his successor shall be elected and shall qualify. The term of office for each officer extends to and expires at the meeting of the Board of Directors following the next annual meeting of shareholders.

Item 5.  Market for Registrant's common equity and related stockholder matters

See Item 8 - Note 16 to the Consolidated Financial Statements.

Item 6.  Selected financial data

All per share and shares outstanding amounts have been restated to reflect the two-for-one common stock split effective April 1, 1999.

Reclassifications: Certain amounts included in Selected financial data have been reclassified to conform with the 1999 presentation.

(1)  Includes the effect of the extraordinary loss related to the early extinguishment of debt that decreased net income by $18 million and earnings per share by 15 cents and the nonrecurring benefit from the sale of the company's coal-fired generation assets net of the writeoff of Nine Mile Point 2 that increased net income by $14 million and earnings per share by 12 cents.

(2)  Depreciation and amortization includes accelerated amortization of Nine Mile Point 2 related to the sale of the company's coal-fired generation assets, authorized by the PSC. (See Item 8 - Note 7 to the Consolidated Financial Statements.)

(3)  Includes the effect of fees related to an unsolicited tender offer that decreased net income by $17 million and earnings per share by 12 cents.

(4)  Includes the effect of the writedown of the investment in EnerSoft Corporation that decreased net income by $10 million and earnings per share by 7 cents.

Item 7.  Management's discussion and analysis of financial condition and results of operations

The company has implemented a series of strategies to profitably grow its energy infrastructure in the Northeast. During 1999 the company successfully completed the sale of its coal-fired generation assets, announced merger agreements with four energy companies in the Northeast and entered into an agreement to sell its 18% interest in Nine Mile Point 2. The company completed its merger with Connecticut Energy Corporation (CNE) on February 8, 2000.

The company's major focus remains on promoting competition, providing superior customer service, offering an array of competitive products and services, profitably growing its energy infrastructure and building shareholder value.

Three of the definitive merger agreements entered into by the company on the following dates during 1999 are still pending: CMP Group, Inc. on June 14, CTG Resources, Inc. on June 29 and Berkshire Energy Resources (Berkshire Energy) on November 9. Each of the companies will become a wholly-owned subsidiary of the company. The transactions will be accounted for using the purchase method and are expected to close by the end of the second quarter of 2000. In connection with the mergers the company intends to register as a holding company with the Securities and Exchange Commission (SEC) under the Public Utility Holding Company Act of 1935.

Connecticut Energy Merger: The company completed its merger with CNE on February 8, 2000. The transaction had an equity market value of $433 million. Under the agreement 50% of the common stock of CNE (5.2 million shares) was converted into 9.4 million shares of Energy East common stock, and 50% of the common stock of CNE was exchanged for $218 million in cash, which was $42.00 per CNE share. The company assumed approximately $149 million of CNE long-term debt.

CMP Group Merger: The company will acquire all of the common stock of CMP Group for $29.50 per share in cash. The transaction has an equity market value of approximately $957 million. The company will also assume approximately $113 million of CMP Group preferred stock and long-term debt.

On October 7, 1999, CMP Group shareholders approved the merger agreement. Orders approving the merger were issued by the Maine Public Utilities Commission on January 4, 2000, and the Nuclear Regulatory Commission on February 4, 2000. The merger is subject to, among other things, the approvals of various regulatory agencies, including the SEC and Federal Energy Regulatory Commission (FERC). All necessary filings have been made.

CTG Resources Merger: This transaction values CTG Resources' common equity at approximately $355 million, and the company will assume approximately $220 million of CTG Resources' long-term debt.

Under the agreement, 45% of the common stock of CTG Resources will be converted into the company's common stock with a value of $41.00 per CTG Resources share, and 55% will be converted into $41.00 in cash per CTG Resources share, subject to restrictions on the minimum and maximum number of shares to be issued. Shareholders will be able to specify the percentage of the consideration they wish to receive in stock and in cash, subject to proration.

On October 18, 1999, CTG Resources shareholders approved the merger agreement. The Connecticut Department of Public Utility Control (DPUC) issued an order approving the merger on January 19, 2000. The merger is subject to, among other things, the approvals of various regulatory agencies, including the SEC. All necessary filings have been made.

Berkshire Energy Resources Merger: The company will acquire all of the common stock of Berkshire Energy for $38.00 per share in cash. The transaction has an equity market value of approximately $96 million. The company will also assume approximately $40 million of Berkshire Energy preferred stock and long-term debt. On February 29, 2000, Berkshire Energy shareholders approved the merger agreement. The merger is subject to, among other things, SEC approval. All necessary filings have been made.

The company's energy delivery business consists of its electricity distribution, transmission and generation operations and its natural gas distribution, transportation and storage operations in New York. After completing its merger with CNE in February 2000, the company began distributing natural gas in Connecticut.

Sale of Coal-fired Generation Assets: The company accepted offers totaling $1.85 billion from The AES Corporation and Edison Mission Energy in August 1998 for its seven coal-fired stations and associated assets and liabilities, which were placed up for auction earlier in 1998. The company completed the sale of its Homer City generation assets to Edison Mission Energy in March 1999, and the sale of its remaining coal-fired generation assets to AES in May 1999.

The proceeds from the sale of those assets - net of taxes and transaction costs - in excess of the net book value of the generation assets, less funded deferred taxes, were used to write down the company's 18% investment in Nine Mile Point 2 by $374 million. This treatment is in accordance with the company's restructuring plan approved by the Public Service Commission of the State of New York (PSC) in January 1998. The company wrote down its 18% investment by an additional $102 million due to the required writeoff of funded deferred taxes related to Nine Mile Point 2. Both writedowns are reflected in depreciation and amortization for 1999.

Now that the sale of its coal-fired generation assets is complete, approximately 60% of the company's power requirements are satisfied through generation from its nuclear and hydroelectric stations and by purchases under long-term contracts from non-utility generators (NUGs) and the New York Power Authority. At year-end the company had electricity contracts for calendar year 2000 for half of its remaining power requirements. For the remainder, the company assumed the risk of market prices that fluctuate, since it has capped the prices it can charge customers.

The company uses electricity contracts, both physical and financial, to manage its exposure to fluctuations in the market price of electricity. These contracts allow the company to fix the cost of physical electricity purchases. The cost or benefit of electricity contracts is included in the amount expensed for electricity purchased when the electricity is sold.

Nine Mile Point 2: The company announced in June 1999 that it has agreed to sell its 18% interest in Nine Mile Point 2 to AmerGen Energy Company, a joint venture of PECO Energy Company and British Energy. In the same announcement, Niagara Mohawk Power Corporation announced the sale of Nine Mile Point 1 and its 41% interest in Nine Mile Point 2 to AmerGen. At closing, the company will receive $27.9 million in proceeds, subject to adjustments, based on its 18% ownership share. The company may be entitled to additional payments through 2012 under a financial sharing agreement. A power purchase agreement with AmerGen requires the company to purchase 17.1% of all electricity from Nine Mile Point 2 at negotiated prices for three years.

AmerGen will assume full responsibility for the decommissioning of its ownership share of Nine Mile Point 2. The decommissioning fund will be pre-funded to a fixed amount by the sellers, with all potential costs above the fixed amount paid by AmerGen.

In December 1999 Rochester Gas and Electric Corporation (RG&E), a Nine Mile Point 2 cotenant, exercised its right of first refusal in connection with the sale of the plants, and stated that it would match AmerGen's offer and accept the terms and conditions of the AmerGen agreements. RG&E has contracted with a subsidiary of Entergy Corporation to lease, operate and maintain the plants. The PSC began settlement negotiations in January 2000 seeking modifications to the proposed terms of the sale of the company's and Niagara Mohawk's interests in the Nine Mile Point units, whether to AmerGen or RG&E. The company cannot predict the effect of this event on the sale of Nine Mile Point 2.

Issues have been raised regarding worsening performance at the Nine Mile Point units, which are operated by Niagara Mohawk. On September 30, 1999, the Nuclear Regulatory Commission issued a Plant Performance Review on the Nine Mile Point units. The NRC stated that it would increase its scrutiny of the operation of the Nine Mile Point nuclear units over the next six months as a result of the worsening performance of those units and weaknesses in areas such as plant maintenance, work planning and scheduling and engineering support.

Niagara Mohawk has made significant management changes at Nine Mile Point, including the hiring of PECO Energy for managerial advice, because performance of the units has not reached expected levels. The company supports these efforts to improve performance at Nine Mile Point 2 and continues to believe that the sale of the plants is in the best interests of customers and the company's shareholders.

If the operating performance of Nine Mile Point 2 continues to deteriorate and it becomes apparent that significant expenditures would be required to improve performance, the company intends to take whatever actions it believes are appropriate to protect the interests of its customers and shareholders, including support for the potential shut down of the unit.

Based on its agreement to sell Nine Mile Point 2 to AmerGen the company wrote off $82 million, its remaining nuclear generation investment after the writedowns discussed earlier, in accordance with Statement of Financial Accounting Standards No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of. (See Sale of Coal-fired Generation Assets.)

New York Independent System Operator: The New York Independent System Operator (ISO) began operating on November 18, 1999. The ISO and the New York State Reliability Council were formed to restructure the New York Power Pool in response to FERC Order 888. FERC Orders 888 and 889 were issued to foster the development of competitive wholesale electricity markets by opening up transmission services and to address the resulting stranded costs. The ISO administers a new, centralized energy and ancillary services market. The company is unable to predict the effect of the restructuring on its financial position or results of operations.

Electric Retail Access Program: Since August 1, 1999, all of the company's electricity customers have been able to choose their electricity supplier. Already approximately 31,000 customers have chosen another supplier, a strong indication of the company's commitment to promote competition.

The company is responsible for delivering customers' electricity on its transmission and distribution system. Rates charged for use of the company's transmission system are subject to FERC approval, while rates for the use of its distribution system are subject to PSC approval. The PSC approved the company's distribution rates in January 1998. The company's transmission rate case, which was filed with the FERC in March 1997, has not yet been approved. The company charges its filed rate, which was accepted by the FERC subject to refund based on the FERC final order.

Competitive Electric Metering: On June 16, 1999, the PSC issued an Order Providing for Competitive Metering, which calls for opening up competition for electric metering services among a limited number of large customers (50 kilowatts or more) in New York State. The services include installation and maintenance of electric meters, meter reading and meter data retrieval and storage. The PSC has delayed the effective date of the tariffs filed by the company to April 1, 2000. The company does not anticipate that this order will have a material effect on its financial position or results of operations.

NUG Initiatives: The company continues to seek ways to provide relief to its customers from onerous NUG contracts that the company was ordered to sign by the PSC. The company expensed approximately $354 million in 1999 for NUG power, and estimates that its purchases will total $349 million in 2000, $359 million in 2001 and $387 million in 2002, unless it is able to change the NUG contracts.

Petition to the FERC on NUGs: The company petitioned the FERC in 1995, asking for relief from having to pay approximately $2 billion more than its avoided costs for power purchased over the term of two NUG contracts. The FERC denied that petition and the company's subsequent request for a rehearing. The company believes that the overpayments under the two contracts violate the Public Utility Regulatory Policies Act of 1978.

The company commenced an action in the United States District Court for the Northern District of New York in August 1997. The complaint asks the District Court to either reform the two NUG contracts by reducing the price the company must pay for electricity under the contracts, or send the matter back to the FERC or to the PSC with direction that they modify such contracts. The complaint also seeks repayment of all monies paid above the company's avoided costs. The case is still pending before the District Court.

Auction of NUG Contract Rights: On November 4, 1999, the company announced that it intends to sell - through competitive bidding - entitlements to 470 mw of natural gas-fired energy, capacity and certain other benefits under three of its power purchase agreements with NUGs.

The contracts are with Saranac Power Partners (240 mw) in Plattsburgh, New York, Lockport Energy Associates (175 mw) in Lockport, New York, and Indeck Energy Services of Silver Springs, New York (55 mw). The agreements expire on June 21, 2009, October 8, 2007, and April 11, 2006, respectively. Over the remaining terms of the contracts it is estimated that the company's customers will pay over $2 billion dollars above the competitive market price. After receiving final bids in February 2000 the company determined that the bids were not acceptable and canceled the auction process without selling any entitlements.

Allegheny Hydros: On December 18, 1999, the company sent a letter to Allegheny Hydro No. 8 and Allegheny Hydro No. 9 demanding that they each provide adequate assurance that they will perform their individual contractual obligations under two power purchase agreements with the company, including the obligation to pay back overpayments made by the company over the course of the agreements. Such overpayments are the cumulative difference between the rate the company pays for power under the agreements and the company's actual avoided costs. At the end of 1999, this cumulative overpayment was more than $111 million and is expected to grow to approximately $2.7 billion by 2030 when both agreements expire.

In a letter dated January 17, 2000, Allegheny responded to the company's demand letter and argued against the company's right to demand assurances. On January 18, 2000, Allegheny filed a complaint in the United States District Court for the Southern District of New York (Southern District Court) asking for declaratory relief, including a declaration that the company is not entitled to demand adequate assurances of Allegheny's performance under the agreements. Allegheny's deadline for providing adequate assurances expired on January 19, 2000. In a letter dated January 20, 2000, the company notified Allegheny's lenders that Allegheny's failure to provide adequate assurances amounted to a repudiation of the agreements and advised that the company would terminate the agreements at the end of 15 days after the lenders received the notice dated January 20, 2000.

On February 3, 2000, the company entered into a letter agreement with Allegheny and its lenders, under which the parties agreed to jointly petition for an expedited trial on the merits, in exchange for the company's agreement to suspend its right to terminate the power purchase agreements. If a trial does not begin, or is not scheduled to begin, on or before December 31, 2000, the company will have the ability to reinstate its right to terminate. Consistent with the February 3, 2000 agreement, Allegheny filed a complaint in the Supreme Court of the State of New York, County of New York (New York Supreme Court) on February 7, 2000, seeking declaratory relief, including a declaration that the company is not entitled to demand adequate assurances of Allegheny's performance under the agreements, and on February 8, 2000, Allegheny filed a Notice of Dismissal of its complaint in the Southern District Court.

On March 3, 2000, Allegheny's lenders filed a complaint in the New York Supreme Court seeking declaratory relief and damages in an unspecified amount, including a declaration that the company's actions in demanding assurances are in violation of the agreements, certain financing agreements and the Public Utility Regulatory Policies Act of 1978. Pursuant to the February 3, 2000 agreement, Allegheny, the company and the lenders must use their best reasonable efforts to consolidate the lenders' action with Allegheny's suit.

Electric Restructuring Plan: The company's restructuring plan, which included a five-year electric rate price cap, was approved by the PSC, with minor modifications, in January 1998.

The restructuring plan will save customers an estimated $725 million over five years. Specifically the plan:

• Eliminated a 7% increase in electricity prices previously approved by the PSC.
• Reduces prices 5% each year in the five years of the plan for eligible industrial, commercial and public authority customers who are heavy users of electricity.
• Caps the overall average prices for all other customers for four years and reduces their prices 5% at the beginning of the fifth year.
• Allowed all of the company's retail customers to choose their electricity supplier by August 1, 1999.

The company submitted a tariff filing in compliance with the restructuring plan in January 1999. On July 15, 1999, and September 17, 1999, the PSC issued orders relating to the compliance filing. Those orders addressed issues related to the company's retail access credit (the amount backed out of a customer's bill when that customer participates in retail access), suppliers' obligations and customer identification.

As a result of the orders, the company's retail access credit was maintained at its current value. The PSC determined that retail access suppliers are responsible for energy, capacity and some ancillary services for their own customers and the company may require a deposit from residential customer applicants who fail to provide adequate identification. The PSC also concluded that costs for line losses, installed reserves and certain ancillary services are being recovered through the company's delivery charge and are not part of the retail access credit. The company submitted filings in compliance with the orders on July 29, 1999, and October 7, 1999.

In September 1999 the company reached settlement on the remaining issues in the restructuring plan. The settlement established the electric rate structure for the remaining three years of the price cap period. In February 2000 the PSC approved the September settlement. Tariffs in compliance with the PSC's order approving the settlement were filed and became effective March 3, 2000.

Natural Gas Franchises: The company continues to grow its natural gas business in New York by expanding natural gas service in existing franchise areas and by pursuing new franchises. During the last five years, the company added 26 new franchises to its natural gas service area.

Natural Gas Rate Agreements: The company's natural gas rate agreement filed with the PSC cut prices for most customers by reducing natural gas revenues by $25.6 million, or 2.1%, over the four years ending September 30, 2002. The PSC issued an order in December 1998 that includes certain modifications made by the PSC, which were accepted by the company after clarifications from the PSC Staff, and one modification by the company that maintains present rates for certain areas. The PSC accepted the company's clarifications and modification.

On January 28, 2000, the Connecticut DPUC issued a final decision approving a $502,000 annual revenue increase and denying a request to implement performance-based ratemaking at this time. The additional revenue amounts to approximately a 0.2% increase over current rates for firm sales customers. In February 2000 the company requested reconsideration of the DPUC's denial of the performance-based ratemaking proposal. The DPUC denied the company's request for reconsideration and informed it that it will consider the company's performance-based ratemaking proposal when the DPUC establishes rate design in connection with the company's latest rate proceeding. The rate design phase will not commence until a final decision is issued in the generic cost of service proceeding currently pending before the DPUC. The decision in the cost of service proceeding is expected to be issued in June 2000. The DPUC initiated the generic cost of service proceeding in 1999 to review cost of service methodologies in an effort to promote a more competitive and equitable natural gas industry within Connecticut.

Role of Natural Gas Local Distribution Companies: The PSC, on November 3, 1998, issued a "Policy Statement Concerning the Future of the Natural Gas Industry in New York State and Order Terminating Capacity Assignment." The policy statement includes the PSC's vision for furthering competition in the natural gas industry in New York State. The PSC believes the most effective way to establish a competitive gas market is for natural gas utilities to exit the merchant function over a period of three to seven years. The PSC also established guidelines and began several proceedings related to implementing its policy statement. The company is participating in each of the proceedings and continues to believe the competitive marketplace should decide who will be the suppliers of natural gas.

In compliance with the PSC's Order, effective April 1, 1999, the company ceased assigning certain capacity costs to customers who switch from fully bundled sales service to transportation service. Any capacity costs that may be stranded as a result of terminating capacity assignment are being recovered from all applicable customers via a surcharge.

Natural Gas Commodity Prices: The company uses risk management techniques such as natural gas futures and options contracts to manage its exposure to fluctuations in natural gas commodity prices. Such contracts allow the company to fix margins on sales of natural gas generally expected to occur over the next 18 months. The cost or benefit of natural gas futures and options contracts is included in the commodity cost when the related sales commitments are fulfilled. Gains and losses resulting from the use of those contracts for 1999, 1998 and 1997 were not material to the company's financial position or results of operations.

Statement 71: Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain Types of Regulation, allows companies that meet certain criteria to capitalize as regulatory assets incurred costs that are probable of recovery in future periods. Those companies record as regulatory liabilities obligations to refund previously collected revenue or obligations to spend revenue collected from customers on future costs.

Although the company believes it will continue to meet the criteria of Statement 71 for its regulated electricity and natural gas operations in New York State and Connecticut, the company cannot predict what effect a competitive market or future PSC or Connecticut DPUC actions will have on its ability to continue to do so. If the company can no longer meet the criteria of Statement 71 for all or a separable part of its regulated operations, it may have to record as expense or revenue certain regulatory assets and liabilities. The company may also have to record as a loss an estimated $1.4 billion, on a present value basis at December 31, 1999, of above-market costs on its power purchase contracts with NUGs. These items are currently recovered in rates.

Statement 133: The FASB issued Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities, in June 1998 and No. 137, Accounting for Derivative Instruments and Hedging Activities - Deferral of the Effective Date of FASB Statement No. 133, in June 1999. Statement 133 establishes standards for the accounting and reporting for derivative instruments and for hedging activities. Statement 133 requires that all derivatives be recognized as either assets or liabilities on a company's balance sheet at their fair value. Statement 137 delayed for one year the effective date for implementing Statement 133, to fiscal years beginning after June 15, 2000. The company will adopt Statement 133 as of January 1, 2001. Based on the company's current risk management strategies, this adoption is not expected to have a material effect on its financial position or results of operations.

Many of the company's computer systems, which include mainframe systems and special-purpose systems, refer to years in terms of their final two digits only. Such systems, if not corrected, may interpret the year 2000 as the year 1900 and could cause the company to, among other things, experience energy delivery problems, report inaccurate data or issue inaccurate bills.

The company worked diligently to address this problem by reviewing its mainframe and special-purpose systems; identifying potentially affected software, hardware, and date-sensitive components, often referred to as embedded chips, of various equipment; determining and taking appropriate corrective action; and, when appropriate, testing its systems.

The company's mainframe systems consist of the hardware and software components of NYSEG's and CNE's information technology systems. The company believes it identified, took appropriate corrective action and tested its mainframe systems and that those systems are now able to process year 2000 and beyond transactions.

The company's special-purpose systems consist of its non-information technology systems and the information technology systems of its subsidiaries other than NYSEG and CNE. The company identified items in its special-purpose systems that may have been affected by the Year 2000 problem. Items identified include software, hardware and embedded chips in systems such as those that control the acquisition and the delivery of electricity and natural gas to customers and those in its communication systems. The company believes it fixed, eliminated, replaced or found no problem with all of the special-purpose items it identified that affect its electricity and natural gas delivery systems and its communication systems.

Even though the company's computer systems did not experience problems on January 1, 2000, and February 29, 2000, and the company believes it has taken corrective action with respect to its own Year 2000 issues, the Year 2000 issue could adversely affect it if there are items in its computer systems that may be affected by the Year 2000 problem, that were not identified in its review of those systems and that have not been put into application to date.

Through December 31, 1999, the company spent approximately $12.4 million on Year 2000 readiness, including contingency plan preparations, and believes that amount was adequate to address its Year 2000 issues. The amount was expensed as incurred and was financed entirely with internally generated funds. Addressing the Year 2000 issue has not caused the company to delay any significant information system projects.

The company's financial strength provides the flexibility required to compete in the emerging competitive energy market and continue expanding its products and services, including its energy infrastructure, in the Northeast.

Investing Activities: The company sold its seven coal-fired generating stations and associated assets and liabilities for $1.85 billion. (See Energy Delivery Business - Sale of Coal-Fired Generation Assets.)

Capital spending, including nuclear fuel, totaled $83 million in 1999, $137 million in 1998 and $130 million in 1997. Capital spending in all three years was financed entirely with internally generated funds and was primarily for the extension of energy delivery service, necessary improvements to existing facilities and compliance with environmental requirements.

Capital spending, including nuclear fuel but excluding the pending merger transactions, is projected to be $126 million in 2000. It is expected to be paid for entirely with internally generated funds and will be primarily for the same purposes described above.

Financing Activities: The company's financing-related activities during 1999 consisted of:

• The redemption, at par, of $25 million of NYSEG's 7.40% Series preferred stock and
  $50 million of NYSEG's adjustable rate preferred stock.
• The purchase, at a discount, of the following amounts of these series of NYSEG's preferred stock: $7.2 million of 3.75%, $2.8 million of 4 1/2% (Series 1949), $1.4 million
  of 4.15%, $4.8 million of 4.40%, and $3.1 million of 4.15% (Series 1954).
• The redemption, at a premium, of $25 million of NYSEG's 6.30% Series preferred stock.
• The redemption, at a premium, of $50 million of NYSEG's 7 5/8% Series first mortgage bonds due November 1, 2001.
• The purchase, on the open market, at premiums, of $77 million of NYSEG's
  9 7/8% Series first mortgage bonds due May 1, 2020 and $77 million of NYSEG's
  9 7/8% Series first mortgage bonds due November 1, 2020. Those purchases were financed with the issuance of $163 million of unsecured notes, which were redeemed in January 2000 with cash and commercial paper. The company incurred a $27 million charge in the fourth quarter of 1999, including premiums of $9 million for early redemption and the writeoff of $18 million of unamortized debt expense and debt issuance costs, as a result of the purchase of the bonds. That amount is reflected as an extraordinary loss on early extinguishment of debt on the income statement.
• The repurchase of 16.6 million shares of the company's common stock.

The company raised its common stock dividend in January 2000 to a new annual rate of 88 cents per share. The dividend had been raised to an annual rate of 84 cents per share in January 1999.

A two-for-one stock split on common stock outstanding was effective April 1, 1999.

On April 1, 1999, the holders of a majority of the votes of shares of NYSEG's serial preferred stock consented to increase the amount of unsecured debt NYSEG may issue by up to an additional $1.2 billion.

The company uses short-term, unsecured notes to finance certain refundings and for other corporate purposes. The company had $163 million of short-term debt outstanding at December 31, 1999, and $78 million outstanding at December 31, 1998, all of which was issued by NYSEG. The weighted average interest rate on short-term debt was 7.2% at December 31, 1999, and 6.2% at December 31, 1998.

NYSEG also has a revolving credit agreement with certain banks that provides for borrowing up to $200 million until December 31, 2001. There were no amounts outstanding under this agreement during 1999 or 1998.

CNE and The Southern Connecticut Gas Company (Southern) have credit lines with certain banks that renew annually and provide for borrowing up to $70 million. Southern has committed lines of $50 million until the end of June 2000, and CNE and Southern share a committed line of $20 million until December 29, 2000. There was $40 million outstanding under these lines at December 31, 1999.

Southern expects to file an application with the DPUC in the second quarter of 2000 requesting authorization to issue up to $200 million of secured medium-term notes. The proceeds from the debt issuance will be used to pay down short-term debt incurred to redeem, at a premium, $77 million of first mortgage bonds, and for other general corporate purposes. This redemption is due to a provision in Southern's bond purchase agreements that gave the bondholders the right to have the bonds redeemed as a result of Energy East's acquisition of CNE.

The company uses interest rate swap agreements to manage the risk of increases in variable interest rates. It records amounts paid and received under the agreements as adjustments to the interest expense of the specific debt issues.

The company expects to issue long-term debt prior to the completion of the CMP Group, CTG Resources and Berkshire Energy merger transactions. The proceeds from the debt issuance, along with the proceeds from the sale of its generation assets and internally generated funds, will be used to fund the cash portion of the consideration for the merger transactions and to fund the company's ongoing share repurchase program. (See Merger Agreements and Energy Delivery Business - Sale of Coal-Fired Generation Assets.) In anticipation of this debt issuance, in June 1999 the company entered into a $500 million, one-year interest rate hedge on the benchmark 30-year Treasury Bond.

This Form 10-K contains certain forward-looking statements that are based upon management's current expectations and information that is currently available. The Private Securities Litigation Reform Act of 1995 provides a safe harbor for forward-looking statements in certain circumstances. Whenever used in this report, the words "estimate," "expect," "believe," or similar expressions are intended to identify such forward-looking statements.

In addition to the assumptions and other factors referred to specifically in connection with such statements, factors that could cause actual results to differ materially from those contemplated in any forward-looking statements include, among others, unanticipated Year 2000 issues, the deregulation and unbundling of energy services; the company's ability to compete in the rapidly changing and increasingly competitive electricity and natural gas utility markets; its ability to control non-utility generator and other costs; changes in fuel supply or cost and the success of its strategies to satisfy its power requirements now that all of its coal-fired generation assets have been sold; its ability to expand its products and services, including its energy infrastructure in the Northeast; its ability to integrate the operations of CNE, CMP Group, CTG Resources and Berkshire Energy with its operations; market risk; the ability to obtain adequate and timely rate relief; nuclear or environmental incidents; legal or administrative proceedings; changes in the cost or availability of capital; growth in the areas in which it is doing business; weather variations affecting customer energy usage; and other considerations that may be disclosed from time to time in its publicly disseminated documents and filings. The company undertakes no obligation to publicly update any forward-looking statements, whether as a result of new information, future events or otherwise.

*Percent change is not meaningful.

All per share and shares outstanding amounts have been restated to reflect the two-for-one common stock split effective
April 1, 1999.

Earnings Per Share

In 1999 the company's earnings per share increased 37 cents, including 15 cents from the extraordinary loss related to the early extinguishment of debt and a nonrecurring benefit of 12 cents from the sale of the company's coal-fired generation assets net of the writeoff of Nine Mile Point 2.

Earnings per share for 1999 increased primarily due to investment income realized on the net proceeds from the sale of the generation assets, fewer shares outstanding as a result of the share repurchase program, higher transmission wheeling revenues, higher pension income, cost control efforts and higher retail electricity deliveries (a record high for the company) and natural gas deliveries caused by an improved economy and weather. Those increases were partially offset by lower wholesale electricity deliveries as a result of the sale of the company's coal-fired generation plants and lower retail prices.

The company's earnings per share increased in 1998 primarily due to higher wholesale electricity prices and deliveries, higher pension income, cost control efforts and fewer shares outstanding as a result of the share repurchase program. Those increases were partially offset by lower retail natural gas deliveries, primarily because of unusually warm winter weather, and lower retail electricity prices. The 1997 earnings per share include the effect of a nonrecurring charge of 12 cents per share.

Other income and deductions increased in 1999 primarily due to interest income realized on the net proceeds from the sale of the generation assets.

Preferred stock dividends decreased in 1999 due to redemptions and repurchases of preferred stock.

Operating Revenues: Operating revenues for 1999 decreased $246 million primarily due to lower wholesale electricity deliveries because, without its coal-fired generation plants, the company had less power to sell. Lower retail electricity and natural gas prices also reduced revenues. Those decreases were partially offset by higher transmission wheeling revenues and higher retail electricity and natural gas deliveries caused by an improved economy and weather.

The 1998 operating revenues increased $336 million. Revenues increased due to higher wholesale electricity and natural gas deliveries and higher wholesale electricity prices. Those increases were partially offset by lower natural gas retail deliveries, primarily due to warmer weather, and lower retail electricity prices.

Operating Expenses: Operating expenses for 1999 decreased $220 million, excluding the nonrecurring benefit from the sale of the company's coal-fired generation assets, which includes the related accelerated amortization of Nine Mile Point 2, net of the writeoff of Nine Mile Point 2. That decrease was primarily due to lower fuel and other costs associated with the generation assets that were sold, higher pension income and cost control efforts. Those decreases were partially offset by increased purchases of electricity to meet retail customers' needs.

The 1998 operating expenses increased $292 million due to an increase in electricity purchased for wholesale deliveries, partially offset by a decrease in other operating and maintenance costs, primarily due to higher pension income, cost control efforts and the effect of a 1997 nonrecurring charge, and a decrease in the cost of natural gas purchased.

Item 7A.  Quantitative and qualitative disclosures about market risk

Market risk represents the risk of changes in value of a financial instrument, derivative or non-derivative, caused by fluctuations in interest rates and prices. The following discussion of the company's risk management activities includes " forward-looking" statements that involve risks and uncertainties. Actual results could differ materially from those contemplated in the "forward-looking" statements. The company handles market risks in accordance with established policies, which may include various derivative transactions.

The financial instruments held or issued by the company are for purposes other than trading or speculation. Quantitative and qualitative disclosures are discussed by the following market risk exposure categories:

• Interest Rate Risk
• Commodity Price Risk
• Other Market Risk

Interest Rate Risk: The company is exposed to risk resulting from interest rate changes on its variable-rate debt and commercial paper. The company uses interest rate swap agreements to manage the risk of increases in certain variable rate issues. It records amounts paid and received under those agreements as adjustments to the interest expense of the specific debt issues. The company believes that there is no material market risk associated with these agreements. (See Item 8 - Notes 4 and 10 to the Consolidated Financial Statements.)

In June 1999 the company entered into a $500 million, one-year interest rate hedge on the benchmark 30-year Treasury Bond in anticipation of the expected issuance of long-term debt related to its pending mergers. The interest rate associated with this Bond is 6.302%. Based on current interest rates, the company believes that this market risk is not material.

Proceeds from the sale of the coal-fired generating assets have been invested in money market and short duration, high-quality fixed income securities with outside investment managers. While the value of these investments is affected by changes in interest rates, the company believes that, because of their short duration, the market risk associated with these securities is not material.

Commodity Price Risk: NYSEG is exposed to the effect of market fluctuations in the price of natural gas and electricity purchased. The company manages this risk by the use of forward purchases, futures, contracts for differences (CFDs) and options.

The company uses natural gas futures and options contracts to manage its exposure to fluctuations in natural gas commodity prices. Such contracts allow the company to fix margins on sales of natural gas generally expected to occur over the next 18 months. The cost or benefit of natural gas futures and options contracts is included in the commodity cost when the related sales commitments are fulfilled. The difference between cost and fair value of natural gas futures and options contracts outstanding is not material to the company's results of operations.

Exposure to fluctuations in the spot price of natural gas is also reduced by natural gas in storage. During times of high natural gas spot prices the company may draw on its stored natural gas inventory.

The company uses electricity contracts to manage its exposure to fluctuations in the cost of electricity. These contracts allow the company to fix margins on the majority of its retail electricity sales. The cost or benefit of electricity contracts is included in the amount expensed for electricity purchased when the electricity is sold. With the implementation of the ISO the company began utilizing CFDs. CFDs, which are financial contracts with features similar to commodity swap agreements, effectively fix the price the company pays for certain power purchased from the ISO. At December 31, 1999, the company's CFDs had a notional amount of 2.7 million megawatt-hours (mwh) for power purchases in 2000 at an average price of $23.81 per mwh. The company believes that the difference between cost and fair value of the CFDs is not material to its results of operations.

The company is also exposed to daily price fluctuations in the spot price of electricity. In situations where the electricity contracts do not cover peak demand, the company must buy electricity in the spot market. Conversely, when the company has contracts for more electricity than its demand, it must sell the excess in the spot market. The company uses a cash flow at risk (CFAR) calculation to measure this price risk. At year end, the CFAR for electricity requirements was $12.2 million for the next 12-month period. The CFAR indicates the amount by which the fair value of the company's net position could vary from its current level over a 12-month period, with a 97.5% certainty, assuming all unhedged positions during that period are filled in the spot market.

Other Market Risk: The company maintains a qualified trust fund, as required by the Nuclear Regulatory Commission, to fund certain costs of nuclear decommissioning. The funds in the qualified trust are invested in money market instruments. The company believes that the market risk exposure is limited to immaterial fluctuations in the money markets. (See Item 8 - Note 8 to the Consolidated Financial Statements.)

The company's pension plan assets are made up of equity and fixed income investments. Fluctuations in those markets could cause the company to recognize increased or decreased pension income or expense.

Item 8.  Financial statements and supplementary data
(All per share and shares outstanding amounts have been restated to reflect the two-for-one common stock split effective April 1, 1999.)

Energy East Corporation
Consolidated Statements of Income

The notes on pages 34 through 50 are an integral part of the financial statements.

Energy East Corporation
Consolidated Balance Sheets

The notes on pages 34 through 50 are an integral part of the financial statements.

Energy East Corporation
Consolidated Balance Sheets

The notes on pages 34 through 50 are an integral part of the financial statements.

Energy East Corporation
Consolidated Statements of Cash Flows

The notes on pages 34 through 50 are an integral part of the financial statements.

Energy East Corporation
Consolidated Statements of Changes in Common Stock Equity

(Thousands, except per share amounts)

Principles of consolidation: These financial statements consolidate the company's majority-owned subsidiaries after eliminating intercompany transactions.

Depreciation and amortization: The company determines depreciation expense using straight-line rates, based on the average service lives of groups of depreciable property in service. The company's depreciation accruals were equivalent to 3.4% of average depreciable property for 1999 and 1998 and 3.5% for 1997. Amortization expense includes the amortization of certain regulatory assets and the accelerated amortization of Nine Mile Point 2 authorized by the PSC. (See Note 7. Sale of Coal-fired Generation Assets.)

Revenue recognition: The company recognizes revenues upon delivery of energy and energy-related products and services to its customers.

Accounts receivable: The company has an agreement that expires in November 2002 to sell, with limited recourse, undivided percentage interests in certain of its accounts receivable from customers. The agreement allows the company to receive up to $152 million from the sale of such interests.

At December 31, 1999 and 1998, accounts receivable on the consolidated balance sheets are shown net of $152 million of interests in accounts receivable sold. All fees related to the sale of accounts receivable are included in other income and deductions on the consolidated statements of income and amounted to approximately $9 million in 1999, 1998 and 1997. Accounts receivable on the consolidated balance sheets are also shown net of an allowance for doubtful accounts of $7 million at December 31, 1999, and $9 million at December 31, 1998. Bad debt expense was $12 million in 1999, $18 million in 1998 and $17 million in 1997.

Temporary investments: The company has temporary investments in various securities, including cash equivalents and debt instruments, that are classified as available-for-sale. The temporary investments have various maturity dates ranging from less than 30 days through August 2005. There were unrealized losses on the temporary investments, net of taxes, of $1 million at December 31, 1999. The investments will be used to fund the company's pending mergers and its ongoing share repurchase program.

Income taxes: The company files a consolidated federal income tax return. Deferred income taxes reflect the effect of temporary differences between the amount of assets and liabilities recognized for financial reporting purposes and the amount recognized for tax purposes. Investment tax credits (ITC) are amortized over the estimated lives of the related assets.

Utility plant: The company charges repairs and minor replacements to operating expense accounts and capitalizes renewals and betterments, including certain indirect costs. The original cost of utility plant retired or otherwise disposed of and the cost of removal less salvage are charged to accumulated depreciation.

Regulatory assets and liabilities: Pursuant to Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain Types of Regulation, the company capitalizes, as regulatory assets, incurred costs that are probable of recovery in future electric and natural gas rates. It also records, as regulatory liabilities, obligations to refund previously collected revenue or to spend revenue collected from customers on future costs. In accordance with its current rate agreements in New York State, the company no longer defers most costs that were previously subject to deferral accounting.

Unfunded future federal income taxes and deferred income taxes are amortized as the related temporary differences reverse. Unamortized loss on debt reacquisitions is amortized over the lives of the related debt issues. Demand-side management program costs, other regulatory assets and other regulatory liabilities are amortized over various periods in accordance with the company's current New York State rate agreements. The company earns a return on all regulatory assets for which funds have been spent.

Consolidated statements of cash flows: The company considers all highly liquid investments with a maturity date of three months or less when acquired to be cash equivalents. Those investments are included in cash and cash equivalents on the consolidated balance sheets.

Total income taxes paid were $647 million in 1999, $97 million in 1998 and $111 million in 1997.

Interest paid, net of amounts capitalized, was $123 million in 1999, $119 million in 1998 and $117 million in 1997.

Risk management: The company uses natural gas futures and options contracts to manage its exposure to fluctuations in natural gas commodity prices. Such contracts allow the company to fix margins on sales of natural gas generally expected to occur over the next 18 months. The cost or benefit of natural gas futures and options contracts is included in the commodity cost when the related sales commitments are fulfilled.

The company uses electricity contracts, both physical and financial, to manage its exposure to fluctuations in the market price of electricity. These contracts allow the company to fix the cost of physical electricity purchases. The cost or benefit of electricity contracts is included in the amount expensed for electricity purchased when the electricity is sold.

The company uses interest rate swap agreements to manage the risk of increases in variable interest rates. It records amounts paid and received under the agreements as adjustments to the interest expense of the specific debt issues.

In June 1999 the company entered into a $500 million, one-year interest rate hedge on the benchmark 30-year Treasury Bond in anticipation of its expected issuance of long-term debt related to its pending mergers.

Gains and losses resulting from the use of risk management techniques in 1999 and 1998 were not material to the company's financial position or results of operations. The company does not hold or issue financial instruments for trading or speculative purposes.

Estimates: Preparation of the consolidated financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Reclassifications: Certain amounts have been reclassified on the consolidated financial statements to conform with the 1999 presentation.

Note 2. Common Stock Split

In January 1999 the company declared a two-for-one stock split on common stock outstanding. Shareholders of record at the close of business on March 12, 1999, were entitled to the shares on April 1, 1999. All per share amounts and shares outstanding in the consolidated financial statements have been restated to reflect the stock split.

The company's effective tax rate differed from the statutory rate of 35% due to the following:

The increase in depreciation not normalized and ITC amortization are the result of the sale of coal-fired generation assets and the writeoff of Nine Mile Point 2. (See Note 7. Sale of Coal-fired Generation Assets and Note 8. Nuclear Generation Assets.)

The company's deferred tax liabilities consisted of the following:

All of the company's consolidated long-term debt at December 31, 1999 and 1998, was issued by its subsidiaries.

At December 31, 1999, long-term debt and capital lease payments (in thousands) that will become due during the next five years are:

(1) NYSEG's first mortgage bond indenture constitutes a direct first mortgage lien on substantially all of its utility plant. The mortgage also provides for a sinking and improvement fund. This provision requires the company to make an annual cash deposit with the Trustee equal to 1% of the principal amount of all bonds delivered and authenticated by the Trustee before January 1 of that year (excluding any bonds issued on the basis of the retirement of bonds). Pursuant to the terms of the mortgage, the company satisfied the requirement in 1999 by crediting "bondable value of property additions" against the amount of cash to be deposited. The company redeemed, in June 1999, $50 million of 7 5/8% Series first mortgage bonds, due November 1, 2001, and purchased, in November 1999, $77 million of 9 7/8% Series first mortgage bonds, due May 1, 2020, and $77 million of 9 7/8% Series first mortgage bonds, due November 1, 2020. Those transactions resulted in an after-tax extraordinary loss on early extinguishment of debt of $18 million, or 15 cents per share.

(2) Fixed-rate pollution control notes totaling $306 million were issued to secure the same amount of tax-exempt pollution control revenue bonds issued by a governmental authority. The interest rates range from 5.70% to 6.15%.

Adjustable-rate pollution control notes totaling $132 million were issued to secure the same amount of tax-exempt adjustable-rate pollution control revenue bonds (Adjustable-rate Revenue Bonds) issued by a governmental authority. The Adjustable-rate Revenue Bonds bear interest at rates ranging from 4.01% to 4.38% through dates preceding various annual interest rate adjustment dates. On the annual interest rate adjustment dates the interest rates will be adjusted, or at the company's option, subject to certain conditions, a fixed rate of interest may become effective. Bond owners may elect, subject to certain conditions, to have their Adjustable-rate Revenue Bonds purchased by the Trustee. The company has entered into interest rate swaps to manage the risk of increases in the interest rates on the Adjustable-rate Revenue Bonds, and such swaps are reflected in the above interest rates.

Multi-mode pollution control notes totaling $175 million were issued to secure the same amount of tax-exempt multi-mode pollution control refunding revenue bonds (Multi-mode Revenue Bonds) issued by a governmental authority. The Multi-mode Revenue Bonds have a structure that allows the interest rates to be based on a daily rate, a weekly rate, a commercial paper rate, an auction rate, a term rate or a fixed rate. Bond owners may elect, while the Multi-mode Revenue Bonds bear interest at a daily or weekly rate, to have their bonds purchased by the Registrar and Paying Agent. The maturity dates of the Multi-mode Revenue Bonds are February 1, 2029, June 1, 2029, and October 1, 2029, and can be extended subject to certain conditions. At December 31, 1999, the interest rate for the multi-mode pollution control notes was at the daily rate. The weighted average interest rate for all three series was 3.15%, excluding letter of credit fees, for the year ended December 31, 1999.

NYSEG has irrevocable letters of credit that support certain payments required to be made on the Adjustable-rate Revenue Bonds and Multi-mode Revenue Bonds, and that expire on various dates. If the company is unable to extend the letter of credit related to a particular series of Adjustable-rate Revenue Bonds, that series will have to be redeemed unless a fixed rate of interest becomes effective. Multi-mode Revenue Bonds are subject to mandatory purchase when there is any change in the interest rate mode and in certain other circumstances. Payments made under the letters of credit in connection with purchases of Adjustable-rate Revenue Bonds and Multi-mode Revenue Bonds are repaid with the proceeds from the remarketing of those Bonds. To the extent the proceeds are not enough, the company is required to reimburse the bank that issued the letter of credit.

At December 31, 1999 and 1998, NYSEG's serial cumulative preferred stock was:

(1) At December 31, 1999, there were 2,353,411 shares of $100 par value preferred stock, 10,800,000 shares of $25 par value preferred stock and 1,000,000 shares of $100 par value preference stock authorized but unissued.

(2) On April 1, 1999, the company purchased, at a discount, the following amounts of these series of preferred stock: $7.2 million of 3.75%, $2.8 million of 4 1/2% (Series 1949), $1.4 million of 4.15%, $4.8 million of 4.40%, and $3.1 million of 4.15% (Series 1954).

(3) Redeemed February 1, 1999.

(4) Redeemed December 10, 1999.

The company uses short-term, unsecured notes to finance certain refundings and for other corporate purposes. The weighted average interest rate on short-term debt, all of which belonged to NYSEG, was 7.2% at December 31, 1999, and 6.2% at December 31, 1998.

NYSEG has a revolving credit agreement with certain banks that provides for borrowing up to $200 million through December 31, 2001. The revolving credit agreement does not require compensating balances. The company had no outstanding loans under this agreement at December 31, 1999 or 1998. At the company's option, the interest rate on borrowings is related to the prime rate, the London Interbank Offered Rate or the interest rate applicable to certain certificates of deposit. The agreement provides for payment of a commitment fee, which was .125% at December 31, 1999 and 1998.

The company accepted offers totaling $1.85 billion from The AES Corporation and Edison Mission Energy in August 1998 for its seven coal-fired stations and associated assets and liabilities, which were placed up for auction earlier in 1998. The company completed the sale of its Homer City generation assets to Edison Mission Energy in March 1999, and the sale of its remaining coal-fired generation assets to AES in May 1999.

The proceeds from the sale of those assets - net of taxes and transaction costs - in excess of the net book value of the generation assets, less funded deferred taxes, were used to write down the company's 18% investment in Nine Mile Point 2 by $374 million. This treatment is in accordance with the company's restructuring plan approved by the PSC in January 1998. The company wrote down its investment by an additional $102 million due to the required writeoff of funded deferred taxes related to Nine Mile Point 2. These writedowns are reflected in depreciation and amortization on the 1999 consolidated statement of income. (See Note 8. Nuclear Generation Assets.)

The company has an 18% interest in the output and costs of Nine Mile Point 2, which is operated by Niagara Mohawk Power Corporation. Ownership of Nine Mile Point 2 is shared with Niagara Mohawk 41%, Long Island Power Authority 18%, Rochester Gas and Electric Corporation (RG&E) 14% and Central Hudson Gas & Electric Corporation 9%. The company's 18% share of the rated capability is 210 mw. The company's share of operating expenses is included in various categories on the consolidated statements of income.

The company announced in June 1999 that it has agreed to sell its 18% interest in Nine Mile Point 2 to AmerGen Energy Company, a joint venture of PECO Energy Company and British Energy. In the same announcement, Niagara Mohawk announced the sale of its interest in Nine Mile Point 2 to AmerGen. At closing, the company will receive $27.9 million in proceeds, subject to adjustments, based on its 18% ownership share. The company may be entitled to additional payments through 2012 under a financial sharing agreement. A power purchase agreement with AmerGen requires the company to purchase 17.1% of all electricity from Nine Mile Point 2 at negotiated prices for three years.

AmerGen will assume full responsibility for the decommissioning of its ownership share of Nine Mile Point 2. The decommissioning fund will be pre-funded to a fixed amount by the sellers, with all potential costs above the fixed amount paid by AmerGen.

In December 1999 RG&E, a Nine Mile Point 2 cotenant, exercised its right of first refusal in connection with the sale of the plants, and stated that it would match AmerGen's offer and accept the terms and conditions of the AmerGen agreements. RG&E has contracted with a subsidiary of Entergy Corporation to lease, operate and maintain the plants. The PSC began settlement negotiations in January 2000 seeking modifications to the proposed terms of the sale of the company's and Niagara Mohawk's interests in the Nine Mile Point units, whether to AmerGen or RG&E. The company cannot predict the effect of this event on the sale of Nine Mile Point 2.

Based on its agreement to sell Nine Mile Point 2 to AmerGen the company wrote off $82 million, its remaining nuclear generation investment after the writedowns discussed in Note 7, in accordance with Statement of Financial Accounting Standards No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of. (See Note 7. Sale of Coal-fired Generation Assets.)

Nuclear insurance: Niagara Mohawk maintains public liability and property insurance for Nine Mile Point 2. The company reimburses Niagara Mohawk for its 18% share of those costs.

The public liability limit for a nuclear incident is approximately $8.9 billion. Should losses stemming from a nuclear incident exceed the commercially available public liability insurance, each licensee of a nuclear facility would be liable for up to $84 million per incident, payable at a rate not to exceed $10 million per year. The company's maximum liability for its 18% interest in Nine Mile Point 2 would be approximately $15 million per incident. The $84 million assessment is subject to periodic inflation indexing and a 5% surcharge should funds prove insufficient to pay claims associated with a nuclear incident. The Price-Anderson Act also requires indemnification for precautionary evacuations whether or not a nuclear incident actually occurs.

Niagara Mohawk has obtained property insurance for Nine Mile Point 2 totaling approximately $2.8 billion through the Nuclear Insurance Pools and Nuclear Electric Insurance Limited (NEIL). In addition, the company has purchased NEIL insurance coverage for the extra expense that would be incurred by purchasing replacement power during prolonged accidental outages. Under NEIL programs, should losses resulting from an incident at a member facility exceed the accumulated reserves of NEIL, each member, including the company, would be liable for its share of the deficiency. The company's maximum liability per incident under the property damage and replacement power coverage is approximately $2 million.

Nuclear plant decommissioning costs: Based on the results of a 1995 decommissioning study, the company's 18% share of the cost to decommission Nine Mile Point 2 is $167 million in 2000 dollars ($422 million in 2026 when Nine Mile Point 2's operating license will expire). The estimated liability for decommissioning Nine Mile Point 2 using the Nuclear Regulatory Commission's minimum funding requirement is approximately $102 million in 2000 dollars. The company's electric rates in New York State currently include an annual allowance for decommissioning of $4 million, which approximates the minimum funding requirement as set forth in the 1995 decommissioning study. Decommissioning costs are charged to depreciation and amortization expense and are recovered over the expected life of the plant.

The company has established a Qualified Fund under applicable provisions of the federal tax law to comply with NRC funding regulations. The balance in the fund, including reinvested earnings, was approximately $27 million at December 31, 1999, and $21 million at December 31, 1998. Those amounts are included on the consolidated balance sheets in other property and investments, net. The related liability for decommissioning is included in other liabilities - other. The investments are recorded at market value and changes in market value are reflected in the decommissioning liability. At December 31, 1999, the external trust fund investments were classified as available-for-sale.

From time to time environmental laws, regulations and compliance programs may require changes in the company's operations and facilities and may increase the cost of electric and natural gas service.

The U.S. Environmental Protection Agency and the New York State Department of Environmental Conservation (NYSDEC), as appropriate, notified the company that it is among the potentially responsible parties who may be liable for costs incurred to remediate certain hazardous substances at nine waste sites, not including its sites where gas was manufactured in the past, which are discussed below. With respect to the nine sites, seven sites are included in the New York State Registry of Inactive Hazardous Waste Sites and three of the sites are also included on the National Priorities list.

Any liability may be joint and several for certain of those sites. The company recorded an estimated liability of $1 million related to five of the nine sites. The ultimate cost to remediate the sites may be significantly more than the estimated amount. Factors affecting the estimated remediation amount include the remedial action plan selected, the extent of site contamination and the portion attributed to the company.

The company has a program to investigate and perform necessary remediation at its sites where gas was manufactured in the past. In 1994 and 1996, the company entered into Orders on Consent with the NYSDEC. These Orders require the company to investigate and, where necessary, remediate 34 of its 38 sites. Eight sites are included in the New York State Registry.

The company's estimate for all costs related to investigation and remediation of the 38 sites ranges from $77 million to $175 million at December 31, 1999. That estimate is based on both known and potential site conditions and multiple remediation alternatives for each of the sites. The estimate has not been discounted and is based on costs in 1996 dollars that the company expects to incur through the year 2017. The estimate could change materially based on facts and circumstances derived from site investigations, changes in required remedial action, changes in technology relating to remedial alternatives and changes to current laws and regulations.

The liability to investigate and perform remediation, as necessary, at the known inactive gas manufacturing sites, reflected on the company's consolidated balance sheets was $77 million at December 31, 1999, and $79 million at December 31, 1998. The company recorded a corresponding regulatory asset, net of insurance recoveries, since it expects to recover the net costs in rates.

The carrying amounts and estimated fair values of some of the company's financial instruments included on its consolidated balance sheets are shown in the following table. The fair values are based on the quoted market prices for the same or similar issues of the same remaining maturities.

The carrying amounts for cash and cash equivalents, temporary investments, notes payable and interest accrued approximate their estimated fair values.

Special deposits may include restricted funds set aside for preferred stock and long-term debt redemptions. The carrying amount approximates fair value because the special deposits have been invested in securities that mature within one year.