(Mark one)
 X  ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
    ACT OF 1934
For the fiscal year ended December 31, 1999

OR

    TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
    ACT OF 1934
For the transition period from             to              

Commission file number 1-3103-2

Registrant's telephone number, including area code (607) 347-4131

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

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

Title of Class

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.

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 number of shares of common stock (par value $6.66 2/3 per share) outstanding as of March 15, 2000, was 64,508,477. All shares are owned by Energy East Corporation.

PART I

PART II

TABLE OF CONTENTS (Cont'd)

PART III

PART IV

(a)  General development of business

New York State Electric & Gas Corporation was organized under the laws of the State of New York in 1852.

In May 1998 the company was reorganized into a holding company structure pursuant to an Agreement and Plan of Share Exchange with Energy East Corporation. Each outstanding share of the company's common stock was exchanged for one share of Energy East's common stock and Energy East became the company's parent.

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

(See Item 7 - Electric Business, Sale of Affiliate's Coal-fired Generation Assets, Nine Mile Point 2 and Item 8 - Notes 2 and 3 to the Financial Statements.)

Regulatory and Rate Matters
(See Item 7 - Electric Business and Natural Gas Business.)

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

(c)  Narrative description of business
    (See Item 7 - Electric Business and Natural Gas Business.)

The company's principal business is purchasing, transmitting and distributing electricity and purchasing, transporting and distributing natural gas. The company also generates electricity from its nuclear and hydroelectric stations. The company's service territory, 99% of which is located outside the corporate limits of cities, is in the central, eastern and western parts of the State of New York. This service territory has an area of approximately 19,900 square miles and a population of 2,500,000. The larger cities in New York in which the company serves both electricity and natural gas are Binghamton, Elmira, Auburn, Geneva, Ithaca and Lockport. The company provides delivery service to approximately 825,000 electricity customers and 246,000 natural gas customers. The service territory reflects a diversified economy, 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. During 1997 through 1999 approximately 84% of operating revenue was derived from electricity deliveries with the balance derived from natural gas deliveries.

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.

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

After an affiliate completed 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 - Natural Gas 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 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. The company expects to purchase its natural gas supply for 2000 in a similar proportion as was purchased in 1999. The company uses natural gas futures and options contracts to manage its exposure to fluctuations in natural gas commodity prices.

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.

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.

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

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.

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 an affiliate'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 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.

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.

The company had 3,161 employees as of February 29, 2000.

(d)  Financial information about geographic areas  Not applicable

Item 2.  Properties
(See Item 7 - Electric Business, Sale of Affiliate's Coal-fired Generation Assets 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 owns 430 substations 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 natural gas system consists 74 miles of transmission pipeline and 7,056 miles of distribution pipeline.

The company's first mortgage bond indenture constitutes a direct first mortgage lien on substantially all of its properties.

Item 3.  Legal proceedings

Information regarding legal proceedings is set forth in Exhibit
99-3, which is incorporated herein by reference. Also, see Item 7 - Electric Business and Natural Gas Business.

Item 4.  Submission of matters to a vote of security holders

Not applicable

* * * * * * * * *

The company and Energy East have entered into an employment agreement with Michael I. German that provides for his employment as President and Chief Operating Officer of the company and Senior Vice President of Energy East for a term ending on February 28, 2003. The agreement provides for automatic one-year extensions unless either party to the 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

Energy East owns all of the company's common stock. Information regarding dividends declared is on page 25 of this report.

Item 6.  Selected financial data

(1) Includes the effect of the extraordinary loss related to the early extinguishment of debt that decreased net income by $18 million and the writeoff of Nine Mile Point 2 net of the nonrecurring benefit from the sale of an affiliate's coal-fired generation assets that decreased net income by $5 million.
(2) Depreciation and amortization includes accelerated amortization of Nine Mile Point 2 related to the sale of an affiliate's coal-fired generation assets, authorized by the PSC. (See Item 8 - Note 2 to the Financial Statements.)
(3) Includes the effect of fees related to an unsolicited tender offer that decreased net income by $17 million.
(4) Includes the effect of the writedown of the investment in EnerSoft Corporation that decreased net income by $10 million.

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

Earnings for 1999 increased primarily due to higher pension income, cost control efforts, higher retail electricity deliveries (a record high for the company) and natural gas deliveries caused by an improved economy and weather, and higher transmission wheeling revenues. Those increases were partially offset by lower retail prices and higher electricity purchased power costs, after excluding the extraordinary loss related to the early extinguishment of debt and the writeoff of Nine Mile Point 2 net of the nonrecurring benefit from the sale of an affiliate's coal-fired generation assets and the effect of transferring wholesale electricity activity to an affiliate due to the reorganization into a holding company structure in May 1998.

After excluding the transfer of NGE Generation and XENERGY Enterprises to the company's parent as part of the reorganization into a holding company structure on May 1, 1998, earnings increased in 1998 primarily due to higher wholesale electricity prices and deliveries, higher pension income and cost control efforts. 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 include the effect of a nonrecurring charge of $17 million.

Operating revenues for 1999 increased due to higher retail electricity deliveries caused by an improved economy and weather and higher transmission wheeling revenues, partially offset by lower retail electricity prices, after excluding the effects of transferring wholesale activity to an affiliate in May 1998. Operating expenses for 1999 increased primarily due to higher purchased power costs, partially offset by higher pension income and cost control efforts, after excluding the writeoff of Nine Mile Point 2 net of the nonrecurring benefit from the sale of an affiliate's coal-fired generation assets, which includes the related accelerated amortization of Nine Mile Point 2, and the effect of transferring wholesale activity to an affiliate in May 1998.

Excluding the effect of the transfer of NGE Generation and XENERGY Enterprises to the company's parent as part of the reorganization into a holding company structure on May 1, 1998, 1998 operating revenues increased due to higher wholesale prices and deliveries, partially offset by lower retail prices. 1998 operating expenses increased due to an increase in electricity purchased primarily for wholesale deliveries, partially offset by a decrease in operations and maintenance costs primarily due to higher pension income and cost control efforts and the effect of a 1997 nonrecurring charge.

Operating revenues for 1999 increased due to higher retail sales, primarily due to colder weather. There was no change in operating expenses for 1999. An increase in natural gas purchased, due to higher volume partially offset by lower prices, was offset by cost control efforts.

1998 operating revenues were reduced by lower retail deliveries, primarily due to warmer weather, partially offset by an increase in wholesale deliveries. Operating expenses for 1998 decreased due to a decrease in the cost of natural gas purchased and a decrease in other operating costs due to the effect of a 1997 nonrecurring charge.

The company's principal electric business is transmitting and distributing electricity. It also generates electricity from its nuclear and hydroelectric stations.

Sale of Affiliate's Coal-fired Generation Assets: Offers totaling $1.85 billion were accepted from The AES Corporation and Edison Mission Energy in August 1998 for an affiliate's seven coal-fired stations and associated assets and liabilities, which were placed up for auction earlier in 1998. The affiliate 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 Affiliate's 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 Federal Energy Regulatory Commission (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.

The company's natural gas business delivers, transports and stores natural gas in New York State.

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 Agreement: 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.

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, the company cannot predict what effect a competitive market or future PSC 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 its 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. The company identified approximately 5,000 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 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 mainframe or special-purpose 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.

Investing Activities: An affiliate of the company sold its seven coal-fired generating stations and associated assets and liabilities for $1.85 billion. (See Electric Business - Sale of Affiliate's Coal-Fired Generation Assets.)

Capital spending, including nuclear fuel, totaled $69 million in 1999, $127 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, is projected to be $80 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 7.40% Series preferred stock and $50 million of adjustable rate preferred stock.
• The purchase, at a discount, of 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).
• The redemption, at a premium, of $25 million of 6.30% Series preferred stock.
• The redemption, at a premium, of $50 million of 7 5/8% Series first mortgage bonds due November 1, 2001.
• The purchase, on the open market, at premiums, of $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 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.

On April 1, 1999, the holders of a majority of the votes of shares of the company's serial preferred stock consented to increase the amount of unsecured debt the company 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. The weighted average interest rate on short-term debt was 7.2% at December 31, 1999, and 6.2% at December 31, 1998.

The company 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.

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.

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 affiliate's coal-fired generation assets have been sold; 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.

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 rates changes on its variable-rate pollution control notes and commercial paper. The company uses interest rate swap agreements to manage the risk of increases in certain variable-rate pollution control note 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 7 to the Financial Statements.)

Commodity Price Risk: The company 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 3 to the 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

New York State Electric & Gas Corporation
Statements of Income

New York State Electric & Gas Corporation
Balance Sheets

New York State Electric & Gas Corporation
Balance Sheets

New York State Electric & Gas Corporation
Statements of Cash Flows

New York State Electric & Gas Corporation
Statements of Changes in Common Stock Equity

(Thousands)

The company's financial statements exclude NGE Generation, Inc. and XENERGY Enterprises, Inc. as of May 1, 1998, the effective date of the reorganization into a holding company structure, and exclude Somerset Railroad as of July 31, 1998, the effective date of its transfer to NGE Generation.

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 2. Sale of Affiliate's 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 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 statements of income and amounted to approximately $9 million in 1999, 1998 and 1997. Accounts receivable on the balance sheets are also shown net of an allowance for doubtful accounts of $6 million at December 31, 1999 and 1998. Bad debt expense was $12 million in 1999, $15 million in 1998 and $17 million in 1997.

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.

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 balance sheet.

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 $118 million in 1999, $118 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 cost 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.

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 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 financial statements to conform with the 1999 presentation.

Offers totaling $1.85 billion were accepted from The AES Corporation and Edison Mission Energy in August 1998 for an affiliate's seven coal-fired stations and associated assets and liabilities, which were placed up for auction earlier in 1998. The affiliate 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 statement of income. (See Note 3. 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 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 2, 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 2. Sale of Affiliate's Coal-fired Generation Assets.)

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.

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 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.

At December 31, 1999 and 1998, the company's long-term debt was:

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

(1) The company'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.

(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.

The company 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.

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 was 7.2% at December 31, 1999, and 6.2% at December 31, 1998.

The company 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.

At December 31, 1999 and 1998, the company'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 carrying amounts and estimated fair values of some of the company's financial instruments included on its 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, notes payable and interest accrued approximate their estimated fair values because they mature within one year.

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.

Selected financial information for the company's two business segments is presented in the following table. The electric business segment consists of electricity distribution, transmission and generation operations. The natural gas business segment consists of natural gas distribution, transportation and storage operations. "Other" includes subsidiary activity through April 30, 1998, and corporate assets.

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 an affiliate's coal-fired generation assets and the writeoff of Nine Mile Point 2. (See Note 2. Sale of Affiliate's Coal-fired Generation Assets and Note 3. Nuclear Generation Assets.)

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