ML20210R844

1998 Annual Rept for Energy East

ML20210R844
Person / Time
Site:	Nine Mile Point
Issue date:	12/31/1998
From:	Von Schack W NEW YORK STATE ELECTRIC & GAS CORP.
To:
Shared Package
ML17059C735	List: ML20210R810 ML20210R844
References
NUDOCS 9908170233
Download: ML20210R844 (49)

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3 l ENERGY EAST CORPORATE PROFILE 4 t. NYSEG NGE Generatsen Energy East Entergerises: s. ~ 'w y s. ..J.

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Letter to SharehoMers ./ D3_ nerg Eas~: s

DearSharehokler:

1998 was a major transitional year for your company. It was a crucial dividing line between ehat was and what %; l>e. Ve ue movirig tiom a serucahy inte;; rated upstate New bd. unlity to a growing energy distnbution and services company in the Northeast. We are now better positioned to grow and meet the challenges of an emerging competitive market. And we are committed to achieving -best in l class' operations and continued growth in value for you, our shareholders. During 1998 we took maior steps in refocusing our bustness on energy distribution. First, and most important, we accepted offers i Earnings Per Share t, above book value for the sale of our coal-fired generation assets. san l Generation has been a corneistone of NYSEG for our entire exis-f 1 tence. 'Ihis was a very difTicult decision to make, but we felt we

1. 57 had to take this step if we were going to refocus your company.

E 37 i j With this decision, we will no longer face the risk and uncertainty ,s of stranded generation costs. We will use the proceeds to continue to buy back common stock and to focus on new opportunities. a t We are considered progressive and a leader in the deregulation i of the industrv. We capped electricity and natural gas prices in upstate New York through 2002 and are operaung without the ] fuel cost protection that most other utilities base. Since we will no longer have base load generation, we must now secure j / energy in the sometimes volatile open market. Our natural gas I customers have benefited from a competitive market for several o years and all of our electric customers will be able to choose J their supplier this coming summer. s v i

The steps we have taken and the strategies we have cho3en, combined with our proven ability to adapt to the changin;; energy market, are intended to create a more efficient and more market driven company. Managing change in an environment where our state regulators are unbundling and dismantling our traditional business in no predetermined order, yet tving held accountable to the rules and regulations of the past, is no small challenge for our employees. Our people continue to deliver superior customer service during this period of convulsive change and I thank them for their performance and support. Our customer complaint rate is the lowest among all of the electric and gas utilities and telephone companies in New York State. Customers are especially pleased with the reliability we provide and the results of the direct contacts they hase with us. The traditional side of our business will continue to concentrate on making yesterday's commi'.ments more effective as the transitional business focuses on new opportunities and becomes the business of tomorrow. The tension between ,p _.. the traditional and transitional businesses will remain with us for the future, but t I am confident that you can continue to count on us to deliver the value that } you and our customers expect. 3 Following the Annual Meeting of Shareholders in April 1999, Everett A. Gilmour and Alton G. Marshall will be retiring from the Board of Directors. Their con-tributions during their respective 19 and 28 years of dedicated service to our f company are deeply appreciated and I especially want to thank them for the guidance they have given me for the past two years. gj 1 kok forward to shanng with you further progress at Energy East. } } On behalf of the Board of Directors. t fA-b Wesley W. von Schatk Chairman, President and Chief Executise Officer February 9,1999 i } l l l

Amesw.8y New Mwe State is n. e.I ro,e t 1998 HIGHLIGHTS ,,,,,e /.,,,n, ay A au.t s tm u, ts,e untry an electriesty cue-The storus andphatas on thefullowmg pages wmara wm t,e able to choose their ofer a snapsbot tf the msnatnes Erwrgy East u taking to add to the tatue <(30ur smestment. ,,e,m, namer ar,aice ku Adding to the value of your invest-5; ment

• Our stock price increased 59% during the year while the S&P Utility Average, which com.

prises 39 electnc and natural gas utilities, increased 8% Earnings increased 18% over 1997. That is on top of an 8% increase in 1997. Our common stock dividend was raised in January 1999 to a new annual rate of $1.68. Also, the Board of Directors declared a two-for-one stock split on common ? stock outstanding. Shareholders of f record at the close of business , Q' on March 12,1999, will be enuded to the shares .4 on April 1,1999. [ ,) t . i' '/ Helping communities grow e [ Our economic development 4,' " professionals are at the forefront of bb-creatmg projects such as Axiohm's consohdation of its U.S. pnnting manufactunng operations in Ithaca and Scepter Corporation's aluminum recychng plant in Geneva. ] ~ ~. e.. p.ene . To help

• "'***";8'.*

Managing costs

• Working effi-tion, WWe are Wpen ciently and doing more with less piering the seie of are not new to us. Our costs are j

our s v,mt eoner. sting .es te rh* dechning and we expect that to AEs corporati*" conurt.e. We fund our capital and Edison Mission ts% stake in the P' V, Energy We are also Nine Mile Point nully generated funds. actinty pwousne nucioar mting the snoe at our unit No.1 i

l l l 1 o.ne, i a., J

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Euilding strong relationships with our custorners = i Relationships are about much more than responding l ,,,,,,,,4a,,,p /.h to questions about a customer's bill, hooking up a 2 1 der cueromer arv-new senice on time, or restoring power quickly after W

• • "'""*8*

J/ [*[,'f j,,, an interruption. They are also about helping cus-tomers use energy wisely. We teamed up with the compietars emong our cursomers re# City of Norwich, New York to design and install a en et ene es.erric un ch,r ., soing natural gas-powered engine to pump the city's water. mas anturat ens ma eno*'wr /a6 The result. fewer maintenance problems, reduced l "'"****"d* costs and a satisfied customer. Near Buffalo, our mar- ,,,'**#'",7 ,,,,,h ketmg, engineering r.nd construcuon people joined forces to install a new electric sesvice for a growing business. Our reputation 4r high quahty work and excellent sen-ice made our custo.;-e's decision to C look to us an easy one. /J O., fs. 4 &Y Building on our excellent reputation for service ob/ reliability

• Even the devastating ice storm that left k

30,000 of our customers without power in the Plattsburgh area last January and the tornadoes that ripped through threc areas in May were no match for our power restoration team. Customers applauded our efforts and the Pubhc Service Commission called our response to the ice storm ' outstanding

• Even so, we are stepping up our abihties. A new information system allows us to respond to power interruptions more quickly and more efficiently.

y l l \\ ,;thA$W4i4 i ~ g w e.2 w. x l ^ l Committing our energy to the communities we serve

• We have a long and proud tradition of financia!!y supporung community activities and educational programs.

Our people show a strong commitment to their communities by giving their time and energy to deserving organizations, including the American Cancer Society, the American Heart Association. L'nited Way, Rotary Clubs and dozens of community i senice organizations This strong etluc of giving back extends to all of our opera-tions and is reflected in our Adopt-a-}{ighway and Community Watch programs.

i 47' o_ .. rne mond empennen of one of our newest /' b =rusten een *t Linking communities vd1 fiber optics

• We are j

E building a fiber optic communications net-two pspn mm end l'h work linking Binghamton, Ithaca and wn,,,,ng, Syracuse in upstate New York in a joint

• • • • • • '**a**

venture with Telergy, a Syracuse, New Y rk-based firm. Internet access and w ty moren. we sentinw so 6e long distance telephone service pg o,,,,eme. o,,e o,,,e e., providers are potential users of the With our empension gmwing naturel pu into New Enalaad. sempsaies in the g network. This infrastructure will N******"d*"' help acact new businesse* to '""' 'u* t. the region. the b \\\\- \\ r+ k l lgh / p.n. - g v Delivering a new energy y j ('.' option in Maine

• Clean, g

efficient, economical natural gas will soon be at the 6 doorstep of homes and busi-j y neues in central and r.outhern i f Maine. Our joint venture with ] Central Maine Power will serve i most of the populated areas out-l side of the greater Ponland area. 3 Bringing natural gas to southern Vermont

• Te are planning a combined natural gas supply and electric generation project in southwestern Vermont with Iroquois Gas Transmission Sys-tem and Vermont Energy Park if

,I Holdings. The project includes an h-mu,y,,,,,,,,,,, extension of pipehne from New F - h H. p.e.ne.. and our song-re,m York to Vermont, two combined I-We h*w purch=d pim call for bnny. { cycle electric generating plants,

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and natural as distribution to 8 bution system in industrial, commercial and resi-Q gone, u,. dential customers. unmashi. we e,e encouraged

f Adapting to a cc:nsetitive marketplace

• Our success in a competitive enuronment has enabled us to reduce and cap e prices, with no fuel adjustment, through 2002 and deliver an me

'i reduction in natural gas pnces, with no gas adjustment fa j r. September 2002 In addition to taking costs out of the business w '.2 have sharpened our focus on performance excellence. ) (' / ) Helping businesses rnanage energy use

• We contin-ue to develop strong relatioru. hips with nationally known businesses to manage their energy use.

Among our new customers in 1998 was Pitney Bowes Inc. Our system helps Pitney Bowes manage omaae, among competitim August t.1sso. att 's/ and control its energy costs wtule gathering, consoli-r ev.e.=. sy suppliers er mom 812000 or ur elec-Q.,, dating and reponing energy use information. than u years, and o aince 1996 this option was made tricoty customers wdlbe able to evallable to smaller d( choose theirpoent customers through Q .y-supplier. Ourlargest an aggegation [ y, naturalgas cus-1

process, tomers hawe had the option of shopping

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~ vs.. we are provkling inde-g \\ l pendent energy agencies in consultmo services Califamia, to businesses and Massachusetts govemmental and Rhode Island, ~ the hrst states to y% 1 4 restructure their

ceeding in an evolving em~,;y matkat

• We are elecencity marsets.

ng for the business of consumers in the Northeast 'k j'g ' ,$,* [**,' o are already able to choose their electricity and j i n, ruult or ur y P o ural gas suppliers. In addition, we have joined ) Succas da two es with South Jerwy Energy to market energy '4** Put sus- -ices and electricity to end-use customers in the '*'",",'],"[*" ' Atlantic region. The alliance leverages South ,oyntry. ey Energy's market presence and customer rela-ship and our trading and retail sales expertise. ~ l 1

p-FINANCIAL HIGHLIGHTS 1 Per Common Share ~' 1997 % Change Common Stack Price at Year End $56.50 l $35 50 59 Eammgs $3.02 I. $2.57 18 Dmdends Paid $1.55 $140 11 Book Value at Year End $27.22 $26.71 2 Other Common Stock information Retum on Average Common Equity 11.2 % 98% 14 Average Common Shares Outstanding (Thousands) 64,371 68.153 (6) Common Shares Outstanding at Year End (Thousandst 62.947 67.508 (7) Operating Results (Thousands) Total Operstmg Revenues $2,499.418 $2.170.102 15 Total Ope ating Expenses $2,024,579 31,733.141 17 Net income $194,205 1175.211 11 Retail Delwenes lMegawatt-hours) 13277 13.238 Wholesale Delivenes (Megawatt hours) 22,711 l 10.406 118 Retail DeNenes (Dekatherms) 54.162 1 59.324 (91 ? Wholesale Deliveries (Dekatherms) 7,527 3.027 149 6 i l Total Assets at Year End (Thousands) $4.883.337 1 15 028.681 (3) l i Stock Performance i umaa i i i f I st '93 '94 '95 5 '91 '98 { M SbP EC an0an k total terum e 19!G segnshcantry m as@med tre S&PUtrher Avrage $gp mn wy at the $&P50g' ann This grap aswm's e $@ evesunent nas meJe y an DecemDer 31.1981anddreamus g were re neestett l 4

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Electric and natural gas utilities across the country continue to transform as competition evolves. To meet the challenges and seize the opportunities presented by competition, we, too, have changed. In April 1998 our shareholders ovenvhelmingly approved the formation of Energy East Corporation, our new holding company that became the parent of NYSEG. We are in the process of finalizing the sale of our coal-fired generation assets and are actively pursuing the sale of our 18% interest in Nine Mile Point nuclear generating unit No. 2. (See Sale of our Coal-fired Generation Assets below.lwe are also expanding our products and services, including our energy distribution system in the Nonheast. Liquidity and Capital Resources ELECTRIC BUSINESS E Our electric business consists of electric generation, transmission and distribution operations. (f Sale of our Coal-fired Generation Assets: We placed our seven coal-fired stations and associated assets and liabilities up for auction in 1998. We accepted offers totaling $1.85 billion from The AES Corporation and Edison Mission Energy in August 1998 for those generation assets. All proceeds, net of taxes and transaction costs, in excess of the net book value of the generation assets, less funded deferred taxes, will be used to write down our 18% investment in Nine Mile Point 2. This treatment is in accordance with our restructuring plan approved by the Public Senice Commission of the State of New York in January 1998. There are a number of items such as depre-ciation, book value of inventories, taxes and the exact date of the closing that will affect the finan- ) cial statements as we continue to precisely define the specific costs of the items included in the transactions. Any differences will affect the net proceeds. The net cash received from the sales will { be used to repurchase conunon stock and continue expanding our products and services, includ-( ing our energy distribution network in the Northeast. l< The PSC approved the sales in November 1998 and the Federal Energy Regulatory Commission [ approved the sales in January 1999. We expect the sales to close by the end of the first quarter of 1999. We are developing strategies to satisfy our remaining energy requirements in New York after a ? the coal-fired stations are sold. The power may be purchased at market prices that are different f l than the cost to generate the power from the coal-fired stations, which would increase or decrease our operating expenses. We expect to finalize these strategies before the stations are sold. We use electricity contracts to manage our exposure to fluctuations in the cost of electricity. Such contracts allow us to fix margins on the majority of our retail and wholesale sales of electricity. The cost or benefit of electricity contracts is included in the cost of electricity purchased when the electricity is sold. New York 1bwer fbo/ Restructuring: The Federal Energy Regulatory Commission issued Orders 888 and 889 in 1996 to foster the development of competitive wholesale electricity markets by opemng up transmission services and to address the resulting stranded costs. In subsequent orders, the i FERC generally affirmed Orders 888 and 889. Various parties, including us, have appealed these orders in the United States Coun of Appeals for the D.C. Circuit. j g, " J -

l 1 i[ In response to Order 888, the New York Power Pool submitted a compliance filing to the FERC. Power pool members submitted additional filings to the FERC in 1997 proposing the restructuring of the power pool by establishing a New York Independent System Operator, a Power Exchange and a New York State Reliability Council. The FERC conditionally authorized the formation of the system operator and reliability council in June 1998 and conditionally accepted the tariff and rates applicable to transmission service, and energy, capacity and ancillary services in January 1999 FERC also set certain issues for hearing and required additional filings to implement the restructur-ing proposal. Power pool members must file the necessary applications to transfer control of transmission facilities to the system operator. We are currently evaluating the FERC's conditional acceptance and are unable to predict its effect on our financial position or results of operations. Electric RetailAccess Program: Customers in cenain sections of our service territory were eligible to choose their electricity supplier in mid-1998. All of our electricity customers in New York wili be fh. able to choose their electricity supplier by August 1,1999. This is one of the most progressive ? retail access programs in the country. t Throughout the first phase and continuing after August 1,1999, we are responsible for delivery of our customers' electricity on our transmission and distribution system. Rates charged for the use of our tmnsmission system are subject to FERC approval, while rates for the use of our distribution system are subject to PSC approval. The PSC approved our distribution rates in January 1998. Our transmission rate case, which was filed with the FERC in March 1997, has not yet been approved. Ibtition to the FERC on NUGs We continue to seek ways to provide relief to our customers from 2 the onerous NUG contracts that we were ordered to sign by the PSC. NUG power purchases totaled $323 million in 1998, and we estimate that those purchases will total $358 million in 1999 j and $376 million in 2000 and in 2001, unless we are able to change those contracts. ej We petitioned the FERC in 1995, asking for relief from having to pay approximately $2 billion 4 more than our avoided costs for power purchased over the term of two NUG contracts. The FERC j denied that petition and our subsequent request for a rehearing. We believe that the overpayments under the two contracts violate the Public Utility Regulatory Policies Act of 1978. We petitioned the United States Court of Appeals for the District of Columbia in 1995 to review the I FERC's decision. The Court of Appeals issued a decision in July 1997 stating that it lacked jurisdic-tion to rule on our appeal but that we may pursue our claim in the United States District Court. We commenced an action in the United States District Coun for the Nonhern District of New York in August 1997. The complaint asks the District Coun to either reform the two NUG contracts by reducing the price we 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 repay. ment of all monies paid above our avoided costs. The case is still pending before the District Court. Electric Restructuring Plan: Our restructuring plan, which included a five-year electric rate price cap, was approved by the PSC, with minor modifications, in January 1998. It supersedes our previ-ous three-year electric rate agreement, which was to expire on July 31,1998. I r u

r 4 The restructuring plan will save customers an estimated $725 million over five years. Specifically the plan: eliminates 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; allows all of our retail customers to choose their electricity supplier by August 1,1999; and '1 includes a 12% return on equity cap and a 9% floor, exclusive of common stock repurchases, e d] during each of the five years of the price cap. NATURAL G AS BUSINESS Our natural gas business delivers, transports and stores natural gas in New York State. New Franchises: We are growing our natural gas business in New York by expanding natural gas service in existing franchise areas and by developing new franchises. We began developing eight new franchises during 1998. 4 Natural Gas Rate Agreement: We filed a natural gas rate agreement with the PSC in May 1998. l This agreement cuts prices for most customers by reducing natural gas revenues by $25.6 million, { or 2.1%, over the four-year period ending September 30, 2002. The PSC approved the agreement 3 in September 1998 after making certain modifications. After seeking clarification of the modifications from the PSC Staff, we accepted the PSC Order with the clarifications and one modification that e maintains present rates for cenain areas. The PSC accepted our clarifications and modification { and issued an order in December 1998. .1 Seneca Lake Natural Gas Storage Encility: Our Seneca Lake natural gas storage facility includes a natural gas storage cavern, a compressor station and a natural gas transmission pipeline. The 3 - 1 facility is located on Seneca Lake nonh of Watkins Glen and began operations in 1996. We built this facility to ensure an adequate natural gas supply to customers, to support economic growth I in southern and central New York and to increase supply flexibility. We expanded the facility in 1997 to increase the cavern's working capacity from 800 million to { 1.45 billion cubic feet of natural gas and the compressor station's deliverability from 80,000 to 145,000 dekatherms per day. This expansion allows for the sale of storage capacity. Role ofLocalDistr/lmtion Con'panies: 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 three to seven year period. The PSC also established guidelines and began several proceedings related to implementing its policy statement. We are participating in each of the proceedings and continue ,1 to believe the competitive marketplace should decide who will be the suppliers of natural gas. r. We have not yet determined what effect the PSC Policy Statement will have on us.

r The PSC's Order requires local distribution companies, effective April 1,1999, to cease assigning capacity costs to customers who switch from distribution service to transportation service. The local - distribution companies will be provided a reasonable opportunity to recover any capacity costs that may be stranded. We expect to recover all costs associated with our customers switching to trans-ponation service. Natural Gas Commodity Prices: We use risk management techniques such as natural gas futures and options contracts to manage our exposure to fluctuations in natural gas commodity prices. Such contracts allow us 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 1998,1997 and 1996 were not material to our financial position or _.-y results of operations. ig I OTHER OPERATIONS XENERGY Enterprises, Inc.

• We invest in providers of energy, telecommunications and financial services.

XENERGE We provide energy services, infornution systems and energy consulting to utilities, governmental agencies and end-use energy consumers, primarily commercial and industrial. 1 N Energy East Solutions: We market electricity and natural gas to end-use customers and wholesale S markets in the Northeast. In October 1998 Energy East Solutions formed a joint venture with South 4 Jersey Energy Company to market retM -lectricity and energy management services in the mid-Adantic region, Energy East Enterprises, Inc.

• We own natural gas and propane air distribution companies e

outside of New York State. 8 CMP Natural Gas LLC We signed an agreement with Central Maine Power Company in November 1997 to form a jointly-owned company to distribute natural gas in Maine and New Hampshire to M 3 customers who are not currently served. CMP Natural Gas has received approval from the Maine f Public Utilities Commission to provide service to 60 towns in Maine. CMP Natural Gas' plans have r been developed to coincide with the construction schedules of two natural gas pipelines from ' Canada. One pipeline began construction in mid-1998 and the other is expected to begin in early 1999. CMP Natural Gas expects initial service to customers in mid-1999. New Hampshire Gas Corporation: We established a presence in New Hampshire with our pur-chase of s franchise and propane air distribution system in Keene, New Hampshire. Our shon-term plans call for the continuation of the existing propane air distribution system. Long-term plans call for bringing natural gas to the Keene area. Southern Permont Natural Gas: We are working with hoquois Gas Transmission System and Vermont Energy Park Holdings to develop a combined natural gas supply and electric generation project. The proposal includes an extension of an Iroquois pipeline from New York to Vermont, two combined-cycle electric generating plants, and natural gas distribution to industrial, commercial and residential customers. Our role in the project will be to construct a natural gas pipeline from the new Iroquois pipeline to the electric generating plants and to build distribution systems to provide natural %.'i gas service to industrial, commercial and residential customers along the pipeline.

= , OTH E R M ATT E R S Accounting lasues

Statement 71: Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Cenain 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 we believe we will continue to meet the criteria of Statement 71 for our regulated electric and natural gas operations in New York State, we cannot predict what effect a competitive market or future PSC actions will have on our ability to continue to do so. If we can no longer meet the criteria of Statement 71 for all or a separable part of our regulated operations, we may have to j.Q record as expense or revenue cenain regulatory assets and liabilities. We may also have to record Q as a loss an estimated $1.5 billion, on a present value basis at December 31,1998, of above-market q costs on our power purchase contracts with NUGs. These items are currently recovered in rates. With approval of our restmeturing plan inJanuary 1998, we discontinued application of Statement 71 to our coal-fired generation operations and applied Statement of Financial Accounting Standards No.101, Regulated Enterprises-Accounting for the Discontinuance of Application of FASB s Statement No. 71. Application of Statement 101 did not affect our financial position or results of operations. (See Electric Business, Sale of our Coal-fired Generation Assets] g Statement 133: The FASB issued Statement of Financial Accounting Standards No.133, Accounting for Derivative Instruments and Hedging Activities, in June 1998. Statement 133 establishes standards 5 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 h at their fair market value. We plan to adopt Statement 133 as of the beginning of the first quarter . of 2000. Based on our current risk management strategies, this adoption is not expected to have j a material effect on our financial position or results of operations. g

g. '

+ . EITF96-10: In November 1998 the FASB's Emerging Issues Task Force reached a consensus on i M Issue Number 98-10, Accounting for Contracts Involved in Energy Trading and. Risk Management Activities. EITF 98-10 requires that energy trading activity be measured at fair value on the balance f sheet with gains and losses recognized in current earnings. Based on our current energy procure-ment strategies, the implementation of EITF 98-10 in 1999 is not expected to have a material effect o on our financial position or results of operations. Year 2000 Readiness Disclosure

• Many of our computer systems, which include mainframe j

systems and special-purpose systems, refer to years in terms of their final two digits only. Such j systems may interpret the year 2000 as the year 1900. If not corrected, those systems could cause us to, among other things, experience energy delivery problems, repon inaccurate data or issue inaccurate bills. .We are working diligently to address this problem by reviewing all of our 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 our systems. i

Our mainframe systems consist of the hardware and software components of NYSEG's information technology systems. We believe we have identified, taken appropriate corrective action and tested all of our mainframe systems. We believe those systems are now able to process year 2000 and i beyond transactions. Our special-purpose systems consist of our non-information technology systems and the informa-tion technology systems of our subsidiaries other than NYSEG. We have identified approximately 6,000 items in our special-purpose systems that may be affected by the Year 2000 problem. Items ' identified include software, hardware and embedded chips in systems such as timse that control the acquisition and the delivery of electricity and natural gas to customers and those in our com-munication systems. We believe we have fixed, eliminated, replaced or found no problem with = . over 90% of thi apeial-purpose items we have identified, including those in our electric and 2 natural gas delivery systems. We are determining and takmg appropriate corrective action for the q* remaining identified items. Additional items, however, continue to be identified as we proceed with the review of our special-purpose systems. We expect to have reviewed, identified and deter-1

mined and taken the appropriate corrective action on all of our special-purpose systems by the end of the second quaner of 1999 Even though we believe we will have taken corrective action with respect to our own Year 2000 issues, the Year 2000 issue could adversely affect us if there are items in our mainframe or special-purpose systems that may be affected by the Year 2000 problem and that we have not identified in our review of those systems. The Year 2000 issue could also adversely affect us if third parties such as suppliers, customers, neighboring or interconnected utilities and other entities fail to correct any of 6

their Year 2000 problems. We have contacted key third parties to determine the status of their Year g 2000 readiness programs. Many have responded satisfactorily, some have not responded satisfactorily p-and some have not responded at all. We are developing contingency plans, some of which are dis-cussed below, for reasonably likely worst case scenarios based upon an assumption that we and those third panies will not be Year 2000 compliant. Our Year 2000 program is progressing on schedule and we believe we are taking all necessary !M j steps to address this issue successfully. Through 1998 we have spent approximately $11.4 million .g and expect to spend an additional 50.8 million on Year 2000 readiness. We believe this amount is j adequate to address our Year 2000 issues. These amounts are being expensed as incurred and are being financed entirely with internally generated funds. Addressing the Year 2000 issue has not caused us to delay any significant information system projects. As part of our normal business practice we have plans in place for use during emergencies, some of which could arise from Year 2000 problems. We are completing contingency plans to specifically ~ address reasonably likely worst case scenarios that could arise as a result of the Year 2000 problem. The contingency plans will address, among other scenarios, the interruption or failure of normal business activities or operations such as a partial electrical and/or natural gas system shutdown. If the interruption or failure is.due to embedded chips in equipment such as automatic control devices, our contingency plan is to implement the normal system restoration procedures that we utilize during emergencies. If the interruption or failure is dus 'o telecommunications not being available, we plan to use alternative communication devices s wh as satellite phones. Another scerario is the failure of our customer information system. Should that occur, we plan to rely on S customer information previously stored and make the appropriate adjustment to each customer's next bill after the system is restored.

4 l Additionally, we are dependent on others for our supply of natural gas. In the event one of our suppliers is not able to meet our needs, we plan to purchase the needed amount of natural gas from one of our many other suppliers on the same transmission line. Since we expect to sell our-coal-fired generation stations by the end of the first quaner of 1999, we will be buying instead of producing the majority of the electricity our customers need by the beginning of the year 2000. If the electricity available in our region is not adequate for all of the customers on our system, I we plan to operate at lower levels of power as outlined in our established emergency procedures. [ Should our mainframe hardware be disabled, we have a backup mainframe system that is capable of operating all of our business systems. We expect to have all of our contingency plans ready and tested by mid-1999. The PSC issued an Order on October 30,1998, adopting a July 1,1990, deadline for New York $3 L utilities to complete their Year 2000 readiness programs for

• mission critical" systems and for con-C-{

~ tingency plans. Mission critical systems include those systems that control the acquisition and the delivery of electricity and natural gas to customers, emergency management systems and cenain electric generation plants. We believe that our Year 2000 readiness program for mission critical 1 systems and for contingency plans will be completed by the PSC's July 1,1999, deadline. The PSC Order requires the filing of status reports with the PSC regarding certain Year 2000 issues. We filed our first status report in December 1998 and plan to file our next status report prior to the July 1,1999, deadline. ( INVESTING AND FINANCING ACTIVITIES Investing Activities

• Capital spending, including nuclear fuel, totaled $137 million in 1998, 7

$130 million in 1997 and $216 million in 1996. Capital spending in those three years was financed entirely with internally generated funds and was primarily for the extension of service, necessary f improvements to existing facilities and compliance with environmental requirements. ? Capital spending, including nuclear fuel, is projected to be $140 million in 1999, $127 million in 2000 and $150 million in 2001, and is expected to be paid for entirely with internally generated funds. l M, l Financing Activities = Our current financial strength provides the flexibility required I to compete in a competitive energy market and continue expanding our products and services, j including our distribution system, in the Northeast. J Our financing-related activities during 1998 consisted of: 1

• redemption of $30 million of 61/2% Series first mortgage bonds;

= redemption, at a premium, of $30 million of 6.48% preferred stock; and

• use of interest rate swaps to fix the interest rates on our three one-year, adjustable-rate, tax-exempt issues totaling $132 million.

I i

~ We repurchased 4.6 million shares of our common Average Shares Outstanding stock during 1998. m 27 We raised the common stock dividend in January 1999 to a new annual rate of $1.68. 68,153 In January 1999 we declared a two-for-one stock split on common stock outstanding. Shareholders of record at "3" the close of business on March 12,1999, will be entitled to the shares on April 1,1999 We use short-term, unsecured notes, usually com-mercial paper, to finance certain refundings and herage dares out-E~ for other corporate purposes. We had $78 million of standing continued to commercial paper outstanding at December 31,1998, decline due to common and $58 million outstanding at December 31,1997, ,' stock buyback. all of which was issued by NTSEG. The weighted aver-f age interest rate for commercial paper was 6.2% at December 31,1998, and 6.3% at December 31,1997. 9s 97 '98 ( I NYSEG also has a revolving credit agreement with certain banks that provides for borrowing of up to $200 million until December 31, 2001. We had no amounts outstanding under this agreement 4 jo during 1998 or 1997. g We use interest rate swap agreements to manage the risk of increases in variable interest rates. We record amounts paid and received under the agreements as adjustments to the interest expense of ] f the specific debt issues. FORWARD LOOKING STATEMENTS g This Annual Report to Shareholders contains cenain forward-looking statements that are based ol upon management's current expectations and information that is currently available. The Private 8 Securities l_itigation Reform Act of 1995 provides a safe harbor for forward-looking statements in f certain circumstances. Whenever used in this repon, the words " estimate," " expect," "believe " or similar expressions are intended to identify such forward-looking statements. = In addition to the assurr.ptions and other factors referred to specifically in connection with such statements, factors that could cause actual results to differ materially frorn those contemplated in any forward-looking statements include, among others, the risk that more Year 2000 problems may be found as we continue the review of our systems; the risk that our progress in addressing Year 2000 problems may not proceed as we expect; the fact that despite all of our efforts, there can be no assurances that all of our Year 2000 issues can or will be remedied; the fact that there can be no assurances that all Year 2000 issues that could affect us can or will be totally eliminated by our suppliers, customers, neighboring or interconnected utilities and other entities; and the fact that our assessment of the effects of Year 2000 issues are based, in part, upon information received from our suppliers, customers, neighboring or interconnected utilities and other entities, our rea-sonable reliance upon this information and the risk that inaccurate or incomplete information may ?,- have been supplied to us. Some additional factors that could cause actual results to differ materially from those contemplated in any forward-looking statements include, among others, the deregulation and unbundling of i L

energy services; our ability to compete in the rapidly changing and increasingly competitive electric and natural gas utility markets; our ability to control nonutility generator and other costs; changes in fuel supply or cost and the success of our strategies to satisfy our electric energy requirements after our coal-fired generating stations are sold; our ability to expand our products and services, including our energy distribution network in the Nonheast; the ability to obtain adequate and time-ly rate relief; nuclear or environmental incidents; legal or administrative proceedings; changes in the cost or availability of capital; growth in the areas in which we are doing business; weather variations affecting customer energy usage; and other considerations that may be disclosed from time to time in our publicly disseminated documents and filings. We undertake no obligation to publicly update any forward-looking statements, whether as a result of new information, future ~ events or otherwise. .{ 11 Y Results of Operations 1998 1997 over over 1997 1996 1997 1996 Change Change (Thousands, except per share amounts) Total Operating Revenues $2,499,418 $2,170,102 $2,108,865 15 % 3% Operating incorne $474,839 $436.961 $425.316 9% 3% Net incorne $194,205 $175.211 $168.711 11 % 4% Average Shares Outstanding 64,371 68.153 71.127 (6%) (4%) g Earnings Per Share, basic and diluted $3.02 $2.57 $2.37 18 % 8% 2 Earnings Per Share Excluding Certain Charges $3.02 $2.81 $2.51 7% 12 % Dividends Paid Per Share $1.55 $1.40 $1.40 11 % g i t EARNINGS PER SHARE i Our earnings per share increased in 1998 primarily due to higher electric wholesale prices and { higher electric wholesale deliveries, cost control efforts and a reduction in the number of common j , -p shares outstanding. Those increases were Earnings Per Share 5 ~ partially offset by lower natural gas retail a deliveries, primarily because of unusually sf2 ( warm winter weather, and lower electric retail prices. The 1997 earnings per share $2.57 f include the effect of a nonrecurring charge 52 37 of 24 cents per share. Excluding the net effects of nonrecurring s items, our earnings per share for 1997 increased compared to 1996 primarily due i to higher electric wholesale deliveries, Dividend 81 80 k lower costs of natural gas purchased and Rate Per 81 80 I a reduction in the number of common he,' rind shares outstanding. Those increases were h panially offset by a decrease in earnmgs per share due to the price of NUG power. l gg7 '96 '97 '98

OPERATING RESULTS FOR THE ELECTRIC BUSINESS SEGMENT 1998 1997 over over 1997 1996 1997 1996 Change Change (non nds) Retail Deliveries - Megawatt-hours 13,277 13,238 13.216 Wholesale Deliveries - Megawatt-hours 22,711 10.406 7,914 118 % 31 % Operating Revenues $2,159,868 $1,792.164 $1,723.147 21 % 4% Operating Expenses $1,713,509 $1.411,820 $1,322,885 21 % 7% Operating incorne $446,359 $380,344 $400,262 17 % (5%) Operating Retenues: Our 1998 electric operating revenues increased $368 million due to an y.k j increase in wholesale deliveries and higher wholesale prices totaling $380 million, partially offset ~~{ I by an $8 million decrease due to lower retail prices. Our 1997 electric operating revenues increased $69 million over 1996 due to a $70 million increase in wholesale deliveries. Operating Expenses: Our 1998 electric operating expenses increased $302 million due to a $343 million increase in electricity purchased for wholesale deliveries, partially offset by a $34 million j decrease in other operating and maintenance costs primarily due to cost control efforts and the effect of a 1997 nonrecuning charge. 10 Our 1997 electric operating expenses increased $89 million primarily due to a $49 million increase in electricity purchased, due to purchases for wholesale deliveries and the price of NUG power. g g Expenses also increased as a result of a $19 million increase in operating costs, primarily due to 1 the effect of a 1997 nonrecurring charge, and an $11 million increase in fuel costs, due to j increased electric generation. 3 I >) i

~ 1 i OPERATING RESULTS FOR THE NATURAL GAS BUSINESS SEGMENT 1998 1997 over over 1997 1996 1997 1996 Change Change (mumes) Retail Deliveries-Dekatherms 54,162 59.324 61,542 (9%) (4%) s l Wholesale Deliveries-Dekatherms 7,527 3,027 4,056 149 % (25%) l Operating Revenues $305,881 $337,825 $344,385 (9%) (2%) Operating Expenses $266.138 $275,501 5287,104 (2%) (4%) Operating income $39,743 $62.324 $57.281 (36%) 9% h Our natural gas deliveries decreased in 1998 primarily due to warmer weather, and decreased in [ 1997 due to one low-margin customer that closed its cogeneration plant. Excluding the loss of that ir customer,1997 natural gas deliveries increased 2% over 1996. Operat/ng Retenues: Our 1998 natural gas operating revenues decreased by $32 million. Revenues l were reduced $48 million by lower retail deliveries, primarily due to warmer weather. That l decrease was partially offset by a 513 million increase in wholesale deliveries. The $7 million decrease in 1997 natural gas operating revenues was primarily due to lower retail deliveries that reduced revenues S12 million and a $3 million decrease in other revenues. Those g decreases were partially offset by a more favorable sales mix that added $9 million to revenues. j Operating Expenses: Our 1998 natural gas operating expenses decreased $9 million due to a 11 l $6 million decrease in the cost of natural gas purchased and a $3 million decrease in other operating costs due to the effect of a 1997 nonrecurring charge. f I Our 1997 natural gas operating expenses decreased $12 million due to a decrease in the cost of f natural gas purchased of $16 million, partially offset by an increase in operating costs of $3 million g that was due to a nonrecurring charge. gl Iw W l . l l 1-x

CONSOLIDATED BALANCE SHEETS + December 31 1997 (Thousands) Assets Current Assets Cash and cash equivalents $48,068 $8.168 Special deposits 4,729 3,170 Accounts receivable, net 148,712 189.008 Fuel, at average cost 44,643 43.706 Materials and supplies, at average cost 38,040 41,561 Prepayments 111,082 68.452 Accumulated deferred federal income tax benefits, net 2,148 ify Total Current Assets 395,274 356.213 $I7 Utility Plant, at Original Cost Electric 5,299,604 5.234,725 Natural gas 602,904 576,683 Common 144.043 152.034 6,046,551 5.963,442 f Less accumulated depreciation 2.211,608 2,093.274 Net Utility Plant in Service 3,834,943 3,870,168 Construction work in progress 27,741 52,104 g Total Utility Plant 3,862,684 3,922,272 1 j Other Property and investments, Nel 129,088 l 143.449 f Regulatory and Other Assets y, Regulatory assets ~ Unfur.ded future federal income taxes 136,404 243,119 -r i wn l Unamortized debt expense 71,530 76.418 ? ~5 '- f Demand-side management program costs 64,466 64.466 Environmental remediation costs 60,600 82,900 = Other 125,604 113.637 Total regulatory assets 458,604 580.550 Other assets 37,687 26,197 Total Regulatory and Other Assets 496,291 l 606,747 Total Assets $4,883,337 l $5.028.681 The notes on pages 17 through 29 are an integral part of the financial staternents. )

CONSOLIDATED BALANCE SHEETS December 31 1997 (Thousands) Liabilities Current Liabilities Current portion of long term debt $31,077 $38.240 Current portion of preferred rtock of subsidiary 75,000 Commercial paper 78,300 58,000 Accounts payable and accrued liabilities 116,582 124,981 Interest accrued 19,556 20,500 Taxes accrued 587 6,146 Accumulated deferred federal income tax. nel 10,029 Other 82,143 79.631 Total Current Liabilities 413.274 327,498 (. l Regulatory and Other Liabilities ., i Regulatory liabilities Deferred income taxes 98,038 81,986 Deferred income taxes - unfunded future federal income taxes 60,896 99,126 Other 42,182 79,709 Total regulatory liabilitie; 201,116 260.821 Other liabilities Deferred income taxes 765,592 753,722 Other postretirement benefits 137,681 117,760 i I Environmental remediation costs 80,600 82.900 Other 82,028 73.021 I Total other liabilities 1,065,901 1,027.403 13 Long-term debt 1,435,120 1,450,224 f Total Liabilities 3.115.411 3,065.946 Commitments l Preferred Stock of Subsidiary 2 Preferred stock redeemable solely at the option of subsidiary 29,440 134,440 5 Preferred stock subject to mandatory redemption requirements 25,000 25,000 l K Common Stock Equiry '.f Common stock ($.01 par value,200.000 shares authorized and 2 l 62,947 shares outstanding as of December 31,1998, and } 56.66 2/3 par value,90,000 shares authorized and 67,508 shares 6 l outstanding as of December 31,1997) 631 462,250 l Capitalin excess of par value 1,057,904 811,648 l Retained earnings 662,562 568.844 Treasury stock, at cost (136 shares at December 31,1998, and 1,829 shares at December 31,1997) (7,611) (39.447) Total Common Stock Equity 1,713,486 1,803.295 Total Liabilities and Stockholders' Equity $4,883,337 $5,028,681 The notes on pages 17 through 29 are an integral part of the financial statements. ,? l

CONSOLIDATED STATEMENTS OF INCOME l Year Ended December 31 1997 1996 (Thousands, except per share amounts) Operating Revenues Sales and services $2,499,418 $2.170,102 $2.108,865 Operating Expenses Fuel used in electric generation 239,258 233,180 222,102 Electricity purchased 752,978 409,883 360,753 Natural gas purchased 158,656 164,661 180,866 Other operating expenses 366,403 406,830 412,915 Maintenance 111,502 110.373 107,697 Depreciation and amortization 191,073 201,768 192,501 Other taxes 204,709 206,446 206,715 Total Operating Expenses 2,024,579 1.733,141 1,683,549 Operating Income 474,839 436,961 425,316 Other income and Deductions 9,318 11,496 16,403 Interest Charges, Net 125,557 123,199 122,729 Preferred Stock Dividends of Subsidiary 8,583 9,342 9,530 income Before Federalincome Taxes 331,381 292.924 276,654 FederalIncome Taxes 137,176 117,713 107,943 Net income $194,205 $175,211 $1S8,711 4 Earnings Per Share, basic and diluted $3.02 $2.57 $2.37 ij Average Common Shares Outstanding 64,371 68.153 71,127 .s The notes on pages 17 through 29 are an integral part of the fiencial staternents 14 h: l4 h [:4- '.5. 7 .E -l t

CONSOLIDATED STATEMENTS OF CASH FL0wS Year Ended December 31 1997 1996 (Thousands) Operating Activities Net income $194,205 $175.211 $168,711 Adjustments to reconcile net income to net cash provided by operating activities Depreciation and amortization 191,073 201,768 192,501 Federal income taxes and investment ix uedits deferred, net 38,749 5,884 28,928 Changes in current operating assets and h;bilities Accounts receivable 40,296 35 6.791 Prepayments (42,630) (21,283) (15.798) Accounts payable and accrued liabilities (8,399) 3,858 3.486 Taxes accrued (5,559) 6,146 (22.231) Other, net 60,052 75,115 84,932 % j. Net Cash Provided by Operating Activities 467,787 446,734 447,320 investing Activities Utility plant additions (130,417) (123,768) (214,373) Proceeds from govemmental and other sources 1,368 1.443 2.977 Other property and investment 19,070 (57,803) (916) Net Cash Used in investing Activities (103,979) l (180.128) (212.312) Financing Activities Repurchase of common stock (177,243) (7.245) (40,198) E Treasury stock acquired, net (7,611) (39,447) Repayments of first mortgage bonds and preferred stock, including net premiums (60,600) (73,000) (171,478) 15 Changes in funds set aside for first mortgage bond repayments 25,000 (25,000) long-term notes, net 7,733 (5,203) (2,581) j Commercial paper, net 20,300 (71,300) 100,680 J Dividends on common stock (100,487) (95.496) (99,611) y Net Cash Used in Financing Activities (317,908) (266,691) (238.188) j Net increase (Decrease)in Cash and Cash Equivalents 39,900 (85) (3,180) [ g. Cash and Cash Equivalents, Beginning of Year 8,168 8.253 11.433 y Cash and Cash Equivalents, End of Year $48,068 $8,168 $8.253 ' a B The notes on pages 17 through 29 are an integral part of the financial staternents. f n. -2

^ CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY (Thousands, escept per share amounts) Common Stock Capitalin Outstanding"' Excess of Retained Treasury g~ Shares Amount Par Value. Earnings Stock Total Balance, January 1,1996 71,503 $476,686 $842,442 $424.412 $1.743,540 Net income 168,711 168,711 Common stock dividends declared ($1.40 per share) (99.611) (99,611) ' Comman stock repurchased (1,833) (12,217) (27,981) (40,198) Premium paid on redemption of subsidiary's preferrad stock, net (4,383) (4,383) Amortization of capital stock issue expense 1,923 1,923 Balance, December 31,1996 69,670 464,469 816,384 489.129 1,769.982 d'

• 7 Net income 175,211 175,211 9

Common stock dividends declared ($1.40 per share) (95.496) (95.496) Common stock repurchased (333) (2.219) (5,026) (7.245) Treasury stock transactions, net (1,829) 56 $(39,447) (39,391) Amortization of capital stock issue expense 234 234 Balance, December 31,1997 67,508 462,250 811,648 568.844 (39,447) 1,803,295 g _-j Net income 194,205 194,205 3 Common stock dividends declared ($1.55 per share) (100,487) (100,487) 16 Common stock repurchased (4,425) (20.015) (157,228) (177.243) Treasury stock transactions, net (136) (12,192) (27,235) 31.836 (7,591) f Change in par value of common stock (429,412) 429,412 5 Amortization of capital stock issue expense 1,307 1,307 Balance, December 31,1998 62,947 $631 $1,057,904 $662,562 $(7.611) $1,713,486 8 "' Par value of 3.01 at December 31,1998, and $6.66 2/3 at December 31,1997 and 1996 and January 1,1996. E b The notes on pages 17 through 29 are an integral part of the financial statements. e i

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1 Holding Company Formation Energy East Corporation is an energy delivery, products and services company with operations in New York, Massachusetts, Maine, New Hampshire, Vermont and New Jersey. We deliver electricity and natural gas to retail customers and provide electricity, natural gas and energy management and other services to retail and wholesale customers in the Northeast. On May 1,1998, Energy East Corporation became the parent of New York State Electric & Gas Corporation pursuant to an Agreement and Plan of Share Exchange. Each share of NYSEG's outstand-ing common stock was exchanged for a share of Energy East's common stock. 2 Significant Accounting Policies y Principles of consolidation

• These financial statements consolidate our majority-owned subsidiaries after eliminating intercompany transactions.

Depreciation and amortization

• Te determine depreciation expense using straight-line rates,

' based on the average service lives of groups of depreciable property in service. Our depreciation accmals were equivalent to 3.4% of avenge depreciable property for 1998 and 3.5% for 1997 and 1996. Amortization expense includes the amonization of certain regulatory assets authorized by the PSC. ) t Accounts receivable

• We have an agreement that expires in November 2001 to sell, with l

limited recourse, undivided percentage interests in certain of our accounts receivable from cus-l tomers. The agreement allows us to receive up to $152 million from the sale of such interests. At December 31,1998 and 1997, accounts receivable on the consolidated balance sheets are shown 17 net of $152 million of interests in accounts receivable sold. All fees related to the sale of accounts g receivable are included in other income and ceductions on the consolidated statements of income a and amounted to approximately S9 million in 1998,1997 and 1996. Accounts receivable on the j consolidated balance sheets are also shown net of an allowance for doubtful accounts of $9 million at December 31,1998, and $7 million at December 31,1997. Bad debt expense was $18 million in i W 1998, $17 million in 1997 and $19 million in 1996. i Y Income taxes

• We file 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 - are amortized over the estimated lives of the related assets. Utility plant

• We charge repairs and minor replacements to operating expense accounts. We capitalize 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.

r,.,7..

Regulatory assets and liabilities

• Pursuant to Statement 71, we capitalize, as regulatory assets, incurred costs that are probable of recovey in future electric and natural gas rates. We also record, as regulatory liabilities, obligations to refund previously collected revenue or to spend revenue

. collected from customers on future costs. In accordance with'our current rate agreements in New York State, we no longer defer most costs that were previously subject to deferral accounting. Unfunded future federal income taxes and deferred income taxes are amortized as the related tem-porary differences reverse. Unamortized debt expense is amortized over the lives of the related l debt issues. Demand-side management program costs, other regulatory assets and other regulatory liabilities are amonized over various periods in accordance with our current New York State rate agreements. We earn a return on all regulatory assets for which funds have been spent. ,c Consolidated statements of cash flows

• We consider all highly liquid investments with a y

l maturity date of three months or less when acquired to be cash equivalents. Those investments are y included in cash and cash equivalents on the consolidated balance sheets. Total income taxes paid were $92 million in 1998,$111 million in 1997 and $98 million in 1996. Interest paid, net of amounts capitalized, was $104 million in 1998, $107 million in 1997 and l $112 million in 1996. Risk management

• We use natural gas futures and options contracts to manage our exposure 9

to fluctuations in natural gas comn'.odity prices. Such contracts allow us to fix margins on sales of l natural gas generally expected to occur over the next 18 months. The cost or benefit of natural gas i 18 futures and options contracts is included in the commodity cost when the related sales commit-ments are fulfilled. 1 1 l / We use electricity contracts to manage our exposure to fluctuations in the cost of electricity. Such ) contracts allow us to fix margins on the majority of our retail and wholesale sales of electricity. a The cost or benefit of electricity contracts is included in the cost of electricity purchased when l the electricity is sold. qg 3 We use interest rate swap agreements to manage the risk of increases in variable interest rates. We j record amounts paid and received under the agreements as adjustments to the interest expense of i e the specific debt issues. l Gains and losses resulting from the use of risk management techniques in 1998 and 1997 were not material to our financial position or results of operations. We do not hold or issue financial instru-ments 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 reponed 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.

I Reclassifications

• Cenain amounts have been reclassified on the consolidated financial state-ments to conform with the 1998 presentation.

on 1 J

.i 3 IncomeTaxes Year ended December 31 1997 1996 (Thousands) Current $98,427 $111,829 $79,015 Deferred net Accelerated depreciation 20,684 29,070 52,572 Miscellaneous 22,718 (18,130) (17,307) ITC (4,653) (5,056) (6,337) Total $137,176 $117.713 $107.943 Our effective tax rate differed from the statutory rate of 35% due to the following: r: Year ended December 31 1997 1996 (Thousands) l Tax expense at statutory rate $118,987 l $105.792 $100,165 Depreciation not normalized 16,776 16,854 20.542 ITC amortization (6,354) l (6.359) (6.337) Other, net 7,767 l 1,426 (6,427) Total $137,176 1 $117,713 $107,943 i Our deferred tax assets and liabilities consisted of the following: } December 31 998 - " 1997 19 (Thousands) f Current Deferred Tax Assets $2.148 Current Defened Tax Liabilities $10,029 Noncurrent Deferred Taxes l Depreciation $775,034 $775,943 Unfunded future federal income taxes 60,896 99,126 i s':l Accumulated deferred 11C 109,987 114,640 g Future income tax benefit-ITC (37,584) (40,087) 6 f Other 14,192 (16.399) Total Noncurrent Deferred Tax Liabilities 922,525 933,223 Valuation Allowance 2,001 1,611 Less amounts classified as regulatory liabilities Deferred income taxes 98,038 81,986 Deferred income taxes-unfunded future federalincome taxes 60,896 99,126 Noncurrent Deferred Income Taxes 1765,592 j $753,722

(.- i 4 Prererred Stock of Subsidiary At December 31,1998 and 1997, hTSEG's serial cumulative preferred stock was: Shares Par Value Redemption Authorized Per Price and Amount Series Share Per Share Outstanding (1) 1997 meusands) Redeemable solely at the option of the company: 3.75 % $100 $104.00 150,000 $15,000 $15,000 4 1/2% (1949) 100 103.75 40,000 4,000 4,000 4.15 % 100 101.00 14,000 1,400 i,400 4.40 % 100 102.00 55.200 5,526 5,520 )1 4.15 % (1954) 100 102.00 35.200 3,520 3,520 6 48 % (2) 100 30,000 7.40% (3) 25 25.00 1,000,000 25,000 25.000 Adjustable Rate (3) 25 25.00 2,000.000 50,000 50.000 104,440 134,440 less preferred stock redemptions due within one year - included in current liabilities 75,000 g Total $29,440 $134.440 ) Subject to mandatory redemption requirements: 6.30% (4) 100 102.52 250.000 $25,000 $25.000 t (1) At December 31,1998, there were 1,910,600 shares of $100 par value preferred stock, 7,800,000 d shares of $25 par value preferred stock and 1,000,000 shares of $100 par value preference stock f authorized but unissued. After giving effect to the redemptions referred to in (3) below, there will 3 be 10,800,000 shares of $25 par value preferred stock authorized but unissued. 8

-H (2) Redeemed July 1,1998.

?

? (3) To be redeemed February 1,1999 (4) On January 1 of each year from 2004 through 2008, we must redeem 12,500 shares at par, and on January 1,2009, we must redeem the balance of the shares at par. This Series is redeemable at our option at $102.52 per share before January 1, 2000. The $102.52 price will be reduced annual-ly by 63 cents for the years ending 2000 through 2002; thereafter, the redemption price is $100.00, We are restricted in our ability to redeem this Series before January 1,2004. 1

5 Bank Loans and Other Borrowings We use short-term, unsecured notes, usually commercial paper, to finance certain refundings and

- for other corporate purposes. The weighted average interest rate on commercial paper balances, all of which belonged to NYSEG, was 6.2% at December 31,1998, and 6.3% at December 31,1997. dk

k NYSEG has a revolving credit agreement with certain banks that provides for borrowing of up to $200 million through December 31,2001. The revolving credit agreement does not require compensating balances. We had no outstanding loans under this agreement at December 31,1998 or 1997. At our option, the interest rate on borrowings is related to the prime rate, the London Interbank Offered Rate or the interest rate applicable to certain cenificates of deposit. The agreement provides for payment of a commitment fee, which was.125% at Deceruber 31,1998 and 1997. 6 tong-Term nebt All of our consolidated long-term debt at December 31,1998 and 1997, was issued by our subsidiaries. Maturity Interest Amount ./ Dates Rates 1997 '(Thousands) First mortgage bonds (1) 2001 to 2023 6 3/4% to 9 7/8% $800,000 $830.000 Pollution control notes (2) 2006 to 2034 3.58% to 6.15% 613,000 613.000 Long-term notes 12/31/01 26,200 28.000 Various long-term notes 25,235 12.569 Obligations under capitalleases 8,605 12.269 Unamortized premium and discount on debt. net (6,843) (7.374) 1,466,197 1,488.464 Less debt due within one year - included in current liabilities 31,077 38.240 j Total $1,435,120 $1.450.224 2 21 At December 31,1998, long-term debt and capital lease payments that will become due during the next five years are: e 1999 2000 2001 2002 2003 (Thousands)' l $31.077 $19,127 $51.867 $151.460 $1,167 (1) NYSEG's first mongage bond indenture constitutes a direct first mongage lien on substantially all of its utility plant. The mongage also provides for a sinking and improvement fund. This provi-sion requires us 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 mongage, we satisfied the requirement in 1998 by crediting

• bondable value of propeny addi-tions" against the amount of cash to be deposited. We redeemed, in March 1998, $30 million of 61/2% series first mongage bonds, due september 1,1998.

l (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%. Ul

i l l l l l Adjustable-rate pollution control notes totaling $132 million were issued to secure the same amount j of tax-exempt adjustable-rate pollution control revenue bonds (Adjustable-rate Revenue Bonds) i issued by a governmental authority. The Adjustable-rate Revenue Bonds bear interest at rates ranging from 3.58% to 4.18% through dates preceding various annual interest rate adjustment dates. On the annual interest rate adjustment dates the interest rates will be adjusted, or at our option, subject to certain conditions, a fixed rate of interest may become effective. Bond owners may elect, subject l to certain conditions, to have their Adjustable-rate Revenue Bonds purchased by the Trustee. We have 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 O. 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 31,1998, 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 3.28%, excluding letter of credit fees, for the year g ended December 31,1998. } NYSEG has irrevocable letters of credit that suppon certain payments required to be made on the 22 Adjustable-rate Revenue Bonds and Multi-mode Revenue Bonds, and that expire on various dates. 5 If we are unable to extend the letter of credit related to a panicular series of Adjustable-rate j Revenue Bonds, that series will have to be redeemed unless a fixed rate of interest becomes effec-tive. Multi-mode Revenue Bonds are subject to mandatory purchase when there is any change in 2 f 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 g Bonds are repaid with the proceeds from the remarketing of those Bonds. To the extent the pro- ??( ( ceeds are not enough, we are required to reimburse the bank that issued the letter of credit. [ 7 sale or coal-fired Generation Assets i in the spring of 1998 we put our seven coal-fired generating stations and associated assets and liabilities up for auction. The net book value of those coal-fired generation assets was $1.10 billion at December 31,1998. In August 1998 we accepted two offers totaling $1.85 billion for the coal-fired generation assets. The PSC approved the sales in November 1998 and the FERC approved the sales in January 1999. We expect the sales to close by the end of the first quaner of 1999 All proceeds, net of taxes and transaction costs, in excess of the net book value of the generation assets, less funded deferred taxes, will be used to write down our 18% investment in Nine Mile Point nuclear generating unit No. 2. This treatment is in accordance with our restructuring plan approved by the Public Service Commission of the State of New York in January 1998. (See Note 8. Jointly-Owned Generating Stations.) y

e4 8 Jointly-Owned Generating Stations Nine Mile Point nuclear generating unit No. 2

• We have an 18% interest in the output and costs of NMP2, which is operated by Niagara Mohawk Power Corporation. Ownership of NMP2 is shared with Niagara Mohawk 41%, Long Island Power Authority 18%, Rochester Gas and Electric Corporation 14% and Central Hudson Gas & Electric Corporation 9%.

Our share of the rated capability is 205 megawatts. Our share of net utility plant investment, excluding nuclear fuel, was approximately $573 million at December 31,1998, and $591 million at December 31,1997. The accumulated provision for depreciation was approximately $178 million at December 31,1998, and $162 million at December 31,1997. ~ Net proceeds from the sale of our coal-fired generation assets will be used to write down our 18% si investment in NMP2. (See Note 7. Sale of Coal-fired Generation Assets.) Our share of operating I expenses is included in the consolidated statements of income. We are actively pursuing the sale of our interest in NMP2. We are working with Niagara Mohawk who is also pursuing the sale of its interest in NMP2. Nuclear insurance

• Niagara Mohawk maintains public liability and propeny insurance for NMP2. We reimburse Niagara Mohawk for our 18% share of those costs.

The public liability limit for a nuclear incident is approximately $9.1 billion. Should losses stem-l ming from a nuclear incident exceed the commercially available public liability insurance, each 2 licensee of a nuclear facility would be liable for up to $84 million per incident, payable at a rate 23 not to exceed $10 million per year. Our maximum liability for our 18% interest in NMP2 would be approximately $15 million per incident. The $84 million assessment is subject to periodic inflation f 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 evacua-l tions whether or not a nuclear incident actually occurs. @i Niagara Mohawk has obtained property insurance for NMP2 totaling approximately $2.8 billion j through the Nuclear Insurance Pools and Nuclear Electric Insurance Limited. In addition, we have { 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 resuhing from an incident at a member facility exceed the accumulated reserves of NEIL, each member, including us, would be liable for its share of the deficiency. Our maximum liability per incident under the property damage and replacement power coverage is approximately $2 million. Nuclear plant decommissioning costs

• Based on the resuhs of a 1995 decommissioning study, our 18% share of the cost to decommission NMP2 is $161 million in 1999 dollars ($422 million in 2026 when NMP2's operating license will expire). The estimated liability for decommissioning NMP2 using the Nuclear Regulatory Comnussion's muumum funding reouirement is approximately $101 million in 1999 dollars. Our electric rates in New York State currently include an annual allowance for decom-r missioning of $4 million, which approximates the minimum funding requirement as set forth in the 1995 decommissioning study. Decommissioning costs are charged to depreciation and amonization

. expense and are recovered over the expected life of the plant. 4 k.

We have 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 approx- - imately $21 million at December 31,1998, and $13 million at December 31,1997. Those amounts are included on the consolidated balance sheets in other propeny and investments, net. The related liability for decommissioning is included in other liabilities - other. At December 31,1998, the external trust fund investments were classified as available-for-sale. Homer City = We have an undivided 50% interest in the output and costs of the Homer City Genera'ing Station, which comprises three generating units. The station is owned with Pennsylvania Electric Company and is operated by its affiliate, GPU Generation, Inc. Our share of the rated capability is 952 megawatts, and our net utility plant investment was approximately $266 million at December 31,1998, and $262 million at December 31,1997. The accumulated 3 provision for depreciation was approximately $184 million at December 31,1998, and $190 million Q at December 31,1997. Our share of operating expenses is included in the consolidated statements of income. We accepted an offer of $900 million in August 1998 for our 50% share of the Homer City Generating Station. (See Note 7. Sale of Coal-fired Generation Assets.) 9 Environmental tiability From time to time environmental laws, regulations and compliance programs may require changes E in our 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 Depanment of Environmental g Conservation, as appropriate, notified us that we are among the potentially responsible parties i who may be liable for costs incurred to remediate certain hazardous substances at nine waste sites, ] not including our sites where gas was manufactured in the past, which are discussed below. With g 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. N1 hl Any liability may be joint and several for certain of those sites. We recorded an estimated liability f 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 us. We have a program to investigate and perform necessary remediation at our sites where gas was manufactured in the past. In 1994 and 1996, we entered into Orders on Consent with the NYSDEC. These Orders require us to investigate and, where necessary, remediate 34 of our 38 sites. Eight ,c sites are included in the New York State Registry. Our estimate for all costs related to investigation and remediation of the 38 sites ranges from $79 million to $178 million at December 31,1998. 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 we expect 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. I l

n The liability to investigate and perform remediation, as necessary, at the known inactive gas manu-l facturing sites, reflected in our consolidated balance sheets was $79 million at December 31,1998, and $81 million at December 31,1997. We recorded a corresponding regulatory asset, net of insurance recoveries, since we expect to recover the net costs in rates. 10 netirement nerents p I Pension Benefits Postretirement Benefits 1997 1997 frhousandd Change in projected benefit obligation Benefit obligation at January 1 $746,008 $679.778 $258,884 $226.193 Service cost 19,500 19.317 6,283 7.010 't. { interest cost 51,556 50,951 16,606 17.075 Amendments 4.120 Actuarialloss (gain) 21,831 24,835 (3,889) 16.891 Benefits paid (35,614) (32.993) (8.432) (8.285) Projected benefit obligation at December 31 $803,281 $746.008 $269,452 $258.884 Change in plan assets Fair value of plan assets at January 1 $1,176,184 $995.795 Actual return on plan assets 155,956 213.382 Benefits paid (35.614) (32.993) t Fair value of plan assets at December 31 $1,296,526 $1.176,184 d ~ Funded status $493,245 $430.176 $(269,452) $(258.884) 25 Unrecognized net actuarial gain (395,780) (372,046) (12,847) (13.824) Unrecognized prior service cost 26,290 28,307 { Unrecognized net transition (asset) obligation (37,421) (44.660) 144,618 154.948 e f Prepaid (accrued) benefit cost $86,334 $41,777 $(137,681) $1117.760) Our postretirement benefits were unfunded as of December 31,1998 and 1997. i4 y-g Pension Benefits Postretirement Benefits 1997 1997 [ w Weighted average assumptions l as of December 31 l Discount rate 6.5% 7.0% 6.5% 7.0% Expected retum on plan assets 8.5% 8.5% N/A N/A l Rate of compensation increase 3.75 % 4.25 % N/A N/A We assumed a 7% annual rate of increase in the costs of covered health care benefits for 1999 that l gradually decreases to 5% by the year 2003 l f l l l

l b i rd Pension Benefits Postretirement Benefits 1997 1996 1997 1996 (Thousands) Components of net periodic benefit cost Service cost $19,500 $19,317 $18.593 $6,283 $7,010 $6.436 Interest cost 51,556 50.951 46.070 16,606 17.075 15.795 Expected return on plan assets (84,007) (73.777) (62.615) Amortization of prior service cost 2,016 2.078 661 Recognized net actparial gain (26,384) (18.056) (11,603) (4,865) (3,565) (3.246) - ]; Amo;ti2ation of transition {: tusset) obligation (7,238) (7.238) (7.238) 10,330 10.330 10.330 Deferral for future l recovery (9.600) (11.766) (8.950) Net periodic benefit cost $(44,557) l $(26.725) $(16.132) $18.754 l $19.084 $20.365 The net periodic benefit cost for postretirement benefits represents the cost we charged to j expense for providing health care benefits to retirees and their eligible dependents. The amount of j postretirement benefit cost deferred was $10 million as of December 31,1998, and $14 million as ,j of December 31,1997. We expect to recover any deferred postretirement costs by the year 2002. The transition obligation for postretirement benefits is being amortized over a period of 20 years. 26 A one-percent change in the health care cost inflation rate from assumed rates would have the f following effects: e l One-Percent One-Percent j f' increase Decrease [ Effect on total of service and interest cost components $4 million $(3 million) aj j Effect on postretirement benefit obligation $45 million $(36 million) ( [ w f 11 Stock-Based Compensation We apply Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees in accounting for our stock-based compensation plans. Compensation expense would have been the same in 1998,1997 and 1996 had it been determined consistent with Statement of Financial Accounting Standards No.123, Accounting for Stock-Based Compensation. We may grant options and stock appreciation rights to senior management and certain other key employees under our stock option plan. Options granted in 1997 vested in 1997, while those granted in 1998 vest over a three-year period, subject to, with certain exceptions, continuous employment. All options expire ten years after the grant date. Of the 3.3 million shares authorized, unoptioned shares totaled 2.3 million at December 31,1998, and 2.9 million at December 31,1997. During 1998 550,308 options /SARs were granted with a weighted-average exercise price of $36.87. 11,438 options with a weighted-average exercise price of 521.75 and 94,678 SARs with a weighted-d,_. average exercise price of $21.86 were exercised in 1998.18,000 options /SARs with an exercise price of $35.88 were fcrfeited in 1998. The 645,463 options /SARs outstanding at December 31,1998, had l

a weighted-average exercise price of $34.28. Of those outstanding at December 31,1998,113,155 options /SARs with exercise prices ranging from $21.75 to $34.13 and a weighted-average remaining life of eight years had a weighted-average exercise price of $21.95, and 532,308 options /SARs with exercise prices ranging from $35.88 to $57.44 and a weighted-average remaining life of nine years had a weighted-average exercise price of $36.90. Of those exercisable at December 31,1998, 113,155 options /SARs with exercise prices ranging from $21.75 to $34.13 had a weighted-average exercise price of $21.95, and 242 options /SARs had an exercise price of $39.25. During 1997 420,479 options /SARs were granted with a weighted-average exercise price of $21.83. 7,933 options and 193,275 SARs with an exercise price of $21.75 were exercised in 1997. 216,792 outstanding options /SARs with a weighted-average exercise price of $21.87 were exercisable at December 31, 1997. 2,479 outstanding options with a weighted-average exercise price of $33.32 were not exercis-able at December 31,1997. We recorded compensation expense for options /SARs of $9.2 million 1 in 1998 and $4.9 million in 1997. n Our Long-Term Executive Incentive Share Plan provides participants cash awards if certain share-holder return criteria are achieved. There were 108,577 performance shares outstanding at December 31,1998, and compensation expense for 1998 was $5.2 million. 12 FairValue of FinancialInstruments The carrying amounts and estimated fair values of some of our financial instruments included in our consolidated balance sheets are shown in the following table. The fair values are based on the j quoted market prices for the same or similar issues of the same remaining maturities. 27 ~ December 31 m. 1997 1997 Carrying Estimated Carrying Estimated e Amount Fair Value Amount Fair Value 2 f ( m nande Investments held in extemal g trust funds-classified as Jin ~' available-for-sale $30,097 $30,230 $53.049 $53.708 i Preferred stock subject to mandatory { redemption requirements $25,000 $25,188 $25.000 $24,315 g first mortgage bonds $793,157 $861,756 $822.626 $882.616 l Pollution controf notes $613,000 $631,421 $613.000 $625.149 I The carrying amounts for cash and cash equivalents, commercial paper and interest accrued approximate their estimated fair values because they mature within one year. Special deposits include restricted funds set aside for preferred stock and long-term debt redemp-tions. The carrying amount approximates fair value because the special deposits have been invested in securities that mature within one year. f i t

y, .n q-13 Segment Information Our two primary business segments are electric and natural gas. Our electric business segment consists of electric generation, transmission and distribution operations. Our natural gas business segment consists of natural gas distribution, transportation and storage operations in New York. Other includes our. energy services business, natural gas and propane air distribution operations outside of New York, common corporate assets of $201 million in 1998, $139 million in 1997 and $105 million in 1996, and intersegment eliminations. Selected financial information for each of our business segments is presented in the following table. Natural k Year Electric Gas Other Total l r.;, (lj (Nmads) 1998

• r Operating Revenues

$2,159,868 $305,881 $33,669 $2,499.418 Depreciation and Amortization $172,382 $15,497 $3.194 $191,073 Operating Income $44G,359 $39,743 $(11,263) $474,839 Interest Charges Net $106,195 $17,718 $1,644 $125,557 Federalincome Taxes $133,111 $7,638 $(3,573) $137,176 Net income $191,460 $11,056 $(8,311) $194,205 Identifiable Assets $4,069,627 $575,088 $238,622 $4,883,337 Capital Spending $96,987 $32,268 $8,095 $137,350 5I 1997 '28 Operating Revenues $1.792.164 $337,825 $40,113 $2,170,102 Depreciation and Amortization $183,304 $15,255 $3.209 $201,768 g Operating Income $380,344 $62,324 $(5,707) $436,961 interest Charges, Net $104,569 $17.113 $1,517 $123,199 Federalincome Taxes $104.575 $15,212 $(2,074) $117,713 Net income $154,315 $26,482 $(5,586) $175,211 Identifiable Assets $4.273,100 $588,773 $1E3,808 $5,028,681 Capital Spending $78,667 $45,240 $5,644 $129,551 d' y { 1996 l Operating Revenues $1.723.147 $344,385 $41,333 $2.108,865 Depreciation and Amortization $176,906 $12,495 $3,100 $192,501 Operating income $400,262 $57,281 $(32,227) $425,316 Interest Charges, Net $108,696 $12,735 $1,298 $122,729 Federalincome Taxes $102,223 $16,822 $(11,102) $107,943 Net income $167,201 $24,189 $(22,679) $168,711 identifiable Assets $4,376,814 $550,196 $132.671 $5.059,681 Capital Spending $132,190 $82,625 $916 $215.731 p .a. Ae

14 Commitments Capital spending

• We have commitments in connection with our capital spending program and estimate that spending, including nuclear fuel, will approximate $140 million for 1999,$127 million for 2000 and $150 million for 2001. Our capital spending program is expected to be financed entirely with internally generated funds. The program is subject to periodic review and revision.

Our capital spending will be primarily for the extension of service, necessary improvements to existing facilities and environmental compliance requirements. Nonutility generator power purchase contracts

• We expensed approximately $326 million in 1998, $324 million in 1997 and $320 million in 1996 for NUG power, including termination costs. We estimate that NUG power purchases will total $358 million in 1999 and $376 million in 2000 and in 2001, unless we are able to change the NUG contracts.

{ 15 Quarterly Financial Information (Unaudited) Quarter ended March 31 June 30 Sep.30 Dec. 31 (Thousands, except per share amounts) Operating Revenues $637,630 $548,308 $698,705 $614,775 j Operating income $155,644 $87,664 $117,447 $114,084 i Net income $76,171 $29,353 $45,050 $43,631 N Eamings Per Share, basic and diluted $1.15 $ 46 $.71 $.69 Dividends Per Share $.35 $.40 S.40 $.40 g Average Common Shares Outstanding 66,408 64,349 63,667 63,103 Common Stock Pricem High $40.50 $44.19 $51.38 $58.00 l low $33.06 $38.94 $39.88 $46.75 g R w 1997 1997 1997 1997 5 P f' Operating Revenues $599,146 $479,684 $501,779 $589,493 Operating income $165,728 $80,766 $81,401 $109.066 g Net income $79,662 $23,923 $25.929 * $45.697 Eamings Per Share, basic and diluted $1.15 S.35 S.38 m $.68 Dividends Per Shtce $.35 $.35 $.35 $.35 Average Common Shares 0;!"anding 69,353 68.279 67,503 67.504 Common Stock Price

• High

$24.50 $22.50 $27.19 $35.75 Low $21.25 $20.63 $20.81 $25.75 '" Our common stock is ksted on the New York Stock Exchange. The number of shareholders of record at December 31,1998 was 33,792.

• Includes the effect of fees related to an unschcited tender offer that decreased net income by $17 milhon and eamings per share by 24 cents.

vj l 1 i

c_ REPORT OF MANAGEMENT ..Our management is responsible for the preparation, integrity and reliability of the consolidated ~ financial statements, notes and other information in this annual repon. The consolidated financial statements have been prepared in accordance with generally accepted accounting principles and include estimates that are based upon management's judgment and the best available information. Other financial information contained in this repon was prepared on a basis consistent with that of the consolidated financial statements. We maintain a system of internal controls designed to provide reasonable assurance to our management and board of directors regarding the preparation of reliable published financial state-ments and the safeguarding of assets against loss or unauthorized use. The system contains self-monitoring mechanisms and actions are taken to correct deficiencies as they are identified. Even an effective internal control system, no matter how well designed, has inherent limitations, includ-G ing the possibility of the circumvention or overriding of controls, and therefore can provide only M reasonable assurance with respect to financial statement preparation and the safeguarding of ' ~ assets. Further, because of changes in conditions, internal control system effectiveness may vary over time. We maintain an internal audit depanment that independently assesses the effectiveness of the internal controls. In addition, our independent accountants, PricewaterhouseCoopers llP, have ' considered our internal control structure to the extent they considered necessary in expressing g an opinion on the consolidated financial statements. Our management is responsive to the } recommendations of our internal audit depanment and the independent accountants concerning internal controls and corrective measures are taken when considered appropriate. The board of 30 directors oversees our financial reponing through its audit committee. The committee, which g consists entirely of outside directors, meets regularly with management, the internal auditor and y the independent accountants to discuss auditing, internal control and financial reponing matters. Both the internal auditor and independent accountants have direct access to the audit committee, i .f independent of management. =-I We assessed our internal control system as of December 31,1998, in relation to criteria for effec- .Q j tive internal control over financial reporting and the. safeguarding of assets described in Internal g Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, we believe that, as of December 31,1998, our system of internal control over financial reporting and over the safeguarding of assets against loss or unauthorized use met those criteria. 4 M ck d Roben E. Rude Controller 4-b Wesley W. von Schack Chairman, President and Chief Executive Officer

REPORT OF INDEPENDENT ACCOUNTANTS Pnicwsrnuousekeens a e PricewaterhouseCoopers LLP 1301 Avenue of the Americas NewYork NY100194013 Telephone (212)2591000 Facsimile (212)259 1301 January 29,1999 (% To the Shareholders and Board of Directors, Uj Energy East Corporation and Subsidiaries Albany, New York In our opinion, the accompanying consolidated balance sheets and the related consolidated state-ments of income and retained earnings and of cash flows present fairly, in all material respects, the financial position of Energy East Corporation, "the Company," and its subsidiaries at December 31, 1998 and 1997, and the results of their operations and their cash flows for each of the three years in the period ended December 31,1998, in conformity with generally accepted accounting princi-ples. These financial statements are the responsibility of the Company's management; our responsi- { bility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with generally accepted auditing standards, which M require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test g basis, evidence supporting the amounts and disclosures in the financial statements, assessing the e accounth;g principles used and significant estimates made by management, and evaluating the ) overall financial statement presentation. We believe that our audits provide a reasonable basis for .I the opimon expressed above. .l

7..

t

l. E l SELECTED FINANCIAL D ATA 1997 1996 1995 1994 1993 (Thousands, except per share emeents) l Operating Revenues Sales and services $2,499,418 $2.170.102 $2.108.865 $2.040.895 $1.918.431 $1.800.149 Operating Expenses Fuel used in electric generation 239,258 233,180 222,102 229,759 231,648 245,283 Electricity purchased 752,978 409,883 360.753 318.440 242,352 161,967 Natural gas purchased 158,656 164,661 180,866 157,476 161,627 141,635 Other operating expenses 366,403 406.830 412,915 367,150 354,553 351.215 Restructuring expenses 26.000 Maintenance 111,502 110,373 107.697 116.807 106,637 111,757 Depreciation and amortization 191,073 201,768 192,501 188.367 182,598 164.765 i Other taxes 204,709 206,446 206,715 210,910 210.729 204,962

[

Total Operating Expenses 2,024,579 l 1,733,141 1,683.549 1,588.909 1,490.144 1,407,584

• [2 Operating income 474,839 436.961 425,316 451,986 428.287 392,565 Otherincome and Deductions 9,318 11 A96 16A03 9,865 2.089 (312) i interest Charges, Net 125,557 123,199 122.7E 129.567 136.092 141,099 Preferred Stock Dividends of Subsidiary 8,583 9,342 9.530 18.721 18.947 20.638 i

income Before Federal Income Taxes 331,381 292,924 276.654 293.833 271,159 231,140 j Federalincome Taxes 137,176 117,713 107.943 115.864 102A61 85.750 f Netincome 194,205 175,211 m 168,711

• 177,969 168.698
• 145,390
• Common Stock Dividends 100,487 95A96 99.611 100.104 142.265 152.316 32 Retained Earnings increase (Decrease)

$93,718 $79.715 $64.717 $77,865 $26A33 $(6.926) f Average Common Shares l 5 Outstanding 64,371 68.153 71.127 71,503 71,254 69.990 .l Earnings Per Share, basic 9 and diluted $3.02 $2.57 m $2.37 * $2 49 $2.37 * $2.08 * .I l Dividends Paid Per Share $1.55 $1.40 $1.40 $1.40 $2.00 $2.18 , (,i j Book Value Per Share of W Common Stock at Year End $27.22 $26.71 $2541 $24.38 $23.28 $22.89 = f Capital Spending $137,350 $129.551 $215,731 $167,446 $282.703 $284,813 Total Assets $4,883,337 $5,028.681 $5,059.681 $5.114.331 $5,230.685 $5.287.958 w Long-term Obligations, Capital Leases and ~ Redeemable Preferred Stock $1,460,120 $1.475,224 $1,505.814 $1.606.448 $1.776.081 $1.755.629 Reclassifications: Certain amounts included in Selected Financial Data have been reclassified to conform with the 1998 presentation.

• Includes the effect of fees related to an unsolicited tender effer that decreased net income by $17 million and earnings per share by 24 cents.

((

• Includes the effect of the writedown of the investment in EnerSoft Corporation that decreased net income by $10 million and eamings per share by 14 cents.

} Includes the effect of the 1993 production-Cost penalty that decreased net income by $8 million and eamings per share by 12 cents.

• Includes the effect of restructuring expenses that decreased net income by $17 million and eamings per share by 25 cents

FINANCIAL STATISTICS 1997 1996 1995 1994 1993 Financial Statistics Return on average common stock equity (Percent) 11.2 9.8 9.5 10.4 10.3 9.1 Mortgage bond interest (Times earned) 4.9 4.4 4.1 4.0 3.5 3.0 Interest charges and preferred dividends (Times earned) 2.4 2.3 2.3 2.2 2.1 1.9 Common stock price at year end $56.50 $35.50 $21.63 $25.88 $19.00 $30.75 Dividend payout ratio (Percent) 51.3 54.5 59.1 56.2 84.4 104.8 Price earnings ratio at year end 18.7 13.8 9.1 10.4 8.0 14.8 Property, Plant and Equipment (includes construction cP work in progress)(Thousands) 2 2- - Electr'ic $5,315,597 $5.267.080 $5.208,307 $5.125.336 $5.027.137 $4.887,125 Natural gas 611,430 586.144 544,898 472,056 431.202 393.945 Common 147,265 162.322 162,758 157.823 171.639 180.532 Total $6,074.292 l $6.015.546 $5.915.963 $5.755.215 $5.629.978 $5.461.602 Accumulated Depreciation $2.211.608 ! $2.093.274 $1.933.599 $1.791,625 $1.642.653 $1.541.456 Number of Shareholders of Record l Common stock 33,792 38.238 45.608 50,576 56.279 58.990 } Preferred stock 803 1.068 1.211 1.297 1.329 3.632 j E 33 .h I a b q l

s ELECTRIC AND NATURAL GAS DELIVERIES STATISTICS 1997 1996 1995 1994 1993 (mande Electric Deliveries (Megawatt hours) Residential 5,143 5.267 5,393 5,286 5.399 5,423 Commercial 3,393 3,495 3,430 3,405 3,315 3,298 Industrial 3,118 3,065 2.992 3.010 2,997 2.950 Other 1,623 1,411 1.401 1,392 1,437 1,417 Total Retan 13,277 l 13.238 13.216 13.093 13.148 D,088 Wholesale 22,711 l 10,406 7,914 7,636 6,827 6.233 Total Electric Deliveries 35,988 l 23.644 21.130 20.729 19.975 19.321 Electric Revenues v-Residential $715,705 $728.776 $744,439 $725,299 $679,124 $635,155 i Commercial 391,224 403.480 400,841 395.076 366.854 333.674 Industrial 239,455 243.850 242,792 247,576 245,218 228,215 Other 172,823 157,537 158.377 158.568 153.888 138,320 Total Retail 1,519,207 l 1,533.643 1.546.449 1,526.519 1.445.084 1.335,364 Wholesale 611,851 l 232,138 162,232 150,444 141,902 147,175 Other 28,810 26.383 14.466 31,334 13.089 44.823 's g Total Electric Revenues $2,159,868 l $1.792.164 $1,723.147 $1,708.297 $1.600.075 $1,527,362 5 I E Natural Gas Deliveries (Dekatherms) I N Residential 20,955 ! 24,357 25,470 23,512 24,662 25.080 g Commercial 7,898 10.178 10,146 10.540 10,611 10,640 t industrial 1,779 2,409 2,726 2,587 2,180 1,820 Other 2,735 2.230 2,463 2,038 1,805 2,568 l Transportation of customer-Owned natural gas 20,962 l 19,645 20,970 19.433 19.133 18,701 Total Retail 54,162 1 59.324 61,542 58.535 58,624 58.046 Ek.s j Wholesale 7,527 ! 3,027 4.056 4,754 B Total Natural Gas Deliveries 61,689 l 62,351 65,598 63.289 58.624 58,046 I Natural Gas Revenues Residential $171,382 $190,564 $198.338 $181,697 $185,073 $170,734 Commercial 60,966 83,091 83,393 75.178 72,360 66.648 Industrial 8,155 13.044 14,509 11,310 11,542 9,602 Other 14,257 17,839 15.697 14.584 12,997 10,943 i Transportation of customer- ) owned natural gas 29,589 i 21,949 17.476 13,718 12.791 12.091 Total Retail 284,349 326,487 329.413 296,487 294.763 270,018 Wholesale 17,791 9.114 10,444 8,771 Other 3,741 2,224 4,528 3.673 4.017 2,769 Total Natural Gas Revenues $305,881 l $337.825 $344.385 $308.931 $298.78J $272.787 t

ELECTRIC GENERATION STATISTICS System Capability (Megawetts) -Coal 2,286 2,277 2,236 2,226 2,278 2,394 Nuclear 205 207 206 206 189 189 Hydro 59 - 66 62 61 69 67 Intemal combustion 7 7 7 7 7 7 Total Generating Capability 2,557 2.557 2,511 2,500 2,543 2.657 Purchased Power New York Power Authority 641 594 591 517 514 486 NUGs 565 551 599 595 594 362 Less: Firm sales (527) (625) ' (607) (118) (367) (311) Total System Capability 3,236 1 3,077 3.094 3,494 3,284 3,194 ' System Capability (Percent) j,. Coal 71 74 72 63 69 75 J' Nuclear 6 7 7 6 6 6 Hydro 2 2 2 2 2 2 Total Generating Capability 79 83 81 71 77 83 Purchased Power i New York Power Authority 20 ! 19 19 15 16 15 NUGs 17 l 18 20 17 18 12 Less: Firm sales (16)i (20) (20) (3) (11) (10) .O Total System Capability 100 ' 100 100 100 100 100 Megawatt-Hour Production, i E Not(Thousands) l 35 Generated Coal 16,146 14,985 14,195 14,296 14.338 15,131 l Nuclear 1,315 1,598 1,566 1,306 1,509 1,295 e Hydro 317 313 309 240 321 309 j q Total Generated 17,778 I 16,896 16.070 15,842 16.168 16,735 4 Purchased Power l d

• w New York Power Authority 2,006 1,957 1,921 1,849 1,700 1,617 i

NUGs 4,016 4.051 4,235 4.413 3,601 2.472 0 Oli f Other, net 13,548 2,199 465 155 14 78 Total 37,348 1 25,103 22,691 22,259 21,483 20,902 w Production Expenses (Thousands) Generated $330,590 $327,042 $322,233 $335,706 $339,546 $371,891 Purchased Power New York Power Authority 32.253 27,923 27,263 26.079 21,478 16,713 NUGs 326,008 323,959 319,958 283,913 214,010 137,791 i Other 394,717 58,001 13,532 8,448 6,864 7,463 Total $1,083,568 l $736,925 $682,986 $654.146 $581,898 $533,858 Note: We accepted offers from The AES Corporation and Edison Mission Energy in August 1998 for the purchase of our seven coal-fved stations and associated assets and liabilities. The sales are expected to close by the end of the first Quarter of 1999. D

p_.,- BOARD OF DIRECTORS Richard Aurelio *a director since 1997, is a director of the Citizens Committee for New York City, Inc. and the Javits Foundation, both in New York, New York. James A. Carrigg *a director since 1983, is a director of Security Mutual Life Insurance Company of New York and a trustee of Dr. G. Clifford & Florence B. Decker Foundation, both in Binghamton, New York. Alison R Casarett *a director sirce 1979, is Dean Emeritus at Cornell University in Ithaca, New York and Emeritus Professor of Radiation Biology at the New York State College of Veterinary Medicine of Cornell University. Joseph J. Castiglia *a director since 1995, is Chairman of the Catholic Health System of Western New York and of Blue Cross & Blue Shield of Western New York, both in Buffalo, New York. Lois B. DeFleur *a director since 1995, is President of the State University of New York at S-Binghamton, New York. pb Everett A. Gilmour *a director since 1980, is Chairman of the Board of The National Bank and Trust Company of Norwich and N.B.T. Bancorp, Inc., both in Norwich, New York, f Paul L. Gioia *a director since 1991, is of counsel at LeBoeuf, Lamb, Greene & MacRae, 5 attorneys-at-law in Albany, New York. f John M. Keeler a a director since 1989, is of counsel at Hinman, Howard & Nattell, attorneys-at-j law in Binghamton, New York. i d Ben E. Lynch = a director since 196,7. is President of Winchester Optical Company in Elmira, New York 36 Alton G. Marshall =a director since 1971, is President of Alton G. Marshall Associates, Inc., f a real estate investment company in New York, New York. Walter G. Rich ea director since 1997, is Chairman, President, Chief Executive Officer and a i f director of Delaware Otsego Corporation in Cooperstown, New York, and its subsidiary, The ]g New York, Susquehanna & Western Railway Corporation. n. i Wesley W. von Schack *a director since 1996, is Chairman, President and Chief Executive ne j Officer of the corporation. 3 Committees *(Chairperson listed first) Audit: Lynch, DeFleur, Gioia, Rich Executire Compemation and Succession: Gilmour, Aurelio, Castiglia, Marshall Nominating: Marshall, Aurelio, DeFleur, Gilmour hTSEG's Corporate Responsibility: Carrigg, Casarett, Keeler, Rich EXECUTIVE ~ OFFICERS ENERGY EAST CORPORATION Wesley W. von Schack

• Chairman, President and Chief Executive Officer Michael I. German
• Senior Vice President Kenneth M. Jasinski e Senior Vice President and General Counsel Robert D. Kump
• Treasurer

^ Robert E. Rude

• Controller Daniel W. Farley
• Secretary

i i. l SHAREHOLDER INFORMATION Shareholder Services

• Shareholder Services representative 3 are available between 8 a.m. and

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30 p.m. (Eastern Time) on regular business days at 1-800-225-5643 Or you may write to-M *.,

Energy East Corporanon Attention: Shareholder Services P.O. Box 3200 Ithaca, NY 14852-3200 Please contact Shareholder Services with questions regarding: = our dividend reinvestment and stock purchase plan a dividend payments or lost dividend checks a direct deposit of dividends e replacement of lost certificates j + a change of address + annual report requests e our annual meeting of shareholders The Shareholder Connection.1-800-225-5643 Investor information is available at your fingertips. This service provides quick access to Energy East's common stock closing price as well 1 as timely dividend and news release information 24 hours a day, seven days a week. Internet Address a www.engyeast.com Information of interest to shareholders, including finan-cial documents and news releases, is available at our Web site. Transfer Agent and Registrar ChaseMellon Shareholder Services To present certificates for transfer (certified or registered mail is recommended) write to: ChaseMellon Shareholder Services j P.O. Box 3312 South Hackensack, NJ 07606-1912 To request transfer instructions, write to: ChaseMellon Shareholder Services P.O. Box 3315 South Hackensack, NJ 07606-1915 Investor Relations = Members of the financial community may contact our Manager, Investor jd,. Relations by phone at 607-347 2561 or by fax at 607-347-2560. 1 _U Principal Office Addresses

• P.O. Box 12904, Albany, NY 12212-2904 P.O. Box 1196, Stamford, CT 06904-1196 Shareholders may also obtain a free copy of Form 10-K, which is filed each year with the Securities and Exchange Commission, by contacting Shareholder Services at the telephone number or address listed above.

Trading Symbol

• NEG is the trading symbol for Energy East Corporation common stock listed on the New York Stock Exchange.

Annual Meeting

• The annual meeting of shareholders will be held at 10:30 a.m. on April 23,1999.

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