ML17059A819

Niagara Mohawk Power Corp 1994 Annual Rept

ML17059A819
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Site:	Nine Mile Point
Issue date:	12/31/1994
From:	NIAGARA MOHAWK POWER CORP.
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Niagara Mohawk Power'Corporation 1994 Annual Report 1

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~ Oippoittuuty'ontents 1

Highlights 2

ALetter to Our Shareholders 5

A Commitment to Customer Service 6

Working to Improve Our Performance and Financial Strength 8

Building Our Business 9

Financial Results 52 Corporate Information 58 Officers and Directors ON THLPCOVLlt In this cra ofchange, there remain some constants at Niagara Mohawk. One of these is the tremendous pride we all take in the heritage of the company. That pride is perhaps best embodied by The Spirit ofLight, which graces both our corporate headquarters in Syracuse and the cover ofthis year's Annual Report.

This reporl was produced by Niagara Mohawk employees.

Serving Our Custom~sin UPstate New Yorlc C.

~ Malone

~ Ogdensburg

~ Potsdam Saranac Lake e Glens Fa s

~ Rome

~O

~ Glove+It Schenecta y~

Alb'enyo l

Hudson Niagara Mohawk Power Corp. is an investor-owned utilityproviding energy to the largest customer service area in New York.

Our electric system meets the needs of more than 1.5 million residen-tial, commercial, and industrial customers, with power supplied by hydroelectric, coal, oil, natural gas, and nuclear generating units.

Electricity is transmitted through an integrated operating network that is linked to other systems in the Northeast for economic exchange and mutual reliability.

Our natural gas system provides service to more than 500,000 residential and business customers on a retail basis, as well as a growing number ofcustomers for

~ Os ego whom we transport gas that they purchase directly from suppliers.

Niagara Falls

~ Batavla Syracu e ea We also own a Canadian

~ Buffalo Ii 0 subsidiary, Opinac Energy Corp.,

which operates the electric utility

~oungrk Cortlan

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Canadian Niagara Power.

~ Olea~n Niagara MohawVs Service Area I-iElectric Service 0 Gas 8cElectri Service printod on recrded papdf

HighLights 1994 1993

%Change Total operating revenues Income available for common stockholders Earnings per common share.........

Dividends per common share......

Common shares outstanding (average)...

$ 4,152,178,000 145,311,000 1.00 1.09 143,261,000

$ 3,935,431,000 239,974,000 1.71 0.95 140,417,000 (40.3)

(41.5) 14.7 2.0 Utilityplant (gross) 810,485,889,000

[ '10,108,529,000 Construction work in progress...

Gross additions to utilityplant

. ~~........

Public kilowatt-hour sales.

Total kilowatt-hour sales Electric customers at end ofyear..........

Electric peak load (Ifilozvatts).........

Natural gas sales (de1~atlfenns)

Natural gas transported (delfathenns)

Gas customers at end ofyear...............

Maximum day gas deliveries (delfzztherzzv)...

481,555,000 490,124,000 54,006,000,000 41,599,000,000 1,559,000 6,458,000 85,615,000 85,910,000 512,000 995,801 569,404,000 519,612,000 33,750,000,000 37,724,000,000 1,552,000 6,191,000 83,201,000 67,741,000 501,000 929,285 (15.5)

(5.7) 0.8 10.5 0.5 4.3 2.9 26.8 2.2 7.2 THE l994 REVENUE DOLLAR AND WHEREITWENT~

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'xduding the effect of the write-off of costs associated with the Voluntary Empfoyee Reduction Program.

I A Letter to From Chairman and CEO WilliamL. Davis "We are incorPorating the lessons of the past few years into an aggressive agenda designed to protect the interests ofour shareholders and customers, and guide

¹iagara Mohawk into the new competitive era."

For the past several years, this letter has chronicled the approach ofcompetition in the electric util-ity industry, and the preparations your company has been making to meet the challenges and take advantage of the opportunities that lie ahead.

The events of 1994 provided vivid examples of both the chal-lenges and opportunities facing us. We saw how well-intended government action, as well as government inaction, can have dramatic and harmful conse-quences. We are incorporating the lessons of the past few years into an aggressive agenda designed to protect the interests ofour share-holders and customers, and guide Niagara Mohawk into the new Our Shareholders are still reverberating in Washing-ton as well as Albany, where a new party has taken over leadership after 20 years. Governor Pataki's administration has already ap-pointed a new chairman, commissioner, and general counsel ofthe NewYorkState Public Service Commission, has moved to abolish the state Energy Office, and other personnel and policy changes are likely.

Niagara Mohawk is eager to work with these new government officials to reform regulatory policies that have cost our customers and shareholders dearly.

To that end, I have designated a team to help put in place a legislative and regu-latory regime based on sound economic principles, and to spearhead efforts to reduce the unreasonable payments we must make to unregulated generators, from whom we are required to buy power.

Headed by Gary I ovine, our senior vice president for Legal and Corporate Relations, the team includes experienced talent in the governmental, legal, commu-nications, and financial areas, as well as planning, power supply, gas, and market-ing. Their mission is to persuade govern-ment leaders to allowNiagara Mohawk to compete on an equal footing with un-regulated generators and to ensure that risk is properly compensated, good ser-vice is rewarded, and consumers have the benefit ofenergy costs that willfacilitate, rather than stifle, economic growth.

California ProPosal Becomes A Catalyst for Competition Several key government actions during 1994 had major impacts on the industry, hastening the approach of competition. Perhaps the most important move took place in April when the California Public Utilities Commission announced a proposal to allow large industrial and commercial electricity users in that state to choose their suppliers by 1996. Allcustomers, includ-ing residential, would be able to choose their suppliers by 2002.

Open competition, or retail wheeling, had long been discussed as an abstract concept, but the California proposal brought it into the here and now. The proposal triggered intense debate nation-wide, with more than a dozen other states around the country entertaining some sort ofretail wheeling plan.

Financial markets reacted strongly.

California utility stocks lost the most value, but the shares of virtually every

'lectric utilityin the country dropped, not just in reaction to the California proposal butalso to other industry events through-out tlie year.

Niagara Mohawk's stock price fell in September as a direct result of two adverse regulatory actions. First, the Public Service Commission's trial staff unveiled a proposal to cut our rates by

$146 million.At the same time, the trial staff proposed a plan that would phase in market-based pricing for electricity generation over a 10-year period.

Then, the PSC leap-frogged the California proposal by approving the sale ofelectricity at the retail level by an unregulated generator, Sithe Energies, to Alcan Rolled Products, one of our largest customers.

As a condition of the sale, the PSC required Sithe to partially com-pensate Niagara Mohawk for the loss of Alcan's revenue. Neverthe-less, we believe that the Sithe/Alcan sale is illegal, and are challenging it in court. Without question, this PSC decision highlights the challenges ofemerging competition.

Internal Efforts HelP IrnProve Bottom Line We are working to meet that competition by streamlining our organization dramatically. Since the beginning of 1993, we have consolidated operations and reduced our work force by more than 3,100 positions, or roughly 27 percent.

Despite a smaller workforce, we are aggressively pursuing continued improvement in our performance.

We'e redesigning processes to gain operating efficiencies, eliminating low-value activities, and working together with our labor union to implement.important work-practice improvements that will help us compete.

During 1994 we announced the sale of HYDRA-CO, our indepen-dent power production subsidiary, formore than $200 million.We took that action after a careful review of the regulatory environment for utility subsidiaries in New York state and the advantages ofselling the operation at this time.

We have strengthened our focus on internal cost control by pursuing an activity-based budget-ing process. Every program must be justified each year to ensure that resources are being used efficiently.

For 1994, departmental ex-penses finished below the toughest targets we'e ever imposed. More-over, our 1995-1997 capital budget has been cut by nearly $130 million from the forecast developed at the b'eginning of 1994.

The company earned $1.00 per share in 1994, including a one-time charge against earnings of89 cents-per-share in the fourth quarter to reflect the costs associated with our Voluntary Employee Reduction Program. That program resulted in a 1,400-person reduction in staff-ing and will produce long-term operational savings, including expected savings ofnearly $100 mil-lion in 1995.

Also, shortfalls in all classes of sales, equivalent to 46 cents-per-sharc, were deferred for future recovery in rates under the Electric Revenue Adjustment Mechanism.

With the continuing trend toward competition, this adjustment mechanism may soon be elimi-nated, making the company's sales and earnings more sensitive to market conditions.

InApril,your Board ofDirectors increased the quarterly dividend to 28 cents-per-share, the third increase since the dividend was restored in 1991. At the same time, however, the Board is keenly aware that market and regulatory pres-sures will challenge the company's dividend policy in thc future.

Unregulated Generation and Taxes Remain Major Concerns We'e building strength and competitiveness in our electric operations, but itis clear that inter-nal changes alone aren't enough.

We have significant external costs, and chief among them is the cost ofelectricity we are required to buy from unregulated generators.

Payments made to unregulated generators amounted to nearly

$ 1 billion in 1994, more than 27 cents ofevery dollar we collected from our electricity customers.

More than $350 million of that total is excess cost above what customers would have paid had we not been required to purchase "DesPite our Progress, itis clear that a comPrehensive solution to the unregulated generator Problem is needed to resolve comPetitive inequities.

We wi7lcontinue to aggressiveLy Pursue changesin state policy that willreduce our obligation to purchase unneeded electricity at above-marhet prices from unregulated generators. "

unneeded electricity from unregu-lated generators. Through a variety of actions, we have cut the size of our potential obligations to unregu-lated generators by nearly $2 billion since 1991. Notwithstanding the success of these efforts, we expect our customers will still pay more than $400 million in excess costs during 1995.

Despite our progress, it is clear that a comprehensive solution to the unregulated generator problem is needed to resolve competitive inequities. We will continue to aggressively pursue changes in state policy that will reduce our obligation to purchase unneeded electricity at above-market prices from unregulated generators.

We also have joined other utilities across the nation to pursue actions at the federal level to reduce unregulated generator payments and obligations.

Taxes also are a major cause of escalating electric bills. On average, continued...

New York's utilities pay more than twice as much in taxes as utilities elsewhere. Our second major effort to control external cost factors is directed toward lessening our tax burden, challenging property tax assessments in localities across our service territory, and working to cut or eliminate New York's regressive Gross Receipts Tax.

Setting the Stage for An Orderly Transition We undertook two major initia-tives in 1994 to help promote an orderly transition to a competitive energy marketplace.

First, we proposed a five-year rate plan that would give us more flexibility to compete and save both the company and its regulators the time and expense of annual rate case litigation. We proposed a modest rate increase for 1995, followed by four years during which any rate increases would be capped by a formula based on the inflation rate.

The PSC trial staff responded with a plan intended to cut our elec-tricity rates dramatically over the next 10 years, and force Niagara Mohawk shareholders to bear the brunt of the price cuts. We have strongly opposed the trial staff's plan because it would unfairly penalize shareholders for unregu-lated generator payments,

taxes, and other utility obligations that result directly from state policy.

In late January 1995, the PSC Administrative I awJudges issued a recommended decision on our 1995 rate proposal. The effect would be a decrease in 1995 electricity revenues of $28 million, or 0.9 percent, while gas rates would increase

$ 10.3 million, or 1.7 percent. Ifthe PSC approves 1995 rates at levels similar to those proposed in the ALJ recommended decision, and sales remain weak because ofthe lag in the economic recovery in upstate New York, our 1995 earnings will be considerably lower than adjusted 1994 results of

$1.89 per share.

The second major initiative was a proposal to the PSC of our own transition plan entitled "The Impacts of Emerging Competition iin the Electric UtilityIndustry." Our proposal would reduce some utility costs, redistribute others, and slow down the transition enough for all parties to adjust to a world ofgreater choice. It would share the costs and benefits ofcompetition among all energy suppliers and their customers. We are eager to compete but we will oppose any transition plan or any outcome based on a lack of planning that treats our shareholders and our custom-ers unfairly.

Although the past year was a difficultone, we made progress in several areas. We are buoyed, for instance, by the strong performance and growth of our natural gas operations and by our nuclear performance. We also are encour-aged by our economic development activities, which have helped maintain and attract business.

We remain committed to our Vision of becoming the most responsive and efficient energy services company in the Northeast, and to being the energy provider of choice for our customers. Achieve-ment of that Vision requires that we continue to change, and that we influence both the pace and the direction of the transition to competition in our industry.

The leadership of your com-pany remains certain that every employee is up to the task, and we are grateful foryour confidence in our efforts.

Chairman of the Board and Chief Executive Officer Niagara Mohawk Power Corp.

In Appreciation John M. Endrfes Michael P. Ranalli Niagara Mohawk recognizes with deep gratitude the many contributions ofcompany President John M. Endries and Electric Sup-ply8: Delivery Senior Vice President Michael P. Ranalli, both of whom willretire this year.

Endries joined the company in 1973 as the assistant to the execu-tive vice president of Finance and Corporate Planning. Advancing through positions of increasing responsibility, he was named president in 1988. Endries leaves Niagara Mohawk with a reputation as an astute strategist in a rapidly changing industry.

"I'e had the privilege of working alongside Jack since the day I joined the company," said Chairman WilliamE. Davis. "Ihave been greatly impressed with his intelligence and character. Jack has been the steady hand that guided our operations through a period of major change and challenge."

Ranalli, a 37-year employee, has played many critical roles in the company from overseeing completion of the Nine Mile Unit Two n'uclear plant, to running a successful, corporatewide self-as-sessment program, to streamlining and reshaping the Electric Supply 8c Delivery business unit.

"Everyone who has worked with Mike appreciates his tenacity and forthrightness," said Davis. "We wish them both well."

tv rrvr'rr A Commitment to Customer Service Re are striving for better service to all customers, even as we cut the cost ofproviding that service.

In the world of customer

service, Niagara Mohawk competes with more than just energy providers. We measure our performance against companies ofall types with the best sew ice levels.

To meet this formidable challenge, we'e revamped our customer service orgam-zation from top to bottom.

Two newly renovated facilities the Center for Customer Service Excellence in down-town Syracuse, and Collection Services in the BufTalo Electric Building embody our cus-tomer service commitment.

Replacing regional customer service and collection centers, these centtalized operations offer both improved eAiciency and one-stop shopping for all customers.

Butour commitment goes far beyond these physical changes.

We have been busy identifying best practices within Niagara Mohawk and among peer utili-ties and other service-oriented industries and incorpotating them into our stan-dard customer service procedures.

The result is consistent, high-quality service.

service for customers who deserve prompt answers to their questions and

concerns, and quick responses to their service needs.

Despite the obstacles inherent in broad organizational change, we are making progress in the customer service area. In 1994, for example even with the retirement ofexperienced employees 1994 PSC Complaint Rates for New York State Investor-Owned Gas and Electric Utilities (per 100r000 customers) g Niagara Mohawk iS.2 i2.4 Q Average for sht other trtiLties ip.p J

do gnd ~

<st ~

Itii<'iI The Best Systems and EmPloyees The telecommunication system to be used at these facilities will be second to none. We also willemploy various state-of-the art employee monitoring and assessment methods to ensure continual improve-ment of the level of cus-tomer service.

Operating these new facilities are a group of

<<rima highly trained employees dedicated to helping cus-tomers in any way they can.

The goal ofboth the Cen-Artist's rendering of the compfeted Center for Customer Service Excetlence in downtown Syracuse.

ter for Customer Service Excellence and Collection Services is to provide convenient, efficient, around-the-clock telephone and the coldest winter on record we achieved the second-lowest combined gas and electric PSC complaint rate among New York state utilities. Also, a recent surveyshowedasignificantincrease in the number of customers who gave us a positive rating for their telephone contacts with the company.

During 1995, we will aggressively implement and evaluate a new service commitment: service guarantees.

We will promise to deliver accurate bills and install service withina specific time frame.

And ave will back that promise with custoiner rebates.

Superior customer service is vital to our success.

We are striving for better service to all customers, even as we cut the cost ofproviding that service.

5

'I 1

Working to ImProve Niagara Mohawk was tested at every turn in 1994. Several regulatory developments and escalat-ing payments to unregu-lated generators took their tollon the company's stock price and credit ratings.

Yet the company con-fronted each issue head-on, challenging ill-advised policy, cutting internal and external costs, and improv-ing eHiciency.

The company conPonted each issue head-on, challenging ill-advised Policy, cuttinginternal and external costs, and improving efjciency.

Financial Developments In 1994, the company completed public offerings of $ 150 million of preferred stock and $325 million in first mortgage bonds. In early 1995, we final-.

ized the sale of HYDRA-CO Enterprises, an unregulated generating subsidiary, to CMS Generation, for $206.6 million.

Also, through various refinancing activities during 1994, Niagara Mohawk achieved savings of $5.5 million on long-term debt.

Our Performance and Niagara Mohawk's Eznanczal Strength common stock price de-clined along with other utility stocks in response to investor perceptions of increasing risk due to growing competition. Our stock declined further following two negative actions taken by the New York State Public Service Commission. The price held steady, how-ever, through the latter part of 1994, closing the year at $14.25.

1994 Total Payments and Overpayments to Unregulated Generators (in millions of doHars) st Pgt sz 041 sg60 st,262 st,216

$ 52 Reducing Payments to Unregu lated Generators Mandated payments to unregulated generators are the leading cause of rising electricity bills. We have taken a number of aggressive actions to reduce these payments, including strictlyenforc-ing, and in some cases, renegotiating or canceling contracts. These actions are expected to save customers an estimated

$2 billion in future payments.

However, the problem continues to grow. About 2,400 megawatts of unregu-lated generator capacity are expected to be on-line by the end of 1995. The com-pany is continuing its efforts to mitigate price impacts on customers. During 1994, for example, Niagara Mohawk sought to require several unregulated generators to provide assurance they will repay front-end subsidies.

We estimate that unregulated generators will owe our customers approximately $2.5 billion in such subsidies by 2008. The matter is now in court.

One-time Charge for Employee Reduction In December, the company took a

$ 197 million charge against earnings to cover the cost ofthe Voluntary Employee Reduction Program offered to all employ-ees. In 1995 alone, this program is expected to produce capital and opem-tional savings ofnearly $ 100 million.

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1994 Actual 996 1997 Estimated 1998 1999

NMGas Continues Strong Performance Competition is nothing new to NMGas, our natural gas business unit. In 1994, NMGas operated under the effects of the Federal Energy Regulatory Commission Order 636, the first full year the order was in place. By unbundling gas ser'vices, Order 636 allowed NMGas to compete more effectively for large industrial customers and gave the business unit the abilityto buy natural gas directly from pro-ducers through interstate pipelines.

During the year, several natural gas refueling stations also were added to serve the growing number ofnatural gas vehicles operating in our service territory. NMGas excelled at obtaining, storing and delivering natunl gas economically, offering the lowest prices ofany gas utilityin New Yorkstate during the harsh 1993-1994 winter. And NMGas performed admirably when it set a one-day record for natural gas deliveries by supplying nearly 1 billion cubic feet over a 24-hour period inJanuary 1994.

Seizing these and other oppor-tunities to expand its business, NMGas transported approximately 86 million dekatherms of gas for the year, an increase of nearly 27 percent over the 1993 level. At year-end 1994, NMGas had 512,000 customers, a jump of 11,000 over the year-end 1993 number.

Improvi~ Other Areas Nuclear Performance:

The Nine Mile Units One and Two nuclear plants enjoyed an excep-tional year, operating at 92.1 per-cent and 90.4 percent of capacity, respectively, compared to an industry average of approximately 75 percent. This'erformance marks the best production year ever as a two-unitsite, and their capacity factors are expected to rank Units One and Two on the list of the Top 20 performing nuclear plants in the United States.

In addition, an economic study completed in November supported the continued operation of Nine Mile One, which marked its 25th year ofcommercial operation during 1994.

Cutting Other Generation Costs: Responding to a continuing generating capacity surplus, we have placed Oswego Five, an oil-fired 850-megawatt unit, in long-term cold standby and moved aggres-sively to lower the cost of our remaining generation. Our fossil and hydro generation expense bud-get has declined 45 percent since 1991, improving our ability to com-pete in the wholesale market and helping drive 1994 wholesale sales volume to an all-time high. Capital budgets have declined almost 60 percent since 1991, and will decrease further when federal Clean AirAct modifications to our generating facilities are completed in 1995.

Employment Levels: The Volun-tary Employee Reduction Program was the biggest cost-reduction step in 1994. Nearly 1,400 employees took advantage of this program. By year-end 1995, the company will have 8,750 full-time employees, representing a reduction of 3,100 employees, or nearly 27 percent of the work force, since early 1993.

Employment Levels (ycarwnd)

S75 (995 g 994 p~ec!~4

)993 (992 Committed to the Environment The company continues to build its standing as an environmental leader. In November, Niagara Mohawk and Arizona Public Service signed a precedent-setting agree-ment to reduce carbon dioxide and sulfur dioxide emissions.

Niagara Mohawk willexchange carbon dioxide r'eductions achieved through its Greenhouse Warming Action Plan forsulfur dioxide allow-ances earned by APS under the federal Clean Air Act's acid rain regulations. Niagara Mohawk will permanently remove the sulfur dioxide allowances from the market-place by donating them to an envi-ronmental group. The agreement willreduce national sulfur dioxide emissions, the principal cause of acid rain, by 25,000 tons. Pending IRS approval, Niagara Mohawk will use about $ 1 millionin expected tax benefits from the agreement to fund additional projects that benefit our customers and the environment.

The company also completed plans for the protection ofenviron-mentally sensitive lands on three major river corridors. Niagara Mohawk conveyed 1,768 acres along the Salmon River to the state as part ofa comprehensive plan for the use and care ofthe corridor, and sold a 4,000-acre gorge along the Hudson River to the Nature Conservancy, which will open the area to the public. The company also plans improvements on the Beaver River as part. ofa hydro relicensing agree-ment with the state.

The land-use projects earned the company several environmental awards, including the American Greenways DuPont Award, pre-sented by the Conservation lund, DuPont and the National Geo-graphic Society. Chairman William E. Davis also was selected to serve on the Energy and Transportation Task Force of the President's Council on Sustainable Development.

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Cost cutting and im-proved performance are just two aspects of Nia-gara Mohawk's strategy to enhance its financial standing. To attract new business and to help

~+'~ 'rrir'r>ire cnimncedonrmarketing and pricing programs.

The company's new-est service classification

~

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rates, SC-10 and SC-ll, BuZlding Our BuSZneSS provide discounted flex-'ble pricing options for customers who have altcrnativcs to Niagara Mohawk's electric service. These alternatives include self-gencration, moving, or transferring work to facilities outside ofour franchise area.

For the year, a total of17 commercial and industrial customers took advantage of SC-10, resulting in discounts of approximately $ 12 million. Our SC-11 rate, available since August, has already attracted interest from more than 50 customers.

role in attracting new business and industry. Among the success stories:

~ Wal-Mart Distribution centers in Marcy and Sharon Springs willcreate more than 1,200 newjobs.

~ The United States Post Office selected Syracuse and Latham as locations for two major ncw facilities; 1,250jobs willresult.

~ Deluxe Corp. will bring 250 jobs to downtown Syracuse when the banking supply company opens a

30,000-square-foot processing center in 1995.

~ Transccdar Industries selected Wheatfield in western New York as the location for a 20,000-square-foot warehouse that will eventually employ 40 people.

~ U.S. Electricar chose central New York as the site of a new facility for the production, maintenance, and marketing ofelectric vehicles, bring-ing at least 100 jobs to the area.

Niagara Mohawk willwork with U.S.

Electricar to market electric vehicles in New York state.

To attract new business and to helP existing business customers grow, we have enhanced our marketing and Pricing Programs.

Alltold, Niagara Mohawk's Economic Development department, working with other agencies, chambers of commerce, and local governments, helped bring at least 3,300 newjobs to upstate New York.

Niagara iVIohawk also assisted in the expansion of existing companies that resulted in over 2,200 additional jobs.

Giving Customers the Flenbility to ComPete Our Economic Development department also has been heavily involved in helping customers compete through discounted rate offerings. The most widely used during 1994 was the Economic Revitalization Incentive Rider, available for business customers experiencing financial distress.

In '1994, 25 customers took advan-tage ofERIR discounts, helping to California-based U.S. Eiectricar made major economic news when preserve

$ 13 2 million in net itsefectedupstatewewYorkasthesiteofanewproductionfacility.

Pictured is the mid-size Eiectricar Sedan.

electricity sales and 7,500 jobs.

Another 375 customers participated in two other economic development pro-grams that offer discounts for customers who increase electricity usage, resulting in discounts of approximately $8.5 mil-lion during 1994.

Niagara Mohawk's Economic Devel-opment department also played a vital

l Financial ResuLts Contents 10 Market Price of Common Stock and Related Stockholder Matters 11 Selected Financial Data 12 Management's Discussion and Analysis of Financial Condition and Results ofOperations 29 Report ofManagement 29 Report ofIndependent Accountants 30 Consolidated Financial Statements SS Notes to Consolidated Financial Statements 52 Electric'and Gas Statistics

Market Price ofCommon Stock and Related Stockholder Matters 1994 Dividends Paid Per Share Price Range High Low 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter 1993

$.25

.28

.28

.28

$20e/i 19 17/e 14'/i

$17/e 14'/e 12 12/e 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter

$.20

.25

.25

.25

$22e/e

$18r/e 24'/e 21%

25'/e 23e/e 237/e 19~/i The Company's common stock and certain of its preferred series are listed on the New York Stock Exchange.

The common stock is also traded on the Boston, Cincinnati, Midwest, Pacific and Philadelphia stock exchanges.

Common stock options are traded on the American Stock Exchange. The ticker symbol is "NMK".

Preferred dividends were paid on March 31, June 30, September 30 and December 31. Common stock dividends were paid on February 28, May 31, August 31 and November

30. The Company presently estimates that none of the 1994 common or preferred stock dividends willconstitute a return of capital and therefore all of such dividends are subject to Federal tax as ordinary income.

The table below shows quoted market prices and dividends pcr share for the Company's common stock:

aside for payment, the holders of such stock can elect a majority ofthe Board ofDirectors. Whenever dividends on any Preference Stock are in default in an amount equivalent to six full quarterly dividends and thereafter until all dividends thereon are paid or declared and set aside for payment, the holders of such stock can elect two members to thc Board of Directors.

No dividends on Preferred Stock are now in arrears and no Preference Stock is now outstanding.

Upon any dissolution, liquidation or winding up of the Company's business, the holders of Common Stock are entitled to receive a pro rata share of all of the Company's assets remaining and available for distribution after the full amounts to which holders of Preferred and Preference Stock are entitled have been satisfied.

The indenture securing the Company's mortgage debt provides that retained earnings shall be reserved and held unavailable for the payment of dividends on Common Stock to thc extent that expenditures for maintenance and repairs plus provisions for depreciation do not exceed 2.25% of depreciable property as defined therein.

Such provisions have never resulted in a restriction of the Company's retained earnings.

At year end, about 92,000 stockholders owned common shares of the Company and about 6,000 held preferred stock.

The chart below summarizes common stockholder ownership by size ofholding:

Other Stockholder Matters: The holders ofCommon Stock are entitled to one vote per share and may not cumulate their votes for the election of Directors.

Whenever dividends on Preferred Stock are in default in an amount equivalent to four full quarterly dividends and thereafter until all dividends thereon are paid or dcclarcd and set Size of Holding (Shares) 1 to99 100 to 999 1,000 or more 35,919 50,539 5,247 91,705 1,045,670 12,596,578 130,669,218 144,311,466 Total Stockholders Total Shares Held 8~O 91 A%

MARKETIBOOKCOMPARISON 115&i 1174'Yi u7A7e

$1447

$16%

$17.25

$17.06 1990 1991 1992 1993 1994 10 0

Selected Financial Data As discussed in Management's Discussion and Analysis of Financial Condition and Results of Operations and Notes to, Consolidated Financial Statements, certain of the following selected financial data may not be indicative of the Company's future financial condition or results ofoperations.

1994 1993 1992 1991 1990 Operations: (000's)

Operating revenues.

Net income S 4,152,178 176,984

$3,933,431 271,831

$3,701,527

$3,382,518

$3,154,719 256,432 243,369 82,878 Common stock data:

Book value per share at year end.............

Market price at year end.

Ratio of market price to book value at year end..

Dividend yield at year end.

Earnings per average common share..........

Rate of return on common equity Dividends paid per common share............

Dividend payout ratio Capitalization: (000's)

Common equity.

Non-redeemable preferred stock Redeemable preferred stock.

Long-term debt Total.

First mortgage bonds maturing within one year..

$17.06 141/4 83.5%

79%

S 1.00'8%

S 1.09

, 109.0%

S 2,462,398 290,000 256,000 3,297,874 6,306,272

$17.25 201l4 117.4%

49%

$ 1.71 10.2%

.95 55.6%

$2,456,465 290,000 123,200 3,258,612 6,128,277 190,000

$ 16.33 191ls 117.1%

42%

$ 1.61 10.1%

.76 47 2%

$2,240,441 290,000 170,400 3,491,059 6,191,900

$15.54 177ls 115.0%

36%

$ 1.49 10.0%

.32 21.5%

$2,115,542 290,000 212,600 3,325,028 5,943,170 100,000

$14.37 131ls 91 4%

0.0%

S

.30 2 1oio

.00 0.0%

$1,955,118 290,000 241,550 3,313,286 5,799,954 40,000 Total.

S 6,306,272

$6,318,277

$6,191,900

$6,043,170

$5,839,954 Capitalization ratios:

(including first mortgage bonds maturing within one year)

Common stock equity Preferred stock Long-term debt Financial ratios:

Ratio of earnings to fixed charges..................

Ratio of earnings to fixed charges without AFC.......

Ratio of AFC to balance available for common stock...

Ratio of earnings to fixed charges and preferred stock dividends.........

Other ratios -% of operating revenues:

Fuel, purchased power and purchased gas........

Other operation expenses Maintenance, depreciation and amortization.......

Total taxes.......

Operating income Balance available for common stock..............

39.0%

8.7 52.3 1.91 1.89 6.3oio 1.63 39.6%

18.2 12.3 14.7 10.4 3.5 38.9%

6.5 54.6 2.31 2.26 6.7%

2.00 36.1%

20.9 13.0 16.2 13.3 6.1 36.2%

7.4 56.4 2.24 2.17 9.7%

1.90 34.1%

19.7 13.5 17.3 14.2 5.9 35.0%

8.3 56.7 2.09 2.03 9.3%

1.77 32.1%

20.0 14.4 16.4 15.5 6.0 33.5%

9.1 57.4 1.41 1.35 52.8%

1.17 36.9oio 19.9 14.4 14.4 14.3

1.3 Miscellaneous

(000's)

Gross additions to utilityplant.

Total utilityplant Accumulated depreciation and amortization...

Total assets...........

490,124 10,485I339 3,449,696 9,649,439 519,612 10,108,529 3,231,237 9,471,327 502,244 9,642,262 2,975,977 8,590,535 522,474 431,579 9,180,212 8,702,741 2,741,004 2,484,124

'8,241,476 7,765,406

$470

$574

$659

$659 TOTALTAXES INCLUDINGINCOME TAXES qittUQNs PF MvAs)

OPERAT1ON EXPENSE CONSTRUCllON EXPENOI1VRES

$453

$17

$554

$20 1992

$640

$16 1993

$636

$21 1994

.$625

$609

$ 16 1991 1992 1993 1994 RETAINED EARNINGS (MtUMCF KuNS)

..$169.7

..$329.1

$445.3

$551.3

..$538.6 0

Management's Discussion and Analysis ofFinancial Condition and Results ofOPerations Overview of1994 Results Earnings declined to $143.3 million or $1.00 pcr share as compared to $240.0 million or $1.71 pcr share in 1993, reflecting management's decision to charge earnings for nearly all of the cost of thc Voluntary Employee Reduction Program (VERP), described below, rather than seek rate recovery, based on the impact on future rates of deferring and recovering these costs.

The VERP had been initiated to bring the Company's stafling levels and work practices more into line with peer utilitics and to enable the Company to become more competitive in its cost structure.

Without the VERP charge of approximately $ 197 million

($.89 per sharc), earnings would have improved, reflecting continued cost control efforts and improved gas sales.

Also, because of the Company's NERAM (dcscribcd below),

shortfalls in all classes of sales, equivalent to $.46 pcr share in 1994, were dcfcrrcd for future rccovcry in rates.

The Company's 1995 and multi-year rate proceedings do not seek to extend the NERAM in view of the pricing flexibility sought, although thc separation of thc 1995 phase of the case may present some opportunity to extend this mechanism. The Company's earned return on equity was 5.8%, but without thc VERP charge would have been 10.7%, somewhat below the PSC authorized return on equity on electric utilityoperations of 11.4%.

Earnings for 1995 depend substantially on the outcome of the 1995 rate case discussed below and thc level of rate discounts necessary to minimize loss of industrial customers.

An Administrative Law Judge's Recommended

Decision, discussed below, ifadopted by thc PSC, could result in 1995 earnings being considerably lower than 1994 earnings exclusive of VERP costs.

Beyond 1995, earnings will depend on the outcome of thc multi-year rate case, also discussed below, and thc cxtcnt to whidi competition may erode thy Company's revenues without relief from the burden ofregulatory and legislatively mandated costs.

The Company increased the common stock dividend 12% in 1994 to an annual rate of $1.12.

Exclusive of the VERP charge, the common dividend payout ratio was relatively low, 57.7%, as compared to the rest of the electric and gas industry in 1994. I.Iowevcr, several utilitics reduced common dividend levels and resulting payout ratios in 1994, stating publicly that such actions were to better position these companies for a more compctitivc future. In making future dividend decisions, the Company must likewise evaluate the results of thc 1995 and multi-year phases of its pending rate case and the degree of competitive prcssure on its prices and, therefore, on its future earnings.

The outcome of these rate proceedings will have a signiflcant effect on the Company's liquidityand financing requirements and its ability to obtain financing on customary terms.

Short-term debt exceeded

$400 million at December 31, 1994. A substantial portion of this short-term debt was repaid in January 1995 with the proceeds from the sale of HYDRA-CO (discussed later).

The Company must renew a significant portion of its bank credit arrangements in 1995, and while it expects to be able to secure new arrangements, the cost may be signiiflicantly higher.

The Company also faces a possible downgrade in the ratings of its senior securities to below investment grade.

While management belicvcs long-term debt financing can still be secured by issuing First Mortgage Bonds, the cost ofsuch securities willlikely be higher. The Company is precluded from issuing preferred stock in 1995 due to insufficient dividend covcragc, as a result of the VERP writcoff.

The Company is increasingly challenged to maintain its flnancial condition in the face of expanding competition and probable erosion of traditional regulation.

While utilitics across the nation must address thcsc concerns to varying degrees, the Company believes,that it is more vulnerable than others to competitive threats.

Thc factors contributing to this vulnerability include a,large industrial customer base, an oversupply of high cost mandated power purchases from unregulated generators, an excess supply of wholesale power at relatively low prices and a high tax burden. Recent changes in state leadership may change the energy policics ofNcwYork State. The Company willbe pursuing actions to redress incquitics and reform regulatory policies that have contributed to the Company's increasing prices.

The following sections present an assessment of competitive conditions and steps being taken to improve the Company's strategic and financial position.

Changing Competitive Environnlent'he potential intensity and accclcrating pace of competition may be the most significant factor driving fundamental changes in the way utilities, including the Company, are being managed.

Thc Company believes that the price of electricity may be thc most important element of future success in thc industry and has intcnsiflcd its efforts to reduce various costs that signiflcantly influcnce the price of electricity. The ability to control or rcducc costs may be significantly limited in a number of ways, particularly in the areas of state mandated unregulated generator contracts and cxccssive taxes such as thc gross receipts tax and property taxes.

These costs arc among the most prominent causes of the Company's recent increases in prices, but may be the most controversial problems to solve as judicial, regulatory and/or legislative action will almost certainly be nccdcd to achieve desired results.

The dismissal of the Inter-Power lawsuit and certain developments in the Sithe/Alcan proceeding described below demonstrate some progress, but much more needs, to bc accomplished.

The failure to sccurc favorable 12

judicial, regulatory and/or legislative actions in the near future could have, depending on the pace of competition, severe financial consequences to the Company and would require dramatic steps to protect stockholder interests.

The Company has made significant progress in managing the costs under its direct control.

As described

- below, the Company, as part of its downsizing efforts, completed the VERP program, in which approximately 1,400 active employees elected to participate.

Since December 1992, the employee level willliave been reduced by over 5,100, or 27%.

Capital spending has also been reduced sharply in recent years, with electric construction spending in future years expected to be limited to the level of depreciation expense, thereby resulting in little growth in traditional rate base.

The Company remains focused on materially reducing its total costs.

The increasing movement towards a competitive environment has rcquircd regulators on both the state and federal levels to begin to address the many substantial issues confronting electric utilities. During 1994, the Federal Energy Regulatory Commission (FERC) and the New York State Public Service Commission (PSC) each provided or proposed guidelines to address different aspects of competition.

Thc FERC issued guidelines for pricing clcctric transmission service and proposed guidelines for the rccovcry of stranded (unrecovcrable due to a change in the regulatory environment) costs.

Meanwhile, the PSC, in Phase I of its generic competitive proceeding, adopted guidelines to govern flexible rates which could be offered by utilitics to retain qualified customers.

Phase II of this proceeding willexamine issues relating to the establishment of a wholesale and retail competitive markets (see "Defining Competitive Challenges" below).

Dejz ning Competitive Challenges Company Compctitivcness Study.

Under the terms of its 1994 Rate Agreement with thc PSC, the Company filed a "competitiveness" study on April 7, 1994, entitled "The Impacts of Emerging Competition in the Electric Utility Industry." The assessment ofcompetition contained in thc rcport describes the initial results of the Company's CIRCA 2000 (Comprehensive Industry Restructuring and Competitive Assessment for the 2000s) studies.

Although there is considerable debate about what changes should occur in the electric industry and even more uncertainty about what will actually happen, thc study explores the Company's best estimate of how impacts would vary dcpcnding on the cxtcnt ofchanges in the industry and the

'ace at which those changes are allowed to unfold.

The Company generates electricity from diverse sources to reduce sensitivity to changes in the economics of any single fuel source.

However, the average cost of these diverse fuel sources may be greater'han any single fuel source.

While thc Company's average generation costs are competitive with costs of new suppliers of electricity, the current excess supply of capacity in the Northeast and Canada has signiTicantly depressed wholesale prices, which

'ay be indicative of retail prices in the near term ifretail customers are allowed direct access to the wholesale generation market.

Under these circumstances, by-pass (i.e., sale directly to existing customers by others) of the Company's generation system is a growing threat, although no regulatory structure for by-pass currently exists in New York State. A growing number of municipalities within the Company's service territory are investigating the possibility of achieving by-pass through formation of their own utility operations.

As wholesale entities these new utilities would have open access to transmission and thus would be able to acquire alternative sources of supply.

While thc municipalities exploring this possibility are mostly in the earliest stages of inquiry and currently represent an extremely small percentage of Company

sales, municipalization has the potential to adversely affect the Company's customer base and profitability.

From a broader industry perspective, the Company's assessment concludes that sclcctive discounting to avoid uneconomic by-pass is likely to be effectiv in the current regulatory and competitive regime. Full retail competition, ifnot managed appropriately and consistently, could create significantly higher prices for core customers, jeopardize the financial'viability of the Company and devastate the social programs delivered by thc Company.

While aggressive cost management must be part of any response to competition, it alone cannot address thc financial consequences that may arise from any sudden and dramatic policy change.

As mentioned above, a significant portion of the Company's costs are outside its direct control. The Company believes that regulators, legislators, and utilitics must collaborate to deal with overpaid unregulated generation and other issues to create a fair and equitable transition to increased competition that addresses the obligation to serve, including addressing regulatory obligations for social programs, (i.e., low-income programs),

and provide for proper recovery of shareholder's invcstmcnt.

Certain adversaries of thc Company in New York State and certain governmental officials have stated" that the best way for thc Company to address competitive issues would be to take substantial, but unspccificd in amount, writcdowns of its assets, particularly its nuclear and fossil generating plants.

The Company's position is that any proper solution to the problems posed by increasing competition and deregulation must be substantially more evenhanded, and will ncccssarily be more complicated, than any such proposal.

The Company willvigorously contest inequitable solutions to competitive conditions.

FERC NOPR on Stranded Investment.

The FERC issued a Notice of Proposed Rulcmaking (NOPR) on June 29, 1994 proposing rules governing the ability of utilities to recover wholesale and retail stranded investments (or costs).

The NOPR defines wholesale stranded costs as "any legitimate, prudent and verifiable costs incurred by a public utilityor a transmitting utilityto provide service to a wholesale customer that subsequently

becomes, in whole or in part, an unbundlcd transmission service customer of that public utilityor transmitting utility." The same definition applies to "retail stranded investment" for "retail franchise customers."

c'

For existing contracts, the NOPR proposes that a three-ycar period be set during which the contracts can be negotiated to permit recovery of stranded costs.

FERC would bar recovery where contracts already have exit fees or address stranded costs in some other way. Ifthe parties fail to reach agreement, the utility may unilaterally file a stranded cost provision.

The FERC believes it to be generally inappropriate to permit recovery ofstranded costs via transmission rates and instead prefers renegotiation of bulk (generally wholesale) power contracts.

Further, FERC has indicated a strong preference for the costs of the transition to competition at the retail level to be addressed by the states.

The NOPR sccks comments as to whether the FERC should allow recovery of retail stranded costs in transmission rates under certain circumstances.

The Company has responded, with other New York State utilities, that it is generally supportive of the FERC's findings, but believes that thc FERC must play a more active role in addressing retail stranded cost recovery, particularly in the context of increased municipalization activity discussed above.

PSC Competitive Opportunities Proceeding Electric. In June

1994, the PSC instituted Phase II of its competitiveness opportunities proceeding, the overall objective ofwhich is "to identify regulatory and ratemaking practices that will assist in the transition'o a more competitive electric industry designed to increase efficiency in the provision of electricity while maintaining safety, environmental affordability, and service quality goals."

In an order issued December 22, 1994, the PSC released for comment a series of principles to guide the transition to competition.

The principles emphasize the importance of the economic and environmental well-being of New York State, which "cannot be compromised to accommodate other principles."

Other proposed principles recognize that competition, at least at the wholesale level, willfurther thc economic and environmental well-being of New York State, that "billshock" for any class of customers should be minimized, that the integrity, safety and reliability of the bulk (transmission and distribution) electric system should not be jeopardized, that the current industry structure of a vertically integrated utility (ownership of generation, transmission and distribution activities) is incompatible with effective wholesale or retail competition and that utilities should have a reasonable opportunity to recover "prudent and verifiable expenditures and commitments made pursuant to their legal obligations, as long as the utilities are cooperating in furthering all of the principles."

According to the order, similar cooperation by independent power producers (IPP) should result in "respect for the reasonable expectations of IPP investors."

The PSC has said it believes the transition to competition should balance order, deliberation and speed.

Although the focus of the original order was on the wholesale market, the PSC concluded that the proceeding should examine issues related to retail competition as well. The PSC notes, in its order, that it can only implement these principles within the context of its own authority and that coordination across government is necessary to avoid major dislocation among suppliers of electricity. The Company cannot predict the timing ofresults ofthe proceeding.

FERC Order 636 and PSC Competitive Opportunities Proceeding Gas. Portions ofthe natural gas industry have undergone significant structural. changes.

A major milestone in this process occurred in November 1993 with the implementation of FERC Order 636.

FERC Order 636 requires interstate pipelines to unbundle pipeline sales services from pipeline transportation service.

These changes enable the Company to arrange for its gas supply directly with producers, gas marketcrs or pipelines, at its discretion, as well as to arrange for transportation and gas storage services.

The flexibilityprovided to the Company by these changes should enable it to protect its existing market and still, expand its core and non-core market offerings.

With these expanded opportunities come increased competition from gas marketers and other utilities.

Similar rate initiatives on competitively priced natural gas werc addressed in a generic investigation completed by the PSC in December 1994.

The PSC order in the proceeding significantly expands customer access to competitive gas suppliers using a framework designed to "assure that (1) local distribution companies (LDCs) and new entrants can compete; (2) customers benefit from increased choices and improved performance resulting from a more competitive industry; and (3) core customers continue to receive quality services at affordable rates." The Company intends to respond by proposing a comprehensive restructuring ofrates and services designed to take advantage of the opportunities presented by this new "open" environment.

State Energy Planning Board Initiatives. In October 1994, the State Energy Planning Board issued an updated New York State Energy Plan, which called for significant reductions in state energy taxes, called upon thc New York Power Authority (NYPA) and the state's investor-owned utilities to study the feasibility of creating a joint entity to operate and maintain the nuclear generating stations in the state and endorsed greater competition in utilitypurchases of electricity. The report also called for the development of a fully competitive wholesale generation market in the state within five years and observed that ifutilitygeneration is separated from transmission, the PSC "should consider carefully the valuation and allocation of utilityassets in the regulated and competitive sectors." It recommended that retail competition should occur when fair treatment of all customer classes, competitors, energy efficiency and renewables and capital committed in prudent response to past government mandates is reasonably assured.

The Company is unable to predict whether or how this plan will influence regulatory policy.

NYPA Restructuring Study.

Also during 1994, the NYPA issued a report to its trustccs concerning a proposed restructuring effort for the 21st century. This report stated that a major step toward a competitive electric industry would be to separate transmission from generation. It also stated that another significant advance toward cutting the

'rice of electricity would be the creation of a single C

0 p

~

operating company for all six of New York State's nuclear power plants. In addition, the report recommends creation of a "New York State Electrical Thruway" that would combine all of the State's transmission lines into one independent entity.

The effect on the Company's financial position or results of operations based on any or all of the above events cannot be determined at this time.

In summary, the electric and gas utility industry is undergoing large changes and faces an uncertain future.

To succeed, utilities must be prepared to respond quickly to change.

The Company must be successful in, among other things, helping to bring about favorable regulatory reform to deal with such change, managing the economic operation of its nuclear units and addressing growing electric competition, expanded gas supply competition, and various cost impacts, especially excess high-cost unregulated generator power contracts and taxes.

While the Company will seek full recovery of its investment through the rate setting process with respect to the issues described herein, a review of political and regulatory actions during the past 15 years with respect to industry issues and the experiences of virtually every other industry that has gone through deregulation, indicate that utility shareholders may ultimately bear a significant portion of the burden ofsolving these problems.

Company Efforts to Address Competitive Challenges In response to these issues being faced by the Company, the Company has considered, and is continuing to consider, various strategies designed to enhance its competitive position and to increase its ability to adapt to and anticipate changes in its utility business.

These strategies may include business combinations with other companies, acquisitions of related or unrelated businesses, and additions to or disposition of portions of its franchised service territories.

Additionally, a number of electric utilities have recently announced consideration of plans to organize their operations so that generation and power supply activities are conducted by an entity within the corporate group separate from the entity which provides transmission and distribution services to the utility's customers.

The Company is also studying such a division of its operations, in part because of suggestions by New York governmental officials that power supply should be separated from transmission and distribution functions and in part as a means of dealing with issues related to unregulated generator contracts.

Voluntary Employee Reduction Program (VEEP). In July 1994, the Company announced a voluntary early retirement program and a voluntary separation program (together the VERP) to achieve substantial reductions in its staQing levels in an effort to bring the Company's staHing levels and work practices more into line with other peer group utilities and become more competitive in its cost structure.

Later, union employees approved amendments to the current labor agreement which offered union employees the VERP, in exchange for a negotiated package ofwork rule changes.

Approximately 1,400 active employees elected to participate in the VERP and most terminated their employment as of October Sl, 1994.

The number of employees electing the VERP did not meet management's expectations, and some layoffs have and will continue to occur in an effort to reach a level of approximately 8,750 regular employees during 1995. At December Sl, 1994, the Company had approximately 9,200 employees.

The accrued cost of the VERP is estimated at approximately

$212 million. The Company decided to reduce 1994 earnings by the cost ofthe VERP that is allocable to electric customers, net of allocation to cotenant and other ventures, or approximately $197 million ($.89 per share).

The Company deferred, for proposed recovery over a five year period beginning in 1995, the $ 11 million of VERP costs allocable to gas customers.

In reaching these decisions; the Company considered, among other things, the impact on future rates of deferring and recovering these costs.

Most of the VERP cash cost willbe provided by pension fund assets over time, thereby limiting the immediate cash impact to the Company.

The 1995 cash impact will be approximately $20 million, primarilyin the first quarter.

In a filingwith the PSC on December 23, 1994, the Company updated its rate request for 1995 to reflect the labor and labor-related savings in operating costs as a result ofthe VERP. The savings are expected to amount to nearly

$100 million annually, of which $60 million in 1995 is the labor and related savings allocable to electric and gas expense (the remaining savings, generally allocable to construction, should enable the Company to achieve its construction spending plans for 1995, which have been reduced from prior forecasts).

Unregulated Generator Initiatives are discussed in a separate section below.

Tax Initiatives. The Company has launched a media initiative to inform customers ofhow much (approximately 16%) oftheir utilitybilldirectly pays various forms oftaxes.

The Company is also working with utility and state representatives to explain the negative impact that all tmes, including the gross receipts tax, are having on rates and the state of the economy.

At the same time, the Company is contesting with many taxing authorities the high real estate taxes it is assessed, particularly compared to the taxes assessed unregulated generators.

Customer, Discounts.

The Company is experiencing a loss of industrial load across its system for a variety of reasons.

In some cases, customers have found alternative suppliers or are generating their own. power.

In other cases a

weakened economy has forced customers to relocate or shut down.

As a first step in addressing the threat of further loss of industrial load, the FSC approved a rate (referred to as SC-10) under which the Company was allowed to negotiate 0

0 0

0 15

individual contracts with some of its largest industrial and commercial customers to provide them with clcctricity at lower prices. Under this rate, customers had to demonstrate that they could generate power more economically than the Company's service.

While the SC-10 tariff has now been superseded by the SC 11 tariffdescribed below, seventeen contracts are still in effec and expire by carly 1997.

The total SC-10 discounts amounted to $12.4 millionin 1994.

In Junc 1994, the PSC announced the adoption of guidclincs to govern flexible electric rates offered by utilitics to retain qualified industrial customers in the face of growing competition from unregulated generators, and requiring the Company (and other New York utilities with flexible tariffs) to file amendments to SC-10.

On August 10, 1994, thc Company filed for a new service tariff, SC-II, for "Individually Negotiated Contract Rates."

All new contract rates will be administered under the new SC-ll service classiTication based on demonstrated industrial and commercial competitive pricing situations including, but not limited to, on-site generation, fuel switching, facility relocation and partial plant production shifting. Contracts will be for a term not to exceed seven years without PSC approval.

The Company expects a significant number of industrial customers to negotiate contracts.

Many of these contracts may result in increased load which may be revenue enhancing.

As of December 31, 1994, approximately 20 customers, representing approximately 80 MWofload, had made requests to the Company for an SC-ll contract. 'Thc Company also offers economic development rates, which can result in discounts for existing, as well as new, load. In total, thc Company granted

$39 million in discounts against 1994 revenues, of which it absorbed 20% pursuant to thc 1994 Settlement.

Under its 1995 and multi-year rate proposal, the Company anticipates offerin approximately

$30 million of discounts in excess of the approximately $42 million expected to be reflected in rates in 1995, although no assurance can be given as to the actual amount of discounts. The amount of discounts given willalso depend on thc level of rates authorized in the 1995 rate procccding and the allocation between customer classes. The lcvcl of discounts beyond 1995 and the attendant financial consequences willdepend on a variety offactors.

The increase in the Company's rates over thc past four years, due in large part to required purchases from unregulated generators, has made cogeneration and sclf-generation by many industrial and large commercial customers more economically feasible.

The Company believes its SC-11 tariffpricing flexibilitywill help prevent erosion of its customer base. Price prcssure, however, may limit the recovery of such costs from thc remainder of its customer base.

Sithc/Alcan. In April 1994, the PSC ruled that, in the event Sithc Independence Power Partners Inc. (Sithe) ultimately obtained authority to sell electric power at retail, those retail sales would be subject to a lower level of regulation than the PSC presently imposes on thc Company.

Sithe, which sells electricity to Consolidated Edison Company of Ncw York, Inc. and the Company on a wholesale basis from its 1,040 megawatt natural gas cogeneration plant, also provides steam to Alcan Rolled Products (Alcan).

As authorized by the PSC in September 1994, Sithe also sells a portion of its electricity output on a retail basis to Alcan, previously a customer ofthe Company, and is authorized to sell to Liberty Paperboard (Libe'rty), a potential new industrial customer.

The PSC ordered that Sithe pay the Company a fee over a period of ten years, based upon the prices at which Sithe would sell to Alcan, structured to produce a net present value of approximately $ 19.6 million. For 1995, the fee would be approximately $3.05 million. Thc Company had argued for compensation, which assures discounted rates to Alcan, with a net present value of $39 million. The PSC did not authorize a fee in connection with Sithe's sale to Liberty.

On October 12, 1994, the Company filed an appeal in State Supreme Court, Albany County, which states that the April 1994 PSC Order is a violation of legal procedure and precedent and should bc reversed.

Thc Company cannot"predict the outcome of this proceeding, but will continue to press its position vigorously. Notwithstanding the Company's strong opposition to Sithc's ability to sell to a retail customer, and the level of compensation

involved, the decision to require compensation to utilitics for costs that would otherwisc be stranded has established a

precedent in by-pass situations for some level of recovery of the Company's investment.

Asset Management Studies Fossil.

The Company continually examines its competitive situation and future strategic direction.

Among other things, it has, and continues to, study the economics of continued operation of its fossil-fueled generating plants, given current forecasts ofcxccss capacity. Growth in unregulated generator supply sources, compliance requirements of the Clean AirAct and low wholesale market prices are kcy considerations in evaluating the Company's internal generation needs.

While the Company's coal-burning plants continue to be cost advantageous, certain older units and certain gas/oil-burning units arc continually assessed to evaluate their economic value and estimated remaining useful lives. Due to projected excess capacity, the Company plans to retire or put certain units in long-term cold standby. A total of 340 MW's ofaging coal fired capacity is to bc retired by the end of 1999 and 850 MW's of oil fired capacity was placed in long-term cold standby in 1994.

Thc Company is also continuing to evaluate under what circumstances the standby plant would be returned to service, but barring unforeseen circumstances it is not likely that a return would occur before the end of 1999.

This action will permit the reduction of operating costs and capital expenditures" for retired and standby plants.

The remaining investment in these plants of approximately

$250 million at December 31, 1994 (of which approximately $180 million relates to the facility in cold standby) is currently being recovered in rates through depreciation.

See Note 1 of Notes to Consolidated Financial Statements "Exposure Draft on Impairment ofAssets."

16 0

Asset Management Studies Nine Mile Point Nuclear Station Unit No. 1 (Unit 1). Under the terms ofa previous regulatory agrccmcnt, the Company agreed to prepare and update studies of thc advantages and disadvantages of continued operation ofUnit 1 prior to the start of thc then next two refueling outages.

The first report, which rccominended continued operation ofUnit 1 over thc then next fuel cycle, was filed with the PSC in March 1990 and a second study in November 1992 indicated that the Unit could continue to provide benefits for the term of its license ifoperating costs could be reduced and generating output improved above its then historical average.

Operating experience at Unit 1

has improved substantially since thc 1992 study.

Unit I's capacity factor has been about 94% since its last rcfucling outage.

The third study was filed with the PSC on November 1, 1994.

This study agreed with the November 1992 study, confirming continued operation over the remaining term of its license.

No further economic studies arc currently required for this Unit, although the Company continues as a matter of course to examine thc economic and strategic issues related to operation ofall iis generating units.

In connection with these asset management studies, thc Company also updated its estimated costs to decommission Unit 1. The estimate includes amounts for both radioactive and non-radioactive dismantlement

costs, as well as spent fuel storage cost cstimatcs until the fuel can be transferred to a permanent fcdcral repository. The current estimate of radioactive ($344 million) and non-radioactive

($51 million) dismantlement, in 1994 dollars is approximately

$395 million. Fuel storage and plant maintenance estimates will increase the total estimated costs to approximately $527 million (in 1994 dollars), and this amount escalates to $ 1.4 billion by the time decommissioning is completed.

While these estimates have increased from previous cstimatcs, the delayed dismantlement approach is believed to be the most economic.

The ncw estimates along with increased estimates for the decommissioning of Nine Mile Point Nuclear'tation Unit No. 2 (Unit 2), willbe required to bc rcflcctcd in rates in the future.

Scc also Notes 1 and 3 of Notes to thc Consolidated Financial Statements.

Regulatory Agreements/ProPosals 1995 Five-Year Rate Plan. 'In February 1994, the Company made an electric and ps rate filing,for rates to be effective January 4, 1995, seeking a $133.7 million (4.3%) increase in electric revenues and a $24.8 million (4.1%) incrcasc in gas rcvenucs.

The electric filing included a proposal to institute a methodology to establish rates beginning in 1996 and running through 1999.

Thc proposal would provide for rate indexing,to an applicable qiiarterly forecast of the consumer price index as adjusted for a productivity factor.

Thc methodology sets a price cap, but thc Company could elect not to raise its ntes up to the cap.

Such a'decision would. be based on the Company's assessment of the market.

NERAM (scc "Prior Regulatory Agreements" below) and certain other expense defcrrals would be eliminated, while the fuel adjustment clause would be modified to cap thc Company's exposure to fuel and purchased power cost varianccs from forecast at $ 20 million annually.

However, certain items which are not within the Company's control would be included in billing adjustment factors outside of thc indexing; such items would include legislative, accounting, regulatory and tax law changes as well as environmental and nuclear decommissioning costs.

These items and the existing balances of certain other deferral items, such as MERIT (see "Prior Regulatory Agreemcnts" below), NERAM and demandeide management (DSM), would bc recovcrcd or returned using a temporary rate surcharge.

The proposal would also establish a minimum return on cqtiity which, if not achieved, would permit the Company to refile and reset base rates subject to indexing or to seek some other form of rate relief.

Conversely, in the event earnings exceeded an established maximum allowed return on equity, such excess earnings would bc used to accelerate recovery of regulatory or other assets.

The proposal would provide thc Company with greater flexibilitto adjust prices within customer classes to meet competitive pressures from alternative electric suppliers, but would also substantially increase thc risk that the Company willnot earn its allowed rate of return and that earnings would bc much more volatile than in the past. The Company believes that its proposed rate plan meets the criteria for continued application ofStatcmcnt of1'inancial Accounting Standards No. 71, "Accounting for the Effects of Certain Types of Regulation" (SFAS No. 71).

Gas rate adjustmcnts beyond 1995 would followtraditional regulatory methodology.

In 1994, the Company agreed to cxtcnd the date by which thc PSC must rulc on the Company's rate request by twelve weeks, to March 29, 1995. The Company willabsorb one-half of the costs (thc lost margin) arising because of the extension fromJanuary 4, 1995. The remainder of the costs willbe recovered through a noncash credit to income, and is dependent upon thc amount of rate rclicfultimately granted by the PSC for'995.

Based. on its rcccnt updated filing dcscribcd below, thc Company would absorb approximately $41 million.

On August 31, 1994, the PSC Staff, in response to thc Company's proposal, proposed an overall decrease in electric rcvcnues from 1994 levels of approximately $146 million, excluding anticipated sales growth.'his contrasts with the Company's original proposed total revenue increase, excluding'sales growth, of $146 million for 1995.

Bccausc the Company's proposed total revenue increase reflect an effcctive date of March-29, 1995, while the PSC Staffs proposal is an annualized amount, the difference betwccn the two positions is approximately $366 million.

The more significant adjustments proposed by the PSC Staff include disallowance of approximately $90 million in

'urchased.

'power payments made principally to unregulated generators; additional adjustmcnts to the 1995 unregulated generator forecast for prices, capacity levels

, and in-service dates of certain projects; reductions in operating and maintenance expenses stemming largely from the PSC Staff's contention that, the Company's forecast was unsupported; and assumed increases in 0

17

revenues from sales to other utilities and transmission revenues.

The PSC Staff also proposes to disallow certain unregulated generator buyout costs equal to approximately

$12 million in 1995 and to sct thc electric return on equity at 10.5%, as compared to the Company's request of 11%.

The PSC Staff recommends that gas revenues be reduced by $5 million in 1995, while also recommending a return on equity of 10.5% (as opposed to the Company's request of 11.59%).

The reduction from the Company's gas proposal relates principally to lower departmental expenses and higher expected sales in 1995.

In response to the Company's electric indexing proposal for 1996 through 1999, the PSC Staff proposed the use ofa different index based on the annual change in a national average electricity price, elimination ofall of the Company-proposed adjustment factors outside ofindexing, including those for fuel and purchased power costs, environmental costs, nuclear decommissioning and accounting and tax law

changes, and elimination of thc minimum and maximum return on equity limit. The PSC Staff went well beyond the Company's proposal by recommending a "regulatory regime that accepts market based prices for utility generation."

The PSC Staff's plan would limit, in increasing amounts, the amount of embedded generation

'osts (including certain plant and unregulated generator costs) that could bc charged to customers.

The reference price each year would bc based initially upon the Company's marginal cost of generation (which is significantly below its embedded cost) until a reliable market price becomes available.

After a 10 year phase-down, the Company would only be able to charge a market-related price for generation.

The Company would be forced to absorb the difference between its embedded costs and what it could charge customers, regardless ofwhether its past practices were prudent or even mandated by government action.

Rates with respect to the Company's costs of transmission, distribution and customer service would continue to be based on cost ofservice for 1995, but would be indexed in 1996-1999 by the national average electricity index.

While the PSC Staff's case contains no financial modeling of the potential conscqucnces of its proposal on the Company, such consequences, ifthe plan is adopted as proposed could bc substantial.

While the PSC Staff identified a number of general cost reduction measures intended to mitigate the financial consequences of its proposal, the Company bclievcs the value of the measures is greatly overstated.

The PSC StafFs plan is based on a price ceiling rather than a cost of service theory of

'ratemaking a departure from the Company's case and all prior New York State ratemaking principles. It in effect also proposes a substantial but unquantified disallowance with respect to thc Company's generating plants and a similar but undifferentiated disallowance with respect to the diffcrcncc bctwcen estimated market costs of power and the amount the Company is required, by law and PSC mandate, to pay for unregulated generator power.

If those elements of the PSC Staff's case were to be implcmentcd as proposed, the Company would also be required to discontinue the application ofSFAS No. 71 and incur substantial additional writeoffs. Such writeoffs, which would include a substantial portion of thc $1.4 billion of regulatory assets on the Company's balance sheet as well as the disallowed plant costs and purchased power costs described above, would arise because ofthe departure from cost-based ratemaking and because they would no longer meet the accounting criteria regarding probability of recovery. The Company believes the financial consequences to be of an order of magnitude that would adversely affect the Company's financial position and results ofoperations, its ability to access the capital markets on reasonable and customary terms, its dividend paying capacity, its ability to continue to make payments to unregulated generators and its ability to maintain current levels ofservice to its customers.

Senior members ofthe PSC Staff and other senior public officials in Albany have stated that the PSC trial staff's proposal was developed independent of consultation with Commissioners, that the trial staff functions independently of those individuals and that the process in this proceeding is far from complete.

In the meantime, the Company is continuing to aggressively advocate its own position.

With the December 1994 filing in which the Company proposed to absorb certain VERP costs and reflect labor and related savings, the Company updated its rate request and resultant total bill impact for 1995.

Thc Company is now requesting an increase in 1995 electric revenues of approximately $89 million (2.8%), which reflect the delay in implementing ncw rates, and an increase in 1995 gas revenues of $20.6 million (3.4%). This compares with the electric bill impact ofapproximately 4.3% and gas revenue increase of 4.1% requested in its original filing. The difference between the Company's most recent filing and the PSC StafFs proposal still exceeds $300 million on an annualized basis.

The current rate proceeding has been separated into two distinct phases. 'A final PSC decision on 1995 rates is not expected until thc end ofApril 1995 and new electric rates would be implemented about that time along with any final adjustments to gas rates. Aschedule for the multi-year phase of the procccding has not been established, but is expected to extend at least into the summer of 1995.

On January 27, 1995, thc Administrative Law Judges (ALJ) issued a Recommended Decision with respect to the 1995 phase of the rate proceeding.

The Recommended Decision would allow the Company to increase its electric base rates $253.8 million (7.3%) for thc 1995 rate year and

$10.3 million (1.7%) for gas base rates. The ALJ disallowed from recovery approximately $18 million of unregulated generator costs, but rejected $68 million of disallowances associated with contracts the PSC Staff bclicved should have been bought out. The existing fuel adjustment clause mechanism'would be retained, including full recovery of prudent unregulated generator payments, until addressed in the multi-year phase of the proceeding.

A number of other adjustmcnts to unregulated generator purchases relate to timing of in-service dates, gcncration levels and pricing, which thc Company expects will be fully considered in the fuel adjustmcnt clause.

Finally, the ALJ stated that sufficient evidence had been produced by the 18 0

0 0

0

PSC Staff to warrant a prudence investigation of the Company's unregulated generator contract practices absent a multi-year rate plan.

The Recommended Decision reduced the level of departmental expenses by over $50 million based on the ALJ's assessment of lack of adequate support for the Company's rate request.

The ALJ also recommended a

1% gross margin penalty to ensure that all of.the benefits that might othenvise inure to the shareholders due to the ALJ's perceived lack ofsupport are captured for ratepayers.

In addition, the Recommended Decision does not reflect any of the VERP cost savings, which could be used to further reduce the annualized electric base rate increase by as much as $55 million,and the gas base rate increase by $5 million, depending on whether the Company could demonstrate that several of the ALJs'ecommendations would be duplicated by the VERP cost savings.

An 11%

return on equity was recommended.

Ifthe Recommended Decision were to be adopted in its entirety by the PSC, excluding the further reduction in base rate reliefgranted forVERP cost savings, the Company expects that 1995 electric revenues would decrease by at least 1% or approximately $28 million as compared to 1994, although on a twelve month basis, electric revenues would increase approximately $57 million or 1.9%.

The impact on the Company's earnings, ifthe Recommended Decision were to be fullyadopted by the PSC, will depend substantially on the Company's ability to further reduce costs since little growth in sales is forecast. Without further cost reductions, which must be judged relative to costs under the Company's direct control, earnings for 1995 will be considerably lower than 1994 earnings adjusted for VERP. Ifthe unregulated generator disallowances were adopted by the PSC, the Company would be required to assess whether a loss associated with these contracts, measured by the net present value of unrecoverable costs over the remaining term of the contracts, would be recorded in 1995.

Using projections of long-run avoided

costs, the recordable loss could exceed

$100 million.

While the adoption of the PSC StafFs proposals or the Recommended Decision by the PSC would have a mate'rial adverse impact on the Company's 1995 results of operations, the Company is unable to predict the outcome of these proceedings, or the possible attendant financial consequences.

However, the Company strongly believes that its unregulated generator administrative practices were prudent and should not be disallowed, that the Company's unregulated generator purchases are in large part the result of government policy and should be recovered at no penalty to the shareholders and that any transition plan to a more competitive environment must provide for an equitable allocation of transition costs across customer classes.

In addition, the Company believes that any transition to a morc competitive rate structure should be addressed in a generic proceeding rather than the Company's current multi-year rate filing. The ultimate impact on the Company's financial condition will depend on the pace of change in the marketplace, the actions of regulators and government in response to that change and the actions of the Company in controlling costs and competing effectively while remaining, in substantial part, a regulated enterprise.

The Company is unable to predict the effects of the interaction ofthese factors.

Prior Regulatory Agreements.

The Company's results during the past several years have been strongly influenced by several agreements with the PSC.

A brief discussion of the key,terms of certain of these agreements is provided below.

The 1991 Financial Recovery Agreement implemented the Niagara Mohawk Electric Revenue Adjustment Mechanism (NERAM) and the Measured Equity Return Incentive Term (MERIT).

The NERAM requires the Company to reconcile actual results to forecast electric public sales gross margin used in establishing rates.

The NERAM produces certainty in the amount of electric gross margin the Company will receive in a given. period to fund its operations.

While reducing risk during periods ofeconomic uncertainty and mitigating the variable effects of weather, the NERAM does not allow the Company to benefit from unforeseen growth in sales.

The Company's 1995 and multi-year rate proceedings do not seek to extend the NERAM in view of the pricing flexibilitysought, although, the separation of the 1995 phase of the case may present some opportunity to extend this mechanism.

The lack of a NERAM will inevitably increase earnings volatilitydue to variations in weather and economic conditions.

In 1994, the Company deferred for recovery $ 101.2 million of revenue under the NERAM mechanism for collection in 1995 and 1996.

The MERIT program is the incentive mechanism which originally allowed the Company to earn up to $180 million of additional return on equity through May 31, 1994. The program was later amended to extend the performance period through 1995 and add $ 10 million to the total available award. Overall goal targets and criteria for the 1993-1995 MERIT periods are results-oriented and are intended to measure change in key overall performance areas.

The total available award for 1994 is $34 millionand

$41 million in 1995. Through the 1993 MERIT period, the Company has earned approximately $85.5 million of the

$ 115 millionofMERITavailable and presently assesses that it earned approximately $28 million of the $34 million available for 1994.

On January 27, 1993, the PSC approved a 1993 Rate Agreement authorizing a 3.1% increase in the Company's electric and gas rates providing for additional annual revenues of $108.5 million (electric $98.4 million or 3.4%;

gas $10.1 million or 1.8%).

Retroactive application of the new rates toJanuary 1, 1993 was authorized by the PSC.

The increase reflected an allowed return on equity of 11.4%, as compared to the 12.3% authorized for 1992. The agreement also included extension of the NERAM through December 1993 and provisions to defer expenses related to mitigation of unregulated generator costs, (aggregating

$50.7 million at December 31, 1993) including contract buyout costs and certain other items.

The Company and the local unions of the International Brotherhood of Electrical Workers, agreed on a two-year

nine-month labor contract eflective Junc I, 1993. The new labor contract includes general wage increases of 4% on each June 1st through 1995 and changes to employee benefit plans including certain contributions by cmployccs.

Agreement was also reached concerning several work practices which should result in improved productivity and enhanced customer service.

Thc PSC approved a filing resulting from the union settlemcnt and authorized $8.1 million in additional revenues

($6.8 million electric and

$ 1.3 milliongas) for 1993.

On February 2, 1994, the PSC approved an increase in gas rates of $ 10.4 million or 1.7%.

The gas rates bccamc effective as ofJanuary I, 1994 and include for thc first time a weather normalization clause.

The PSC also approved the Company's electric supplement agreement with the PSC Staff and other parties to extend certain cost recovery mechanisms in the 1993 Rate Agreement without increasing electric base rates for calendar year 1994.

Thc goal of the supplement was to keep total electric bill impacts for 1994 at or below the rate of inflation. Modifications were made to thc NERAM and MERIT provisions which determine how these ainounts are to be distributed to various customer classes and also provided for the Company to absorb 20% of margin variances (within certain limits) originating from SC-10 rate discounts (as described above) and certain other discount programs for industrial customers as well as 20% of the gross margin variance from NERAM targets for industrial

'customers not subject to discounts.

The supplcinent also allows thc Company to begin rccovcry over three years of approximately $ 15 million of unrcgulatcd generator buyout costs, subject to final PSC dctcnnination with respect to the reasonableness ofsuch costs.

Unregulated Generators In recent years, a leading factor. in thc incrcascs in customer bills and the deterioration of thc Company's competitive position has bccn thc requireincnt to purchase power from unregulated generators at prices in cxccss of the Company's internal cost of production and in volumes greater than the Company's needs.

The Company is being forced to make excess payments to unregulated generators, in comparison with its own costs ofproduction, for energy and capacity it docs not currently need.

The Company estimates that it made excess payincnts of approximately $205 million in 1993 and approximately $364 million in 1994 and expects to make excess payments of approximately $409 million in 1995.

Thc Company has initiated a scrics of actions to address ELECIIC PRODUCTION AND PURCHASED POWER Gwhrs 45,000 40,000 35,000 30,000 25,000 20,000 15,000 10,000 5,000 ALLOTHER

'. -.1989 1990 1991 1992 f993 1994 1995 1996 1997 1998 1999 this situation, but cannot predict thc outcome.

Recent changes in state leadership may change the energy policics of New York State.

The Company will be pursuing actions to redress inequities and reform regulatory policies that have contributed to the Company's increasing prices.

As of December 31, 1994, 148 of these unregulated gcncrators with a combined capacity of 2,592 iMWwere on linc and selling power to thc Company.

Of these, 2,273 MW are considered finn capacity (including 207 MW of unregulated generator projects on standby). The table at the bottom of the page illustrates the actual and estimated growth in capacity, payments and rclativc magnitude of unregulated generator purchases compared to Company rcquircments.

By the end of 1994, the Company had virtually all unregulated gcncrator capacity scheduled to come into service on line.

In order to deal with thc growth of cxccss supply, thc Company has taken numerous actions to attempt to realign its supply with demand.

Thcsc actions include mothballing and retirement of Company owned generating facilities (see "Asset Management Studies Fossil") and buyouts of unregulated generator

projects, as well as the implementation of an aggressive wholesale marketing effort.

Such actions have been successful in bringing installed capacity reserve margins down to levels in line 1vith normal planning criteria.

Thc Company is actively pursuing other initiatives to reduce its unregulated generator costs.

Actua!

1991 1992 1993 1,549 2,253

$543

$736 32%

56%

67%

Capacity MW's........

1,027 Payments (millions).....

$268 Percent of Total Fuel and Purchased Power Costs........

1994 2 273

$960 73%

1995 2,403

$1,041 76%

1996 2,403

$1,091 77%

Estimated 1997 2,403

$1,152 77%

1998 2,413

$1,213 78%

1999 2,413

$1,262 78%

20 0

0

$ Mill 1,600 1,400 1,200 1,000 FUEL EXPENSE AND PURCHASED POWER lolls implementation of "curtailment procedures."

Under existing FERC and PSC policy, this petition would allow the Company to limit its purchases from unregulated generators when demand is low. Also, the Company lias commenced settlement discussions with certain unregulated generators regarding curtaihnents.

On April 5, 1994, after informing the PSC of its progress in settlement,.the Company requested the PSC to cxpcditc the consideration of its petition.

The; Company cannot predict the outcome of this action.

ALLOTHER 1989 1990 1991 1992 1993 1994 1995 1996 1997 1996 1999 FERC Proceeding.

On January ll, 1995, the FERC issued an order in a case involving Connecticut Light 8c Power (CL8:P) that the Public UtilityRegulatory Policy Act (PURPA) forbids the states from requiring utilities to pay morc than avoided cost to qualifying facilities (QFs) for electric power. FERC, however, also ruled that itwould not invalidate any pr~xisting contracts, but only would apply its ruling prospectively or'to contracts that are subject to a pending challenge (instituted at the time of signing) by a utility. On the same day, FERC issued an order that an ongoing challenge by the Company to the Ncw York I aw requiring utilitics to pay QFs a minimum of six cents for electric power (thc "Six Cent Law") Ivas moot in light of amendment of that law in 1992 to prohibit future power purchase contracts requiring the utilityto pay morc than its avoided cost. This latter proceeding had been filed in 1987.

In April 1988, FERC had ruled in the Company's favor, finding that the states could not impose rates exceeding avoided cost for purchases from QFs, but then stayed that decision in light of a rulemaking it was instituting to address the issue. That rulemaking was never completed.

On February 10, 1995, the Company filed a petition for rehearing of both orders. The Company argues, among other things, that Federal law requires that FERC apply the ruling in CL8cP in all pending cases, including its case involving thc Six Cent Law, and that it, is entitled to the opportunity, either at FERC or in the courts, to dcinonstrate that pre-existing power purchase contracts resulting from the Six Cent Law should be invalidated. The Company argues further that amendmcnt of the Six Cent Law did not render the procccding addressing that law moot because the amendment has perpetuated and, in some instances, expanded the Company's obligation to purchase power from QFs at rates above avoided cost. The Company intends to press its rights vigorously, but cannot predict the outcome of these procccdings.

Demand for Adequate Assurance.

On February 4, 1994, the Company notified the owners of nine projects with contracts that provide for frontwnd loaded payments of the Company's demand for adequate assurance that the owners will perform all of their future repayment obligations, including the obligation to deliver electricity in thc future at prices below thc Company's avoided cost. and the repayment of any advance payment balance which rcrnains outstanding at the cnd ofthe contract.

The projects at issue total 426 MW. The Company's demand is based on its assessmcnt of the amount of advance payinent to be accumulated under the terms of the contracts, future avoided costs, and future operating costs of the projects. The Company has been sued by the owners of three unrcgulatcd generator projects who challenge the Company's right to demand adequate assurance.

The Company cannot predict'the outcome of these federal and state court actions or the response otherwise to its February 4, 1994 notifications, but willcontinue to press for adequate assurance that thc owners of these projects willhonor their repayment obligations.

EARNED RATE OF RETURN ON COMMON EQUITY 1990 ~

1991 1992 1993 2.1%

1P P%

.......1 0.1 %

.......10.2%

Results ofOPerations Earnings for 1994 were $ 143.3 millionor $1.00 pcr sliarc compared with $240.0 million or $ 1.71 per share in 1993 and $219.9 million or $1.61 per share in 1992. The decline in 1994 earnings was principally due to the charge to earnings of the cost of the VERP of $197 million ($.89 pcr share).

NERAM equivalent to $ 101.2 million ($.46 per share) was recorded in 1994 and deferred for future recovery in rates ss compared to NERAM of $65.7 million

($.31 per share) recorded in 1993.

The primary factor contributing to the increase in earnings in 1993 as compared to 1992 was the impact of electric and gas rate increases effectivJanuary 1, 1993 and July 1, 1992.

Curtailment Procedures.

On August 18, 1992, the Company filed a petition with the PSC which calls for the 1994

~

58%

~

o 0

21-

In 1994, the Company's earned return on common equity was 5.8%, but without the VERP charge would have been 10.7%, compared to 10.2% in 1993 and 10.1% in 1992.

The Company's return on common equity authorized in the rate setting process for the year ended December 31, 1994, provided an electric return on equity cap of 11.4% and a return on equity cap for gas of 10.4%. Factors contributing to the earnings being below authorized levels in 1993 included lower than anticipated results from the Company's subsidiaries, certain operating expenses which were not included in rates and exclusion of approximately $23 million from the Company's rate base (upon which the Company would othenvise earn a return) as a consequence ofprior year writcoffs ofdisallowed Unit 2 costs.

Thc following discussion and analysis highlights items having a signiTicant effect on operations during the three-year period ended December 31, 1994. It may not be indicative offuture operations or earnings. It also should be read in conjunction with the Notes to Consolidated Financial Statements and other financial and statistical information appearing elsewhere in this. report.

Electric revenues increased

$621.7 million or 21.4% over the thrcc-year period.

This increase results primarily from rate increases, NERAM revenues, higher recoveries through the operation of the fuel adjustment clause mechanism, increased sales to other electric systems and other factors as indicated in the table below. An increa'se in the base cost offuel, (which is included in base rates), would typically result in a corresponding decrease in fuel and purchased power cost revenues, thus having a revenue neutral impact.

Purchased power costs, largely from unregulated generators, have increased significantly during this period, offsetting much ofthe decrease in Fuel Adjustment Clause (FAC) revenues which would have occurred otherwise.

Increase (decrease) from prior year, (in millions ofdollars)

Electric revenues Increase in base rates

'uel and purchased power cost revenues..

Sales to ultimate consumers Sales to other electric systems.

DSM revenue Miscellaneous operating revenues.

NERAM revenues.

MERITrevenues.

1994

$ 36.0 108.3 (13.6) 62.1 (27.7)

(4.6) 35.5 0.5

$196.5 1993

$193.1 (42.6) 11.0 11.7 (30.3) 23.9 24.0 (6.0)

$184.8 1992

$250.6 (6.4) 39.7 (12.8)

(24.3)

(11.3) 7.8 (2.9)

$240.4 Total

$479.7 59.3 37.1 61.0 (82.3) 8.0 67.3 (8 4)

$621.7 Although sales to ultimate customers increased slightly in 1994, this level ofsales was substantially below the forecast used in establishing rates for the year.

As a result, the Company accrued NERAM revenues of $101.2 million ($.46 per share) during 1994 as compared to $65.7 million ($.31 per share) ofNERAM revenues in 1993. NERAMwould no longer be available under the ncw rate plan as originally proposed by the Company, thus creating exposure for lost margin ifsales forecasts are not met.

The sales forecast underlying the Company's 1995 rate request reflects an increase in kwh sales of.5% over 1994 actual results.

The Company recorded $12.3 millionof the 1994 MERIT availablc based on management's assessment of thc achievement of objectively measured criteria.

Changes in fuel and purchased power cost revenues are generally margin-neutral (subject to an incentive mechanism discussed in Note 1 ofNotes to Consolidated Financial Statements), while sales to other utilities, because of regulatory sharing mechanisms and relatively low prices due to cxccss supply, generally result in low margin contribution to thc Company.

Thus, fluctuations in these revenue components do not generally have a significant impact on net operating income. The Company has proposed certain changes in thc fuel adjustment clause in its 1995 and multi-year rate proposal (discussed above under "1995 Five-Year Rate Plan" ). Electric revenues reflec the billingof a separate factor for DSM programs, which provide for the recovery ofprogram related rebate costs and a Company incentive based on 10% oftotal net resource savings.

Electric kilowatt-hour sales were 41.6 billion in 1994, an increase of 10.3% from 1993 and an increase of 13.6% over 1992.

The 1994 increase reflects increased sales to other electric systems, while sales to ultimate consumers were generally flat. The increase in wholesale sales reflect thc increase in purchases from unregulated generators and the increase in nuclear production, both ofwhich enabled the Company to make its fossil generation available for sale.

The 1993 increase reflected increased sales to other electric systems, while sales to ultimate customers increased slightly (See Electric and Gas Statistics Electric Sales). The electric margin effect ofsales in 1994 was adjusted by the NERAM except for the large industrial customer class, withinwhich the Company absorbed 20% oftire variance from the NERAMsales forecast. Industrialkpecial sales are New York State Power Authority allocations of low-cost power to specified customers, from which the Company earns a transportation charge.

22 0

e 0

Details ofthe changes in electric revenues and kilowatt-hour sales by customer group are highlighted in the table belotv:

Class of service 1994

%of Electric Revenues 1994 Revenues Sales

% fncrease (decrease) from prior years 1993 Revenues Sales 1992 Revenues Sales Residential........

Commercial...,....

Industrial..........

Industrial - Special..

Municipal service...

34.9%

36.1 16.4 1.4 1.4 52%

(0 6)%

2.5 (2.2) 4.3 5.0 14.5 5.9 (1.3)

(2.3) 6.9%

7.0 (6.0) 9.1 0.6 P.8 3.9 (5.2) 0.8 (3.1) 11.3%

11.1 13.0 11.8 5.8 P 7%

(0.5)

(1.3) 1.9 (0.4)

Total to ultimate consumers.

Other electric systems.....

Miscellaneous...........

90.2 4.7 5.1 3.9 59.1 8.2 0.8 91.1 4.3 0.5 12.6 31.2 40.6 11.4 (12.1)

(29.0) 0.0 (3.5)

Total..

100 0%

59%

10.3%

5.9 3.0%

8.3%

(0.3)

TOTALELECTRIC AND GAS OPERAllNG REVENUES GAS ELECTRIC 1990 1991

$475

$2,908 1992

$554

$3,148 1993

$801

$3.332 1994

.$3,155

..$3,383

..$3,702

..$3,933

..$4,152 ELECTRIC SALES ULTIMATE CUSTOMERS 1990 1991 33,597 1992 33,581 1993 33.750 1994 (MUX%CF KW HRS.)

SALES FOR RESALE 1,511 7,593

........35,544

........36,738

........36,611

........37,724

........41,599 As indicated in the table below, internal generation from fossil fuel sources continued to decline in 1994, principally at the Oswego oil-fired facilityand Albany gas-fired station, corresponding to the increase in required unregulated generator purchases.

There werc no nuclear refueling outages in 1994, while both Units were rcfucled in 1993. Unit 1 operated at a capacity factor of approximately 92% for 1994, while Unit 2 opcratcd at approximately 90%.

The next nuclear refueling outagcs at each unit are scheduled for 1995. Sce Note 5 ofNotes to the Consolidated Financial Statements.

% Change from prior year 1994 1993 1992 1994 to 1993 1993 to 1992 (In mi%l'ons oldollars)

GwHrs.

Cost GwHrs.

Cost GwHrs.

Cost GwHrs.

Cost GwHrs.

Cost Fuel for electric generation:

Coal................;..

Oil Natural gas.............

Nuclear................

Hydro..................

6,783 1,245 700 8,327 3,485 107.3 40.9 16.1 49.5 7,088 113.0 2,177 74.2 548 12.5 7,303 43.3 3,530 8,340

$128.8 3,372 106.6 1,769 44.6 5,031 28.9 3,818 (4.3)%

(42.8) 27.7 14.0 (1.3)

(5 0)%

(44.9) 28.8 14.3 (15.0)%

(35.4)

(69.0) 45.2 (7.5)

(12.3)%

(30.4)

(72.0) 49.8 20>540 213.8 20,646 243.0 22,330 308.9 (0.5)

(12.0)

(7.5)

(21.3)

Electricity purchased:

Unregulated generators...

Other.................

14,794 960.1 10,382 140.3 11,720 9,046 735.7 8,632 543.0 26.2 30.5 35.8 35.5 118.1 8,917 115.7 14.8 18.8 1.5 2.1 25,176 1>100.4 20,766 853.8 17,549 658.7 21.2 28.9 18.3 29.6 Total generated and purchased.......

Fuel adjustment clause..

Losses/Company use...

45,716 1>314.2 12.7 4,117 41,412 1,096.8 39,879 967.6 10.4 19.8 3.8 13.4 (2.2) 6.0

(677.3)

(136.7) 3,688

',268

11.6

12.9 41>599

$1>326.9 37,724

$1,094.6 36,611

$973.6 10.3%

21.2%

3.0%

12.4%

0

Gas revenues increased $148.0 million, or 31.1%, over the three-year period. As shown by the table below, this increase is primarily attributable to increased sales to ultimate customers and increased base rates and gas adjustment clause recoveries.

In 1994, spot market sales declined because the abundance and price of spot gas made it more difficultto earn su6icient margin on these sales.

Spot market sales are generally the higher priced gas available and sold in the wholesale market and yield margins substantially lower than traditional sales to ultimate customers.

Rates for transported gas also yield lower margins than gas sold directly by the Company and, therefore, increases in the volume ofgas transportation services have not had a proportionate impact on earnings.

Changes in purchased gas adjustment clause revenues are generally margin-neutral.

Increase (decrease) from prior year (In millions oldollars)

Gas revenues Increase In base rates.

Transportation of customerwwned gas.......

Purchased gas adjustment clause revenues...

Spot market sales MERITrevenues.

Miscellaneous operating revenues Sales to ultimate consumers and other sales..

1994

$ 7.1 3.5 7.7 (25.4)

(1.3) 7.6 23.0

$22.2 1993

$ 7.3 (9.7) 12.2 27.2 (0 4)

(4.6) 15.1

$47.1 1992

$ 4.7 6.3 12.5 2.6 (0.3) 52.9

$78.7 Total

$ 19.1 0.1 32.4 4.4 (2.0) 3.0 91.0

$148.0 Gas sales, excluding tnnsportation of customerwwned gas and spot market sales, were 85.6 million dekatherms in 1994, a 2.9% increase from 1993 and an 8.1% increase from 1992 (See Electric and Gas Statistics Gas Sales).

The increase in 1994 includes a 2.9% increase in residential sales, a 8.6% increase in commercial sales, both ofwhich were strongly influenced by weather, and a 28.2% decrease in industrial sales. The gas weather normalization clause had an e6ective date ofFebruary 12, 1994, was not ordered to be implemented on a retroactive basis and, therefore, did not have a significant impact on gas revenues. The Company has added approximately 30,000 new customers since 1991, primarily in the residential class, an increase of 6.2%, and expects a continued increase in new customers in 1995.

During 1993, there also was a shift from the transportation sales class to the industrial sales class, corresponding with the implementation ofa stand-by industrial rate.

SALES 78.8 71.7 79.2 1993 83.2 1994 85.8 87.8 132 85 9 1.8 GAS SALES PmmpF sATIItftMs)

DEUVERIES SPOT

..........1 1 2.9 122.4

..........146.2

........164.2

......173.1 In 1994, the Company transported 85.9 million dekatherms (a signiTicant increase from 1993) for customers purchasing gas directly from producers, and expects a continued increase in such transportation volumes in 1995, leading to a forecast increase in total gas deliveries in 1995 ofapproximately 18% above 1994. Public sales are expected to increase approximately 2%. Factors affecting these forecasts include the economy, the relative price di6erences between oil and gas in combination

'with the relative availability of each fuel, the expanded number of cogeneration projects served by the Company and increased marketing efforts. Changes in gas revenues and dekatherm sales by customer group are detailed in the table below:

Class of service 1994

%of Gas Revenues 1994 Revenues Sales

% Increase (decrease) from prior years 1993 Revenues -

Sales 1992 Revenues Sales Residential...

Commercial..

Industrial....

63.9%

25.5 2.4 7.5%

2.9%

9.9 8.6 (21.0)

(28.2) 46%

9.2 84.8 1.8%

6.5 143.6 17.0%

16.6 18.6 12.0%

10.2 (2.2)

Total to ultimate consumers.

Other gas systems........

Transportation of customerwwned gas....

Spot market sales........

Miscellaneous...........

91.8 0.2 6.1 0.7 1N 7.1 2.9 8.7 4.3 10.1 26.8 (85.3)

(88.1) 423.3 7.4 (77.5)

(18.5) 1,056.1 (79.4) 6.4 (80.3) 2.9 1,053.8 17.2 30.0 0.4 16.9 11.1 (32.0)

(21.7)

Total...

10Q Q%

3.7%

5.4%

8.5%

12.3%

16.5%

19.5%

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The total cost of gas purchased decreased 3.2% in 1994, while increasing 13.6% in 1993 and 16.1% in 1992.

The cost fluctuations generally correspond to sales volume changes, particularly in 1993, as spot market sales activity increased.

The Company sold 1.6 and 13.2 million dekatherms on the spot market in 1994 and 1993, respectively.

In 1993, this activity accounted for two-thirds of the 1995 purchased gas expense increase.

The purchased gas cost increase associated with purchases for ultimate consumers in 1994 resulted from a 1.5% increase in dekatherms purchased, coupled with a.9% increase in rates charged by suppliers and an increase of $6.4 million in purchased gas costs and certain other items recognized and recovered through the purchased gas adjustment clause.

Gas purchased for spot market sales decreased

$24.4 million in 1994 and increased $25.8 million in 1993.

The purchased gas cost increase associated with purchases for ultimate consumers in 1993 resulted from a 8.7%

increase in dekatherms purchased, combined with a 2.1%

increase in rates charged by suppliers, offset by a $ 17.8 million decrease in purchased gas costs and certain other items recognized and recovered through the purchased gas adjustment clause. The Company's net cost per dekatherm purchased for sales to ultimate consumers increased to

$3.44 in 1994 from $5.34 in 1993 and was $5.47 in 1992.

Through the electric and purchased gas adjustment

clauses, costs of fuel, purchased power and gas purchased, above or below the levels allowed in approved rate schedules, are billed or credited to customers.

The Company's electric fuel adjustment clause provides for partial pass-through of fuel and. purchased power cost fluctuations from those forecast in rate proceedings, with the Company absorbing a portion of increases or retaining a portion of decreases to a maximum of $15 million per rate year.

While the amounts absorbed in 1992 and 1993 were not material, the Company retained the maximum benefit of$ 15 millionin 1994.

Other operation expense decreased in 1994 by 8.1%, as compared to increases of 9.8% in 1993 and 5.9% in 1992.

The 1994 decrease relates primarily to decreases in nuclear costs associated with the Unit 1 and Unit 2 refueling outages in 1993 ($27 million) and the decrease in amortization of regulatory deferrals ($49 million) which expired in 1993. The 1993 increase is due to an increase in DSM program expenses, nuclear expenses related to increased production along with refueling outages at Unit 1 and Unit 2, amortization of regulatory assets deferred in prior years, increased recognition of other post-retirement benefit costs and inflation.

Maintenance expense decreased 14.2% in 1994 as compared to an increase of 4.5% in 1995, principally due to nuclear expenses incurred during the 1993 refueling outages at Unit 1 and Unit 2 ($19 million).

MAINTENANCEAND OTHER OPERATlON EXPENSE q4lce oF DottNS)

MAINTENANCE OTHER OPERATION

..$805.2

$231.9

$5733

$227.8

$706.4

$228.1

$748.0

..$1,057.6

$236.4

$821.2Ml~

..$957.4

$202.7

$754.7

$934.2 Depreciation and amortization expense for 1994 and 1993 increased 11.5% and 0.9%, respectively.

The increase is attributable to the completion ofrequired improvements to plant into service during late 1993 and early 1994.

Net Federal and foreign income taxes for 1994 decreased due to lower pre-tax income. In 1993 the decrease was due to the tax benefit derived from the Company's Canadian subsidiary upon the sale of its oil and gas investments.

The increase in Other taxes in the three-year period is due principally to higher revenue-based taxes ($36 million),

combined with higher property taxes ($28 million).

Net interest charges decreased

$5.5 million in 1994 and

$9.3 million in 1995, as the result of the First Mortgage Bond refinancing program that began in 1992 and based on existing market conditions is now complete. Dividends on preferred stock increased

$1.8 million in 1994 due to the issuance of $150 million of preferred stock in August 1994, while decreasing

$4.7 million and $5.9 million in 1993 and 1992, respectively, because of reductions in the average amounts of stock outstanding.

The weighted average long-term debt interest rate and preferred dividend rate paid, reflecting the actual cost of variable rate issues',

changed to 7.79% and 6.84%, respectively, in 1994, from 7.97% and 6.70%, respectively, in 1993, and from 8.29%

and 7.04%, respectively, in 1992.

Other items, net, excluding Federal income taxes and allowance for funds used during construction (AFC),

increased

$8.0 million in 1994 and increased $23.4 million in 1993.

The 1994 increase primarily related to increased earnings of subsidiaries which included a nonrecurring gain on the sale of an investment for $9 million. The 1995 increase was the effect of the recording in 1992 of a $45 million reserve against the carrying value of Canadian subsidiary oil and gas reserves.

The sale of the Company's subsidiary, HYDRA-CO Enterprises, Inc. (HYDRA-CO),will be recorded in the first quarter of 1995 as the sale was completed in January 1995 and did not affect 1994 earnings.

HYDRA-CO's earnings for the three years ended December 31, 1994 were not material.

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Effects ofChanging Prices Thc Company is especially sensitive to inflation because of the amount of capital it typically nccds and because its prices are regulated using a rate base methodology that rcflccts thc historical cost ofutilityplant.

The Company's consolidated financial statements are based on historical events and transactions when the purchasing power of the dollar was substantially different from the present.

The effects of inflation on most utilitics, including thc Company, are most significant in thc areas of dcprcciation and utilityplant.

The Company could not.

replace its utilityplant and equipmcnt for the historical cost value at which they are recorded on thc Company's books.

In addition, the Company would not replace these assets with identical ones due to technological advances and compctitivc and regulatory changes that have occurred.

In light of these considerations, the depreciation charges in operating expenses do not reflect the current cost of providing service.

The Company will scck additional revenue or reallocate resources, ifpossible, to cover the costs ofmaintaining service as assets are replaced or rctircd.

I'inancial Position, Liquidityand Capital Resources Financial Position. Thc Company's capital structure at December Sl, 1994 was 52.3% long-term debt, 8.7%

prefcrrcd stock and 39.0% common equity, as compared to 54.6%, 6.5% and 38.9%, rcspcctivcly, at Dccernber 31, 1993.

Book value of the common stock was $ 17.06 pcr share at December Sl, 1994, as compared to $ 17.25 per share at December 31, 1993, reflectin the charge to earnings of the VERP and thc payment of dividends in 1994.

Market analysts have observed that the Company's low market to book ratio, 83.5% at December Sl, 1994, stems from the adverse effects of New York State's economy and regulatory attitudes, as well as unccrtaintics about thc pace of regulatory change, which could result in increased cornpctition and reduced prices.

These adverse clfccts and uncertainties, coupled with high cmbcddcd costs of the Company due principally to unregulated gcncrators and taxes, may make the Company morc vulncrablc titan some other traditional utilitics.

Thc 1994 ratio of earnings to fixed charges was 1.91.

Without the VERP charge, the ratio would have been 2.54.

The ratios of earnings to fixed charges for 1993 and 1992 were 2.31 and 2.24, respectively.

Firms which publish securities ratings have begun to impute certain itcrns into the Company's interest coverage calculations and capital structure, thc most significant of which is the inclusion ofa "levcragc" factor for unregulated generator contracts.

These firms believe that the financial structure of thc unregulated generators (which typically have very high debt-to-equity ratios) and the character of their power purchase agreements increase the financial risk of utilitics. The Company's reported interest covcragc and debt-to-equity ratios have recently been discounted by varying amounts for purposes of establishing credit ratings.

Because of existing commitments for unregulated generator purchases, thc imputation has had and will continue to have a materially negative impact on the Company's financial ratings.

At present, sales of prcfcrrcd stock are not possible and sales of common stock, whichwould cause substantial dilution to current shareholders, arc financially inadvisable.

Construction and Other Capital Requirements.

The Company's total capital rcquiremcnts consist of amounts for the Company's construction program, working capital needs, maturing debt issues and sinking fund provisions on preferred stock. Annual expenditures for the years 1992 to 1994 for construction and nuclear fuel, including related AFC and overheads capitalized, werc $502.2 million, $519.6 millionand $490.1 million, respectively.

PROJECTED CONSTHUCTION AODlTIONS (MLUONS CF DOLLARS CONSTRUCTION AFC & NUCLEAR FUEL

$341

$39

$341

$55

$343

$ 15

$344

$14

$380

.$406

$358

$410

$358 Thc 1995 estimate for construction additions, including overheads capitalized, nuclear fuel and

AFC, is..

approximately $380 million, and is cxpccted to be funded;.';

by cash provided from operations.

Mandatory debt and preferred stock retirements and other requirements are expected to add approximately another $77 million (expected to be refinanced from cxtcrnal sources) to the Company's capital rcquiremcnts, for a total of$457 million.

Current estimates oftotal capital requirements for the years 1996 to 1999 are $475, $408, $480 and $566 million, respectively, of which $406, $358, $410 and $358 million'elates to expected construction additions. The estimate of construction additions included in capital requirements for the period 1996 to 1999 will bc rcvicwed by management during 1995 with the objective of further reducing these amounts where possible.

Thc provisions of the Clean AirAct. Amendments of 1990 (Clean AirAct) arc cxpectcd to have an impact on the Company's fossil gcncration plants during thc period through 2000 and beyond.

The Company has evaluated options for compliance with Phase I of the Clean AirAct, which becomes effective on May Sl, 1995 and continues through 1999. The Company spent approximately $32 and $19 million in 1994 and 1993, respectively, and Iias included $6 millionfor Phase I in its construction forecast for 1995 through 1999 to make.

combustion modifications at its fossil fired plants, including the installation of low NOx burners at the Dunkirk and Huntlcy plants.

With respect to Phase II, preliminary estimates for compliance anticipate approximately $ 17 million in capital costs.

The Company anticipates that 26 0'

additional cxpcnditurcs ofapproximately $70 million may be

.jieccssary for Pliase IIIto be incurred beyond 2000. Thc asset management studies, dcscribcd above, include Phase I, II and IIIestimates for Clean AirAct compliance.

Liquidity and Capital Resources.

Cash flows to meet the Company's rcquiremcnts for operating, investing and financing activities during thc past three years are reported in the Consolidated Statements ofCmh Flows.

During 1994, the Company raised approximately $652.9 million from cxtcrnal sources, consisting of $325.7 million of First Mortgage Bonds, $150 million of Preferred Stock,

$29.5 millionofcommon stock and a net increase of$147.7 millionofshort and intermediate term debt. The proceeds of the $325.7 million ofFirst Mortgage Bonds werc used to provide for the early rcdcmption of approximately $315.7 million of higher coupon First Mortgage Bonds.

The Company also rctircd $190 millionofFirst Mortgage Bonds that matured during 1994.

During January 1995, the Company completed the sale of its wholly-owned subsidiary, HYDRA-CO. Entcrpriscs, Inc. Nct cash proceeds ofapproxiinatcly $200 millionwerc used to reduce short-tcrin debt which aggregated over $400 millionat Decernbcr 31, 1994.

External financing for 1995 is "projected to consist of

$400 to $600 million of First Mortgage Bonds depending upon thc final outcome of the current rate procccding discussed above.

Thc Company's ability to issue more common stock to improve its capital structure is limited by thc unccrtaintics that have dcprcsscd thc stock's price.

The Company would not likely pursue a ncw issue offering unless thc common stock price was closer to book value.

Dcpcnding on the outcoine of the multi-year rate case discussed above, cash provided by operations is generally expected to provide sufficient funds for the Company's anticipated construction program for 1996 to 1999. External financing plans arc subject to periodic revision as underlying assumptions arc changed to reflec developments, most importantly in its rate procccdings.

Thc ultimate level of financing during this four year period will reflect, among other things, thc extent and timing of rate relief, the Company's compctitivc positioning and the extent to which competition penctratcs thc Company's markets, uncertain energy demand due to economic conditions and capital expenditures relating to distribution and transmission load reliability projects, as well as continued expansion of thc gas business.

Environmental standards compliance costs, the effects of rate regulation and various regulatory initiatives, the level of internally generated funds and dividend payments, the availability and cost ofcapital and thc abilityof the Company to-meet its intcrcst and preferred stock dividend coverage requirements, to satisfy legal requirements and restrictions in governing instruments and to maintain an adequate credit rating, also will impact thc amount and type offuture external financing.

ANNUALEXTERNALFINANCINGBY TYPE (MUXMSO:DOUX@

DEST COMMON 1990

......................$ 351.6

$351.6 1991 Pg~'REFERRED

$272.2

$22.9 1992

.............................$ 944.6

$925.1 1993

....................$ 802.1

$685.3

.$652.9

$473.4

$29.5

$ 159.9

$295.1

$ 19.5

$116.8 PREFERRED The Company has initiated a ten to fifteen year site investigation and remediation program that seeks a) to identify and remedy environmental contamination hazards in a proactive and costwffcctive manner and b) to ensure financial participation by other rcsponsiblc parties.

The Company is currently aware of 89 sites with which it has been or may be associated, including 47 which arc Company-owned.

With respect to non-owned sites, thc Company may be rcquircd to contribute some proportionate share ofremedial costs.

The Company has accrued a minimum liabilityof $240 million at Deccmbcr 31, 1994 for its estimated liabilityfor investigation and remediation of certain Company-owned and Company-associated hazardous waste sites, which represents the low cnd of a range of cstimatcs devclopcd from the Company's ongoing site investigation and remediation program. The potential high end of the range is presently estimated at approximately $ 1 billion, including approximately $500 million in thc unlikely cvcnt the Company were required to assume 100% responsibility at nonwwncd sites.

The Company believes that costs incurred in the investigation and rcmcdiation process are rccovcrable in the ratcsctting process as currently in cffcct. Sce Note 9 of Notes to Consolidated Financial Statcmcnts-

"Environmental Contingencies."

Rate agreements since 1991 have included a recovery mechanism and an annual allowance for costs expcctcd to bc incurred for waste site investigation and rcmcdiation.

Thc rccovcry mechanism provides that expenditures over or under the allowance be deferred for future rate consideration.

The Company does not expect these costs to impact external financing, although any such impact is depcndcnt upon the timing of expenditures and associated recovery.

The Nuclear Regulatory Commission (NRC) requires owners of nuclear power plants to place funds associated with decommissioning activities for contaminated portions of nuclear facilitics into an external trust.

Further, the NRC established guidelines for determining minimum amounts that must be available in the trust for these specified decommissioning activities at the time of decommissioning.

Applying thc NRC guidelines, the 27

Company has estimated that the minimum requirements for Unit 1 and its share ofUnit 2, respectively, willbe $381 million and $173 million in 1994 dollars. The Company is seeking an increase in its rate allowance for Unit 1 and Unit 2 decommissioning in its rate case for 1995 to reflect new NRC minimum requirements. Amounts collected for the NRC minimum are being placed in an external trust.

See Note 3 ofNotes to Consolidated Financial Statements "Nuclear Plant Decommissioning."

The Company believes that traditionally available sources of financing should be sufficient to satisfy the Company's external financing needs during the period 1995 through 1999.

As of December 31, 1994, the Company could issue an additional $2,351 million aggregate principal amount of First Mortgage Bonds. This includes approximately $1,311 million from retired bonds without regard to an interest coverage test and approximately $ 1,040 million supported by additional property currently certified and available, assuming a 10%

interest rate, under the applicable tests set forth in the Company's mortgage trust indenture.

The Company also has $200 million of Preference Stock authorized for sale.

The Company will continue to explore and use, as appropriate, other methods ofraising funds.

Ordinarily, construction related short-term borrowings are refunded with long-term securities on a regular basis.

This approach generally results in the Company showing a working capital deficit. Working capital deficits also may be temporarily created because of the seasonal nature of the Company's operations as well as timing differences between the collection of customer receivables and the payment of fuel and purchased power costs.

The Company's accounts receivable increased 23% over 1993, due primarily to the effects of economic conditions in the Company's service territory. A focus on the Company's new centralized collections function will be to improve receivable collections in 1995.

The Company has had sufficient borrowing capacity to fund such a working capital deficit as necessary. Bank credit arrangements which, at December 31, 1994, totaled $580 million are used by the Company to enhance flexibilityas to the type and timing ofits long-term security sales. Ofthe

$580 million total available, $200 million is represented by a Revolving Credit Agreement which expires in 1997. The remainder ofthe arrangements are subject to review by the lenders on an ongoing basis with interest rates negotiated at the time of use.

In 1994, the Company also obtained

$161 million in bank loans, which will expire in 1995 and which the Company expects to renew.

The Company's charter restricts the amount of unsecured indebtedness that may be incurred by the Company to 10% of consolidated capitalization plus $50 million. The Company has not reached this restrictive limit.

The Company's securities ratings at December 31, 1994, were:

Standard & Poors Corporation........

Moody's Investors Service.............

Duff& Phelps......

Fitch Investors Service.............

Secured Debt

'BB-Baa2 BBB BBB Preferred Stock BB+

'baa3

• BBB-

• BBB-Commercial Paper A-3 P-2 Not applicable Not appticable

• Lowest investment grade rating.

As described further below, the security ratings set forth above are subject to revision and/or withdrawal at any time by the respective rating organizations and should not be considered.a recommendation to buy, sell or hold securities of the Company.

The Company's costs offinancing and access to markets have been and could be further negatively affected by events outside its control. The Company's securities ratings could be negatively affected by, among other things, the Company's obligations to purchase power from unregulated generators.

Rating agencies have expressed concern about the impact on Company financial indicators and risk that unregulated generator financial leveraging may have.

The Company's securities ratings and the terms of its access to capital markets could also be negatively impacted by adverse outcomes in the 1995 and multi-year rate proceedings or rapid penetration of competition in the Company's service territory.

In September 1994, Moody's Investors Service placed the credit ratings of the Company under review for possible downgrade.

The review was prompted by both the PSC's September 1994 decision on Sithe/Alcan and the August 1994 proposal from the PSC Staff to reduce the Company's electric and gas rates over the next five years.

Also"in September 1994, Standard and Poors (SkP) placed its ratings on the Company, Con Edison and Long Island Lighting Company on credit watch with negative implications.

This action by S8:P reflected continued concern about a shift in the regulatory environment in New York State that would be even more hostile to the financial health ofthe state's utilities. Ifany rating agency lowers the Company's securities rating, particularly to below investment grade, such action could increase the cost to issue new securities, and/or limitthe Company's flexibility.

28 0

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RePort ofManagement The consolidated financial statements of Niagara Mohawk Power Corporation and its subsidiaries were prepared by and are the responsibility of management.

Financial information contained elsewhere in this Annual Report is consistent with that in the financial statements.

To meet its responsibilities with respect to financial information, management maintains and enforces a system of internal accounting controls, which is designed to provide reasonable assurance, on a cost effective basis, as to the integrity, objectivity and reliability of the financial records and protection of assets.

This system includes communication through written policies and procedures, an organizational structure that provides for appropriate division of responsibility and the training of personnel.

This system is also tested by a comprehensive internal audit program. In addition, the Company has a Corporate Policy Register and a Code of Business Conduct which supply employees with a framework describing and defining the Company's overall approach to business and requires all employees to maintain the highest level ofethical standards as well as requiring all management employees to formally affirm their compliance with the Code.

The financial statements have been audited by Price Waterhouse LLP, the Company's independent accountants, in accordance with generally accepted auditing standards.

In planning and performing their audit, Price Waterhouse considered the Company's internal control structure in order to determine auditing procedures for the purpose of expressing an opinion on the financial statements, and not to provide assurance on the internal control structure. The independent accountants'udit does not limit in any way management's responsibility for the fair presentation ofthe financial statements and all other information, whether audited or unaudited, in this Annual Report.

The Audit Committee of the Board of Directors, consisting of five outside directors who are not employees, meets regularly with management, internal auditors and Price Waterhouse to review and discuss internal accounting controls, audit examinations and financial reporting matters.

Price Waterhouse and the Company's internal auditors have free access to meet individuallywith the AuditCommittee at any time, without management being present.

RePort ofIndependent Accountants To the Stockholders and Board ofDirectors of Niagara Mohawk Power Corporation In our opinion, the accompanying consolidated balance sheets and the related consolidated statements ofincome and retained earnings and of cash flows present fairly, in all material respects, the financial position of Niagara Mohawk Power Corporation and its subsidiaries at December Sl, 1994 and 1993, and the results of their operations and their cash flows for each of the three years in the period ended December Sl, 1994, in conformity with generally accepted accounting principles.

These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits of these statements in accordance with generally accepted auditing standards which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.

An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation.

We believe that our audits provide a reasonable basis for the opinion expressed above.

As discussed in Note 9, the Company is a defendant in lawsuits relating to its actions with respect to certain purchased power contracts. Management is unable to predict whether the resolution of these matters will have a material effect on its financial position or results of operations. Accordingly, no provision for any liability that may result upon resolution of this uncertainty has been made in the accompanying 1994 and 1995 financial statements.

As discussed in Note 2, certain representatives of the New York Public Service Commission have proposed:

i) a plan to establish the Company's rates for its electric business based on a transition plan to market-based prices rather than based on the Company's costs and ii) disallowance of certain costs with respect to unregulated generator contracts. Ifthese proposals or certain provisions thereof are implemented as

proposed, the Company would be required to writedown certain assets, recognize a loss on uneconomic unregulated generator contracts and/or discontinue the application of Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain Types of Regulation" (SFAS No. 71), with respect to portions of the Company's business.

Such writedowns or losses could have a material adverse effect on the Company's financial position and results of operations.

Because the outcome of these matters cannot be predicted, the accompanying financial statements do not include any adjustments that might result from the resolution ofthese proceedings.

Syracuse, New York leap February 1, 1995

('

0 29

Consolidated Statements ofIncome and Retained Earnings In thousands ofdollars For thc year cndcd December 31, Operating revenues:

Electric.............

Gas Operating expenses:

Operation:

Fuel for electric generation Electricity purchased Gas purchased Other operation expenses.

Employee reduction program Maintenance Depreciation and amortization (Note 1)

Federal and foreign income taxes (Note 7).

Other taxes Operating income Other Income and deductions:

Allowance for other funds used during construction (Note 1)..

Federal and foreign income taxes (Note 7).

Other items (net)

Income before Interest charges.

Interest charges:

Interest on long-term debt Other interest.

Allowance for borrowed funds used during construction..

Net Income.

Dividends on preferred stock.

Balance available for common stock Dividends on common stock Retained earnings at beginning of year.

Retained earnings at end of year 1994

'3 528 987 623,191 4,152,178 219,849 1,107,133 315,714 754,695 196>625 202>682 308,351 117,834 496,922 3,719,805 432,373 2,159 6,365 15,045 23,569 455,942

. 264>891 20,987 (6,920) 278>958 176>984 33,673 143,311 156,060 (12,749) 551,332 S

538,583 1993

$3,332,464 600,967 3,933,431 231,064 863,513 326,273 821,247 236,333 276,623 162,515 491,363 3,408,931 524,500 7,119 15,440 7,035 29,594 554,094 279,902 11,474 (9,113) 282,263 271,831 31,857 239,974 133,908 106,066 445,266 551,332 1992

$3,147,676 553,851 3,701,527 323,200

~ 650,379 287,316 748,023 226,127 274,090 183,233 484,833 3,177,201 524,326 9,648 27,729 (16,338) 21,039 545,365 290,734 9,982 (11,783) 288,933 256,432 36,512 219,920 103,784 116,136 329,130 445,266 Average number of shares of common stock outstanding (in thousands).

Balance available per average share of common stock..

Dividends paid per share.

( ) Denotes deduction 143>261 S

1.00 S

1.09 140,417 1.71

.95 136,570 1.61

.76 SO 0

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Consohdated Balance Sheets At December 31, ASSETS Utilityplant (hlole 1):

Electric plant.

Nudear fuel.

Gas plant.

Common plant.

Construction work fn progress...

Total utilityplant Loss: Accumulated depreciation and amortization.

Net utilityplant Other property and Investments Current assets:

Cash, Including temporary cash investments of $50,052 and $100,182 respectively...

Accounts receivable (less allowance fordoubtful accounts of $3,600) (Note 9)..

Unbilled revenues (Note 1)

Electric margin recoverable'.

Matorials and supplies, at average cost:

Coal and oil for production of electricity Gas storage.

Other.

Prepayments:

Taxes Pension expense (Note 8).

Other Rogulatory and other assets (Nolo 2):

Unamortizod debt expense.

Deferred recoverablo energy costs.

Deferred finance chargos...

Income taxes recoverablo.

Recoverablo environmental restoration costs (hlole 9)

Other CAPITAUZATIONAND LIABILmES Capitalization (Note 6):

Common stockholders'quity:

Common stock, issued 144,311,466 and 142,427,057 shares, respectively Capital stock premium and expense.

Retained earnings.

Non.redeemable preferred stock Mandatorily redeemable preferred stock Long.term debt.

Total capitalization.

Current liabilities:

Short-term dobt (Note 5).

Long-tenn dobt duo within one year (Note 6)

SinMng fund roquirements on redeemable proforred stock (Nolo 6).

Accounts payablo.

Payablo on outstanding bank checks Customers'eposits Accrued taxes.

Accrued interest Accrued vacation pay.

Other.

Regulatory and other liabilities:

Accumulated deferred Income taxes (Notes 1 and 7).

Doforrod gnanco charges (hlole 2)

Employoo pension and other benefits (Note 8).

UnbHled revenues (Note 1).

Doferred pension settlement gain Other.

Commltmonts and contingencies (hlotes 2 and 9):

Uabilityfor onvironmental restoration 1994 5 8>285,263 504,320 922,459 291>962 481,335 10>485,339 3,449,696 7,035,643 224,039 94,330 317>282 196,700 66,796 31,652 30,931 150,186 43,249 45,189 976,315 153,047 62,884 239,880 465,109 240,000 252,522 1,413,442

$9,649,439 S

144,311 1,779,504 538,583 2>462,398 290,000 256,000 3>297,874 6,306,272 416,750 77>971 10,950 277,782 64,133 14,562 43,358 63,639 36,550 77,818 1,083,513 1,258,463 239,880 235,741 93,668 50,261 141>641 2,019,654 240,000

$9,649,439 ln thousands oldollars 1993

$7,991,346 458,186 845,299 244,294 569,404 10,108,529 3,231,237 6,877,292 209,051 124,351 258,137 197,200 21,368 29,469 31,689 163,044 23,879 37,238 34,382 920,757 154,210 67,632 239,880 558,771 240,000 203,734 1,464,227;

'9,471,327 k

,142,427 1,762,706 551,332 2,456,465 290,000 123,200 3,258,612 6,128,277 368,016 216,185 27,200 299,209 35,284 14,072 56,382 70,529 40,178 39,565 1 ~166,620 1,344,259 239,880 35,507 94,'968 62,282 159,534 1,936,430 240,000

$9,471,327 0

I 0

i 0

0 0

0

Consolidated Statements ofCash Elotus Increase (Decrease) in Cash-For the year ended December 31, Cash flows from operating activities:

Net income Adjustments to reconcile net income to net cash provided by operating activities:

Amortization of nuclear replacement power cost disallowance....

Depreciation and amortization Amortization of nuclear fuel Provision for deferred income taxes Electric margin recoverable Employee reduction program Allowance for other funds used during construction.

Deferred recoverable energy costs.

(Gain)loss on investments net.........

Deferred operating expenses Increase in net accounts receivable (Increase) decrease in materials and supplies Increase (decrease) in accounts payable and accrued expenses..

Increase (decrease) in accrued interest and taxes Changes in other assets and liabilities.

Net cash provided by operating activities.

Cash flows from Investing activities:

Construction additions Nuclear fuel.

Less: Allowance for other funds used during construction..

Acquisition of utilityplant.

(Increase) decrease in materials and supplies related to construction...

Increase (decrease) in accounts payable and accrued expenses related to construction Increase in other investments.

Proceeds from sale of subsidiary Other Net cash used In Investing activities Cash flows from financing activities:

Proceeds from sale of common stock...

Proceeds from long-term debt Issuance of preferred stock.

Redemption of preferred stock Reductions of long-term debt Net change in short-term debt Dividends paid Other.

Net cash used In financing activities Net Increase (decrease) fn cash Cash at beginning of year Cash at end of year.

Supplemental disclosures of cash flowInformation:

Cash paId during the year for:

Interest Income taxes.

Supplemental schedule of noncash Investing and financing activities:

Liabilityfor environmental restoration 1994

$176,984 (23,081) 308>351 37>887 7,866 (45,428) 196,625 (2,159) 4,748 (59,145) 6,290 (5,991)

(19,914) 14,188 597,221 (439>289)

(46,134) 2,'I59 (483>264) 5>143 (1,498)

(23,375)

(17,979)

(520>973) 29,514 424,705 150,000 (33,450)

(526,584) 48,734 (189,733)

(9,455)

(106,269)

(30,021) 124,351

$ 94,330

$300,242 136,876 fn thousands ofdollars 1993

$271,831 (23,720) 276,623 35,971 30,067 (9,773)

(7,119)

(5,688)

(5,490) 15,746 (36,972) 43,581 15,716 3,996 10,624 615,393 (506,267)

(12,296) 7,119 (511,444) 3,837 3,929 (26,774) 95,408 (15,260)

(450,304) 116,764 635,000 (47,200)

(641,990) 50,318 (165,765)

(31,759)

(84,632) 80,457 43,894.

$124,351

$300,791 106,202 25,000 1992

$256,432 (39,54?)

274,090 26,159 55,929 3,670 (9,648)

(14,329) 44,296 20,257 (44,969)

(28,293) 31,025 10,133 39,565 624,770 (452,497)

(37,247) 9,648 (480,096)

(7,359) 7,756 (11,615)

(31,588)

(522,902) 13,340 835,000 (41,950)

(796,795) 90,130 (140,296)

(44,781)

(85,352) 16,516 27,378

$ 43,894

$323,972 76,519 15,000 0

0 0

Notes to Consolidated Financial Statements I Summary of Significant Accounting Policies The Company is subject to regulation by thc PSC and FERC with respect to its rates for scrvicc under a

methodology which cstablishcs prices based on thc Company's cost. The Company's accounting policics conform to generally accepted accounting principles, as applied to regulated public utilitics, and are in accordance with the accounting requirements and ratemaking practices of thc regulatory authoritics. Sce "Exposure Draft on Impairment of Assets" below and Note 2 Rate and Regula(ory Issues and Contingencies.

Principles of Consolidation:

Thc consolidated financial statements include the Company and its wholly-owned subsidiaries.

Intercompany balances and transactions have been eliminated.

UtilityPlant:

Thc cost of additions to utility plant and of r'cplaccmenis of retircrncnt units of property is capitalized.

Cost includes direct material, labor, overhead and allowance for funds used during construction (AFC).

Replacement of minor items of utilityplant and thc cost of current repairs and maintenance is charged to expense.

Whenever utility plant, is retired, its original cost, together with the cost of removal, less salvage, is charged to accumulated depreciation.

Allowance for Funds Used During Construction:

The Company capitalizes AFC in amounts equivalent to the cost of funds devoted to plant under construction.

AFC rates are determined in accordance with FERC and PSC regulations. The AFC rate in cffcctat December 31, 1994 was 5.75%. AFC is scgrcgatcd into its two components, borrowed funds and other funds, and is reflcc(cd in the Intcrcst charges and the Other income and deductions sections, respectively, ofthe Consolidated Sratcmcnts ofIncome.

Depreciation, Amortization and Nuclear Generating Plant Decommissioning Costs:

For accounting and regulatory purposes, depreciation is computed on thc straight-line basis using the remaining service lives for nuclear and hydro classes of depreciable property and the average service lives for all other classes.

The percentage relationship bctwcen thc total provision for dcprcciation and average depreciablc property was 3.3% for 1994, 3.2%

for 1993 and 3.3% for 1992.

The Company performs dcprcciation studies to determine service lives of classes of property and adjusts thc depreciation rates periodically.

Estimated decommissioning costs (costs to rcmove a nuclear plant from service in the future) for thc Company's Unit 1 and irs sharc of Unit 2 are being accrued over thc scrvicc lives of the units, recovered in rates through an annual allowance and currently charged to operations through dcprcciation. The Company expects to commence decommissioning of both units shortly after cessation of operations at Unit. 2 (currently planned for 2026), using a method which removes or dccontaminates Unit components promptly at that time. Scc Note 3 "Nuclear Plant Decommissioning."

The Financial Accounting Standards Board (FASB) has added to its agenda a project on accounting for obligations for dccomrnissioning of nuclear power plants.

The objective of thc FASB's project is to dctcrmine when a liability for nuclear decommissioning should be recognized, how any such liabilityshould bc measured, and whether a corresponding asset is created.

Ifcurrent electric utility industry accounting practices for such decommissioning are changed, thc Company may bc rcquircd to record the estimated cost for decommissioning as a liability rather than as accumulated depreciation, establish a regulatory asset for thc difl'erence bctwcen the amount accrued to date and the total estimated decommissioning liability and report income from thc external decommissioning trusts as investment incornc

~

rather than as a reduction to decommissioning expense.

The annual provisions for decommissioning could increase.

Thc Company does not believe that such ch'anges, if required, would have an adverse effect on results of operations due to thc Company's belief that decommissioning costs willcontinue to bc recovered in rates (Sce "Exposure Draft on Impairment ofAssets", below).

Amortization of the cost of nuclear fuel is determined on thc basis of the quantity of heat produced for the generation of electric energy.

The cost of disposal of nuclear fuel, which presently is $.001 per kilowatt-hour of net gcncration available for sale, is based upon a contract with the U.S. Departrncnt of Energy.

These costs arc charged to operating expense and recovered from customers through base rates or through the fuel adjustmcnt clause.

Revenues:

Revenues arc based on cycle billings rendcrcd to certain customers monthly and others bi-monthly.

Although thc Company commcnccd thc practice in 1988 of accruing electric revenues for energy consumed and not billed at thc end of the fiscal year, thc impact of such accruals has not yet been fullyrccognizcd in the Company's results ofoperations bccausc ofregulatory requirements.

At Dcccrnbcr 31, 1994 and 1993, approximately $71.8 million and $74.1 million, rcspcctivcly, ofunbillcd clcctric revcnucs remained unrecognized in results of operations, are included in Dcfcrred Credits and may bc used to reduce future revenue rcquiremcnts.

At December 31, 1994 and 1993, thc Company accrued

$21.9 and $20.9 million, rcspectivcly, of unbilled gas revenues which remained unrecognized in results of operations and will similarly be used to rcducc future gas revenue requirements.

Thc Company's tariffs include electric and gas adjustmcnt clauses under which energy and purchased gas costs, rcspectivcly, above or below thc levels allowed in approved rate schedules, arc billed or credited to customers.

The Company, as authorized by thc PSC, charges operations for energy and purchased gas cost 0

0 0

~

0 0

increases in the period of recovery.

The PSC has periodically authorized the Company to make changes in the level of allowed energy and purchased gas costs included in approved rate schedules.

As a result of such periodic changes, a portion of energy costs deferred at the time of change would not be recovered or may be overrecovercd under the normal operation of the electric and gas adjustment clauses.

However, thc Company has to date been permitted to defer and bill or credit such portions to customers, through the electric and gas adjustment clauses, over a speciTicd period oftime from the eflcctive date ofeach change.

The Company's electric fuel adjustment clause (FAC) provides for partial pass-through of fuel and purchased power cost fluctuations from amounts forecast, with the Company absorbing a portion of increases or retaining a portion of decreases up to a maximum of $ 15 million per rate year. Thereafter, 100% of the fluctuation is passed on to ratepayers.

The Company also shares with ratepayers fluctuations from amounts forecast for net resale margin and transmission

benefits, with the Company retaining/absorbing 40% and passing 60% through to ratepayers.

The amounts retained or absorbed in 1992 through 1994 were not material.

In the Company's current rate proceeding the Company has proposed to eliminate the FAC and replace it with the fuel adjustmcnt mechanism (FAM). Ifthis is implemented, the portion of fuel and purchase power cost fluctuations,"

from amounts forecast, that the Company would retain or absorb could reach a maximum of $20 million per rate year. For the additional years of the rate proceeding's five-year plan (1996-1999), the 1995 monthly fuel cost would form the basis for the forecast.

Beginning in 1991, the Company's rate agreements provided for NERAM, which permits the Company to reconcile actual results to forecast electric public sales gross margin as defined and utilized in establishing rates.

Depending on the level of actual sales, a liability to customers was created ifsales exceed the forecast and an asset recorded for a sales shortfall, thereby generally preserving recorded electric gross margin at the level forecast in established rates.

The 1994 rate settlement provided for the operation of the NERAM through December 31, 1994.

Recovery or refund of accruals pursuant to the NERAM is accomplished by a surcharge (either plus or minus) to customers over a twelve-month period, to begin when cumulative amounts reach certain speciiflied levels.

While the NERAM may be terminated in 1995, the recovery period of the outstanding balance as of December 31, 1994 willnot be affected.

In February 1994, the Company implemented a weather normalization clause for retail customers who use gas for heating to reflec the impact of variations from normal weather on a billingmonth basis for the months ofOctober through May, inclusive.

Normal weather is defined as the 30 year average daily high and low temperatures for the Company's main gas service territory. The weather normalization clause will only be activated if the actual weather deviates 2.2% or more from the normal weather.

Weather normalization clause adjustments were not significant to 1994 gas revenues.

A Rate agreements since 1991 also include MERIT, under which the Company has the opportunity to achieve earnings above its allowed return on equity based on attainment of specified goals associated with its self-assessment process.

The MERIT program provides for specific measurement periods and reporting for PSG approval ofMERIT earnings.

Approved MERITawards are billed to customers over a period not greater than twelve months.

The Company records MERIT earnings when attainment of goals is approved by the PSC or when objectively measured criteria are achieved.

MERIT expires at the end of 1995.

Federal Income Taxes:

As directed by the PSC, the Company defers any amounts payable pursuant to the alternative minimum tax rules.

Deferred investment tax credits are amortized to Other Income and Deductions over the useful life ofthe underlying property.

Statement of Cash Flows: The Company considers all highly liquid investments, purchased with a remaining maturity ofthree months or less, to be cash equivalents.

Reclassificationsi Certain amounts from prior years have been reclassified on the accompanying Consolidated Financial Statements to conform with the 1994 presentation.

Exposure Draft on Impairment of Assets:

In November 1993, the FASB issued an Exposure Draft on "Accounting for the Impairment of Long-Lived Assets."

= The Exposure Draftwould require companies, including utilities, to assess the need to recognize a loss whenever events or circumstances occur which indicate that the carrying amount of an asset may not be fully recoverable.

An impairment loss would be recognized ifthe sum of the future undiscounted net cash flows expected to be generated by an asset is less than its book value.

The amount of the loss would. be based on a comparison of book value to fair value.

The Exposure Draft would also amend Statement of Financial Accounting Standards No.

71, "Accounting for the Effects of Certain Types of Regulation," (SFAS No. 71) to require writeoffof a regulatory asset ifit is no longer probable that future revenues willrecover the cost ofthe asset.

The Exposure Draft, which is expected to become applicable in 1996, may have consequences to a number of utilities, including the Company, which are facing growing competitive threats that may erode future prices, and which have relatively high-cost nuclear generating assets and unregulated generator contracts.

The Company is also faced with ratemaking proposals by the PSC Staff in the current 1995 and multi-year rate cases, and by the Administrative LawJudges (ALJ's) Recommended Decision in the 1995 case, that would likely result in asset impairment issues under the Exposure Draft provisions if the PSC StafFs proposals or the Recommended Decision are adopted by the PSC.

See Management's Discussion and c,

o 1[

0

Analysis "Regulatory Agreements/Proposals" for a morc extensive discussion of the competitive threats facing the Company and of the PSC StafFs proposals and the ALJ's Recommended Decision.

While the Company is unable to determine the financial consequences of applying the provisions of the Exposure Draft, if the PSC Staff's proposals and/or the ALJ's Recommended'Decision are adopted, they would have a material adverse effect on the Company's financial position and results ofoperations.

2 Rate and Regulatory Issues and Contingencies In accordance with SFAS No. 71, the Company's financial statements reflec assets and costs based on ratcmaking conventions, as approved by the PSC and the FERC.

Certain expenses and credits, normally reflected in income as incurred, are only recognized when included in rates and recovered from or refunded to customers.

Historically, all costs of this nature which are determined by the regulators to have been prudently incurred have been'recoverable through rates in the course of normal ratemaking procedures and the Company believes that the items detailed below willbe afforded similar treatment.

Continued accounting under SFAS No. 71 requires, among other things, that rates be designed to recover specific costs of providing regulated services and products and that it be reasonable to assume that rates are sct at levels that willrecover a utility's costs and can be charged to and collected from customers.

When a utilitydetermines it can no longer apply the provisions of SFAS No. 71 to all or a part of its operation, it must eliminate from its balance sheet, the effect of actions of regulators that had been recorded previously as assets and liabilities pursuant to SFAS No. 71 but which would have not been so accounted for by enterprises in general.

The Company's proposed multi-year rate plan for 1995-1999 contemplates no change in this approach to such reporting, even though the plan recognizes that in a more competitive environment an effective response to thc general prcssure to manage costs and preserve or expand markets is vital to maintaining profitability. The Company's proposed plan includes thc establishment of rates for 1995 on a cost of service basis, followed by an index-based approach to rates for 1996 through 1999. The index is based on inflation factors believed to be indicative of cost incrcascs to be experienced by the Company.

Tlie proposal for 1996-1999 also includes adjustment factors related to cvcnts outside the Company's control and a mechanism for resetting rates if the expected return on equity falls below a minimum threshold.

Therefore, thc Company believes that it can continue to apply SFAS No. 71 under its multi-year rate proposal.

Thc PSC Staff has proposed a multi-year ratesetting plan which the Company believes would require writedown of certain assets, would not permit the continued application of SFAS No. 71 to its generation operations and may I

r 0

I

~

0 similarlyjeopardize application of SFAS No. 71 to its transmission and distribution operations under certain circumstances.

The ALJ's Recommended Decision proposes to disallow from recovery approximately $ 18 million of unregulated generator costs, recommends a

prudence investigation of the Company's unregulated generator contract practices absent a multi-year rate plan, proposes to reduce the level of departmental expenses and gross margin because of "lack of support" and states that the VERP savings could bc used to further'reduce the rate increase recommended.

Sce Management's Discussion and Analysis ofFinancial Condition and Results of Operations-

"Regulatory Agreements/Proposals" for a discussion of the PSC StafFs and ALJ's proposals and potential financial consequences.

In the event that the Company is required to writedown its assets, recognize a loss on uneconomic unregulated generator contracts and/or could no longer apply SFASNo. 71 to either its generation operations or to its entire electric business, a material adverse effec on its financial condition and results ofoperations would result.

The Company bclicves the financial consequences to be of an order of magnitude that would adversely affect the Company's financial position and results of operations, its ability to access the capital markets on reasonable and customary terms, its dividend paying capacity, its ability to continue to make payments to unregulated generators and its ability to maintain current levels of service to its customers.

The Company has rccordcd the followingregulatory and other assets:

In thousands oldollars At December 31, 1994 1993 Income taxes recoverable...........

Recoverable environmental restoration costs................

Deferred finance charges...........

Unamortized debt expense..........

Deferred postrefirement benefit costs..

Deferred recoverable energy costs....

Deferred unregulated generators'ontract termination costs.........

Deferred gas pipeline costs.........

Other.

Total.

465,109 558,771 240,000 239,880 153,047 67,486 62,884 38,286 17,000 129,750 240,000 239,880 154,210 30,741 67,632 4

50,680 31,000 91,313

$1,413,442

$1,464,227 Income taxes recoverable represents the expected future recovery from ratepayers of the tax consequences of temporary difference between the recorded book bases and the tax bases of assets and liabilities. These amounts are amortized and rccovcrcd as thc related temporary differences reverse.

In January 1998, the PSC issued a

Statement of Interim Policy on Accounting and Ratemaking Procedures that required adoption of Statement of Financial Accounting Standards No. 109 "Accounting for Income Taxes" (SFAS No. 109) on a revenue-neutral basis.

Recoverable environmental restoration costs represent thc Company's sharc of thc estimated costs to investigate and perform certain remediation activities at both Company-

owned sites and non-owned sites with which it may bc associated.

Current rates provide an annual allowance to recover anticipated annual expenditures.

Deferred finance charges represent thc deferral of thc discontinued portion of AFC related to construction work in progress (CWIP) at Unit 2 which was included in rate base.

In 1985, pursuant to PSC authorization, the Company discontinued accruing AFG on CWIP for which a cash return was being allowed.

This amount, which was accumulated in deferred debit and credit accounts up to the commercial operation date of Unit 2, awaits future disposition by the PSC.

A portion of the dcfcrred credit could be utilized to reduce future revenue requirements over a period shorter than the life of Unit 2, with a like amount ofdeferred debit amortized and rccovcrcd in rates over the remaining lifeofUnit 2.

Unamortized debt expense reprcscnts the costs to issue long-term debt securities including premiums on certain debt retirements prior to maturity.

These amounts are amortized as interest expense ratably over the lives of the related issues in accordance with PSC directives.

Deferred gas pipeline costs reprcscnt the estimated restructuring costs the Company anticipates incurring as a result of FERC Order No. 636. These costs are treated as a cost of purchased gas and are recoverable through the operation of the gas adjustmcnt clause mechanism, or direct surcharge to transportation custorncrs over a period of approximately 7 years beginning in 1994, with recovery more heavily weighted in the first 3 years.-

Allother regulatory assets are generally being amortized over various periods or addressed in the Company's current rate filingunder a provision which proposes recovery using a one-year rate surcharge.

The above regulatory assets are generally not included in rate base (and therefore do not earn a return) either because an outlay of funds has not yct occurred or as a result ofregulatory policy.

3 Nuclear OPerations r

The Company is thc owner and operator of thc 613 MW Unit I and the operator and a 41% c~wncr of the 1,062 MW Unit 2. Unit 1 was placed in commercial operation in 1969 and Unit 2 in 1988.

Deferred postretirement benefit costs represent the cxccss of such costs recognized in accordance with Statement of Financial Accountirig Standards No. 106 "Employers'ccounting for Postretirement Benefits Other Than Pensions" (SFAS No..106) over thc amount received in rates.

In accordance with the PSC policy statement, postretirement benefit costs other than pensions are being phased-in to rates over a five-year period and amounts deferred willbe amortized and recovered over a period not to exceed 20 years.

Deferred recoverable energy costs includes thc diffcrcncc between actual fuel costs and thc fuel revcnucs rcceivcd through the Company's fuel adjustment clause.

The balance also includes the unamortized portion of thc Company's mandated contribution to dccornmission thc Department of Energy's (DOE) uranium enrichment facilities. The costs to decommission DOE facilitics result from the Energy Policy Act of 1992, which requires domestic utilities to contribute amounts, escalated for inflation, based upon the amount of uranium cnrichcd by DOE for each utility. The fuel costs arc amortized as they arc collected from customers while thc costs to decommission the DOE facilities are being amortized and recovered, as a fuel cost, over a period ending in 2006.

Dcfcrred unregulated generators'ontract termination costs rcprcsent thc Company's cost to buy out certain unregulated gcncrator projects. Approximately $15 million of these costs are currently being recovered over a three-yea'r period beginning in 1994. The remaining costs are being addressed in the Company's current rate filing.

'Unit 1 Economic Study:

Under thc terms of a previous regulatory agreement, the Company agreed to prcparc and update studies of the advantages and disadvantages of continued operation of Unit 1'. The 1990 study rccommcndcd continued operation of Unit I over the next fuel cycle, and the 1992 study indicated that the Unit could continue to provide benefits for the term of its license (2009) ifoperating costs could bc reduced and generating output improved above its then historical average.

Thc 1994 study again confirmed that continued operation over the remaining term of its license is warranted.

The Company will continue as a matter of course to examine the economic and strategic issues related to operation ofall its generating units.

The operating experience at Unit 1 has improved substantially since the prior study. At Dccembcr 31, 1994, Unit 1's capacity factor Iias been about 94% since the 1993 refueling outage.

The Company's net investment in Unit 1 is approximately

$575 million,cxclusivc ofdecommissioning costs.

Unit I Status:

A scheduled refueling outage began on February 8, 1995.

Using the net design electric rating as a basis, Unit I's capacity factor for 1994 was approximately 92%.

Using NRC guidelines, which reflec nct maximum dependable capacity during the most restrictive seasonal conditions, Unit I's capacity factor was approximately 99%.

Unit 2 Status:

The next refueling outage is scheduled to begin in April 1995.

Using the net design electric rating as a basis; Unit 2's capacity factor for 1994 was approximately 90%.

Using NRC guidelines as described above, Unit 2's capacity factor was approximately 96%.

0 0

0 0

0

Nuclear Plant Decommissioning:

Thc Company estimates thc cost of decommissioning Unit 1 and its ownership intcrcst in Unit 2 at December 31, 1994 as follows:

Site Study(year)...........

End of Plant Life (year)......

Radioactive Dismantlement to Begin (year)...........

Method of Decommissioning Unit 1 Unit 2 1994 1989 (a) 2009 2026 2026 2029 Delayed Immediate Dismantlement Dismantlement Cost of Decommissioning (in 1994 dollars) in millions ofdollars Radioactive Components.........

$344

$207 Non-radioactive Components......

51 33 Fuel Dry Storage/Continuing Care..

132 50

$527

$290 (a) The estimate of Unit 2's decommissioning costs was updated by extrapolating data from the updated Unit 1 decommissioning estimate.

The Unit 2 estimate should be considered preliminary, as the Company expects to perform a more detailed study in 1995.

The Company estimates by the time decommissioning is completed, thc above costs will ultimately amount to $1.4 billion and $1.0 billion for Unit 1 and Unit 2, respectively, using 2.8% as an initial inflation factor.

This factor incrcascs gradually, reaching a maximum of 3.4% in thc year 2004 and for the years thcrcaftcr.

In addition to the costs mentioned above, the Company expects to incur post-shutdown costs for plant rampdown, insurance and property taxes.

In 1994 dollars, these costs are cxpccted to amount to $110 millionand $80 millionfor Unit 1 and the Company's share of Unit 2, respectively.

The amounts willescalate to $235 million and $405 million for Unit 1 and the Company's sharc ofUnit 2, respectively.

Based upon a 1989 study thc Company had previously estimated the cost to decommission Unit 1 to be approximately $416 million in 2009 ($265 million in 1994 dollars).

In addition, non-radioactive dismantlement costs werc estimated to be $25 million in 1994 dollars. The 1989 estimate was based upon a dismantlement of Unit 1 at the end of its useful life in 2009.

Thc $527 million estimate assumes a delayed dismantlement to coincide with Unit 2 and was prepared in connection with the Economic Study

" discussed above.

The estimate differs from the 1989 estimate primarily due to an increase in burial costs and the inclusion of nuclear fuel storage charges and costs for continuing care.

The delayed dismantlement approach should bc the most economic after applying the Company's current weighted average cost ofcapital.

The Company, in a 1989 study, estimated its 41% share of the cost to decommission Unit 2 to be $316 million in 2026 dollars ($112 million in 1994 dollars).

In addition, the Company's share of non-radioactive dismantlement cost were estimated to be $ 18 million (in 1994 dollars).

The $290 million estimate differs from the 1989 study primarily due to an increase in burial costs and thc inclusion of nuclear fuel storage charges and costs for continuing care.

Decommissioning costs recovered in rates are reflected in Accumulated Depreciation and Amortization on the Balance Shcct and amount to $184.1 million and $113.9 million at December 51, 1994 and 1995, respectively for both Units.

The annual allowance for Unit 1 and the Company's share of Unit 2 for the years ended December Sl, 1994, 1993 and 1992 was approximately $ 18.7, $ 18.7 and $23.1 million, rcspectivcly.

These amounts werc based on the 1989 study.

The FASB lias added to its agenda a project on accounting for obligations for decommissioning ofnuclear power plants.

Sec Note 1 "Depreciation, Amortization and Nuclear Generating Plant Decommissioning Costs."

NRC regulations require owners of nuclear power plants to place funds into an external trust to provide for the cost of decommissioning contaminated portions of nuclear facilities and establish minimum amounts that must be available in such a trust at the time ofdecommissioning.

As of December 31, 1994, thc fair value of funds accumulated in thc Company's external trusts werc $74.0 million for Unit 1 and $ 18.7 million for its share of Unit 2. The investmcnts are included in Other property and investments.

Earnings on thc external trust aggregated

$15.1 million through December 31, 1994 and, because they arc available to fund decommissioning, have also been included in Accumulated Depreciation and Amortization See Note 10 Disclosures about Fair Value of Financial Instruments.

Amounts recovered for non-radioactive dismantlcmcnt are accumulated in an internal reserve fund which has an accumulated balance of $37.1 million at December Sl, 1994.

Thc NRC minimum decommissioning cost calculation is based upon a 1986 cost estimate escalated by increases in labor, energy, and burial cost factors.

A substantial increase in burial costs, partly offset by reduced estimates in the volumes of waste to be disposed, increased the NRC minimum requirement for Unit 1 to $381 million in 1994 dollars and the. Company's share of Unit 2 to $173 million in 1994 dollars.

Thc Company's 1995 rate filing includes an aggregate increase of $8 million in decommissioning allowances to reflect funding to the increased NRC

~ minimum requirements.

In its next rate filing thc Company intends to seek decommissioning allowances ncccssary to fund to the Company's 1994 decommissioning cstimatcs discussed above.

There is no assurance that the decommissioning allowance recovered in rates will ultimately aggregate a sufflcient amount to decommission thc units. Thc Company belicvcs that ifdecommissioning costs are higher than currently estimated, thc costs would ultimately be included in thc rate process.

Nuclear LiabilityInsurance:

The Atomic Energy Act of 1954, as amended, requires the purchase ofnuclear liability insurance from the Nuclear Insurance Pools in amounts as dctcrmincd by the NRC. At the present time, the Company maintains thc required $200 million of nuclear liability insurance.

In 1993, the statutory liabilitylimits for the protection of thc public under the Price-Anderson Amendments Act of 1988 (the Act) were further incrcascd.

With respect to a nuclear incident at a licensed reactor, the statutory limit, 0

C 0

0 0

which is in excess of the $200 million of nuclear liability insurance, is currently $8.3 billion without the 5%

surcharge discussed below. This limitwould be funded by assessments of up to $75.5 million against each of the 110 presently licensed nuclear reactors in the United States, payable at a rate not to exceed $10 million per reactor per year.

Such assessments are subject to periodic inflation indexing and to a 5% surcharge iffunds prove insufficient to pay claims.

The Company's interest in Units '1 and 2 could expose it to a potential loss, for each accident, of $111.8 million through assessments of $14.1 million per year in the event of a serious nuclear accident at its own or another licensed U.S. commercial nuclear reactor.

The amendments also provide, among other things, that insurance and indemnity will cover precautionary evacuations, whether or not a nuclear incident actually occurs.

Nuclear Property Insurance:

The Nine Mile Point Nuclear Site has $500 million primary nuclear property insurance with the Nuclear Insurance Pools (ANI/MRP). In addition, there is $1.4 billion, in excess of the $500 million primary nuclear insurance, with Nuclear Electric Insurance Limited (NEIL) and $850 million, which is also in excess of the

$500 million primary and the $1.4 billion excess nuclear insurance, also with NEIL. The total nuclear property insurance is $2.75 billion. NEIL is a utilityindustrywwned mutual insurance company chartered in Bermuda.

NEIL also provides insurance coverage against the extra expense incurred in purchasing replacement power during prolonged accidental outages.

The insurance provides coverage for outages for 156 weeks, after a 21-week watttng penod.

~ NEIL insurance is subject to retrospective premium adjustment under which the Company could be assessed up to approximately $15.8 millionper loss.

Low Level Radioactive Waste:

The Federal Low Level Radioactive Waste Policy Act as amended in 1985 requires states tojoin compacts or to individually develop their own low level radioactive waste disposal site. In response to the Federal law, New York State decided to develop its own site because ofthe large volume oflow level radioactive waste it generates, and committed to develop a plan for the management of low level radioactive waste in New York State during the interim period until a disposal facility is available.

New York State is still developing disposal methodology and acceptance criteria for a disposal facility. The latest New York State low level radioactive waste site development schedule now assumes two possible siting scenarios, a

volunteer approach and a non-volunteer approach, either of which would begin operation in 2001.

Effective July 1, 1994, access to the Barnwell, South Carolina waste disposal facilitywas denied by the state ofSouth Carolina, to outwf-region low level radioactive waste generators, including New York State.

The Company has implemented a

low level radioactive waste management program so that Unit 1 and Unit 2 are prepared to properly handle interim onwite storage oflow level radioactive waste for at least a 10 year period.

Nuclear Fuel Disposal Cost: In January 1983, the Nuclear Waste Policy Act of 1982 (the Nuclear Waste Act) established a cost of $.001 per kilowatt-hour of net generation for current disposal of nuclear fuel and provides for a determination of the Company's liability to the Department of Energy (DOE) for the disposal of nuclear fuel irradiated prior to 1983.

The Nuclear Waste Act also provides three payment options for liquidating such liability and the Company has elected to delay payment, with interest, until 1998, the year in which the Company had initially planned to ship irradiated fuel to an approved DOE disposal facility. See Note 6 Capitalization.

Progress in developing the DOE facilityhas been slow and it is anticipated that the DOE facilitywillnot be ready to accept deliveries until at least 2010.

The Company does not anticipate that the DOE will accept all of its spent fuel immediately upon opening of the facility, but rather expects a transfer period of as long as 20 years.

The Company has several alternatives under consideration to provide additional storage facilities, as necessary.

Each

= alternative will likely require NRC approval, may require other regulatory approvals and would likely require the incurrence of additional costs.

The Company does not believe'hat the possible unavailability of the DOE disposal facilityuntil 2010 willinhibitoperation ofeither Unit.

0

4 JointlyOwned Generating Eaci li ties In thousands oldollars Construction Percentage Utility Accumulated Work in Ownership Plant Depreciation Progress Roseton Steam Station Units No. 1 8 2 (a)...

25 93,090 Oswego Steam StatIon Unit No.6 (b).......

Nine Mlle Point Nuclear Station Unit No. 2 (c).......

41

$1,504,185 76 270,498

$ 46,625

$ 2,679

$106,343

$ 5,143

$252,747

$12,029 (a) The remaining ownership interests are Central Hudson Gas and Electric Corporation, the operator of the plant (35%), and Consolidated Edison Company of New York, Inc. (40%).

On March 30, 1994, the Company and Central Hudson Gas and Electric Corporation (CHG8 E) terminated and cancelled the 1987 agreement where CHG8E had agreed to acquire the Company's 25% interest in the plant in ten equal installments of 2.5% (30 mw.) starting on December 31, 1994 and on each December 31 thereafter.

The cancellation agreement is subject to PSC approval.

Output of Roseton Units No. 1 and 2, which have a capability of 1,200,000 kw., is shared in the same proportions as the cotenants'espective ownership interests.

(b) The Company is the operator.

The remaining ownership interest is Rochester Gas and Electric Corporation (24%). Output of Oswego Unit No. 6, which has a capability of 850,000 kw., is shared in the same proportions as the cotenants'espective ownership interests.

(c) The Company is the operator.

The remaining ownership interests are Long Island Ughting Company (18%), New York State Electric and Gas Corporation (18%) ~ Rochester Gas and Electric Corporation (14%) ~ and Central Hudson Gas and Electric Corporation (9%). Output of Unit 2, which has a capability of 1,062,000 kw., is shared in the same proportions as the cotenants'espective ownership interests.

The following table reflects the Company's share of jointly-owned generating facilities at December Sl, 1994.

The Company is required to provide its respective share of financing for any additions to the facilities.

Power output and related expenses are shared based on proportionate ownership.

The Company's share of expenses associated with these facilities is included in the appropriate operating expenses in the Consolidated Statements ofIncome.

5 Bank Credit Arrangements In thousands ofdollars At December 31, Short-term debt:

Commercial paper.....

Notes payabie........

Bankers acceptances...

Weighted average interest rate (a)...

For Year Ended December 31, Daily average outstanding.....

Monthly weighted average interest rate (a)............

Maximum amount outstanding..

(a) Exduding fees 1994

$ 84,750 321,000 11,000

$416,750 6.21%

$342,801 4 71%

$497,700 1993

$210,016 153,000 5,000

$368,016 3.60%

$165,458 3 72%

$368,016 At December 31,

1994, (excluding HYDRA-Co Enterprises, Inc. which was sold January 9, 1995), the Company had $580 million of bank credit arrangements with 16 banks.

These credit arrangements consisted of

$200 million in commitments under a Revolving Credit Agreement, $199 million in one-year commitments under Credit Agreements,

$111 million in lines of credit and $70 million under a Bankers Acceptance Facility Agreement.

The Revolving Credit Agreement extends into 1997 and the interest rate applicable to borrowing is based on certain rate options available under the Agreement.

All of the other bank credit arrangements are subject to review on an ongoing basis with interest rates negotiated at the time of use.

The Company also issues commercial paper.

Unused bank credit facilities are held available to support the amount of commercial paper outstanding.

In addition to these credit arrangements, the Company had outstanding at December 81, 1994, $161 million in bank loans which expire in 1995 and which the Company expects to renew.

The Company pays fees for substantially all of its bank credit arrangements.

Thc Bankers Acceptance Facility Agreement, which is used to finance the fuel inventory for the Company's generating stations, provides for the payment of fees only at the time of issuance of each acceptance.

The following table summarizes additional information applicable to short-term debt:

c' 0

CaPitalization Capital StoCk The Company is authorized to issue 185,000,000 shares of common stock, $ 1 par value; 5,400,000 shares of preferred stock, $100 par value; 19,600,000 shares ofpreferred stock, $25 par value; and 8,000,000 shares ofpreference stock, S25 par value. The table below summarizes changes in the capital stock issued and outstanding and the related capital accounts for 1992, 1993 and 1994:

e Preferred Stock Common Stock

$ 1 par value Shares Amount'100 par value Non-Shares Redeemable* Redeemablo*

$25 par value Capital Stock Premium and Non-Expense Shares Redeemable'edeemable*

(Net)*

December 31, 1991:

136,099,654

$136,100 2,490,000

$210,000

$39,000 (a)

Issued 1,059,953 1,060 Redemptions (78,000)

(7,800)

Foreign currency translation adjustment

~.

11,222,005

$80,000

$200,550 (a)

$1,650,312 18,401 (1,366,000)

(34,150) 796 (11,494)

December 31, 1992:

Issued Redemptions Foreign currency translation adjustment 137,159,607 5,267,450 137,160 2,412,000 210,000 31,200 (a) 5,267 (18,000)

(1,800) 9,856,005 80,000, 166,400 (a)

(1,816,000)

(45,400) 1,658,015 111,497 (2,471)

(4,335)

December 31, 1993:

Issued Redemptions Foreign currency translation adjustment 142,427,057 1,884,409 142,427 2,394,000 210,000 29,400 (a) 1,884 (18,000)

(1,800) 8,040,005 6,000,000 (1,266,000) 80,000 121,000 (a) 150,000 (31,650) 1,762,706 27,630 (4,619)

(6,213) ecember 31, 1994:

144,311,466

$144,311 2,376,000

$210,000

$27,600 (e) 12,774,005

$80,000 S239,350 (a)

$1,779,504

• In thousands ofdollars (a) Includes sinking fund requirements due within one year.

'Iho cumulative amount of foreign currency translation adjustment at December 31, 1994 was $(13,313).

Non-Redeemable Preferred StoCk (Optionally Redeemable)

The Company has certain issues ofpreferred stock which provide for optional redemption at December Sl, as follows:

Series Shares 1994 In thousands ofdollars 1993 Redemption price per share (Before adding accumulated dNfdends)

Preferred $100 par value:

3.40%

3.60%

3.90%

4.10%

4.85%

5.25%

6.10%

7.72%

Preferred $25 par value:

Adjustablo Rate Series A Series C (1) Eventual minimum $25.00 200,000 350,000 240,000 210,000 250,000 200,000 250,000 400,000 1,200,000 2,000,000 S 20,000 35,000 24,000 21,000 25,000 20,000 25,000 40,000 30,000 50,000

$290>000 S 20,000 35,000 24,000 21,000 25,000 20,000 25,000 40,000 30,000 50,000

$290,000

$103.50 104.85 106.00 102.00 102.00 102.00 101.00 102.36 25.00 25.75(1) 40 0

0 0

Mandatorily Redeentable Preferred Stoch The Company has certain issues ofpreferred stock which provide for mandatory and optional redemption at December 31, as follows:

Shares In thousands ofdot/a/s Redemption price per share (Before adding accumulated dividends)

Series Preferred $100 par value:

7.45% (a)

Preferred $25 par value:

7.85% (a) 8.375% (a) 8.70% (a) 8.75%

9 50%

9.75% (a)

Adjustable Rate Series B (a) 1994 276,000 914,005 400,000 200,000 6,000,000 210,000 1)850,000 1993 294,000 914,005 500,000 600,000 600,000 276,000 1,950,000 1994

$27,600 22)850 10,000 5)000 150,000 5,250 46,250 1993

$ 29,400 22,850 12,500 15,000 15,000 6,900 48,750 1994

$102.41 (b) 25.33,

,25.25 25.25 (c) 25.13 25.00 Eventual minimum

$100.00 25.00 25.00 25.00 25.00 25.00 25.00 25.00 Less sinking fund requirements 266,950 10,950 S256,000 150,400 27,200

$123,200 (a) These series require mandatory sinking funds for annual redemption and provide optional sinking funds through which the Company may redeem, at par, a like amount of additional shares (limited to 120,000 shares of the 7A5% series). The option to redeem additional amounts is not cumulative.

l (b) Not redeemable until 1996.

(c) Not redeemable until 1999.

The Company's five year mandatory sinking fund redemption requirements for preferred stock, in thousands, for 1995 through 1999 are as follows:

$10,950; $9,150; $10,120; $10,120; and $7,620, respectively.

Long-Term Debt Long-term debt at December 31, consisted ofthe following:

In thousands oldollars In thousands oldollars Series Due

'1994 1993 Series Due 1994 1993 First mortgage bonds:

8 7/s%

4 s/s%

5 /s%

6 t/4%

6 t/a%

10 t/%

10 s/s%

9 1/z%

6 7/s%

9 '/4%

5/>'7/%

73/ /

8%

6 s/%

9 s/4%

6 /s%

'11 t/4%

'11s/ %

9 t/z%

8 s/%

8 t/z%

7'/s%

1994 1994 1996 1997 1998 1999" 1999**

2000 2001 2001 2002 2003 2003 2004 2005 2005 2013 2014**

2014**

2021 2022 2023 2024 S'5,000 40,000 60,000 150,000 210,000 100>000 230,000

. 85,000 220,000 300,000 110)000 150,000 45,600 150,000 150,000 165,000 210,000

$ 150,000 40,000 45,000 40,000 60,000 100,000 100,000 150,000 100,000 230,000 85,000 220,000 300,000 110,000 150,000 45,600 75,690 40,015 150,000 150,000 165,000 210,000 8 /s%

'7.2%

2025 2029 75>000 115,705 75,000 Total First Mortgage Bonds Promissory notes:

Adjustable Rate Series due July 1 ~ 2015 December 1, 2023 December 1, 2025 December 1, 2026 March 1, 2027 July 1, 2027 Unsecured notes payablo:

Medium Term Notes, Various rates, duo 1994-2004 Swiss Franc Bonds due December 15, 1995 Revolving Credit Agreement Other Unamortized premium (discount)

TOTALLONG-TERM DEBT Less long-term debt due withinone year 2>611,305 100>000 69)800 75,000 50,000 25>760 931200 45,000 50,000 99,000 169,421 (12,641) 3,375,845 77,971

$3,2971874 2,791,305 100,000 69,800 75,000 50,000 25,760 93,200 55,500 50,000 176,888 (12,656) 3,474,797 216,185

$3,258,612

• Tax-exempt pollution control related issues

'*Retiredprior to maturity 0

0 0

~

Several series ofFirst Mortgage Bonds and Notes were issued to secure a like amount of tax-exempt revenue bonds issued by the New York State Energy Research and Development Authority (NYSERDA). Approximately $414 million of such bonds bear interest at a daily adjustable interest rate (with a Company option to convert to other rates, including a fixed interest rate which would require the Company to issue First Mortgage Bonds to secure the debt) which averaged 2.76% for 1994 and 2.14% for 1993 and are supported by bank direct pay letters ofcredit. Pursuant to agreements between NYSERDA and the Company, proceeds from such issues were used for the purpose of financing the construction of certain pollution control facilities at the Company's generating facilities or to refund outstanding taxwxempt bonds and notes.

The $115.7 millionof taxwxcmpt bonds due 2014 were refinanced at 7.2% during 1994 pursuant to a forward refunding agreement entered into in 1992.

Notes payable include a Swiss franc bond issue maturing in 1995 equivalent to $50 million in U.S. funds. Simultaneously with the sale of these bonds, the Company entered into a currency exchange agreement to fully hedge against currency exchange rate fluctuations.

Other long-term debt in 1994 consists of obligations under capital leases ofapproximately $44.3 million, a liabilityto the U.S. Department of Energy for nuclear fuel disposal of approximately $97.4 million (see Note 3 "Nuclear Fuel Disposal Costs" ) and liabilities for unregulated generator contract terminations of approximately $27.7 million (see Note 9 "Long-term Contracts for the Purchase ofElectric Power").

Certain of the Company's debt securities provide for a mandatory sinking fund for annual redemption.

The aggregate maturities oflong-term debt for the five years subseqiient to Deccmbcr 31, 1994, excluding capital leases, are approximately

$73 million, $61 million,$145 million,$164 millionand $0, respectively.

7 Federal and Foreign Income Taxes AtDecember 31, the deferred tm liabilities (assets) were comprised ofthe following:

In thousands ofdollars Alternative minimum tax.

Unbilled revenue Other.

Total deferred tax assets.

Depreciation related.

Investment tax credit related Other.

Total deferred tax liabilities.

Accumulated deferred income taxes 1994 S

(93,893)

(98,201)

(258,621)

(4501715) 1,398>695 95,325 215,158 1,709,178

$ 1,258,463 1993 S

(95,071)

(82,829)

(163,256)

(341,156) 1,387,244 108,140 190,031 1,685,415

$1,344,259 C

0

(

0

Components ofUnited States and foreign income before income taxes:

1994 In thousands ofdollars 1993 1992 United States.

Foreign Consolidating e!iminations.

Income before income taxes.

$291,501

~, 15,475 (18,523)

,$288,453

$438,914 (24,845) 4,837

$418,906

$410,283 18,394 (16,741)

$411,936 Following is a summary of the components of Fedeml and foreign income tax and a reconciliation bebveen the amount of Federal income tax expense reported in the Consolidated Statements of Income and the computed amount at the statutory tax rate:

SUMMAE?YANALYSISr In thousands ofdollars

'1994 1993 1992 Components of Federal and foreign Income taxes:

Current tax expense:

Federal.

Foreign.

Deterred tax expense:

Federal.

Foreign.

Income taxes included in Operating Expenses Current Federal and foreign income tax credits included in Other Income and Deductions.

Deferred Federal and foreign income tax expense included in Other Income and Deductions.

$117$ 314 4,423 121,737 (6,931) 3,028 (3,903) 117,834 (11,507) 5,142

$118,918 8,445 127,363 35,152

$119,929 915 120,844 54,858 7,531 162,515 (16,061) 621 183,233 (31,787) 4,058 35,152 62,389 Total.

$111,469

$147,075

$155,504 Reconciliation between Federal and foreign income taxes and the tax computed at prevailing U.S. statutory rate on income before Income taxes:

Computed tax Reduction (increase) attributable to flow-through of certain tax adlustments:

Depreciation.

Allowance tor funds used during construction...................

Cost of removal.

Deferred investment tax credit amortization Other Federal and foreign income taxes

$100,959 (33,328) 31291 8,908 8,018 2,601 (10,510)

$111,469

$146,617 (35,153) 2,951 7,822 8,018 15,904

{458)

$147,075

$140,058 (37,543) 11,205 6,845 8,024 (3,977)

(15,446)

$155,504 0

8 Pension and Other Retirement Plans The Company and certain ofits subsidiaries have noncontributory, dcfincd-benefit pension plans covering substantially all their employees.

Benefits are based on thc cmployec's years ofservice and compensation level.'hc Company's gcncral policy is to fund the pension costs accrued with considemtion given to the maximum amount that can be dcductcd forFcdcral income tm purposes.

During 1994, thc Company offcrcd an early retirement program and a voluntary separation program (together the VERP) to reduce the Company's staHing levels and streamline operations.

The VERP, which included both represented and non represented cmployccs, was acccptcd by approximately 1,400 employees.

The following table sets forth the components and allocation ofthe costs ofthe programs:

In thousands ofdollars Plan Pension benefits................

Other Postretirement benefits....

Other Postemployment benefits..

Less: allocation to cotenant and other ventures..

Cost.

Electric Gas Total

$107,800 S 6,200

$114,000 75,900 4,300 80,200 16,800 900 17,700 200,500 11,400 211,900 3,900 3,900

$196,600

$ 11,400

$208,000 Included in 1994 operating expenses is a one-time charge of $196.6 million, representing the cost of the VERP allocable to electric customers.

The Company has recorded a regulatory asset for thc portion of thc VERP cost allocable to gas customers of approximately $11.4 million,which it has proposed to recover over a five-year period beginning in 1995.

Net pension cost for 1994, 1993 and 1992 included the followingcomponents:

n thousands o dollars Service cost benefits earned during tho period Interest cost on projected benefit obligation.

Actual return on plan assets.

Net amortization and deferral.

Net pension cost.

VERP costs.

Regulatory asset.

Total pension cost (1).

$ 30,400 62>700 7,700 (63,600) 37,200 114>000 (6,200)

$145,000 1993 30,100 54,200 (106,100) 38,700 16,900 16,900 1992

$ 27,100 48,800 (59,600) 6,900 23,200 S 23,200 (1) $5.9 millionfor 1994, $5.6 million for 1993 and $6.2 millionfor 1992 was related to construction labor and, accordingly, was charged to construction projects.

The followingtable sets forth the plan's funded status and amounts recognized in the Company's Consolidated Balance Sheets:

In thousands o dollars At December 31, Actuarial present value of accumulated benefit obligations:

Vested benefits Non-vested benefits.

Accumulated benefit obligations....................

Additional amounts related to projected pay increases Projected benefits obligation for service rendered to date Plan assets at fair value;consisting primarily of listed stocks, bonds, other fixed income obligations and insurance contracts Plan assets in excess of (less than) projected benefit obligations...........

Unrecognized net obligation at January 1, 1987 being recognized over approximately 19 years Unrecognized net gain from actual return on plan assets different from that assumed Unrecognized net gain from past experience different from that assumed and effects of changes ln assumptions amortized over 10 years..

Prior service cost not yet recognized in net periodic pension cost...........

Pension asset (liability)included in the consolidated balance sheets Principle Actuarial Assumptions (%):

Discount Rate Rate of increase in future compensation levels (plus merit increases)..

Long-term rate of return on plan assets 1994

$640>689 69,642 710>331 222,667 932,998 893>313 (39>685) 27,122 (58,379)

(67,857) 44,421

$(94,378) 8.00 3.25 8.75 1993

$501,900 64,973 566,873 236,906 803,779 913,200 109,421 32,392 (114,536)

(39,652) 49,613 S 37,238 7.30 3.25 9.00

In addition to. providing pension benefits, the Company and its subsidiaries provide certain health care and life insurance benefits for active and retired employees and dependents.

Under current policies, substantially all of the Company's employees may be eligible for continuation ofsome of.these benefits upon normal or early retirement.

The Company accounts for thc cost of these benefits in accordance with PSC policy rcquircments which generally comply with SFAS No. 106. This Statement, which was implemented beginning in 1993, requires accrual accounting by employers for postrctirement benefits other than pensions reflecting currently carncd benefits.

Thc 1992 cost of these benefits was approximately $16.7 million. Thc Company has various trusts to fund its future OPEB obligation.

The Company made contributions to such trusts, equal to thc amount received in rates, of approximately $24 million and $12 million in 1994 and 1993, respectively.

Nct postrctircment benefit cost for 1994 and 1993 included the followingcomponents:

In thousands ofdollars Service cost benefits attributed to service drtring the period.

Interest cost on accumulated benefit obligation.

Actual return on p'Ian assets.

Amortization of the transition obligation over 20 years Net amortization.

Net postretirement benefit cost VERP costs Regulatory asset Total postretirement benefit cost

'1994 S 15,000 40,200 (900) 20,200 8I900 83,400 80I200 (4,300)

$159,300 1993

$12,300 32,800 20,400 65,500

$65,500 Thc following table sets forth thc plan's funded status and amounts recognized in thc Company's Consolidated B ll'lilccSllccL In thousands oldollars At December 31, Actuarial present value of accumulated benefit obligations:

Retired and surviving spouses Active eligible.

Active ineligible Accumulated benefit obligations Plan assets at fair value, consisting primarily of listed stocks, bonds and other fixed obligations...

Accumulated postretirement benefit obligation in excess of plan assets.

Unrecognized net loss from past experience different from that assumed and effects of changes in assumptions Unrecognized transition obligation to be amortized over 20 years Accrued postretirement benefit liabilityincluded in the consolidated balance sheets Principle actuarial assumptions

(%%:

Discount Rate Long-term rate of return on plan assets Health care cost trend rate:

Pre-65 Post-65 1994

$371,223 20,400 208,900 600,523 36,754 563,769 71,939 337,336

$154,494 8.00 8.75 12.00 9.00 1993

$224,936 73,474 220,420 518,830 11,967 506,863 82,756 388,600

$ 35,507 7.30 10.05 7.05 At Deccmbcr 31, 1994, the assumed health cost trend rates gradually decline to 5.75% in 1999. Ifthe health care cost trend rate was increased by one percent, the accumulated postretircmcnt benefit obligation as of December 31, 1994 would incrcasc by approximately 11.2% 'lild the aggregate of the service and interest cost component of net periodic postrctiremcnt benefit cost for thc year would increase by approxirnatcly 12.7%:

On January I, 1994, thc Company adopted Statement of Financial Accounting Standards No. 112, "Employers'ccounting for Postemployment Benefits" (SFAS No. 112). This Statement requires employers to recognize the obligation to provide postemployment benefits ifthe obligation is attributablc to employees'ast services, rights to those benefits are vested, payment is probable and the amount of thc benefits can be reasonably estimated.

The Company previously accounted for such costs on a cash basis. At December 31, 1994, the Company's postemploymcnt benefit obligation is approximately $26.3 million, including the portion of the obligation related to the VERP. The Company has absorbed in 1994 earrlings, $ 16.8 million related to the postemployrnent benefit portion ofVERP costs allocated to the clcctric business'nd lias recorded a regulatory asset ofapproxirnatcly S9.5 million, thc majority ofwhich is cxpcctcd to bc recovered equally over three years beginning in 1995.

C 0

1 0

9 Commitments and Contingencies Construction Program:

The Company is committed to an ongoing construction program to assure delivery of its electric and gas services.

The Company presently estimates that the construction program for the years 1995 through 1999 willrequire approximately $1.7 billion, excluding AFC and nuclear fuel.

For the years 1995 through 1999, the estimates are $341 million, $341 million, $343 million, $344 million and $344 million, respectively.

These amounts are reviewed by management as circumstances dictate.

Sale of Customer Receivables:

The Company has an agrcemcnt whereby it can sell an undivided interest in a designated pool ofcustomer receivables, including accrued unbillcd electric rcvcnues, up to a maximum of $200 million. At December 31, 1994 and 1993, respectively, $200 million of receivables had bccn sold under this agreement.

The undivided interest in the designated pool of receivables was sold with limited recourse.

The agreement provides for a loss reserve pursuant to which additional customer receivables are assigned to the purchaser to protect against bad debts.

To thc extent actual loss experience of the pool receivables cxcceds thc loss reserve, the purchaser absorbs the excess.

For receivables sold, the Company has retained collection and administrative responsibilities as agent for the purchaser.

As collections reduce previously sold undivided interests, new rcceivablcs are customarily sold.

Long-term Contracts for the Purchase of Electric Powcri AtJanuary 1, 1995, the Company had long-term contracts to purchase electric power from the following generating facilities owned by the NcwYork Power Authority (NYPA):

Facility Niagara hydroelectric project...

St. Lawrence hydroelectric project...

Blenheim-Gllboa pumped storage generating station....

Fitzpatrick nuclear plant........

Expiration Purchased Estimated Date of Capacity Annual Contract in kw.

Capacity Cost 2007 926,000 (a)

$23,200,000 2007 104,000 1,300,000 2002 270,000 7,500,000 year-to-year basis 74,000 (b) 7,900,000 1,374,000

$39,900,000 (e) 926,000 kw for summer of 1995; 951,000 kw forwinter of 1995-96.

(b) 74,000 kw for summer of 1995; 110,000 kw for winter of 1995.96.

The purchase capacities shown above are based on the contracts currently in effect.

The estimated annual capacity costs are subject to price escalation and are exclusive of applicable energy charges.

The total cost of purchases under these contracts was approximately $85.1 million, $72.2 million and $64.4 million for the years 1994, 1993 and 1992, respectively.

Under the requirements of the Federal Public Utility Regulatory Policies Actof 1978, the Company is required to purchase power generated by unregulated generators, as defined therein. At December 31, 1994, the Company had virtually all unregulated generator capacity scheduled to come into service on line, totaling approximately 2,592 MW of capacity of which 2,273 MW is. considered firm. The following table shows the payments for fixed capacity costs and energy the Company estimates it will be obligated to make under these contracts.

The payments are subject to the'tested capacity and availability of the facilities, scheduling and price escalation.

Year 1995 1996 1997 1998 1999 Fixed Costs

$201,000 232,000 246,000 269,000 271,000 In thousands ofdollars Energy

$840,000 859,000 906,000 944,000 991,000 Total

$1,041,000 1,091,000 1 ~152,000 1,213,000 1,262,000 The fixed costs relate to contracts with 10 facilities where:

the Company is required to make fixed payments, including payments when a facility is not operating but available for service.

These 10 facilities account for approximately 708 MW of capacity, with contract lengths ranging from 20 to 35 years.

The terms of these contracts

.~

allow the Company to schedule energy deliveries from the facilities and then pay for the energy delivered.

The Company estimates the fixed payments under these contracts will aggregate to approximately $7.5 billion over their terms.

Contracts relating to the remaining facilities in service at December-31, 1994, require the Company to pay only when energy is delivered.

The Company currently recovers both capacity and energy payments to unregulated generators through base rates and/or through the FAC.

The Company has proposed to recover such costs through the FAMbeginning in 1995.

The. Company paid approximately $960 million, $736 million and $543 million in 1994, 1993 and 1992 for 14,800,000 mwhrs, 11,720,000 mwhrs and 8,632,000 mwhrs, respectively, of electric power under all unregulated generator contracts.

In an effort to reduce the costs associated with unregulated generators, at December 31, 1994, the Company had agreed to buy out 15 projects consisting of 453 MW of capacity. See Note 2 Rate and Regulatory Issues and Contingencies and Note 6 Capitalization.

Additionally, the Company has entered into agreements with 41 projects, comprising 1,153 MW of capacity, which allow the Company to curtail purchases from these unregulated generators when demand is low. The Company expects to continue efforts of these types into thc future, to control its power supply and related costs, but at this time cannot predict the outcome ofsuch efforts.

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Tax assessmcnts:

The Internal Revenue Service (IRS) has conducted an examination ofthe Company's Federal income tm returns for the years 1987 and 1988 and has submitted a Revenue Agents'eport to the Company.

The IRS has proposed various adjustments to the Company's federal income tax liabilityfor these years which could increase Federal income tax liabilityby approximately $80 million, before assessment of penalties and interest.

Included in these proposed adjustments are several significan't issiies involving Unit 2. The Company is vigorously defending its position on each of the issues, and submitted a protest to the IRS in 1993.

Pursuant to the Unit 2 scttlcment entered into with the PSC in 1990, to the extent the IRS is able to sustain adjustments, the Company will be required to absorb a portion of any assessment.

The Company believes any such disallowance will not have a material impact on its financial position or results ofoperations.

Litigation: In March 1993, a complaint was filed in the Supreme Court of thc State of New York, Albany County, against the Company and certain of its officers and employccs.

Thc plaintiff, Inter-Power of New York, Inc.

(Inter-Power), alleges, among other'matters,

fraud, negligent misrepresentation and breach of contract in'onnection with the Company's alleged termination of a power purchase agreement in January 1993.

The plaintiff sought enforcement of thc original contract or compensatory and punitive damages in an aggregate amount that would not exceed $ 1 billion, excluding pre-judgment interest.

In July 1994, the New York Supreme Court dismissed Inter-Power's complaint for lack ofmerit and denied Inter-Power's cross-motion to compel disclosure.

In August 1994, Inter-Power filed a notice of appeal of this decision which was rejcctcd. Inter-Power is pursuing further appeals of'this decision.

The Company believes it has meritorious dcfenscs and willcontinue to defend the lawsuit vigorously.

In November

1993, Fourth Branch Associates Mechanicville (Fourth Branch) filed suit against the Company and scvcral of its oAiccrs and employees in the New York Supreme Court, Albany County, seeking compensatory damages of$50 million, punitive damages of

$100 million and injunctive and other related relief. Thc suit grows out of the Company's termination of a contract for Fourth Branch to operate and maintain a hydroelectric plant the Company owns in the Town of Halfmoon, New York. Fourth Branch's complaint also alleges claims based on thc inability of Fourth Branch and thc Company to agree on terms for the purchase of power from a new facility that Fourth Branch hoped to construct at the Mcchanicville site. In January 1994, the dcfcndants filed a joint motion to dismiss Fourth Branch's complaint.

This motion has yet to be decided.

The Company understands that Fourth Branch has filed for bankruptcy.

In October 1994, Fourth Branch pctitioncd the PSC to direct thc Company to scil the Mcchanicville facility to Fourth Branch for fair value and to relinquish its FERC license, or in the alternative, to require the Company to turn over to Fourth Branch its rate base investment in the plant. The Company has opposed this petition.

The Medina Power Company is an independent power project with a contract requiring it to bc a qualifying facility (QF) under federal law or face a contractual penalty.

Having come on-line without a steam host, Medina did not meet this QF requirement, subjecting it to a 15% rate reduction.

The Company advised Mcdina that it had exercised its contract right and reduced the rate accordingly.

Medina is seeking

$40 million in compensatory

damages, a trebling of this amount to $120 million under the New York State antitrust laws, and $ 100 million in punitive damages.

Thc Company believes Medina's case is without merit, but cannot predict the outcome of this action.

The Company is involved in a number of court cases regarding the price of energy it is required to purcliase in excess ofcontract levels from certain unregulated generators

("overgcneration"). The Company has paid the unregulated generators based on its long-run avoided cost for all such overgcncration rather than the price which the unregulated generators contend is applicable under thc contracts.

The Company cannot predict the outcome of these actions, but willcontinue to aggressively press its position.

The Company believes it has meritorious defenses and intends to defend these lawsuits vigorously, but can neither provide any judgment, regarding the likely outcome nor provide any cstimatc or range of possible loss.

Environmental Contingencies:

The public utility industry typically utilizes and/or generates in its operations a broad range ofpotentially hazardous wastes and by-products. The Company believes it is handling identified wastes and by-products in a manner consistent with Federal, state and local requirements and has implemented an environmental audit program to identify any potential areas of concern and assure compliance with such requirements.

The Company is also currently conducting a program to investigate and restore, as necessary to mcct current cnvironmcntal standards, certain propcrtics associated with its former gas manufacturing, process and other properties which the Company has learned may be contaminated with industrial waste, as well as investigating identified industrial waste sites as to which it may be determined that the Company contributed.

The Company has been advised that various Federal, state or local agcncics believe certain properties require investigation and has prioritizcd the sites to enhance the management of investigation and remediation, ifnecessary.

Thc Company is currently aware of 89 sites with which it has been or may bc associated, including 47 which are Company-owned.

With respect to non-owned sites, the Company may be required to contribute some proportionate share ofremedial costs.

Investigations at each of the Company-owned sites are dcsigncd to (1) determine ifenvironmental contamination problems exist, (2) determine the extent, rate ofmovement and concentration ofpollutants, (3) ifnecessary, dctcrmine

~

p 47

the appropriate remedial actions required for site restoration and (4) where appropriate, identily other parties who should bear some or all of the cost of rcmcdiation.

Legal action against such other parties, ifnecessary, will be initiated. After site investigations are completed, the Company cxpccts to determine site-specific rcmcdial actions and to estimate thc attendant costs for restoration.

IIowevcr, since technologies are still dcvcloping and the Company has not yet undertaken any full-scale remedial actions at any idcntificd sites, nor have any detailed remedial designs been prepared or submitted to appropriate regulatory agencies, thc ultimate cost of remedial actions may chan'ge substantially.

Estimates of thc cost of remediation and post-remedial monitoring are based upon a variety of factors, including identified or potential contaminants, location, size and usc of thc site, proximity to sensitive resources, status of regulatory investigation and knowledge of activities at similarly situated sites and the Environmental Protection Agency (EPA) figure for average cost to remcdiatc a site.

.Actual Company expcnditurcs are depcndcnt. upon thc total cost ofinvestigation and remediation arMl the ultimate determination of thc Company's share of responsibility for

~ such costs, as well as the financial viability of other identified responsible parties since clean-up obligations arc joint and several.

Thc Company has denied any responsibility in certain of thcsc Potentially Rcsponsiblc Party (PRP) sites and is contesting liabilityaccordingly.

As a conscqucncc of site characterizations and asscssmcnts complctcd to date and negotiations with PRPs, the Company has accrued a liability of $240 million, rcprcsenting the low end of the range of its sliare of the es'timated cost for investigation and remediation.

The potential high end of. the range is presently estimated at approximately $ 1 billion, including approximately $500 million in the unlikely event the Company was required to assume 100% responsibility at non-owned sites.

The Company believes that costs incurred in the investigation and restoration process for both Company-owned sites and site's with which it is associated will be recovcrablc in the ratesetting process.

See Note 2 Rate and Regulatory Issues and Coritingencies. Rate agreements in effect since 1991 provide for recovery of anticipated investigation and remediation expenditures.

The Company has proposed in its multi-year rate case net recovery of$13.5

'illionfor 1995 for site investigation and remediation. The PSC Staff rcscrves the right to review the appropriateness of thc costs incurred. While the PSC Staff has not challenged any remediation costs to date, the PSC Staff asserted in the current gas rate procccding that the Company must, in future rate proceedings, justify why it is appropriate that remediation costs associated with non-utility property owned by the Company. be recovered from ratepayers.

Based upon management's assessment that remediation costs will be recovered from ratepayers, a regulatory asset has been recorded representing thc future recovery of remediation obligations accrued to date.

The Company is currently providing notices ofinsurance claims to carriers with rcspcct to the investigation and remediation costs for manufactured gas plant, industrial t,

waste sites and sites for which the Company has been identified as a PRP.

The Company is unable to predict whether such insurance claims willbe successful.

0

10 Disclosures about Fair Value ofFinancial Instruments The followingmethods and assumptions werc used to estimate thc fairvalue ofeach class offinancial instruments:

Cash and short-term investments:

Thc carrying amount approximates fair value because of thc short maturity of thc financial instruments.

Long-term investments:

The carrying value and market value are not material to the financial statements.

Short-term debt: Thc carrying amount approximates fair value bccausc of the short-tenn nature ofthc borrowings.

Mandatorily redeemable preferred stock: Fair value ofthe mandatorily redeemable preferred stock has bccn determined by one of the Company's brokers.

Long-term debt: The fair value ofthe Company's long-term debt has bccn cstimatcd by onc ofthe Company's brokers. The carrying value ofNYSERDA bonds and other long-term debt are considered to approximate fair value.

The flnancial instruments held or issued by the Company are for purposes other than trading. The estimated fair values of the Company's financial instruments are as follows:

In thousands ofdollars At December 31, Cash and short. term investments.

Short-term debt Mandatorily redeemable preferred stock Long.term debt: First Mortgage Bonds....

Medium Term Notes NYSERDA bonds.

Swiss franc bond.

Other Carrying Amount S

94,330 416>750 266,950 2>611 >305 45>000 413>760 50,000 224,107 1994 Fair Value S

94,330 416,750 277>072 2,367,755 45,783 413,760 83,682 224,107 Carrying Amount 124,351 368,016 150,400 2,791,305 55,500 413,760 50,000

,131,587 1993 Fair Value 124,351 368,016 155,326 2,969,228 62,458 413,760 73,794 131,587 In addition, off balance sheet flnancial instruments, consisting of a currency exchange agreeinent used (o fully hedge against currency exchange rate fluctuations related to the Swiss Franc bond, had a fair value of $31.7 and $20.1 million at Dcccmbcr 31, 1994 and 1993, respectively.

As a result of this agreement, at December 31, 1994, the Company's net obligation due at maturity on December 15, 1995, ofthe Swiss Franc bond is estimated to be approximately $50 million.

On January I, 1994, the Company adopted Statement ofFinancial Accounting Standards No. 115, "Accounting for Certain Investments in Debt and Equity Sccuritics." This statcmcnt addresses thc accounting and reporting for investments in equity securities tliat have readily determinable fair values and for all investments in debt securities.

The Company's investments in debt and equity securities are held in trust funds for the purpose offunding the nuclear decommissioning of Unit 1 and its share of Unit 2. See Note 3 "Nuclear Plant Decommissioning." Thc Coinpany has classified all investments in debt and equity sccuritics as available for sale and has recorded all such investments at their fair market value at December 31, 1994.

The proceeds from the sale of investments werc $104.6 million in 1994.

Using the specific identificatio method to determine cost, the gross realized gains and gross realized losses on those sales were $ 1.1 and $1.6 million, respectively.

Nct realized and unrealized gains and losses are reflecte in Accumulated Depreciation and Amortization on the Balance Sheet, which is consistent with the method used by the Company to account for the decommissioning costs rccovercd in rates. The recorded fairvalues and cost basis ofthe Company's investments in debt and equity securities is as follows:

At December 31, 1994:

Security Type Cost In thousands ol dollars Gross Unrealized Gain (Loss)

Fair Value U. S. Government Obfigations.

Tax Exempt Obligations.......

Corporate Obligations.

Other

$ 15,165 45,029 27,407 8,121 S 19 659 9

28 S

(325)

(1,778)

(1,253) 348

$ 14,859 43,910 26,163 7,801

$95,722

$715 S(3,704)

$92,733 Thc contractual maturitics of the Company's investments in debt securities is'as follows:

At December 31, 1994:

In thousands oldollars Fair Value Cost 1 year to 5 years.

5 years to 10 years Due after 10 years

$11,197 20,111 57,689

$11,429 20,778 59,591 0

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49

11 Informatzon Regarding the Electric and Gas Businesses The Company is engaged in the electric and natural gas utilitybusinesses.

Certain information regarding these segments is sct forth in the following table.

General corporate expenses, property common to both segments and depreciation of such common property have been allocated to the segments in accordance with the practice established for regulatory purpose's.

Identifiable assets include nct utilityplant, materials and supplies, deferred finance charges, deferred recoverable cncrgy costs and certain other regulatory and other assets.

Corporate assets consist ofother property and investments, cash, accounts receivable, prepayments, unamortized debt expense and certain other regulatory and other assets.

Operating revenues:

Electric Gas Total 1994

$3,528,987 623,191

$4,152,178 In thousands ofdollars 1993

$3,332,464 600,967

$3,933,431 1992

$3,147,676 553,851

$3,701,527 Operating Income before taxes:

Electric.

Gas Total S

466,978 83,229 S

550,207 625,852 61,163 687,015 645,696 61,863 707,559 Pretax operating Income, including AFC:

Electric.

Gas Total Income taxes, included In operating expenses:

Electric Gas Total Other(income) and deductions Interest charges Net income.

S 475>694 83>592 559,286 97,417 20>417 117>834 (21>410) 285,878 S

176,984 641,435

'1,812 703,247 148,695 13,820 162,515 (22,475) 291,376 S

271,831 666,269 62,721

~

728,990 176,901 6,332 183,233 (11,391) 300,716 256,432 Depreciation and amortization:

Electric..............

Gas.

Total Construction expenditures (Including nuclear fuel):

Electric Gas.

Total Identifiable assets:

Electric.....

Gas.

Total.

Corporate assets.

Total assets.

• Iricludes $196,625 of VERP expenses.

S 283,694 24>657 S

308,351 S

376,159 113,965 S

490,124

$7,162,118 1,009,566 8,171>684 1>477,755

$9,649,439 255,718 20,905 276,623 429,265 90,347 519,612

$7,042,762 926,648 7,969,410 1,501,917

$9,471,327 255,256 18,834 S

274,090 442,741 59,503 502,244

$7,000,659 783,766 7,784,425 806,110

$8,590,535 50 0

0 0

0 0

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12 Quarterly Einancial Data (Unaudi ted)

Operating revenues, operating income, net income and earnings per common share by quarters from 1994, 1993 and 1992, respectively, are shown in the following table. The Company, in its opinion, has included all adjustments necessary for a fair presentation of the results of operations for the quarters.

Due to the seasonal nature of the utility business, the annual amounts are not generated evenly by quarter during the year.

The Company's quarterly results of operations reflect the seasonal nature of its business, with peak electric loads in summer and winter periods.

Gas sales peak in the winter.

In thousands ofdollars Quarter Ended Operating revenues Operating income (loss)

Net income (loss)

Earnings (loss) per common share December 31 1994 1993 1992 September 30 1994 1993 1992 1993 1992 a c 3Q 1994 1993 1992 1 018110 988,195 963,629 918 810 879,952 822,530 6

929,700 929,245 881,427 1 2~35 558 1,136,039 1,033,941 108,539 89,658 48,595 40,401 6320,6K S 6J 559 132,669 65,325 137,515 71,734 203 348 138 46 187,669 177,972 126,956 102,462 4 0 536~(77 422) 95,623 30,955 119,181 41,835 108 937 48 383 L66)

.16

.24 27

.29

.23

.41

.46 92

.86

.68 In the fourth qtiarter of 1994 the Company recorded $196.6 million ($.89 per common share) for"the electric expense allocation of the VERP. In the second quarter of 1992, the third quarter of 1993, and the fourth quarter of 1994 the Company recorded $22.8 million ($.11 per common share), $10.8 million ($.05 per common share) and $12.5 million ($.06 per common share), respectively, for MERIT earned in accordance with the 1991 Agreement.

In the first and fourth quarters of 1992 the Company recorded $21 million ($.09 per common share) and $24 million ($.09 per common share),

respectively, to writedown its subsidiary investment in oil and gas properties.

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Electric and Gas Statistics ELECTRIC STATISTICS 1994 1993 1992 ELECTRIC CAPABILITY Thousands ofkilowatts Electric sales (Millionsofkw-hrs.):

Residential..................

Commercial..................

Industrial....................

Industrial Special.............

Municipal service.............

Other electric systems.........

10,415 11,813 7,445 4,118 215 7,593 10,475 12,079 7,088 3,888 220 3,974 10,392 11,628 7,477 3,857 227 3,030 December 31, Owned:

Coal..

Oil Dual Fuel Oil/Gas...

Nuclear.............

Hydro.

Natural Gas..........

1994 1,285 16.0 646 8.1 700 8.7 1,048 13.1 700 8.7 1993 1992 1,285 1,285 1,496 1,496 700 700 1,048 1,059 700 706 74 108 Electric revenues (fhousands ofdollars):

Residential..........

Commercial..........

Industrial............

Industrial - Special....

Municipal service.....

Other electric systems Miscellaneous........

Electric customers (Average):

Residential.................

Commercial.................

Industrial...................

Industrial Special...........

Other.

41,599

$1,233,007 1,272,234 577,473 49,217 50,007 167,131 179,918

$3,528,987 1,405,343 144,249 2,105 82 2,318 37,724 36,611

$ 1 ~171,787 1,241,743 553,921 42.988 50,642 105,044 166,339

$1,096,418 1.160,643 589,258 39,409 50,327 93,283 118,338 1,398,756 143,078 2,132 76 3,438 1,389,470 142,345 2,197 72 3,262

$3.332.464 S3.147,676 Purchased:

New York Power Authority (NYPA)

Hydro..................

Nuclear.................

Unregutated generators.........

Total capability Electric peak load..

4,379 54.6 1>300 16.2 74 0.9 2,273 28.3 3,647 45.4 8,026 100.0

( 6,458 5,303 5.354 1,302 1,302 65 67 2,253 1,549 3,620 2,918 8,923 8,272 6,191 6,205 Availablo capability can be Increased during heavy load periods by purchases from neighboring Interconnected systems. Hydro station capability is based on average December stream-flow conditions.

Residential (Average):

- Annual kw.hr. use per customer..

,Cost to customer per kw-hr......

Annual revenue per customer....

1,554,097 7,411 11.84C

$877.37

~ 1,547,480 7,489 11.19C

$837.74 1,537,346 7,479 10.55C

$789.09 CorPorate Inforntatiou GAS STATISTICS Gss sales (Thousands ofdekstherms):

Residential...................

Commercial..................

Industrial.....................

Other gas systems.............

Totalsalcs...............

Spotrnarket..................

Transportation of customer-owned gas Total gas delivered...

Gas rovcnues (Thousands ofdollars):

Residential...................

Commercial..................

Industrial.....................

Other gas systems.............

Spot market..................

Transportation of customerwwned gas Miscollancous.................

Gas customers (Average)t Residential..............

Commercial.............

industrial................

Other.

Transportation...........

1994 56,491 25,783 3,097 244 85,615 1,572 85,910 173,097

$398,257 159,157 14,602 1,159 4>370 38,346 7,300

$623,191 463,933 40,256 256 1

661 505,1 07 1993 1992 54,908 23,743 4,316 234 83,201 13,223 67,741 164,165 53,945 22,289 1,772 1,190 79,196 1 ~146 65,845 146,187

$370,565 144,834 18,482 1,066 29,782 34,843 1,395

$354,429 132,609 10,001 4,737 2,576 42,726 6,773 455,629 39,662 233 1

673 496,198 446,571 38,675 234 1

673 486,154

$600,967

$553,851 Annual Meeting The Annual hfecting of sharcholdcrs willbc held at Thc Amherst Marriott, 13'i0 Millcrsport Higltway, BuK~lo, N.Y.

at 10:30 a.m., Tuesday, hfay 2, 1995.

A notice ofthc mccting, proxy statcmcnt and form ofproxy will bc sent in March to hohlcrs of common stock.

SEC Forns IOKIfePorf Acopy ofthe company's Form 10 Krcport, filed annually with the Securities and Exchange Commission, is available without charge by writingthe Investor Relations Department at 300 Erie Boulevard West, Syncusc, N.Y. 13202.

Shareholder Inquiries Questions regarding sharcholdcr accounts may bc dircctcd to thc company's Sharcholdcr Services Department:

(315) f286750 (Syncuse) 1400 IIM450 (clsetvllerc ln continental U.S.)

Stock Exdrange Listings Ticker Spnbofr I>IMK Common stock and most preferred series are listed and traded on the NcwYorkStock Exchange.

Bonds are tnded on the New YorkStock Exchange.

Disbursing Agent Common and Preferred Stocks:

Niagan hfohawk Power Corp.

300 Erie Boulevard West Syncuse, N.Y. 13202 Bonds:

hfarine hfidland Bank, NA.

140 Broadway New York, N.Y. 10015 Transfer Agent and Registrars Common and Prcferrcd Stock:

The Bank ofNew York P.O. Box 11002 Church Strcct Station New York, N.Y. 10286 Bontis:

hfarine Midland Bank, NA.

140 Broadway New York, N.Y. 10015 Residential (Average):

Annual dekatherm use per customer Cost to customer per dekatherm..

Annual revenue per customer....

Maxi'ay gas sendcut (dckatherms) 121.8

$7.05

$858.44 995/01 120.5

$6.75

$813.30 929285 120.8

$6.57

$793.67 905,872 Analyst Inquiries Anal)st inquiries should be directed to Leon T. Mazur, Director.Investor Relations, (315) 4288876 52 0

0 0

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Officers WilliamE. Davis Chairman ofthe Board and Chief Executive Ofliccr John hL Endries President B. Ralph Sylvia Executive Vice President Nuclear DavidJ. Arrington Senior Vice President Human Resources Darlcne D. Kerr Senior Vice President Electric Customer Service GaryJ. Lavine Senior Vice President Legal and Corponte Relations Robert J. Patrylo Senior Vice President Gas Customer Service (Resigned August I, 1994)

John W. Powers Senior Vice President Finance and Corpontc Services Michael P. Ranalli Senior Vice President Electric Supply and Dclivcry Joseph T. Ash Vice President Special Projects Nicholas J. Ashooh Vice President Public M'airs and Corporate Communications Thomas H. Baron Vice President Fossil and Hydro Gencntion Harold J. Bogan Corporate Sccrctary (Rctircd Scptcmbcr 1, 1994)

MichaelJ. Bovalino Vice President Electric Marketing and Rates (EffcctivcAugust 22, 1994)

MichaelJ. Caiull Vice Prcsidcnt Economic and Business Development Norman E. Crowe,Jr.

Vice Prcsidcnt Electric Customer Scrv4cc (Retired October 1, 1994)

Edward J. Dienst Vice President Regional Operations (EffcctivcAprilI, 1994)

Thomas R. Fair Vice President Environmental AKsirs Theresa A. Flaim Vice President Corponte Stntcgic Planning Edward F. Hoffman Vice President Electric Supply and Delivery Support Paul J. Kaieta Vice President Law and Gcncral Counsel Samuel F. Manno Vice President Purchasing and Corporate Services MartinJ. McCormick,Jr.

Vice Prcsidcnt Nuclear Safety Assessment and Support (EffectiveJanuary I, 1994)

Douglas R. hfcCucn Vice President Government and Regulatory Relations Clement E. Nadeau Vice President Power Tnnsactions and Planning James A. Perry Vice President Quality Assunnce Kapua A. Rice Corpomtc Sccrctary (Effcctivc Septcmbcr I, 1994)

ArthurW. Roos Vice President-Treasurer Richard H. Ryczek Vice President Gas Customer Service Opentions Louis R Storz Vice President Nuclear Gcnemtion (Effective hlarch I, 1994)

WilliamJ. Synwoldt Vice President Information Systems and Chief Information Oflicer Steven W. Tasker Vice Prcsidcnt-Controller Carl D. Terry Vice President, Nuclear Enginccring Andrew M. Vcsey Vice President Power Dclivcry Stanley W. Wflczck,Jr.

Vice President Customer Scrvicc Directors WilliamF. Allyn (A, 8, C, F, G)

President and Chief Executive Oflicer, Welch Allyn,Inc., Skaneateles Falls, N.Y.

Lawrence Burkhardt, HI (F)

Former Executive Vice President Nuclear Opentions Douglas hL Costle (D, F)

Distinguished Senior Fellow, Institute for Sustainable Communitics Montpelier, Vt.

Edmund M. Davis (A, 8, D, E)

Partner, Hiscock 8c Barclay Attorneys-at-Law, Syracuse, N.Y.

WilliamE. Davis (A)

Chairman ofthe Board and Chief Executive Oflicer WilliamJ. Donlon Former Chairman ofthe Board and Chief Executive Ofliccr Edward W. Duffy(A, 8, F)

Former Chairman ofthe Board and Chief Executive Oflicer, Marine Midland Banks, Inc.

Sarasota, Fla.

John hL Endrics President Dr. Bonnie Guiton Hill(C, D, G)

Dean, Mclntire School ofCommcrce University ofVirginia, Charlottesville, Va.

Jolm G. Hachl,Jr.

Former Chairman ofthc Board and Chief Executive Oflicer Henry A. Panasci, Jr. (8, E, G)

Chairman ofthe Board and Chief Executive Officer, Fay's Incorporated, Liverpool, N.Y.

Dr. Patti McGillPeterson (A, C, D)

Prcsidcnt, St. Lawrence University, Canton, N.Y.

Donald B. Riefler (A, C, E, F)

Financial Market Consultant Vcro Beach, Fla.

Stcphcn B. Schwartz (8, E)

Former IBMSenior Vice President Palm Beach Gardens, Fla.

John G. Wick (C, D, E)

Emt Atnherst, N.Y.

A. Mcmbcr ofthe Executive Committee B. hlembcr ofthe Compensation and Succession Committee C. Mcmbcr ofthc AuditCommittee D. Mcmbcr ofthe Committee on Corporate Public Policy and Environmental Affairs E. Member ofthe Finance Committcc F. Mcmbcr ofthc Nuclear Oversight Committcc G. Mcmbcr of the Special Committcc 0

0

Niagara Mohawk Power Corporation 300 Erie Boulevard West

Syracuse, New York 13202