ML17058B769

1992 Annual Rept, for Nmpns,Units 1 & 2

ML17058B769
Person / Time
Site:	Nine Mile Point
Issue date:	12/31/1992
From:	Donlon W NIAGARA MOHAWK POWER CORP.
To:
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ML17058B768	List: ML17058B767 ML17058B769 ML17058B770 ML17058B771 ML17058B772 ML20036B498
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NUDOCS 9305240302
Download: ML17058B769 (56)

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j 9305240302 9'30520 PDR ADOCK 05000220 PDR Niagara Mohawk power corporation fl992 ANNUAILIR{Elr OOIR7

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ON THE COVER: A composite photograph illustrates the solid foun-

'dation of quality and service Niagara Mohawk has built through the

~ decades with a look back. at a downtown Syracuse streetr scene of, 1912 and the present-day Albany skyline. The Erie Canal, shown in the foreground, is a reminder of the expanse of the company's service territory which reaches from Buffalo in the west to'Albany in the east.'HOTO CREDITS: Historical photograph of Syracuse courtesy. of';

Syracuse Blue Print Company, Inc. Albany skyline photograph cour tesy of Eastman Kodak Company, Rochester, New York.

This report was designed, photographed, written and produced by.

Niagara Mohawk employees.

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q Contents 1

Highlights 2

Letter to Shareholders 5

Strategic Planning 6

Business Unit Overview 8

Operations Review 18 Management's Discussion and Analysis of Financial Condition 0

I Sl Rcport ofManagement Sl Report ofIndependent Accountants S2 Consolidated Financial Statements S5 Notes to Consolidated Financial Statements 50 Market Price ofCommon Stock 51 Selected Financial Data 52 Statistics, Corporate Information, OHicers, Directors Serving Our Customers in UPstate New YorIr Niagara Mohawk Power Corp. is an investor-owned utility providing energy to the largest customer service area in Ncw York.

Our electric system meets the needs of more than 1.5 million residential, 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 over 490,000 residential and business customers on a retail basis, as well as a growing number ofcustomers from whom we transport gas that they purchase directly from suppliers.

We also operate subsidiary companies in the United States and Canada.

Opinac Energy Corp. operates an oil and gas exploration company and an electric utility in Canada. HYDRA-CO Enterprises builds and operates power production facilities.

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"<ighlights Total operating revenues Income available for common stockholders Earnings per common share Dividends per common share Common shares outstanding (average)

Utilityplant (gross)

Construction work in progress..

Gross additions to utilityplant..

Public kilowatt-hour sales...

Total kilowatt-hour sales...

Electric customers at end ofyear.

Electric peak load (kilofuaffs)...

Natural gas sales (dekafhenns) tural gas transpof ted

( eha

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Gas customers at end ofyear...

Maximum day gas deliveries (dehalhenns) 1992

$3,701,527,000 219,920,000

$ 1.61

$0.76 136,570,000

$9,642,262,000 587,437,000 502,244,000 33,581,000,000 36,611,000,000 1,543,000 6,205,000 79,195,000 65,845,000 493,000 905,872 1991

$3,382,518,000 202,958,000

$0.32 136,100,000

$9,180,212,000 568,994,000 522,474,000 33,597,000,000 36,738,000,000 1,538,000 6,093,000 71,729,000 50,631,000 482,000 852,404

%Change 8.1 137.5 5.0 (3.9)

(3) 1.8 10.4 30.0 THE 1992 REVENUE DOLLAR AND WHERE IT WENT

-39C Residential customers 26C Fuel for the production of efoctncify and eloctncity purchased 17C Income and other taxes 35C Commercial customers ll 17C Industnai customers

~$5555g 9C Allothers 15C Wages, salaries, employee benefits 12C Other BC Gas purchased 8c Interest - not 7C Depreciation 4C Dividends to stockholders 3c Retained in business

To Qur %arehokkm:

Niagara Mohawk made considerable progress in 1992, enhancing service performance and continuing to build financial strength. The year contained its share of challenges,

. but the process ofchange and improvement we initiated three years ago has firmlytaken hold across the company, and results in many areas are beginning to improve.

Earnings for 1992 were $219.9 million or $1.61 per share. This represents over 8 per-cent improvement compared to earnings of$ 1 49 in 1991.

The increase resulted from progress in a number of areas of our operations, but increases in base rates for electric and gas service, and our ability to earn financial incentives were very important contributing factors. Somewhat offsetting these gains has been the necessity to provide for a reduction in value of the oil and gas properties of Opinac, our Canadian subsidiary.

As gratifying as the increase is, our earnings for 1992 remained below our allowable rate of return on equity. We remain committed to the goal of earning the full return allowed in rates.

In 1992, our earnings included $26.8 million in special performance incentive awards known as MERIT. This raises our total merit earnings to $56.8 million since the Public Service Coinmission-approved program began in 1991. We are in the process of final-izing our report of accomplishments during 1992 while also conduding discussions with the PSC on goals for 1993 through 1995.

We achieved our goal ofdividend growth in 1992, raising the quarterly dividend from

$0.16 per share to $0.20 per share. Total return to stockholders in 1992 dividend plus price appreciation was 11.2 percent.

IN CONTROL Above, an early power control center in Albany, and right, Vice Chairman William E Davis, Chairman and CEO WilliamJ. Donlon and President John M Endries pictured in front of Niagara Mohawk's modern power control facilitynear Syracuse.

Increasing the dividend again in 1995 is a key goal ofour board.

We also intend to issue additional common stock in 1993 and 1994 to strengthen our capitalization ratios in response to the increasing risk profile of our business.

We will continue our aggressive debt refinancing program. I est year, most of the proceeds from more than $ 1 billion in transactions went to retire higher cost debt, resulting in annual savings ofabout $9 million.

In addition to our financial progress, 1992 saw numerous other achievements for our company, some ofwhich willbe highlighted in other sections ofthis annual report. I will touch brieflyon several that were ofgreatest significance.

4 We have made impressive strides in the environmental arena, and lrave begun to receive regional and national attention for our initiatives. A prime example is our land management program, especially the coinprehensive Upper Hudson project that included a land transfer to New York State and which has been lauded by New York Gov.

Mario Cuomo and others.

Also, wc developed an extensive program for the remediation of waste sites left from the era when gas was manufactured from coal. And we are developing cost-effective and efficient ways to meet and, where practical, exceed The Clean AirActAmendments'mission reduction targets.

Our research and development efforts with photovoltaic cells and wind power are attracting interest across the nation. Niagara Mohawk will continue to be an industry leader in environmental aKairs for two reasons:

it is the right thing to do, and itis good business.

4 Advance planning and a vigorous marketing program enabled NMGas, Niagara Mohawk's natural gas Strategic Business Unit, to enjoy good results. NMGas increased the number of residential gas heat customers it serves by nearly 11,000 last year and increased total throughput by 22.7 million dekatherms. In 1992, a major Federal regulatory change further opened the natural gas industry to cornpctition. The company is well positioned to take advantage of thc change under its new business unit structure.

Other challenges in the near future, both for our gas and electricity

business, are expected from the National Energy Policy Act of 1992, and from new environmental and tax rcquircmcnts now under discussion.

~ Last year, we spoke ofthc need to come to grips with the proliferation of Non-Utility Generators (NUGs) in our service territory, and the impact they are having on our custorncrs'ills.

Early in 1992, we successfully sought repeal of the state law tlrat granicd a minimum price of six cents per kilowatt.-hour, well above current avoided costs, to qualified NUGs. Wc also actively participated in the Public Service Commission procccding that lowcrcd thc price for future contract negotiations with all NUGs.

Unfortunately, the Six-Cent Law repeal applies only to future NUG projects. We continue to take actions, from contract enforcement to project buyouts, to mitigate the impacts on customer bills caused by NUG contracts grandfathered by the repeal.

~ We negotiated a rate incrcasc that was approved in January by the PSC.

The increase is necessary to mcct cxpcnscs, including significant amounts for NUGs, environmental rcmcdiation efforts, demand-side management programs and amounts caused by cltangcs in accounting for certain post-retiremcnt costs that become cffectivc this year. Thc agrcernent, provided for a reduction in the allowed return on equity to 11.4 percent. We are actively participating in an important generic financing proceeding at the PSC which, among other things, is examining new and improved equity pricing methodologies that would provide compctitivc returns in both high and low interest situations.

Niagara Mohawk has a long tradition of being among the lowest-cost providers of energy services in New York and the Northeast. That is because wc have spent decades developing a divcrsc fuel mixa strategy that has served our shareholders and our customers tvell in good economic times and bad.

Our efforts to control internal costs, to develop new pricing strategies and to reduce thc impact ofNUG payments on our customers'ills are all geared toward one thing being compctitivc. Quality service at reason-able prices is not only our hallmark, it is our lifeblood.

To build value for shareholders, we must provide value to our customers.

By working hard to limitprice incrcascs we can reduce the risk of losing larger commercial and industrial custorncrs to bypass or to relocation out ofour service territory.

letter continued...

There are a number of competitive challenges we must ovcrcoine ifwe are to achieve our corporate vision of becoming the most responsive and eAicient v

scrviccs company in the Northeast, providing maximum value for customc holders and employees. The depth of talent in Niagara Mohawk's work force an

~ur commitment to continuous improvement make us confident wc willsucceed.

For example, our rcccnt economic analysis ofour Nine Mile Point UnitOne nuclear station indicates the plant willlikelyprovide a net benefit to our customers through its next fuel cycle, and, depending on future events, could provide benefits for the remaining 17 years ofits license. The Board ofDirectors concurred with our decision to operate the plant at least through the cnd ofthe next fuel cycle, in early 1995.

The company willfurther evaluate all factors that affect the economics ofUnit One.

But it is'clear tlrat the plant's future depends on improved performance and cost control, without compromising safety.

In fact, cost control remains a priority across the company. Negotiations with the International Brotherhood ofElectrical Workers in 1993 willinclude frank discussions ofwork practices, benefit costs and the nccd to remain coinpetitive. Aunited effort by all is essential. We have also continued our efforts to insure thc fair valuation of our utilityproperty, and to seek real estate tax reductions where appropriate.

We have been evaluating overall employment lcvcls, to ensure our human re-sources match our scrvicc rcquircments.

For example thc nuclear division has reduced staffing levels by approximately 500 positions since 1991, while improving pcrformancc.

Based on a study of non-nuclear cmployincnt coinplctcd in 1992, the company plans to reduce its work force during the next thrcc years, primarily through attrit.

n.

We have taken a number of other steps to control labor costs while providI g employees with competitive wages, benefits and performance incentives. Our inc n-tive management compensation program completed its second year in 1992, anu we arc pleased with the results it has stimulated.

Our flcxible benefits program for managcmcnt employccs, as well as ei ments to savings plans for all employees, willimprove these services for the pc Niagara tXIohawk while helping the company to control cxpcnses better.

Although this is the last annual report I will sign as Niagara Mohawl"s chairman and chief executive oAiccr, I will remain as a member of your Board of Directors.

I am very pleased to report that in November, thc Board unanimously elected William E. Davis as vice chairman. Hc willsucceed me as chairman and chief exccu-tivc officer upon my retirement in April.

Bill Davis joined Niagara Mohawk in 1990 as vice president of corporate planning and was named senior vice president this past April. He joined us from the state' Energy Office, where hc was executive deputy commissioner. His skills are out-standing. Bill has a strong strategic orientation and thc broad expertisc needed for balanced decision making.

He will value and enjoy, as have I since 1988, the effective operational oversight provided by company President Jack Endrics.

Several other changes during 1992 enhanced our outstanding management team.

One was the return of Jack R. Swartz to headquarters in the key position of vice president Employee Relations. He had bccn vice president Electric Customer Service, Eastern. We welcomed Nicholas J. Ashooh as vice prcsidcnt Public Affairs and Corporate Communications, and Neil S. "Buzz" Cams as vice president Nuclear Generation.

During my 45-year career with Niagara Mohawk I have witncsscd many changes in the company and the utility industry. No changes have bccn morc profound than those of the past few years. Niagara Mohawk has come a long way since thc difficult days of the late 1980s. I am proud of thc effor the people of this company have made.

There arc significant issues still to be faced, and diAicult decisions to be made.

But I am confident that Niagara Mohawk willcontinue to move toward and ultimately achieve its vision ofbeing the best.

williamJ. Donlon Chairman ofthe Board and Chief Execute OAicer February 22, 1995

Strategic Planning last tivo annual reports, Niagara Mohawk lias outlined its vision for thc 1990s to bccomc the best energy services company in the Northeast and described the process of reorganization and change tliat was the first stage in achiev-ing the vision.

Thc reorganization is complete, with thc Strategic Busi-ness Units and their Corporate Support Units in place. The process of change goes on, however, as Niagara Mohawk continually looks within to cxarnine wliat it. docs and deter-mine how to do itbetter.

Determining how to become the best rcquircs a unified plan ofaction. Dctcrrning when a company has become the best requires an exacting method ofmeasuring results.

Niagara Mohawk developed both during the past year.

The company's Corporate Strategic Plan is the culmina-tion of many months ofplanning activities. It sets the foun-dation, and provides the direction, for thc Strategic Business Units and Corporate Support Units to dcvclop their own business plans and budgets. It clearly communicatcs those areas ofstrategic importance that willrequire the company's attention over the next several years.

The plan covers the years 1993 to 1995 the period over which Niagara Mohawk intends to become the best. It sets goals and strategies based on four clear-cut objectives:

~ T improve total returns to shareholders.

prove customer service quality.

iprove the work cnvironmcnt for employees.

4 improve environmental performance.

The operating plans and budgets developed by thc Strategic Business Units and Corporate Support Units must support those objectives and thc nurncrous specific goals and strate-gies that flesh out the objectives.

To gauge its success in moving toward the objective, Niagara Mohawk has dcvcloped benchmarks measuring performance in seven specific areas against a peer group of23 utilities.

To bccomc the best energy services company in tile Northeast, Niagara Mohawk must, achieve a top-quartile ranking among these utilitics in all scvcn areas. Over the next three years, the seven benchmarks will also help to identify performance gaps and dctcrminc how to close the gaps.

Thc seven bench marks are:

4 Total return to shareholders.

4 Ratio ofstock price to book value.

4 Non-fuel operating and maintenance costs pcr mcgawatt-hour ofelectricity sales.

4 Non-fuel operating and maintcnancc costs per dekatherm ofgas deliveries.

4 Customer cornphints to the Public Service Commission.

4 Lost workday case accident rate.

l Occupational Safety and Health Administration-ible accident rate.

, gara Mohawk's basclinc for the seven areas is the 1990-91 time frame. Thc company was in thc top qtiartile in only one area, third among 22 electric utilitics in non-fuel oper-ating and maintenance costs per kilowatt-hour ofelectricity.

Stringent cost control measures and implementation by the company's Electric Supply and Delivery SBU ofthe most aggressive substation preventive maintenance program in company history should help Niagara Mohawk to maintain and possibly better that high ranking. Final results for 1992 should be available in May.

Niagara Mohawk ranked fourth among nine gas utiliticsin operating and maintenance costs during the baseline period.

Thc company was also fourth among nine Ncw York State utilities in complaints by customers to thc Public Service Commission. iNiagara Mohawk.'s recorded complaints last year dropped below 1991 levels, which in turn werc 28 pcr-ccnt below 1990 levels.

Anumber ofspecific programs, combined with an overall emphasis on customer service, helped to reduce complaints.

Electric system reliability continued to improve, as mea-sured by customer interruption duration and system inter-ruption frequency.

Electric Supply 8. Delivery also implemented an advanced program that allows its System Power Control center to analyze conditions in power plants and on the transmission system more quickly, avoiding cquipmcnt damage and customer interruptions.

Two of the seven performance bcnchmarks mcasurc safety, and in those, Niagara Mohawk was lagging near the bottom during the baseline period. That is chang-illgqlllckly.

Niagara MohawVs Human Resources CSU has initiated a new company-wide safety program that, for example, reduced the disabling injury rate in ES8:D by morc than 50 percent last year, and two thirds since 1990. In thc high-exposure Fossil 8. Hydro operations, the rate has dropped to slightly above one injury per 100 cmployec-years worked.

The Electric Customer Service SBU's safety performance has also improved beyond expectations.

The remaining two bcnchmarks, measuring financial performance, also pointed to the need for improvcmcnt during the 1990-91 period and it has indccd occurred in the total reuirn to shareholders.

Howcvcr, our stock price market-to-book ratio lags at this point, and is a focal point for management.

Niagara Mohawk has also begun benchnrarking in the SBU's. ES8:D inaugurated a program to define thc processes that create value for customers, and to measure perfor-mance of tasks against industry bcsts. Programs are being extended to the other SBU's as well.

Our organization at a glance...

In 1990, Niagara Mohawh began to restructure its operations into

~r Strategic Business Units (SBUs): Electric Customer Service, Electric Supply and Delivery, Niagara Mohawh Gas and Nuclear. Each is a separate business accountable for its own results in support of overall corporate goals. Each has its own capabilityforsuch functions as planning, budgeting and labor relations, so that it can operate at a high level ofindependence.

The SBUs are largely autonomous.

Only those functions that provide economies ofscale, such as data processing, and those that require overall corporate policy and direction, such as strategic planning, employee benefits and erternal a+airs, are still performed at the corporate level. These Electric Custotner Service-Niagara Mohawl"s largest business unit, with about 4,600 employees sprc the company's entire 24,000-square-mile service territory. This SBU provi e

direct contact point for 1.5 million residential, commercial and industrial customers that used more than 36 billion kilowatt-hours ofelectricity last year.

Electric Customer Service is divided into eight operating regions. Its broad spectrum of customer contacts include ncw service connections, our innovative demand-side management

programs, service tailored to fit the needs of large industrial users, billing, customer telephone contacts and meter reading.

Electric Supply &Delivery-Dcvclops, operates and maintains Niagara Mohawl"s fossil and hydro generating facilities and its extensive electric transmission system, and administers the company's electric research and development programs.

Electric Supply and Delivery also is responsible for buying and selling wholesale power and managing nearly 1,600 megawatts ofinstalled non-utilitygenerating capacity.

Thc company's 4,200 megawatts of fossil and hydro generating capacity is also managed by ESTD.

Niagara Mohawk operates 74 hydro stations, more than any other utilityin the country.

The Power Delivery Department of ES8cD controls more than 900 electric substations an t

9,200 circuit miles ofclcctric transmission lines.

ions are divided among three Corporate Support Units: Finance and Corporate Services, Legal and Corporate Relatioiis and Human Resources.

Pith tlie restructuring completed during 1991, last year was thefirstfull year ofoperation for the four SBUs, and it was a successful one. The SBU striictuie supports our commitment to customer service by sharpening our fociis on the dijfering needs ofcustomers served by the SBUs. It also fiirthers our egort to give employees greater responsibility and authority to malie tlie decisions necessary to meet customer needs.

Below are brief descriptions of the four SBUs. Their major accomplish-ments and fiitureplans are described in thefollowingpages.

h NMGas Serves nearly a halfmillion residential, commercial, industrial and transporta-tion customers in a 4,500-stluare-mile service territory and maintains 7000 miles oftransmission and distribution mains.

NMGas provides every service related to natural gas supply and delivery including purchasing, trans-portation, marketing, delivery and service to individual customers.

¹clear-Operates the bvo Nine Mile Point nuclear power plants, located near Oswego, N.Y., on the shores of L~ke Ontario. Nine Mile One is a 610-megawatt plant owned by the company. Niagara Mohawk owns 41 percent of 1,080-megawatt Nine MileTwo and operates the plant. Fottr other New York utilities own smaller percentages

Comjetition Niagara Mohawk, like every other utility in the country, is now in the midst of an cra of stiffand growing-compctition in both its clcctric and gas businesses.

Competition from non-utility gcncrators (NUGs) has eliminated the company's natural monopoly in clcctricity generation but has not lowered prices for customers. Just the opposite.

Fcdcral law requires that Niagara Mohawk buy all the power offered by qualifying NUGs. In addition, a state statute commonly known as thc Six-Cent Law has, until recently, guaranteed certain NUGs a minimum payment pcf kilorvatt-lrourivhlch ls tivicc as high;ls thc pfcscnt, opcll market wholesale price.

As a result, Niagara Mohawk has been forced to take too rlnich NUG supply at too high a price. Thc company estimates overpaymcnts to NUGs at $268 million in 1992, or about 8 percent extra on our customers'ills.

In response, Niagara Mohawk formalized-an action plan carly in 1992, initially centered on convincing the State Legislature to rcpcal the Six-Cent Law.

Within months, thc Six-Cent Law was repealed, but only as itapplied to NUGs without contracts. In addition to those already operating, thc 7G8 megawatts of NUG projects under construction and thc 1,353 megawatts not yct started but with existing contracts were "grandfathered" in.

Niagara lvlohalvk's other actions to reduce NUG impacts on customers during 1992 have included active participa-tion in the state Public Service Commission's 1992 Run Avoided Cost (LRAC) case, which sets the current and future prices for NUGs tliat do not qualify for the six-cent mininuim. In deciding thc case, the PSC reduced 1992 LRACs to about lialfthc 1990 level.

Niagara Mohawk also has intensified its monitoring of NUG compliance with contracts. It has terminated the contracts of a number ofNUGs that have not been meeting contract terms. Other contracts have been renegotiated, or bought out when that proved economic.

Niagara Mohawk has filed a petition with thc PSC requesting that it be allowed to verify whether certain NUGs arc maintaining "Qualifying Facility" (QF) status under the federal Public UtilityRegulatory Policics Act. The Act contains operating and cfficicncy standards and an ownership test which a NUG nnist satisfy before a NUG becomes a QF and a utilityis required to buy power from it at a price set according to the LRAC. The company wants to be sure tliat NUGs continue to meet those criteria.

In addition, Niagara iVIohawk asked the PSC for permis-sion to curtail NUG output, rather than its own loivcr-cost capacity, during times of low demand. Thc company also petitioned the PSC to rcquirc certain NUGs to provide firm security to ensure tliat they willreturn to Niagara Mohawk customers the ovcrpaymcnts they receive in the early years of operation, as the iNUGs'ontracts require. Action ~

petitions is expected in mid-1993.

POWER OF CHOICE The Stora Papyrus plant in Newton Falls, N.Y., at right, is typical of the new options available to industrial elec-tricity customers.

It runs a hydro dam to produce one-third ol its power, and Niagara Mohawk supplies the other two-thirds. Stora made the paper for this report, using recycled waste paper from Niagara Mohawk. Shown at far right is a historic view of the electric utility business, a turn-of-the-century street light being serviced by a Buffalo Niagara Company employee. The power came from the first alternating current line in the U.S

e company estimates that its efforts have reduced potential NUG overpayments by more than $650 million over thc next 30 years. As a result of actions taken tlms far, and reductions in other billingfactors, the projected risc in customer bills is slowing, and actions still under way will lessen upward pressure on rates still further.

Despite the higher costs from NUGs in its wholesale elec-tric business, Niagara Mohawk sees potential opportunitics in competition.

Last year's major federal energy legislation will further open the electric utility industry to competition. Rcpcal of the Public UtilityHolding Company Act may allow Niagara Mohawk and its subsidiary, HYDRA-CO, greater latitude to pursue unregulated projects ifthey make scnsc for customers and shareholders.

Another provision opens access to utility transmission systems, but whether utilities will receive a fair return for that access remains in doubt. Depending on the resolution of this issue, Niagara Mohawk could realize signilicant additional revenue for transmitting power from the many NUGs in its service territory to other utilities. In addition, gas-fired NUGs arc potential large-volume customers for NMGas.

Natural Gas Market tantial deregulation of the nation's interstate natural elines has made the supply side of the gas business morc competitive and challenging. Overall, deregulation has driven prices down and created the opportunity for Niagara Mohawk to tailor services and rates more closely to customer needs.

In 1992, the Federal Energy Regulatory Commission issued Order 636, which is designed to complete the "unbundling" of the nation's natural gas pipeline services.

Seven years earlier, another FERC order had allowed Niagara Mohawk's 650 largest customers to buy gas directly from producers, with the company providing transporta-tion. In 1991, Niagara Mohawk had successfully negotiated an agreement that partially unbundled service with its major pipeline supplier, giving thc company direct access to firm gas supplies, storage and pipeline transportation ser-vices. Order 636 now grants complctc access to these services for distribution companies such as Niagara Mohawk.

Over the past several years, NMGas has increased its diversity of supply, improved thc infrastructure, stcppcd up marketing elforts and made great strides in providing supe-rior customer service. Those stratcgics leave the company well positioned to take advantage of the opportunities offered by the new competition in thc gas market. NMGas also will be focusing on intensified competition from fuel oil, electricity, other gas companies and unregulated energy service companies.

Environment Land Management As part of its environmental policy, Niagara Mohawk has taken a fresh look at its exten-sive landholdings.

Some land is no longer needed for energy production, and Niagara Mohawk has devel-oped a comprehensive land management policy to find the highest and best use for each parcel, achieving the proper balance between environmental preservation and the region's economic needs.

The first fruits of that policy came during mid-1992, when the company announced ils plan for 24400 acres of ils land along the upper Hudson River in the Adirondack Park.

Niagara Mohawk developed the plan, called the Upper Hudson Greenway Project, in cooper-ation with state government, community inter-ests and environmental groups. As part of the plan, the company conveyed about 1,200 acres along 16 miles of shoreline to the Conservation Fund for ultimate inclusion in tho Adirondack Forest Preserve.

'nro plan drew praise from Gov. Cuomo at an Albany ceremony announcing the land convey-ance to the state, and earned Niagara Mohawk awards from the Adirondack Council and the Adirondack Park Centennial Committee.

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In recent years, environmental challenges have multiplied. At the same time our cus-tomers'wareness of cnvironmcntal issues has grown.

In response, Niagara Mohawk adopted a

forward-looking "beyond compliance" environ-mental policy in 1991. Last year, the company took a number of actions based on thc policy tliat place Niagara Mohawk in the forefront of corporate environmentalism.

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~a~~~ka criteria for measuring corporate environmental performance, and incorporation of the environmental policy and specific targets in business plans. Thc company bcli es it is in thc best interests of customers, shareholders and employees for Niagara Mohawk to be a leader in addressin ronmental concerns.

Niagara Mohawk's approach to environmental protection includes research and development of eflicient and renew;I e

energy technologies, and energy conservation (scc separate stories).

Nearly half of the company's electricity is produced using low-or zero-emitting sources such as hydroelectric, nuclear, and natural gas sources which have relatively low environmental impact. At the oil-and coal-fired plants that make up the remainder, Niagara Mohawk has substantially rcduccd ernissions over the past two decades.

10

The Clean AirAct of 1990 willrcquirc still lower emission and Niagara Mohawk in 1992 forinulated strategy to hase I requirements. To achieve compliance, Niagara awk will implcmcnt a combination of alternatives tliat include: fuel sivitching, lower sulfur coal and gas co-firin, installation of low nitrogen oxide burners on coal units and fine tuning boilers and other steps. Phase I compliance is expected to require capital investment ofabout $90 million.

Phase IIof the Act is schcdulcd to go into effect by the year 2000. Specific requircmcnts for this phase have not yct been determined.

During the year, thc company bccamc onc of the firs utilities in the United States to confront thc problem of greenhouse warming. Despite the current scientific debate over the iiaturc and cxtcnt of warining, Niagara Mohawk thinks the impacts projected by proponents of the green-house warming theory arc so scvcre that action should not be delayed.

Niagara Mohawk's Grccnhouse Warming Action Program has a goal of reducing company carbon dioxide emissions by almost twice as mtich as current fcdcral government goals for the year 2000.

The company also will take actions to reduce emissions of other greenhouse gases such as chlorofluorocarbons.

The actions in thc plan will use low-cost, currently available tcchnologics and will bc economically justifiable in their own rigllt.

Greenhouse warming was a nrajor topic at last June's Rio ciro Earth Summit, along with discussions of how to in the diversity of life on earth, and how to accom-p environmental goals while sustaining the global economy. In December, Niagara Mohawk became one of first corporations in the country to begin applying the lessons ofRio. The company, along with the State University of Ncw York and the state Department of Environmental Conservation, co-sponsored "Environmental Summit '92, Messages from Rio, Directions for New York."

For two days, a distinguished group, including Governor Cuomo and reprcscntativcs of business,

academia, govcrn-ment and the environmental community, planned how to translate the agreements of the Rio conference into prac-tical programs to benefit the people ofNew York state.

The company also is a leader in waste recycling. Niagara Mohawk.'s Investment Recovery Center, staffed almost exclu-sively by disabled workers, more than pays for itself. The center recycles more than 2 million pounds ofpaper a year, and is one of the first utility-opcratcd rccycling programs in the country to process scrap wire into nuggets, which command a higher market price.

While most of Niagara Mohawl"s environmental initia-tives look to the future, some of its environmental liabilities are a legacy of the past. Thc company's predcccssors oper-ated a number of sites whcrc gas was made from coal to lightstreet lamps and provide heat in thc 19th century. Most of these manufactured gas plants sluit down long before Niagara Mohawk came into cxistcnce, but. many left a residue that must be clcancd up.

In December, Niagara Mohawk signed two scparatc agreements with the state Department of Environmental Conservation to study and, where ncccssary, clean up 22 such sites. Niagara Mohawk already lras a clean-up project under way at Harbor Point in Utica which will pilot research and devclopmcnt reinediation tcchnologics. The company estimates that the site rcmcdiation prograin will take more than 10 years.

The company also has been successful in finding uses for flyash, a by-product ofburning coal and fuel oil to produce clcctricity. Disposal in landfills has been costly and cnviron-mcntally sensitive, but Niagara Mohawl's Fossil Generation and Fuel Supply pcrsonncl have worked to find uses for fly ash in, for example, building foundations and roads, and as a component for roofing shingles. As a direct. result of tlieir efforts, last year the state Department of Environmental Conservation granted approval for such uses.

In 1992, about 12 percent, or 40,000 tons, of total ash was diverted from landfills to approved use, lowering landfill costs by S400,000 and generating more tlian $130000 in gross revenues. Efforts willexpand in the coming year.

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Noted photographer B.R. Stoddard captured this view of boaters en.

joying the tranquility of Edmonds Pond in the Adirondacks early in the century.

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Bemand4ide Management Niagara Mohawk's Demandkide Management (DSM) pro-gram links three of the company's main aims: customer service, energy efficiency and environmental protection.

The three-year-old DSM program puts Niagara Mohawk in partnership with its customers to improve their energy ef-ficiency. The program is part of the company's Integrated Electric Resource Plan, a dctailcd study ofthe most econom-ical way to meet each additional increment of future cus-tomer electricity demand.

In many cases, managing demand can be less expensive than adding new supply. Long-range plans call for DSM to contribute as much as 400 megawatts, or 25 percent, of new capacity needed over the next two decades.

Niagara Mohawk's 16 company-sponsored and 6 biddcr-sponsored DSM programs provide rebatcs and incentives to customers for taking energy conservation measures. T a cost to the customer to save a kilowatt-hour, but it is less than thc cost ofgenerating the same kilowatt-hour.

Niagara Mohawk is compensated for DSM program costs and the lost profit resulting from usage reduction based on reduction goals and cost-effective program implementa-tion. In 1992, the company exceeded its goal of 244,000 megawatt-hour reductions by more than 20 percent, based on preliminary figures.

Thc industrial and commercial DSM programs have been so successful in promoting energy-efficien technologies and accelerating changes in the marketplace, that the high level ofrcbates and incentives is no longer necessary.

The company's 1993 program will be adjusted to allow pricing and other market forces to play a larger role.

DEMAND FOR SAVINGS Linda Heim, a consumer relations represen-tative, and Claude Rounds, vice pres-ident of plant management for Albany Medical Center, discuss Niagara Mohawk's Demand Side Management plan for the center. The project, one of the largest to be sponsored by a utility in the country, willsave the Center $ 1.1 million per year in energy costs, a 35 percent reduction.

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Research &'BerjelePment ING THE WIND Niagara Mohawk has known of ower's potential for some time, as shown in the photo of a 15 kilowatt turbine erected in 1977 in awrence County. At top, the company's two 360-kilowatt wind turbines, erected in 1992 near Watertown, demonstrate the advancement of the technology.

Niagara Mohawk has a significant research and development effort focused on developing the clean, renewable energy sources of the future. In September, the company installed two 360-kilowatt wind turbines on 80-foot towers near Water town, N.Y.

The three-year project is the first ofits kind in the North-east and will determine whether the gus'ty 'north 'country winds can develop into an economical, rcliablc source of clcctricity. The advanced, variable speed turbines arc prod-ucts of U.S. Windpowcr, a participant in the project. Also joining Niagara Mohawk in thc project are the Electric Power Rcscarch Institute and Pacific Gas 8e Electric Co.

Another Niagara Mohawk program, exploring the usc of solar cncrgy at a state offic building near Albany, has been named by thc U.S. Department of Energy as a winner of its 1992 "Innovative Energy Award."

The company installed 70 solar photovoltaic panels on thc roofofthe state Division ofMilitaryand Naval AKairs build-ing in 1990. The demonstration project has bccn so success-ful that it has been cxtcndcd by two years and expanded to include testing a battery storage system in combination with the solar array.

Niagara Mohawk is also testing a fleet of seven clcctric-powcred cargo vans as part of a nationwide, three-year project aimed at commercializing clean electric vehicle technology.

The "GVan" is designed for urban use, using a Gcncral Motors body, a special propulsion drive train and 86 lcad-acid batterics. It has a top speed of 52 mph and can travel 60 miles between charges. Its makers hope the vehicle can bc on the market within three or four years.

Niagara Mohawk Gas, the company's natural gas Strategic Business Unit, liad an outstaritling year in 1992, increasing its total itatural gas throughput 44.4 percent over 1991 to 79.2 million dckatherms.

New business from cogeneration projects accounted for much ofthe incrcasc.

NMCas contiiiucd its residential marketing push, picking up about 11,000 residential heating customers, some of whom added heating to their previous service, and many others who were new hoolc-ups. NMGas also completed its merger with Syracuse Suburban Gas. The $6 million trans-action added 4,600 morc customers and filled in a gap in the company's service territory and distribution system.

During the year, NMGas started its Target Account Program, aimed at providing increased value to industrial customers. NMGas made individual contact with 450 large custorncrs and held quarterly group meetings, technical scrninars and other events.

The SBU's focus on personal scrvicc, advertising and promotions increased public awareness of thc advantages of natural gas during 1992.

Thc coming year is cxpccted to see a strong market for natural gas nationally, and NMGas willconccntratc on iden-tifying growth trends and taking advantage of the company's goals include 13,000 new residential custo NMGas is developing a Gas Efficiency Plan, requested from all utilities by the state Public Service Commission by April 1. Thc plan willemphasize the flexibilityand diversity of supply, customer service and operational efficiency programs'that NMGas has developed in response to the intense competition in the natural gas industry. It also will outline some of the future programs NMGas will offer to assist customers in maiiaging their demand for gas, much as Integrated Resource Plans for electricity have made use of demand-side management.

NMGas also will participate in the first installation of a public vehicular natural gas refueling station in the service territory, in partnership with Hess Oil. The station will open in Albany in mid-April. Two more are planned, one each for Albany and Syracuse, with a completion goal of late this year.

The company also has supported demonstrations of natural gas vehicles in the Syracuse school system and regional bus system, in addition to testing natural gas fleet vehicles in its own operations and with others.

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Qv WHAT'S OLD IS NEW Although gas lights faded out in Niagara Mohawk's service territory in the 1920s, the company helped to recreate an 1892 gas.lit street scene for the 1939 New York World's Fair, top. At right, after an absence of more than 70 years, gas street lighting reap-peared as NMGas began service last May for Bellevue Estates in Syracuse.

¹clear At left, a portion of the contain-ment structure for the Nine Mile Point Unit 1 nuclear facility is lowered into place in 1965.

ff7 is 6'Q til/ST r.

j g)i One of Niagara Mohawk's most important tools for cutting costs and improving efficiency is its nuclear materials testing laboratory.

The Iab qualifies parts for the plant as "nuclear grade."

Nuclear utilities pay a premium for parts that meet specifications.

The materials Iab has two major roles in cost-cutting: making sure Niagara Mohawk gets what it paid for, and finding off-the-shelf parts for a fraction of the cost of special-ordered components.

For instance, according to Iab director Grant Pierce (above left),

the company ordered a valve supposedly made of stainless steel, but the Iab found it was nickel.coated brass, which is not nuclear grade.

A special-ordered nuclear grade transistor can cost as much as $2,000, but the lab found transistors at a local electronics store that met specifications for 30 cents each. Testing and certifying the transistors costs $40, but the company still realized considerable savings.

Niagara Mohawk's Nine Mile Point Units One and Two nuclear power plants both finished 1992 on high notes, operating at full power. Nine Mile Onc set monthly production records in November and December, and both plants sct quarterly production records in the last thrcc months of 1992.

The company's Nuclear SBU spent thc year streamlining and strengthening its opentions. In August, thc company rcccivcd two "cxccllcnt"and five "good" marks from the Nuclear Regulatory Commission in an evaluation ofseven catcgorics critical to plant safety and performance.

Executive Vice Prcsidcnt-Nuclear, B Ralph Sylvia, said he is pleased with the rcport, but..., "We arc not satisfied with only being considered a good nuclear operation and willremain focused on... our vision ofbecoming an industry lcadcr."

Management systems improvements included initiation of a comprehensive procedure rewriting process, and development ofa problem identification and resolution program that empowcrs each employcc to address plant concerns.

The nuclear unit continued its industry-wide search for top talent, bringing in a vice president and other executives from other utilities and internally identifying innovative and skilled managers as candidates for further training and promotion.

At thc same time, the company contiiuicd its "right-sizing" efforts, which it began by comparing Niagara Mohawk nuclear operatioiis to thc best operations in the industry to determine the right number of people required to be a top-flight facility.

Steps toward the ultimate "right-sizing" goal ofno morc than 1,600 employees willbe taken during 1993. By 1994 the SBU will have reduced more than 900 positions from 1990 levels.

For the third straight year, thc nuclear budget was rcduccd, and the SBU improved operations under the tighter budget.

Expenditures were 30 percent below the 1990 budget.

h Nine Mile Point units willundergo refueling during 1993. Nine Mile Point Onc began a refueling outage in February.

file Point Two willbegin its third refueling in the fall.

Qutreaeh O'Education I

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SERVING A NEED Above, Niagara Mohawk employees demonstrate cooking with electric and gas appliances at a New York State Fair during the '60s; and, lop, a Consumer Advocate explains company services to customers in a home visit.

Niagara Mohawk strengthened its emphasis on customer service in 1992 identifying, evaluating and responding to customer energy-related needs.

The company's Outreach 8c Education (08".E) program is a vehicle for two-way communication with customers.

Research is used to identify and analyze customer needs and assess the impact on customers of new or revised programs, policies, procedures and services.

For instance, in 1992 the company conducted focus groups and discovered uvo levels of interest those inter-ested only in the amount of their bills, and those interested in everything the company does.

The O&E program takes this information and coordi-nates production and distribution ofinformational materials tailored to meet different customer needs, from senior citi-zens to those who might need help paying their bills. The materials are keyed to different levels ofinterest and literacy.

The materials provide customers with beneficial informa-tion about their rights and responsibilities and how to obtain full and fair resolution of their problems and complaints.

Panels, roundtables and other gatherings are sponsored by Niagara Mohawk to provide fee k

from customers.

The whole aim of the effort, which also includes tr for Niagara Mohaivk customer contact personnel to improve their communications skills, is to make Niagara Mohawk more "user friendly"for customers.

Economic DevelePment a Mohawk continued efforts to improve economic con itions within its scrvicc territory during 1992.

The company's Economic Development program is aimed in part at bringing new business into upstate Ncw York.

The company plans to spend more than $800,000 during 1993 on marketing efforts promoting upstate New York as a great place to do business.

As of the end of 1992, Niagara Mohawk's Department ofEconomic Development is working with 170 Canadian and 80 domestic companies who have indicated intcrcst in locating in the company's service territory as a result ofpast, marketing programs.

Late in 1992, Niagara iMohawk played a lead role in organizing the "Partnership for a New, Ncw York," a consor-tium of the state's energy and telecommunications utilitics that willconduct a five-year effort, in cooperation with state government, to attract kcy industries and markets.

Subsidiaries HYDRA-CO Entcrpriscs, Inc., Niagara Mohawk's wholly-owned subsidiary formed to develop, own and operate indcpcndcnt power projects, entered its second decade of operation by reaching a milestone on a major domestic project and by expanding into the international market.

HYDRA-CO closed construction financing for a $2G2 mil-lion, 257-megawatt natural gas-fuclcd cogeneration plant in Lakcwood, N.J.

A I-IYDRA-COpartnership was recently selected to nego-tiate final contracts on a 60-megawatt diesel power station in

'ngston, Jatnaica. Thc company is working on another inJamaica, and one in Canada.

RA-CO now has 24 plants in operation or under construction, with a capacity of about 800 megawatts under equity ownership. The plants use a variety of tcchnologics powcrcd by divcrsc energy sources, including water, wood, coal, wind and natural gas.

The company's diversity reflect its judgment of what it takes to bc a long-term developer, investor and operator in the independent power market.

Niagara iVIohawk's Canadian subsidiary, Opinac Energy Corp., faced continuing problems in 1992 largely duc to volatile crude oil and natural gas prices, coupled with a sig-nificant reduction in its estimated reserves of natural gas.

As a conseqticnce of the diHiculties encountcrcd, staff and management cliangcs werc made and capital expenses were rcstrictcd. During 1992, Opinac reassessed its stratcgics and direction, and is now positioned to grow through internal means or by way ofcxtcrnal financing.

Canadian Niagara Power Ltd., Opinac's electric division, celebrated its 100th anniversary of operation at cercmonics in June. Its ccntcnary year, like those before, was marked by good performance.

A MUTUALGAINS Management and union repre-sentatives engage in a Mutual Gains Bargaining

session, under the direction of facilitator Bernard L.

Flaherty, standing, of the New York State College of Industrial and Labor Relations, Cornell University.

The process is designed to produce better bargain-ing solutions and improve relationships between the parties. Seated, left to right, are Michael P. Ranalli, senior vice president-Electric Supply and Delivery; Raymond A. Vallilee, acting chairman, Sys-tem Council U.11; Jack R. Swartz, vice president-Employee Relations; Charles A. Borell, president, Local Union 1484; and John W. Powers, senior vice president-Finance

& Corporate Services.

17

NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES Management's Discussion and Analysis ofFinancial Condition and Results ofOperations Ovcrvicwof 1992 Earnings for 1992 were $219.9 millionor $1.61 pcr sharc ver-sus $203.0 million or $1.49 per sharc in 1991. Factors con-tributing to the increase in earnings in 1992 as compared to 1991 include rate increases for gas and electric customers cffcctive July 1, 1991 and July I, 1992, decreased levels of nuclear operating and ryaintenance expenditures and cost management of non-nuclear expenses relative to amounts provided in rates, offset by oil and gas writeoffs. Thc Com-pany's return on common equity in 1992 was 10.1%, as compared to an allowed return on utility operations of 12.3%. Thc earnings deficiency was caused by several kcy factors, including earnings ofsubsidiaries at a rate below the Company's authorized return on equity for regulated opcm-tions and spending for operational activities in an amount that exceeded the amount assumed in setting rates, offset by incentive equity returns for iVIERIT and DSM programs, and the Company's share ofNine MilePoint Nuclear Station Unit No. 2 (Unit 2) proceeds oflitigation relating to its con-struction. These and other factors are discussed in morc detail under "Results of Operations." Through continuing self-assessmcnt and financial and operational benchmark-ing, the Company's Strategic Business Units (SBUs) arc addressing these and other issues that create earnings dcfi-cicncies as well as considering opportunities for earnings cnhanccmcnts.

Non-cash earnings in 1992 werc $35.2 mil-lion, representing 16.0% oftotal earnings.

Dividends pcr common share increased to an annual rate of$.80 from $.64 during 1992, consistent with thc Board of Directors'ong-term financial goals for the Company.

The Company's capital structure at December 31, 1992 was 56.4% long-term debt, 74% preferred stock and 36.2%

common equity. In early 1992 the Company began issuing ncw shares of common stock under the Dividend Reinvcst-mcnt and Employee Stock Plans, and it now anticipates a

public issuance of approximately 5 million shares in 1993.

Such cflorts arc intcndcd to continue improvement, in the Company's capital structure. Market value and book value of common stock at December 31, 1992, were $19.13 and $16.33 per share, respectively; a market to book ratio of 117% versus a 115% ratio at December 31, 1991. The ratio of earnings to lived charges for 1992 was 2.24, up from 2.09 in 1991.

Evpenditurcs for construction in 1992, including nuclear fuel, related AFC, overheads capitalized and capitalized leases were $502.2 million and were primarily funded through internal sources.

Construction expenditures had been forecast to be $513 million in 1992. The reduction in spending reflects emphasis on cost management by the SBUs. The 1993 construction estimate is $525 million of which 90% is expected to bc funded from intcrinl sources.

During 1992, the Company raised approximately $944.6 million from external sources, consisting of $835.0 million of debt (of which $794.8 million was used to refinance debt), $ 19.5 of common stock and a net increase in short-term debt of$90.1 million.The Company took advantage of low interest rates by implementing a refinancing program for approximately 23% of its outstanding debt, lowering its embedded cost of debt from 8.4% to 77%. Thc Company expects to require approximately $631 million of external financing in 1993, of which $438 million represents sc red-uled and optional rclinancings.

There were several kcy developments during 1992 that demonstrate progress in thc Company's continuing sclf-asscssment

program, as well as challenges for the future, including repeal ofNew York State's "6-cent law" for non-util-itygenerator (NUG) contracts, an update of the Company's economic study ofNine Mile Point. Nuclear Station Unit iNo.

1 (Unit I) which indicated that continued operation ofUnit I was economical at least for thc next fuel cycle, issuance by the Fcdcral Energy Regulatory Commission (FERC) ofrules that could expand opportunities for thc Company's gas busi-ness and passage of thc Energy Policy Act of 1992 to repeal certain limiting regulations of the Public UtilityHolding Company Act, of 1935 and expand to others access to utility transmission facilities, including the Company's.

These developments will continue to challenge the Company in 1993 and beyond.

Progress Towards Corporate Vision The Company's Vision is to become the most responsive and eflicient cncrgy services company in the iNortheast to achieve maximum value for customers, shareholders and errrployccs.

Progress towards tint Vision bean with the self-assessment process in 1989 and now forms th s

for many of the new initiatives rcccntly underta the Company.

A significant result of self-assessment and thc drive towards the Vision is a clnnge in focus in the ratesetting process, from base rate incrcascs to customer bill impacts.

The Company is keenly aware that changes in the utility industry and the regulatory environment arc fostering com-,

petition in both the electric and gas businesses. Thc prolif-eration of NUGs or Independent Power Producers (IPPs) aided by federal and state statutes w'hich provide thein guar-anteed markets at rates in excess of the Company's internal cost of production, lns put signiTrcant upward pressure on thc Company's clcctric rates. During the past several years, thc Company's industrial rates have moved from being among thc loivcst in New York State and the iNortheast to approximately the middle of the range. Such increases in rates arc reaching a point where industrial customers must balance the bcncfits and costs of sclfgeneration against rctcntion ofutilityscrvicc. More importantly, industrial and commercial customers may also consider moving operations outside of thc Company's service territory. Loss ofindustrial and commercial customers places additional cost burdens on remaining customers. The potential loss ofjobs in the Company's service territory would put further pressure on rates to remaining customers and on the State's social ser-vices delivery system.

Similar issues face thc gas business, as greater fei ral emphasis is placed on increasing competition for i supply and delivery. Although competitive pressures principally to pipclincs and industrial customers, the possi-bilityofretail competition is growing. Formation of the Gas SBU in 1991 has focused efforts on positioning the business to take advantage of the changing environment, by optimiz-ing its gas supply portfolio to achicvc lower costs without 18

NIAGARA MOHAWK POPOVER CORPORATION AND SVBSIDIARY COMPANIES sacrificing reliability and by aggressively marketing its gas to potential or existing customers near its distribu-ies.

c Measured Equity Return Incentive Tcrrn (MERIT) program, as discussed in more detail below, and the contin-uing self assessment process embody the improvcmcnts in performance necessary to mitigate bill impacts and their attendant effects. Measures that compare Company cost and scrvicc performance with a peer group ofsimilarly situated Northeast utilities willbe included in MERITbeginning in

,1993. Over the next three years, increasingly challenging perfonnance targets for these external indicators will be cstablishcd, dcsigncd to bring the Company to top-quartile performance within the peer group. Achieving these targets ivould demonstrate the Company's ability to respond favor-ably to challenges facing utilities and to mitigate the bill impact consequences discussed above.

The Company must successfully

manage, among other things, the economics of the continued operation of Unit I, implementation of the Clean AirAct Amendmcnts of 1990 and remediation of hazardous waste sites, while responding to thc challenges and taking advantage of thc opportunitics of thc Energy Policy Act of 1992 and addressing the oppor-tunitics of cxpandcd gas supply competition, as well as continuing implementation of its strategies to reduce bill impacts stemming in large part from thc proliferation of cxccss high-cost NUG power. Through initiatives such as "core process redesign," the Company willalso continue its ally dircctcd selfassessment, emphasizing low cost ions and employee empowcrmcnt without compro-g service to customers.

Regulatory Agrccments The Company's results during the past thrcc years have bccn strongly influenced by several regulatory agrecmcnts it has entered into. A brief discussion of thc kcy tcrrns of certain ofthese agrccments is provided below.

1989 Agreement Thc 1989 Agrccmcnt represented a bcllwethcr scttlcmcnt and a significant change in the approach of thc Company and the Public Service Commission (PSC) Staff to the ratc-setting process. A key objective of this agrccmcnt was to sta-bilize thc Company's financial condition and attempt to maintain its senior securities ratings at invcstmcnt grade level. This was accomplished by permitting thc Company to defer, for future recovery, certain operating cxpenscs in an attempt to attain specified intcrcst coverage ratio levels through thc cnd of 1990. Substantially all of the interest covcragc dcfcrrals willbe recovered by thc cnd of 1993.

In return for stabilizing its financial condition, thc Com-pany agreed to formalize the process by which it had been developing a Vision and Mission Statement and a self assess-ment process for continual improvcmcnt in thc way its business is managed. The creation of an incentive return anism was recommended to provide thc Company iortunity to earn an incremental return on equity on performance targets designed to rcflcct improve-ments in the efliciency and effectivcncss of its organization and management.

The Company also agreed to study thc advantages and disadvantages of separation, sale or other action with respect to its gas business and submit a study of the advan-tages and disadvantages ofcontinuing thc operation ofUnit

1. Based upon thc benefits identified in the gas study and consistent. with thc results of thc self assessrncnt process, the Company reorganized its electric and gas operations into SBUs cffcctive July 1, 1991. The Company performed thc Unit I economic study and filed a report dated Mardi 28, 1990 which concluded that continued operation of Unit I was in the best interest of the ratcpayers. Although the PSC Staff disputed certain assumptions used in the study, no further action was taken. In the 1991 Financial Recovery Agrccmcnt discussed below, the Company agrccd to update its Unit I economic study prior to each rcfucling cycle and make it available to the PSC Staff (See Note 8 of Notes to Consolidated Financial Statcmcnts).

1991 Financial Recovery Agreement The 1991 Financial Recovery Agreement (1991 Agrccment) established thc $190.0 million temporary rate incrcasc that bccamc effective January I, 1991 as permanent and provided for electric rate increases of 2.9% ($75.4 mil-lion) cffcctivc July I, 1991 and 1.9% ($557 million) effec-tiveJuly I, 1992. Gas rates increased 1.0% ($5.5 million) on July 1, 1992.

Thc 1991 Agrcemcnt included several kcy clcmcnts which represent departures from thc Company's prior rate setting methodology. Two of these elements, the Niagara Mohawk electric rcvenuc adjustment mechanism (NERAM) and thc MERITarc discussed in morc detail below.

The NERAM requires the Company to rcconcilc actual results to forecast electric public sales gross margin as defined and utilized in establishing rates. Thc NERAM pro-duces certainty in the amount of electric gross margin the Company will rcceivc in a given period to fund its opera-tions. While reducing risk during periods of economic uncertainty and mitigating the variable cffccts of wcathcr, the Company does not benefit'from unforsccn growth in sales. Depending on thc level of actual sales, a liability to customers is crcatcd ifsales cxcccd the forecast and an asset is recorded for a sales shortfall, thereby gcncrally holding recorded clcctric gross margin to the level forecast in estab-lishing rates. The 1991 Agreement provides for the opera-tion of the NERAM through June 30, 1993. Rccovcry or refund ofaccruals pursuant to the NERAM is accomplished by a surcharge (either plus or minus) to customers over a twelve month period, to begin when curnulativc amounts reach certain lcvcls specified in the 1991 Agrccmcnt. Recon-ciliations werc initiated on July I, 1991, Junc I, 1992 and Decernbcr 1, 1992 and thc balances to bc collcctcd were reclassified to Accounts Receivable.

As of Dcccrnbcr 31, 1992, the Company had a recoverablc NERAM balance (amounts subject to reconciliation) of$ 11.G million.

The MERITprogram is thc incentive mechanism crcatcd in contemplation of thc provisions of the 1989 Agrccment which originally allowed the Company to earn up to $180 millionofadditional return on equity through May 31, 1994.

The MERIT program provided for a total of$60 million of the $ 180 million pool during 1991, $30 million for the measurcmcnt, period January 1 through May 31, 1991 and

$30 millionfor the balance ofcalendar 1991.

The PSC granted the full $30 million of MERIT award the Company claimed for the period January I, 1991 through May 31, 1991. Criteria for earning thc initial $30 million of incentive return for the period ending May 31,

NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES 1991, encompassed nuclear performance, progress in im-plcmcnting ideas to capture savings identified in the self-assessment

process, customer satisfaction indicators and a reduction in the layers ofmanagement. This award, amount-ing to approximately $.14 pcr share, was rcflcctcd in earn-ings in the third quarter of 1991 and was collected over the period October 1991 through June 1992.

MERITgoals for the period June I, 1991 through Decem-ber 31, 1991 included measures ofresponsivcncss to custom-ers, implementation of selfassessrnent ideas, nuclear and non-nuclear generation and planning and environmental awareness. The potential value ofMERITfor this period was also $30 million. Of this amount, the PSC granted $22.8 million, or approximately

$.11 pcr sharc. The difference between the Company filingrequesting $26 million and the ultimate award was related to implementation of self-assess-mcnt cost savings measures.

The Company accrued the MERITaward inJunc 1992 in Accounts Receivable and it is being collcctcd over the period July 1992 through May 1993.

The Company and the PSC Staff reached an agreement, which was approved by the PSC on July 9, 1992, to amend the 1991 Agrccment as it related to the MERIT incentives for,.1992 and beyond. The amendment realigns the MERIT schedule to make it consistent with the Company's schedule for achieving its Corporate Vision by 1995. The agreement makes available $25 million of MERITin 1992, $30 million in 1993, $35 million in 1994 and $40 million in 1995. This extends thc original period by 18 months and totals $130 million, making available during this period $ 10 million morc than under the original agreement.

In addition, agreement has been reached to reopen negotiations in 1993 to determine whether additional MERIT incentives should bc established for 1994 and 1995.

Measurement criteria for the $25 million of MERIT for 1992 focus on implementation ofself assessment recommen-dations, including measures of responsiveness to customers, nuclear performance, cost management and environmental performance. A rcport supporting the achievement of MERIT for 1992 was submitted to the parties to the 1991 Agreement on February 12, 1993. The Company claimed an award of approximately $14.3 million, which is expected to be billed to customers beginning in May 1993, after PSC confirmation of the earned award. The shortfall from the full award available reflects the increasing difficulty of achieving the targets established in customer service and cost managcmcnt, as well as lower than anticipated nuclear operating performance.

Criteria for the 1993-1995 MERIT periods are currently being negotiated. Although individual goals have not been decided, progress is being made on the framework within which individual goals will be established. The three focus areas are: (I) Responsiveness to Customer Needs, (2) Efli-cicncy through Cost Management, Improved Operations and Employee Empowerment and (3) Aggressive, Respon-sible Leadership in Addressing Environmental Issues. The Company expects that targets for full award of MERIT will be more exacting and the Company's success through the first three MERIT periods may not be indicative of future accomplishments.

1993 Rate Set tleiiient Early in 1992, the Company filed for a $1637 million rate increase to become effective January 1, 1993, consisting of an electric increase of 4.6% ($1371 million) and increase of 47% ($26.6 million). The significant nents of the request related to a $55 million incre.

operating expenses, increased environmental site investiga-tion and related remediation expenditures of $28 million, current recovery of the $44 million provision for certain post-employment benefits (OPEB) under a new accounting pronouncement and inclusion, as now required by the PSC, of $37 million of NUG capacity payments in base rates ver-sus passing these costs through the fuel adjustment clause.

On September 14, 1992, the Company, the PSC Staff and other intcrvenors submitted a rate settlement plan (1993 Rate Settlement) to the PSC for approval. The 1993 Rate Settlement increases the Company's revenues by $108.5 mil-lion (3.1%) for the year ended December 31, 1993 through changes in rates for electric and gas service. Electric revenues increase $98.4 million or 3.4%, while gas rcvcnues rise by $10.1 million, or 1.8%. The 1993 Rate Settlement was approved by the PSC on January 27, 1993, and new rates werc implcmcnted shortly thereafter. Retroactive application of the new rates to January I, 1993 has been authorized by the PSC.

The increase reflect an allowed return on equity of 11.4%, which is below the 12% requested by the Company in its original filingand the 12.3% rcflected in the 1991 Agree-ment for 1992. A decrease in the Company's cost of capital, including the reduction in return on equity, and allowance for post-retirement benefits in an amount substa below the amount requested by the Company, accoun substantially all of the difference from thc Com s

requested revenue increase. The difference in the post-retiremcnt benefit allowance of approximately $33 million willbe deferred pending the outcome ofthe PSC's consider-ation of a Statement of Policy addressing post-retirement bcncfits. The Company anticipates the release of the PSC's final Statement ofPolicy by no later than the first quarter of 1993. Pending issuance of the Statement of Policy, the 1993 Settlemcnt establishes the intent of the parties for the Company to recover the deferral over a period not to exceed tcn years. As discussed in Note 7 of Notes to the Consoli-dated Financial Statements, thc Company expects that both the 1993 Settlement and the policy contemplated in the PSC's proposed Statcmcnt of Policy will allow the Company to record a regulatory asset for the difference between the allowance in rates and the full accrual for post-rctircment benefits calculated in accordance with the ncw accounting pronouncement.

Other allowances contributing to the increase in revenues include increased amounts for hazardous waste site inves-tigation and remediation costs, capacity payments to non-utilitygcncrators and slightly higher operating costs, as well as inclusion in base rates of costs previously recovered through surcharges.

Beginning in 1993, DSM program costs, exclusive of rebates, will be recovered through base rates rather than through a separate surcharge. Based s

cumulative experience in managing DSM progra the Company believes that base rate treatment is apl ate. The settlement also includes extension of the NERAM through December 1993 and provisions to defer expenses related to the Company's NUG Action Plan, including NUG contract buyout costs and certain other items.

The 1993 Settlement allows the Company to submit a 20

NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPAN'IES second-stage filing in 1993 to consider revenue require-m ts that may arise as thc result of negotiating a ncw contract. The Company's current labor agreement cx-ay 31, 1993.

n February 19, 1993, the Company filed for a gas rate incrcasc of 3.8% or $23.2 million, while submitting a motion to defer an electric base rate filingfor 60 days. The Company will usc that time to attempt to reach an agrcc-ment with the PSC to extend certain cost recovery mecha-nisms in the 1993 electric rate scttlcmcnt without increasing base rates. The Company has requcstcd that the results of both the deferral request and the gas filing become eflec-tive January I, 1994. The increase in gas rates is to cover slightly higher operating expenses, as well as higher real cstatc taxes, property-related costs and construction-rclatcd costs. While some parties arc actively petitioning thc PSC to curtail or suspend the use of settlements in lieu of liti-gated rate cases, the Company believes that all participants have gained from the settlement process. In an Order issued and cffcctive December 30, 1992, the PSC initiated a statewide proceeding to investigate and develop a ratcset-ting process encompassing long-term planning goals, rate strategies and resource utilization.

Non-UtilityGenerators The most significant factor increasing the Company's costs and its customer bills has bccn thc requirement to purchase non-utility generator power at amounts in excess of its i

nal cost of production and in volumes greater than ds. The Public UtilityRegulatory Policies Act of 1978

'A), New York State Law and PSC policics and proce-

<611

$973.6 I

36,738

$837.9 35,544

$877.9 (0.3)%

16.2%

3.4%

(4.6)%

1991 kilowatt-hour generation increased 77% and fuel costs incurred decreased 6.9% as a result of increased generation he Company's nuclear units. 1991 kilowatt-hour purchases decreased 2.4% as a result of the return to service ofUnit 1, osts incurred increased 3.7% as a result ofa 6.3% increase in the average cost per kilowatt hour.

Gas revenues increased $66.5 million or 13.6% over the three-year period. As shown by the table below, this is primarily attributable to increased base rates effective in 1992 and 1991, increased revenues from transportation of gas for others and increased sales to ultimate consumers. Although rates for transported gas yield lower margins than gas sold directly by the Company, decreases in gas rcvcnucs caused by thc migration of customers to the transported gas classiTication has been con-sidered in the ratesctting process and has not had a significant impact on earnings. Also, changes in purchased gas adjustment clause revenues are generally margin-neutral.

Gas revenues fncrease in base rates.

Transportation of customer-owned gas.

Purchased gas adjustment clause revenues...

MERIT revenues Miscellaneous operating revenues...........

Sales to ultimate consumers and other sales...

I 1992 I

$ 4.7 6.3 12.4 (0.3) 2.6 52.9

~ $78.6 I

Increase (decrease) from prior year (ln millions ofdollars) 1991

$ 22.6 14.4 (25.7) 2.7 3.5 (27.7)

$(10.2) 1990 2.2 5.3 (2.0)

(7.4)

$(1.9)

Total

$27.3 22.9 (8.0) 2.4 4.1 17.8

$66.5 Gas sales, excluding transportation of customer-owned gas, werc 79.2 million dckathcrms in 1992, a 10.4% increase from 1991 and a.7% increase from 1990 (See Electric and tatistics Gas Sales appearing on page 52.) The e in 1992 includes a 12% increase in residential sales 4 10.2% increase in commercial sales, which were strongly influenced by weather, offset by a 2.2% decrease in industrial sales reflective offuel-switching and the recession.

The decrease for 1991 includes a 3.6% decrease in sales in the residential class reflecting milder weather factors, an 11.4% decrease in sales in the commercial class and a 56.0%

decrease in sales in the industrial class reflecting the reces-sion and fuel-switching. The changes in the sales mix for 1990 through 1992 reflect more severe weather, unfavorable competition with oil prices and the abilityoflarge customers to purchase gas directly from producers. In 1992, thc Coinpany transported 65.8 million dekathcrms (a 30%

increase from 1991) for customers purchasing gas directly from producers and expects a continued increase in such transportation activities. The Company has forecast an

NIAGARA MOHAWK POPOVER CORPORATION AND SUBSIDIARY COMPANIES increase in total gas deliveries in 1993 in excess of 5.3% of 1992 weather-adjusted deliveries principally in the transpor-tation category, although public sales are expected to increase almost 1.5%. Factors impacting these increases include the effects of the recession that began in 1990, the relative price differences between oil and gas in combina-tion with the relative availability of each fuel, the cxpandcd number of cogeneration projects served by the Company and incrcascd marketing efforts. In 1992, the Ga added 11,000 new customers, primarily in thc resi class, an increase of 2.3%, and expects a similar in in new customers in 1993. Clmnges in gas revenues and dekathcrrn sales by customer group arc detailed in the table below:

Class of service 1992

/ of Gas Revenues 1992 Revenues Sales Increase (decrease) from prior years 1991 Revenues Sales 1990 Revenues Sales Residential.............

Commercial.............

Industrial.

Total to ultimate consumers Other gas systems.......

Transportation of customer-owned gas...

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

7.7 1.7 17.2 30.0 38.5 64.0%

1 7.0%

1 2.0%

23.9 16.6 10.2 1.8 18.6 (2.2) 89.7 16.9 11.1

.9 (32.0)

(21.7)

(1 4)%

(11.5)

(56.4)

(6.6)

(11.9) 65.0 574.1 (3.6)%

(11.4)

(56.0)

(8 7)

(11.8) 47.9 (3.2)%

2.0 57.0 (0.2)

(14.7) 11.4 (84.0)

(5.6)%

(1.4) 57.6 (2.2)

(14.7) 1.4 Total.

100 0%

16.5%

18.5%

(2.1)%

8.4%

(0 4)%

(1.4)%

Thc PSC approved the 1991 Agreement on June 12, 1991, providing for, among other things, the establishment ofper-manent gas rates at thc same level as the temporary rates effcctivcJanuary I, 1991 (an increase of$272 millionor 4.9%)

and a $5.5 millionor 1.0% increase effectiveJuly I, 1992.

GAS SALES (MILLIONSOF DEKATHERMS) 145.0 122.4 LU2 Lll Q

108.7 27.3 114.5 112 9 33!8!

34.3!

50.7' 6$;8>

j 1988 1989 1990 1991 1992 In comparison to the prior year, the total cost ofgas pur-chased increased 16.1% in 1992, after having decreased 13.4% in 1991 and 1.0% in 1990. The increase for 1992 results from increased dekatherms purchased (11.5%), a 1.5% increase in rates charged by suppliers and a $6.9 mil-lion increase in purchased gas costs and certain other items recognized and recovered through the purchased gas adjustment clause. The decrease for 1991 is the result of a 3.3% ($21.3 million) decrease in dekatherms purchased to meet customer demand at slightly lower rates charged by the Company's suppliers, combined with a decrease of$170 mil-lion in purchased gas costs and certain other items recog-nized and recovered through the purchased gas adjustmcnt clause. The decrease for 1990 was the result of a 9.2%

decrease in dekatherms purchased to meet customer demand, offset by higher rates clmrged by the Company's suppliers, and an increase in purchased gas costs recog-nized and recovered through the purchased gas adjustment clause. During the thrcc year period, the Company pur-chased the maximum allowable portion of its gas s

requirements on the spot market, as permitted u contract with its principal supplier, to take advant lower spot market prices. EffectiveJuly I, 1991, thc Company rencgotiatcd its contract with its principal supplier to provide for even greater flexibilityto purchase gas in the spot market and to provide for the utilization of gas storage facilities. Access to these storage facilitics was expanded and liberalized in 1992. Thc Company's net cost pcr dekatherm purchased increased to $3.45 in 1992 from $3.31 in 1991 and $3.70 in 1990.

Further changes in the federal regulation ofgas pipelines, resulting from FERC Order 636 and its amendmcnts issued in 1992, will rcquirc interstate pipelines that offer open access transportation services to unbundle pipeline sales services from pipeline transportation service. These clmnges will cnablc the Company to arrange for its gas supply directly with producers, gas marketers or pipelines, at its discretion, as well as arranging for transportation and increased gas storage services. While gas supply flexibilityis expected to improve the competitive position of the Com-pany in industrial markets, it must meet the challenge in all markets of increased competition while balancing supply flexibilitywith system reliability.

As a result of these structural changes, pipclines face "transition" costs from implementation of the order. Thc principal costs are: unrccovcrcd gas cost that would other-wise lmve been billable to pipeline customers under re-viously existing rules, costs related to restructuring gas supply contracts and costs ofassets needed to iml the order (such as meters, valves, ctc.). Under the cr, pipelincs are allowed to recover 100% ofprudently incurred costs from customers. Prudence will be determined by the FERC review.

The amount of restructuring costs that may be billable

NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES to the Company will bc determined in accordance with e restructuring plans which have been submitted to

'or approval. The Company is actively participating ii C hearings on these matters to ensure an equitable allocation of costs. Based upon information prcscntly avail-able to the Company from thc petitions filed by the pipelines and the Company's participation in settlement negotiations, its liabilitylor the pipelines'nrccovcrcd gas costs could be as much as $56 million and its liabilityfor pipeline restructuring costs could be as much as $60 mil-lion. However, the Company believes ultimate liabilitywill be less than $64 million in total, based on its assessment of the progress ofsettlement negotiations. The Company antic-ipates these costs will be primarily reflected in demand charges paid to reserve space on the various interstate pipelincs and willbe billed over a period of approximately 7 years, with billings more heavily iveighted to the first 3 years. The Company is unable to predict the probablc out-come of current pipeline restructuring settlemcnts and the amounts for which it may bc ultirnatcly liable or the period over which this liabilitywillbc billed. The Company believes any amounts for which it is ultimately determined to be liable willbc recoverable in the ratcsetting process.

Through the energy and purchased gas adjustment

clauses, costs of fuel, purchased power and gas purchased, above or below the levels allowed in approved rate sched-ules, are billed or credited to customers. Thc Company's clcctric fuel adjustmcnt clause provides for partial pass-t i of fuel and purchased power cost fluctuations l

ose forecast in rate proceedings, with the Company a

ing a specific portion of increases or retaining a portion of decreases to a maximum of$15 million per rate year. In 1987, the PSC established a generic procccding to examine the operation of the existing fuel adjustment clause, including whether the fuel adjustment clause should continue. This proceeding is continuing and the Company is unablc to predict the outcome.

Other operation expense increased $52.5 millionor 78%

in 1992 as compared to increases of 78% in 1991 and 9.5%

in 1990. The 1992 increase is primarily duc to wage increases (including the cffccts of the performance based managcmcnt compensation program and union wage increases),

increased computer software cxpenscs and higher medical benefits paid. Thc 1991 increase is primarily due to wage increases, including thc cffccts of a ncw per-formance-based management, compensation program and an increase in bad debt expense. The increase is also due to DSM program expenses, environmental site investigation and remediation costs, and rcscarch and development costs which totaled approximately $41.9 million, but which are matched with specific rcvcnue factors provided for in the 1991 Agreement. Bad debts have increased as a reflection of the effects of the continuing national recession.

Increased collections efforts and innovative collections managcmcnt begun in 1991 to make long-term improvcrnents also con-tr' to the short-term effect ofincreased writeoffs.

Agreement interest coverage (deferral)/amortiza-tion icflccts the impact on operating expenses from the tar-get interest coverage ratio defcrrals allowed under the 1989 Agrccmcnt. The 1991 and 1992 amount rcprcscnts amorti-zation, based on amounts recovered in rates, of defcrrals pcrmittcd in 1989 and 1990. The 1990 deferral was reduced MAINTENANCEAND OTHER OPERATION EXPENSE (MILLIONSOF DOLLARS)

$953.9 0

$668.9 467'9

$778.1 574 I9

$858.1 626;2

$903.0 675.2 727.8 1988 1989 1990 1991 1992 by $42.6 million of cash surcharge rcvcnues permitted by the 1989 Agreement and $14.8 million ofamortization pur-suant to the 1991 Agreement. At December 31, 1992, $16.5 million remained to be amortized.

Maintenance expense dccrcased slightly in 1992 as increased costs associated with outagcs at Unit, I and refuel-ing Unit 2 were offset by rcduccd transmission linc mainte-nance expenses.

Maintenance expense decreased L8% in 1991 due to lower Unit 2 maintenance partly offset by trans-mission line ice storm damage, but increased 12.5% in 1990, primarily due to increased lcvcls of maintenance at pro-duction steam plants, Unit 2 and on the Company's electric distribution system.

Depreciation and amortization cxpensc for 1992 and 1991 incrcascd 5.9% and 172% over 1991 and 1990, respec-tively. The increase is attributable to normal plant growth; howcvcr, the 1991 amount also reflects an $18.2 million in-crease in the provision for nuclear plant decommissioning.

Nct Federal and foreign income taxes for 1992 and 1991 increased as a result of incrcascs in book taxable income.

The 1990 taxes dccrcascd as a result of decreases in book taxable income. The increase in Other taxes in the three-year period is due principally to higher property taxes resulting from property additions along with increased rcvenuc-based taxes.

Other items, net, excluding Federal income taxes, AFC and the nuclear disallowances decreased

$2.7 in 1992 and

$21.9 million in 1991. Thc 1992 decrease is the result of the recording of a $45 million reserve against the carrying value of Canadian subsidiary oil and gas reserves, offset in part by the recognition of thc Company's share of Unit 2 contractor litigation proceeds and increased earnings by the Company's indepcndcnt power subsidiary. The 1991 dccrcase is primarily thc result of a similar writcdown of

$22.7 millionofoil and gas rcscrvcs.

Nct intcrcst charges dccrcascd $12.0 million in 1992 and

$72 million in 1991, primarily as thc result of thc refinanc-ing of debt at interest rates lower than the debt retired. In 1990, nct interest charges increased duc to the issuance of additional First Mortgage Bonds. Dividends on preferred stock decreased

$3.9, $19 and $2.9 millionin 1992, 1991 and 1990, respectively, as a result ofnct reductions in amounts of 27

NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES stock outstanding. The weighted average long-term debt interest rate and preferred dividend rate paid, reflectin the actual cost of variable rate issues, changed to 8.29% and 704%, respectively, in 1992, from 8.74% and 7.53%, respec-tively, in 1991, from 9.11% and 756%, respectively, in 1990.

sects ofCiianging Prices The Company is especially sensitive to inflation because of the amount of capital it must raise to finance its construc-tion program and because its prices arc regulated using a rate base methodology that reflects the historical cost of utilityplant.

The Company's consolidated financial statcmcnts arc based on historical cvcnts and transactions when the pur-chasing power of the dollar was substantially different from the present. Thc effects ofinflation on most utilitics, includ-ing thc Company, are most significant in thc areas ofdepre-ciation and utilityplant. The Company could not replace its utility plant and equipment for the historical cost value at which they are recorded on the Company's books. In addi-tion, the Company would probably not replace these assets with identical ones due to technological advances and regu-latory changes which have occurred. In lightofthese consid-erations, the depreciation charges in operating expenses do not reflect the current cost of providing service. The Com-pany, however, willseek additional revenue'o cover the costs ofmaintaining service as assets are replaced.

Financial Position, Liquidityand CaPital Resources Financial Position The Company's capital structure at Dcccmbcr 31, 1992 was 56.4% long-term debt, 74% preferred stock and 36.2% com-mon equity, as compared to 56.7%, 8.3% and 35.0%, respec-tively, at December 31, 1991. Book value of the common stock was $16.33 per share at, Dcccmber 31, 1992 as com-pared to $15.54 per sharc at December 31, 1991. The improvement in the capital structure and book value is pri-marily attributable to rcinvested earnings, although pre-ferred stock redemptions and sales of common stock under stock purchase plans also had an impact.

The 1992 ratio of earnings to fixed charges was 2.24 as compared to 2.09 in 1991. The ratio of earnings to fixed charges for 1990 was 1.41, which reflect the effects of the loss accrued for disallowed Unit 1 and Unit 2 replacement power costs as discussed above in Results of Operations.

Excluding the effect ofthe loss accrual, the 1990 ratio would have been 182. The 1990 ratio of earnings to fixed charges also reflects the effects of the 1989 Agrecmcnt, which pro-vided for near-term financial stabilization while establishing a frameivork for resolving regulatory and financial issues fac-ing the Company. A key aspect of this financial stabilization was the provision assuring specified interest coverage lcvcls (without.AFC) in 1990.

The Company has been made aware that Iirms which publish securities ratings lravc begun to impute certain items into the Company's interest coverage calculations and capital structure, the most significant of which is the inclu-sion of a "leverage" factor for NUG contracts. These firms believe that the financial structure ofthc NUGs (which typi-cally have very high debt-to-equity ratios) and the character of the power purchase agreements increase the fi al risk of utilities. The Company is aware that its interest coverage and debt-to-equity ratios have r ly been discounted by varying amounts for purposes of estab-lishing credit ratings. Because of the Company's growing commitments for NUG purchases, thc imputation can have a material negative impact on its indicators. Standard and Poors recently changed the "outloolt" for the Company's secured debt from "positive" to "stable" principally due to NUG commitments.

PROJECTED CONSTRUCTION ADDITIONS (MILLIONSOF OOLLARS)

$661 o

$525

$76 I

$72

$85 i $557

$80

$611

$546 27+

$77

$73 I

93 1994 1995 1996 1997 19 Construction and Other Capital Requirements The Company's overall capital requircmcnts consist of amounts for the Company's construction program, working capital needs, maturing debt issues and sinking fund provisions on outstanding debt and preferred stock, and have been affected by the Company's efforts in recent years to lower capital costs through refinancing. Annual expenditures for the years 1990-1992 for construction and nuclear fuel, including rclatcd AFC and overheads capitalized, were $431.6 million, $522.5 million and $502.2 million, respectively.

The 1993 estimate for construction additions, including overheads capitalized, nuclear fuel and AFC, is approxi-mately $525 million, of which approximately 90% is expected to be funded by internal sources. Mandatory and optional debt and prcfcrred stock retirements and other requirements are expected to add approximately er

$579 million (expected to be rcfinanccd from I

sources) to the Company's capital requirements, for tal of $ 1,104 million. Current estimates of total capital requirements for thc years 1994-1997 are $1,170, $784, $813 and $712 million, respectively, ofwhich $661, $557, $611, and

$546 millionrelates to expected construction additions. The estimate of construction additions included in capital requirements for thc period 1994 to 1997 will be reviewed by management during 1993 with the objective of reducing these amounts whcrc possible.

The provisions of the Clean AirAct Amendments of 1990 (Clean AirAct) are expected to ltavc an impact on the Com-pany's fossil generation plants during the period through 28

NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES 2000 and beyond. The Company is studying options for liance with the various provisions of Phase I of the AirAct, which becomes effective January I, 1995 and iues through 1999, including a possible strategy that focuses on fuel-switching at its facilities. Thc potential for changing thc coal burned at the DunkirkSteam Station to a lower sulfur content is under review, and converting Oswego Units 5 and 6 from oil to co-firing with natural gas and oil (including construction of a natural gas pipclinc to the facility) is included in the construction budget. To meet compliance requirements, thc Company must also lower its nitrous oxide (NOx) cmissions and has included $85 million in its construction forecast for 1993 through 1997 to install low NOx burners at the I.Iuntley, Dunkirk and Albany Stcam Stations. Phase II of the Clean AirAct, cffcctivcJanuary I, 2000, willrequire further reductions in sulfur dioxide emis-sions. The Company has conducted studies indicating that the burning of lower sulfur fuels at all its coal and oil fired units is a possible compliance method, but decisions on Phase II liave not yet been made. Thc Company is continu-ing to study its options, taking into consideration thc impacts of emerging environmental laws and regulations at both the Federal and State level and the effect of NUG purchases and DSM initiatives on load forecasts, as well as continuing to examine the emerging market for trading emission allowances.

Thc Company bclievcs that compliance with the new emission restrictions can be achieved with currently avail-ontrol technology and fuel switching alternatives; r, until specific regulations implementing the Clean t arc issued, thc Company can provide no assurance in this regard. The Company believes that all capital costs, as well as incremental operating and maintenance costs and fuel costs, willbe recoverable from its ratepaycrs.

The Company is also studying dnft Ncw York State emis-sions requirements which, as currently proposed, would be far more restrictive than federal requirements and could cause a substantial increase in compliance cost and, in the most extreme case, require retirement of certain of the Company's fossil fuel plants. The Company is unable to predict wlrat requirements will ultimately bc adopted by New York State.

The Company has undertaken a long-term program to reinforce sections of its electric transmission network which are approaching the end of their useful lives. The anti-cipated cost of the reinforcement effort is approximately

$435 millionwithin the period 1993-1997, but the efforts are expected to continue beyond 1997.

The Company has also included amounts in the con-struction forecast for hydro relicensing, as well as for gas system expansion for cogcnention and greater customer market penetration.

Liquidityand Capital Resources Cash flows to meet the Company's requirements for operat-i

'csting and financing activities during the past three e reported in the Consolidated Statements of Cash Flo on page 34.

During 1992, the Company raised approximately $944.6 million from external sources, consisting of $835 million of First Mortgage Bonds, $19.5 million of common stock (which includes $6.1 million issued in connection with the acquisition ofSyracuse Suburban Gas Company, Inc.) and a i1ct increase of $90.1 million of short-term debt and inter-mcdiatc term bank revolving credit obligations, which include the refinancings discussed below The Company also completed

$12.5 million of capital lcasc financing.

These amounts include cxtcrnal debt financing done directly by the Company's subsidiaries, which decreased to

$20.4 millionfrom $54.2 millionin 1991.

During 1992, the Company issued $835 million of First Mortgage Bonds and thc proceeds werc used to refinance

$ 100 millionofmaturing bonds and provide for the call and carly redemption of$638 million ofhigh coupon First Mort-gage Bonds. The Company also refinanced debt underlying a long-term leveraged tnnsmission line lcasc to reduce the interest rate from 11.1% to 8.77% and entered into a forward refunding agreement to rcducc the interest ntc on $115.7 million of tax-exempt bonds from approximately 11.3% to 7.2% beginning in 1994.

ANNUALEXTERNAL FINANCING BYTYPE (MILLIONSOF DOLLARS)

$944.6

$19.5

$407.2

$5.8

$90.7

$372.2

$351.6

$295.1 I $22.9 1988 1989 1990 1991 1992 The Company continues to investigate options to reduce its embedded cost of long-tcrrn debt and take advantage of its current bond ratings and lower interest costs.

External financing of approximately $ 631 million is expected for 1993, of which $438 million is to be used for scheduled and optional rcfundings. This external financing is projected to consist of $510 million in long-term debt,

$100 million from a public offering of common stock and about $41 million through the Company's Dividend Rein-vestment and Employcc Stock Plans, offset by a $20 million decrease in short-term debt. These common stock sales are consistent with management's goal to improve the Com-pany's capital structure. External financing plans for 1994 to 1997 are subject to periodic revision as underlying assump-tions are changed to reflcct ncw developments; however, the Company currently anticipates external financing over this period in the aggregate of approximately $1,177 million.

Substantially all of this financing is for refunding, as cash provided by operations is generally expected to provide sufficient funds for the Company's anticipated construction program. The aggregate level of financing during this four year period willreflect, among other things, the nature, timeliness and adequacy of rate relief, uncertain energy

NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES demand due to economic conditions, and capital ex-penditures relating to distribution and transmission load reliability projects, as well as expansion of thc gas business.

Costs associated with coinpliance with federal and state cnvi-ronmcntal quality standards including the Clean Air Act, thc effects of rate regulation and various regulatory initia-tives, the level of internally generated funds and dividend payments, the availability and cost of capital and the ability ofthe Company to meet its interest and prefcrrcd stock divi-dend coverage requirements, to satisfy legal requirements and restrictions in governing instruments and to maintain an adequate credit rating will also impact thc ainount and type offuture external financing.

The Company has initiated a site investigation and reine-diation program which sccks a) to identify and remedy environmental contamination hazards in a proactive and cost-effective manner designed to satisfy regulatory require-ments and b) to ensure financial participation by other responsible parties. The program involves sponsorship of investigation, reinediation and selected research projects for 42 Company-owned waste sites and, where appropriate, participation in remedial action at 42 waste sites owned by others as to which the Company is one of a number of potentially responsible parties (PRP).

The Coinpany has accrued $215 million at Deccmbcr 31, 1992 for its estimated liabilityfor investigation and remedia-tion of certain Company-owned and Coinpany-associated hazardous waste sites. The amount accrued represents the low end of a range of cost estimates developed from thc Company's ongoing site investigation and remediation pro-gram. Of the $215 million accrued, $195 million rclatcs to Company-owned sites and $20 million represents the Com-pany's estimated cost contribution to sites with which it may bc associated. The accrual of the Company's cost contribu-tion for PRP sites is derived by estimating thc total cost of clean-up of the sites and then applying a contribution factor to the estimated total cost. Total costs to investigate and rcmediate sites with which the Company is associated as a PRP arc estimated to be approximately $492 million.

The Company believes that costs incurred in the investi-gation and remediation process are recoverable in the ratc-setting process.

(See Note 9 of Notes to Consolidated Financial Statements under "Environmental Issues.") The 1991 Agreement included a recovery mechanism and an aiinual allowance of approximately $9 million for costs expected to be incurred during 1991 and 1992 for site in-vestigation and remediation. The 1993 Scttlcmcnt provides for annual recovery of $35 million of cxpccted expendi-tures. The recovery mechanism provides that expenditures over or under the allowance bc deferred for future rate con-sideration. The impact of these cxpcnditures on external financing requirements is depcndcnt upon the timing of expenditures and associated recovery; however, thc Com-pany does not expect these costs to impact external financ-ing materially.

The Company is also undertaking an environmental com-pliance audit program at many of its facilitics. These audits may result in additional expenditures for iiivestigation and remediation that thc Company cannot currently estimate.

Some of the contamination problems thc Company might find include petroleum-related contamination caused by past spills, leaks, or other releases incidental to operation at Company facilities.

Secured Preferred Commercial Debt Stock Paper Standard 8 Poors Corporation BBB BBB-Moody's Investor Service Baa2 baa3 Duff & Phelps BBB BBB-Fitch Investors Service BBB BBB-A-2 p-Not ap Not ap The security ratings set forth above are subject to revision and/or withdrawal at any time by thc respective rating oryl-The Nuclear Regulatory Commission (NRC) issued regu-lations in 1988 requiring owners of nuclear power to place costs associated with decommissioning ac for contaminated portions of nuclear facilities into.

ternal 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.

Based upon studies applying the NRC guidelines, the Company has estimated that the minimum requirements for Unit I and its share of Unit 2, respectively, willbe $364 million and $381 million in future dollars. The 1991 Agreement includes an allowance for iniclcar decommissioning of Units I and 2 that exceeds the Company's currently deterinined minimum requirement.

These amounts arc being placed in an external trust. Pur-suant to the terms of the 1991 Agreement, such allowances willbe accepted in future years unless and until the cost of decommissioning changes. Thc Company filed a decommis-sioning report for each Unitwith thc NRC inJuly 1990.

Statement of Financial Accounting Standards No. 106, "Employccs'ccounting for Postretircment Benefits Other than Pensions" becomes effective in 1993 (See Note 7 of Notes to Consolidated Financial Statcinents). The pro-nouncement requires accrual accounting for these benefits, which the Company currently accounts for on a cash basis.

The 1993 Settlement provides for partial rccovcry of thc post-retirement benefit accrual, with authorization to defer the diAerence for future rccovcry (sce "Rate Agreemcnts" above). The Company is evaluating its funding optio the extent the Company funds amounts in an cxtcrn; in excess of thc rate allowance, financing require may increase.

The Company believes tltat traditionally available sources of financing should be suAicicnt to satisfy the Company's external financing needs during the period 1993 through 1997. As of December 31, 1992, the Company was able to issue an additional $1,689 inillion aggregate principal amount ofFirst Mortgage Bonds. This includes $954 million on the basis of rctircd bonds without, regard to an interest coverage test and approximately $735 million supported by additional property currently certified and available, assuin-ing an 8% intcrcst rate, under thc applicable tests set forth in the Company's mortgage trust indenture. A total of

$200 million of Preference Stock is currently available for sale. The Company also has atithorizcd unissued Preferred Stock totaling $342.4 million. Thc Company will also con-tinue to explore and utilize, as appropriate, other methods ofraising funds.

The Company's securities ratings at Deccmbcr 31, 1992, were:

NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES nizations and should not be considered a recommendation to I i, sell or hold securities ofthe Company.

Company's cost of financing and access to markets e negatively impacted by events outside ofits control.

T i Company's securities ratings could be negatively impacted by, among other things, the growth in its reliance on NUG purchase power requirements.

Rating agencies have cxprcsscd concern about thc iinpact on Company financial indicators and risk that NUG financial leveraging may have.

Ordinarily, construction related short-term borrowings are refunded with long-term securities on a continuing basis. This approach generally results in the Company show-ing a working capital deficit. Working capital deficits may also bc tcrnporarily created as a result ofthe seasonal nature of the Company's operations as well as timing difTcrenccs between the collection of customer reccivablcs and the pay-ment of fuel and purchased power costs.

However, the Company has sufficient borrowing capacity to fund such a deficit as necessary.

Bank credit arrangements which, at December 31, 1992, totaled $516 million (including $220 million in commitrncnts under Revolving Credit Agrce-mcnts, $100 million Direct Pay Lcttcr of Credit Facility and Revolving Credit Agrecrnent of Oswego Facilities Trust, $40 millionin one-year commitments under Credit Agrccments,

$56 million in lines of credit. and a $ 100 million Bankers Acceptance FacilityAgreement) arc used by the Company to enhance flcxibilityas to the type and timing ofits long-term security sales.

The unsecured debt limitation imposed by the Company's charter is 10% of consolidated capitalization plus $50 mil-lion, which, as ofJanuary I, 1993, equates to approximately

$661 million and against which thc Company had outstand-ing unsccurcd debt, ofapproximately $315 million.

RePort ofManagement RePort ofIndePendent Accountants The consolidated financial statcrnents of Niagara Mohawk Power Corporation and its subsidiaries were prcparcd by and are the responsibility of management.

Financial infor-mation contained elsewhere in this Annual Rcport is consis-tent witlithat in the financial statements.

To mcct its responsibilities with respect to financial infor-rnation, martagement maintains and enforces a system of i

ial accounting controls, which is designed to provide ible assurance, on a cost effective basis, as to thc y, objectivity and reliability of the financial records an protection of assets. This.system includes communica-tion through written policics and procedures, an organin-tional structure that, provides for appropriate division of responsibility and thc training of personnel. This system is also tcstcd by a comprchensivc 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 reqiiires all cmployces to maintain the highest level ofethical standards as well as requiring all managcrncnt employees to formallyaffirtheir compliance with thc Code.

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

In planning and performing their audit, Price Watcrhouse con-sidcrcd the Company's intcriial control structure in order to dctcrrnine auditing proccdurcs for thc purpose of express-ing an opinion on the financial statcrncnts, and not to pro-vide assurance on the internal control structure. Thc indcpendcnt accountants'udit docs not limit, in any ivay manageincnt's responsibility for thc fair presentation of the financial statements and all other informatipn, whether audited or unaudited, in this Annual Report.

The Audit Committee of thc Board of Directors, consist-ir we outside directors who are not employccs, meets r.

y with management, internal auditors and Price Wa iousc to review and discuss internal accounting con-trols, 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 prcscnt.

To the Stockholders and Board ofDirectors of Niagara Mohawk Power Corporation In our opinion, thc accompanying consolidated balance sheets and thc related consolidated statcrnents of income and retained earnings and ofcash flows present fairly, in all material respects, the firiancial position of Niagara Mohawk Power Corporation and its subsidiaries at December 31, 1992 and 1991, and the results'of their operations and their cash flows for each of the three years in thc period cndcd Dcccmbcr 31, 1992, in conformity with gcncrally accepted accounting principles. These financial statcmerits are tlie responsibility of the Company's managcmcnt; our responsi-bilityis to express an opinion on these financial statcmcnts based on our audits. Wc conducted our audits of these state-ments in accordance with generally accepted auditing stan-dards which require that, wc plan and pcrforni thc audit, to obtain reasonable assurance about whether the financial statements are free of material misstatement.

An audit includes examining, on a test basis, evidcncc supporting thc amounts and disclosures in tile financial statements, assess-ing the accounting principles used and significant cstirnates made by management, and evaluating the overall financial statement, prcscntation. We believe tliat our audits provide a reasonable basis for the opinion cxprcsscd above.

Syracuse, Ncw York January 28, 1993

NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES Consolidated Balance Sheets At December 31 ~

1992 ln thousands ofdollars 1991 ASSETS Utilityplant (Note 1):

Electric plant Nuclear fuel Gas plant Common plant Construction work in progress Total utilityplant.

Less: Accumulated depreciation and amortization.

Net utilityplant Other property and investments Current assets:

Cash, including temporary cash investments of $4121 and $4,32I, respectively..

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

Unbilied electric revenues (Note 1)

Electric margin recoverable..

Materials and supplies, at average cost:

Coal and oil for production of electricity.

Gas storage Other Prepayments:

Taxes Pension expense (Note 7).

Other Deferred debits:

Unamortized debt expense Deferred recoverable energy costs.

Deferred finance charges (Note 1).

Deferred operating expe0ses Deferred environmental restoration costs (Note 9).

Other CAPITAUZATIONAND UABIUTIES Capitalization (Note 4):

Common stockholders equity:

Common stock, issued 137,159,607 and 136,099,654 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 debt (Note 2)

Long.term debt due within one year (Note 4)

Sinking fund requirements on redeemable preferred stock (Note 4)..

Accounts payable Payable on outstanding bank checks.

Customers'eposits...

Accrued taxes Accrued interest..

Accrued vacation pay Other Deferred credits:

Accumulated deferred income taxes (Note 1)

Deferred finance charges (Note 1).

Unbilied electric revenues (Note 1).

Deferred pension settlement gain (Note 7)

Accrued refunds to customers for replacement power cost disallowance.....,..

Other Commitments and contingencies (Note 9):

Uability for environmental restoration

$7,590,062 445,890 787,448 231>425 587,437 9,642,262 2,975,977 6,666,285 274>169 I

43,894 221>165 180)000 11)595 78>517 20,466 172)637 14,414 33,631 32>522 808,841 140,803 61,944 239,880 16>486 215,000 167,127 841,240

$8,590,535

$ 137,160 1,658,015 445>266 2>240,441 290,000 170)400 3,491>059 6,191)900 227,698 57,722 27,200 275>744 41,738 13,059 52,033 70,882 38>515 40,220 844,811 755,421 239>880 77,768 68,292 46,801 150,662 1,338,824 215,000 I $8>590)535

$7,303,184 408,643 718,935 180,456 568,994 9,180,212 2,741,004 6,439,208 313,371 27,378 176,196 158,700 15,265 65,355 16,373 154,240 17,808 32,877 36,824 701,016 108,629 47,615 239,880 36,743 200,000 155,014 787,881

$8,241,476

$ 136,100 1,650,312 329,130 2,115,542 290,000 212,600 3,325,028 5,943,170 131,218 175,501 26,950 247,401 36,434 11,070 34,587 78,195 36,263 34,956 812,575 699,492 239,880 56,468 73,084 86,348 130,459 1,285,731 200,000

$8,241,476

NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES Consolidated Sta~ents ofIncome tained Earnings For the year ended December 31, 1992 ln thousands ofdollars 1991 1990 Operating revenues:

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

Gas Operating expenses:

Operation:

Fuel for electric generation Electricity purchased.

Gas purchased Other operation expenses.

1989 Agreement interest coverage (deferred)/amortization...

Maintenance Depreciation and Amortization (Note 1).

Federal and foreign income taxes (Note 6)

Other taxes Operating Income.

Other Income and deductions:

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

Federal and foreign income taxes Nuclear replacement power cost disallowance......

income tax of cost disallowance.

(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.

Average number of shares of common stock outstanding (in thousands)

Balance available per average share of common stock Dividends paid per share

( ) Denotes deduction

$3,147)676 553,851 I

3,701,527 323,200 650,379 287,316 727,766 20)257 226,127 274,090 183,233 484,833 I

3,177,201 524,326 9,648 27,729 (16,338)

I 21,039

~. I 545)365 290,734 9>982 (11,783) 288,933 256,432 36,512 219,920 103,784 116,136 329,130 I $

445,266 136,570 1.61

.76

$2,907,293 475,225 3,382,518 438,957 398,882 247,502 675,224 31,176 227,812 258,816 158,137, 420,578 2,857,084 525,434 8,251 24,242 (13,599) 18,894 544,328 302,062 9,577 (10,680) 300,959 243,369 40,411 202,958 43,552 159,406 169,724 329,130 136,100 1.49

.32

$2,669,308 485,411',

3,154,719 460,485 417,429 285,868 626,235 (52,970) 231,895 220,857 121,114 391,745 2,702,658 452,061 10,674 12,395 (139,974) 47,600 8,251 (61,054) 391,007 311,728 7,141 (10,740) 308,129 82,878 42,300 40,578 40,578 129,146 169,724 136,100

.30

.00

NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES Consolidated Statements ofCash Flozos 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:

Nuclear replacement power cost disallowance and related amortization Depreciation and amortization.

Amortization of nuclear fuel.

Provision for deferred income taxes Electric margin recoverable.

Allowance for other funds used during construction.............

Deferred recoverable energy costs Loss on investments net.

Unbilled electric revenues Deferred operating expenses (Increase) decrease in net accounts receivable.

(Increase) decrease in materials and supplies.

increase (decrease) in accounts payable and accrued expenses..

Increase 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 Other.

Net cash used in investing activities.

Cash flows from financing activities:

Proceeds from sale of common stock.

Sale of mortgage bonds.

Issuance of preferred stock.

Redemption of preferred stock Reductions of long-term debt Net change in short-term debt and revolving credit agreements..

Dividends paid Change in dividends payable Other.

Net cash provided by (used in) financing activities..

Net increase (decrease) in cash.

Cash at beginning of year Cash at end of year Supplemental disclosures of cash flow information:

Cash paid during the year for:

Interest Income taxes Supplemental schedule of noncash investing and financing activities:

Capital lease obligations incurred.

Liabilityfor environmental restoration 1992

$256,432 (39,547) 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)

(37r247) 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)

( 893)

(43,888)

(85,352) 16)516 27,378

$ 43,894

$323,972 76,519

$ 12,500 15,000 ln thousands of dollars 1991

$243,369 (28,820) 258,816 38,687 68,138 (20,173)

(8,251) 4,931 30,680 31,176 (25,900) 7,022 4,221 447 17,052 621,395 (504,485)

(13,236) 8,251 (509,470) 4,682 1,055 (69,648)

(13,721)

(587,102) 195,600 22,850 (42,830)

(231,941) 76,606 (83,963) 257 (7,065)

(70,486)

(36,193) 63,571

$ 27,378

$331,828 67,509 4,753 200,000 1990

$82,878 115,168 220,857 27,878 (24,881) 4,908 (10,674) 41,300 8,386 (17,031)

(53,939) 54,964 (39,031)

(36,122) 20,423 106,227 501,311 (418, 328)

(3,2 10, (410, (26,020)

(9,030)

(52,255)

(16,777)

(514,936) 300,000 (25,980)

(240,110) 51,591 (42,300)

(9,148)

(4,769) 29,284 15,659 47,912

$ 63,571

$329,390 19

$ 10,051 During June 1992, the Company acquired all of the common stock of Syracuse Suburban Gas Company, Inc. in exchange for 353,775 shares of the company's common stock haring a vafue of $6.120,006

N IAGARA MOHAWK POWER CORPOR ATION AND SUBSIDIARY COMPANIES Notes to Consolidated Financial Statements

l. Summary ofSignificant Accounting Poli cies T ic Company is subject to regulation by the Ncw York State Public Service Commission (PSC) and thc Federal Energy Regulatory Commission (FERC) with respect to its rates for service and the maintenance of its accounting records.

Thc Company's accounting policics conform to generally accepted accounting principles, as applied to regulated public utilitics, and arc in accordance with the account-ing rcquiremcnts and ratemaking practices of the regula-tory authoritics.

Principles ofConsolidation: Thc consolidated financial state-ments include the Company and its wholly-owned sub-sidiaries. All significant intercompany balances and transactions have been eliminated. Assets and liabilities of its Canadian energy subsidiary, Opinac Energy Corporation, are translated into U.S. dollars at thc exchange rate in cffcct at the balance sheet date. Rcvenuc and cxpcnse accounts arc translated at the avcragc exchange rate in effect during thc year. Currency translation adjustmcnts arc rccordcd as a component of equity and do iiot have a significant impact on financial condition. The results ofoperations ofthc Com-pany's oil and gas subsidiary arc included in other income and deductions on the Consolidated Staterncnts of Income and Retained Earnings.

'ary oil and gas properliesr Thc Company's Canadian subsidiary owns crude oil and natural gas properties w

i are accounted for under the full cost rncthod, whcrc-by all costs relating to the exploration for and development of conventional crude oil and natural gas reserves arc capi-talized. Such costs include'land acquisition expenditures, geological and geophysical expcnditurcs and costs of drill-ing both productive and non-productive wells.

Thc nct book value of oil and gas properties and equip-mcnt, less rclatcd deferred income taxes, is limited to thc sum of the after tax present value of nct revenues from proved oil and gas rcscrvcs and the lower of cost or fair value of unproved properties. The calculation of future nct rcvcnucs is based upon prices and costs in cffcct at the end of thc year. Based upon the calculation of the "ceiling test" at December 31, 1991 and March 31, 1992, the Company rccordcd reserves ofapproximately $23 millionand $21 mil-lion, or an after tax effect of$.07 and $.09 pcr share, respec-tively. At December 31, 1992, the Company recorded a

valuation reserve of$24 millionor an after tax effect of$.09 pcr share in light of a significant, decline in previous esti-mates of proved reserves as indicated by lower than cxpectcd production volumes. Thc net. investment in such properties was approximately $ 101 million and $ 171 million at Dcccmber 31, 1992 and 1991, rcspcctively.

Thc need for additional write<lowns during 1993 will be dependent, upon future oil and gas prices and on future e

cs ofrcservcs. Natural gas prices typically experience ial decline through mid-year, then begin to increase ii cipation ofwinter demand.

Utility Plant: Thc cost of additions to utility plant and of replacements of retirement units of property is capitalized.

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

Replacement of minor items of utilityplant and the cost of current, repairs and maintenance is charged to cxpcnsc.

Whenever utilityplant is retired, its original cost, togcthcr with the cost of removal, less salvage, is charged to accumu-lated depreciation.

Alloreance for Funds Used During Constrrrctionr The Company capitalizes AFC in amounts equivalent to the cost of funds devoted to plant under construction. AFC rates arc deter-mined in accordance with FERC and PSC regulations. Thc AFC rate in effect at. December 31, 1992 was 9.70%. AFC is scgrcgatcd into its two components, borrowed funds and other funds, and is reflectcd in the Interest Charges section and the Other Income and Deductions section, rcspcctively, ofthe Consolidated Statcmcnts ofIncome.

In 1985, pursuant, to PSC authorization, the Company dis-continued accruing AFC on construction work in progress (CWIP) forwhich a cash return iuas being allowed through inclusion in rate base of tliat portion of the invcstmcnt in the Nine Mile Point Nuclear Station Unit Yo. 2 (Unit 2).

Amounts equal to Unit 2's AFC which was no longer accrued have bccn accumulated in deferred debit and credit accounts up to thc commercial operation date of Unit 2, (each amounting to $239.9 million at December 31, 1992 and 1991) and await. future ratemaking disposition by the PSC. A portion of the dcfcrred credit could be utilized to reduce future rcvcnue requirements over a period shorter than the life of Unit 2, with a like amount of deferred debit

~ amortized and recovered in rates over the remaining life of Unit 2.

DePreciation, Amortixatiorr and Nuclear Gerrerating Plant Deconrmissionr'ng Costs: For accounting and regulatory pur-poses, depreciation is computed on the straight-line basis using the average or remaining scrvicc lives by classes of depreciable property. The total provision for dcprcciation and amortization, including amounts charged to clearing

accounts, was $275.3 million for 1992, $260.2 million for 1991, and $222.1 million for 1990. The percentage relation-ship between thc total provision for depreciation and avcr-agc depreciablc property was 3.3% for 1992, 3.2% for 1991 and 2.9% for 1990. The Company performs dcprcciation studies on a contirnring basis and, upon approval by thc PSC, periodically adjusts the rates of its various classes of depreciable property.

Estimated decommissioning costs (costs to remove a

nuclear plant from scrvicc in the future) for the Company's Nine Mile Point Nuclear Station Unit No. I (Unit '1) and its share of decommissioning costs of Unit 2 are being recov-ered ill fates tllrotlgllan alllltlal alloruallce alltl cllafgcd to operations through depreciation (Scc Yotc 8."Nuclear Plant Decommissioning.") Thc amount of accumulated decom-missioning costs is reflcctcd in Accumulated Dcprcciation and Amortization on thc Balance Sheet. Thc annual allowance for Unit I and thc Company's sharc of Unit 2 for the years cndcd Dccembcr 31, 1992, 1991, and 1990 was approximately $23.1, $23.0, and $4.8 million, respectively.

Amortization of thc cost of imclear fuel is determined on thc basis ofthc quantity ofheat produced for the generation ofelectric cncrgy. Thc cost ofdisposal ofnuclear fuel, which presently is $.001 per kilowatt-hour of nct generation avail-

NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES able for sale, is based upon a contract with the U.S. Depart-ment of Energy. These costs are charged to operating expense and recovered from customers through base rates or through the fuel adjustment clause.

Revenues:

Revenues are based on cycle billings rcndercd to certain customers monthly and others bi-monthly. Althougli the Company cornmenccd thc practice in 1988 of accruing electric rcvcruics for energy consumed and not billed at the cnd of thc fiscal year, the impact of such accruals have not yet been fullyrecognized in thc Company's results ofopera-tions. In accordance with regulatory agreemcnts, the Com-pany ceased amortizing unbilled revenues as ofJune 30, 1990. For the year ended Dcccmber 31, 1990, $170 millionof such accrued electric revenues are included in the results of operations. At December 31, 1992 and 1991, approximately

$778 million and $5G.5 million, rcspcctively, of unbilled electric revenues remained unrccognizcd in results ofoper-ations and is included in Dcfcrrcd Credits, and may be used to reduce future rcvcrnic rcquircments. Tile amount of the remaining dcfcrrcd credit balance fluctuatcs as the amount of accrued clcctric unbillcd revcritics is recalculated each year cnd. Thc Company has not been authorized to accrue unbillcd gas rcvcnucs.

The Company's tarifIs include electric and gas adjustment clauses under which energy and purcliased gas costs, respec-tively, above or below the levels allowed in approved rate schedules, arc billed or credited to customers. The Com-pany, as authorized by thc PSC, charges operations for energy and purchased gas cost increases in thc period of recovery. Thc PSC has periodically authorized thc Company to make changes in thc level of allowed energy and pur-cliased 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 overrccovcrcd under the normal operation of the electric and gas adjustment clauses. However, thc Company has bccn permitted to dcfcr and billor credit such portions to customers, through the electric and gas adjustmcnt

clauses, over a specified period of time from thc eflcctivc date ofeach change.

The Company's electric fuel adjustmcnt clause provides for partial pass-through of fuel cost fluctuations from amounts forecast, with the Company absorbing a specific portion of incrcascs or retaining a portion of decreases up to a maximum of $ 15 million per rate year. Thereafter, 100% of the fluctuation to be passed on to ratcpayers. The Company also shares with ratcpayers fluctuations from amounts forecast for nct rcsalc margin and transmission benefits, with the Company retaining/absorbing 20% and passing 80% through to ratcpaycrs.

Beginning in 1991, the Company's rate agreemcnt pro-vides for an electric rcvcnue adjustmcnt mechanism (NERAM) which rcquircs the Company to reconcile actual results to forecast electric public sales gross margin as defined and utilized in establishing rates. Depending on the level ofactual sales, a liabilityto customers is created ifsales cxcccd thc forecast and an asset is recorded for a sales short-fall, thcrcby generally holding rccordcd electric gross mar-gin to thc lcvcl forecast in establishing rates. The 1993 rate settlcmcnt provides for thc operation of the NERAM through December 31, 1993. Recovery or refund ofaccruals pursuant to the NERArWI is accomplished by a surcharge (either plus or minus) to customers over a twelve month period, to begin when cumulative amounts reach c

specified levels.

The 1991 Agreement also includes a Measured Return Incentive Term (MERIT) under which the Com-pany 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 PSC approval of MERIT earnings. Approved MERIT awards arc billed to customers over a period not greater than twelve months. Thc Company records MERIT earnings when attainment of goals is approved by the PSC or when objectively measured criteria are achieved.

Federal Income Taxes: In accordance with PSC rcquircments, the tax effect of book and tax timing diflerences is flowed through except as required by the Internal Revenue Code or unless authorized by the PSC to be deferred. The Company provides deferred taxes on certain benefits realized from accelerated dcprcciation, on deferred energy and purchased gas costs, on nuclear fuel disposal costs accrued prior to April 1983, on nuclear generating plant decommissioning costs, on certain construction overheads and on certain other items. As directed by the PSC, the Company defers any amounts payable pursuant to the alternative minimum tax rules. In conformity with ratemaking practices of the PSC, the Company has not provided deferred taxes on the cumu-lative amount ofapproximately $ 1 billionofother tax rr tions which include certain depreciation diffcren various construction overheads deductible when incui allocated for tax purposes and capitalized and depreciated foraccounting and ratcmaking purposes. The Company has claimed investment tax credits and deferred the benefits of such credits as realized in accordance with PSC directives.

Deferred investmcnt credit is amortized to Other Income and Deductions over thc useful life of thc underlying prop-erty. For purposes ofcomputing capital cost recovery deduc-tions and normalization, the asset basis has been reduced by all or a portion of the credit claimed consistent with then current tax laws.

Since it is the Company's intention to rcinvcst the undis-tributed earnings of its foreign subsidiaries, no provision is made for federal income taxes on these earnings. AtDecem-ber 31, 1992, the cumulative amount of undistributed earn-ings of foreign subsidiaries on which the Company has not provided deferred taxes was approximately $119 million.

The Financial Accounting Standards Board (FASB) has issued Statement ofFinancial Accounting Standards (SFAS)

No. 109 effective for fiscal years beginning after December 15, 1992. This pronouncement willchange the way in which income tax expense and liabilitieswillbe calculated and dis-closed. Thc Company has determined that the more signifi-cant effects of adopting this pronouncement will be (i) providing deferred taxes for tax benefits flowed through to ratepayers, (ii) adjustment of deferred tax assets and I iili-ties for enacted changes in tax law or rates and (iii) tion of net-of-tax accounting. The latter issue would adjustmcnt of the Company's remaining plant balances i iat rcflect net-of tax AFC to a pre-tax basis and record the appropriate amount, of deferred taxes. On January 15, 1993, the PSC issued a Statement ofInterim Policy on Accounting and Ratemaking Procedures to Implement SFAS 109 in

N IAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES which it is soliciting comments by April 15, 1993 from inter-parties. The Company believes that the SFAS 109 will isidered in the ratesetting process and will thcrcforc ave a significant impact on the Company's results of operations. The Company routinely collects the subsequent increased tax liability from previously flowed-through tax benefits. The Company expects that its total reported assets and liabilitieswillsignificantly incrcasc.

Thc Company cstiinatcs that a regulatory asset and a deferred tax liabilityofabout $650 million,duc to previously flowe through tax benefits, AFC, and associated revcinie requirements, and as reduced by excess deferred taxes and defcrrcd investment tax credits, will bc recorded in thc Company's financial statcmcnts in the first quarter of 1993.

Substantially all of thc excess deferred taxes relate to prop-erty and are not subject to immediate refund to customers.

Antortixation ofDebt Issue Costs: Thc premium or discount and debt expenses on long-term debt issues and on certain debt r'etirements prior to maturity are amortized ratably over the lives of thc related issues and included in intcrcst on long-term debt in accordance with PSC directives.

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

ficationst Certain amounts from prior years have been ified on the accompanying Consolidated Financial State-ments to conform with the 1992 presentation.

offees only at the tiine ofissuance ofeach acceptance.

The following table summarizes additional information applicable to short-term debt:

In thousands ofdollars At December 31:

Short-term debt:

Commercial paper.....

Notes payable 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) Excluding fees.

1992

$ 93,248 104,450 30,000

$227)698 4.33%

$110,313 4.80%

$227,698 1991

$ 53,000 28,500 49,718

$131,218 6.49%

$ 68,852 8.37%

$131,218 NOTE3.Jointly-Owned Generating Facilities The following table reflects the Company's share ofjointly-owned generating facilitics at Dcccinber 31, 1992. The Com-pany is required to provide its respective share offinancing for any additions to thc facilities. Power output and rclatcd cxpenscs arc sliarcd based on proportionate ownership. The Company's sliarc of expenses associated with these facilitics is included in the appropriate operating expenses in the Consolidated Statcmcnts ofIncome.

NOTE 2. Banh Credit Anmtgements At December 31, 1992, the Company had $516 inillion of bank credit arrangements with 19 banks. These credit arrangements consisted of $220 million in commitments under Revolving Credit. Agreements (including a Revolving Credit Agreement f'r I-IYDRA-CO, Inc., a wholly-owned subsidiary of the Company), $100 million under a Direct Pay Letter of Credit Facility and Revolving Credit Agrec-mcnt for Oswego Facilitics Trust, $40 million in one-year commitments under Credit Agreements,

$56 million in lines ofcredit and $ 100 millionunder a Bankers Acceptance Facility Agreement. Thc Revolving Credit Agreements extend into 1993 and 1994, and the interest rate applicablc to borrowing is based on certain rate options available under the Agreements. Allofthe other bank credit arrange-ments are subject to review on an ongoing basis with interest rates negotiated at. thc tiine ofusc. Thc Company also issues coinincrcial paper.

Unused bank credit facilitics are held available to support the amount of commercial paper out-ng. In addition to these credit arrangements, the my obtained

$50 million in bank loans which will ex c in 1993.

The Company pays fees for substantially all of its banl'redit arrangements.

The Bankers Acceptance Facility Agrccmcnt, which is used to finance the fuel inventory for the Company's generating stations, provides for the payinent.

In thousands or dollars Construct'cn Rrcentage Utility Accumulated work Ownership Rant depreciation in progress Roseton Steam Station Units No. 1 and 2 (a)

Oswego Steam Station Unit No. 6 (b)

Nine Mile Point Nuclear Station Unit No. 2 (c) 25 88,643

$ 39,698 274 76 275,415

$ 94,203

$ 2,852 41

$1,481,869

$177,140

$ 18,494 (a) The remaining ownership interests are Central Hudson Gas and Elec-tric Corporation, the operator of the plant (35%) and Consolidated Edison Company of New York, inc. (40%). Central Hudson Gas and Electric Corporation has agreed to acquire the Company's 25% inter-est in the plant in ten equal installments of 2.5% (30 mw) starting on December 3l 1994 and on each December 31 thereafter. The Com-pany then has the option to repurchase its 25% interest in 2004. The agreement is subject to PSC approval.

(b) The Company is the operator. The remaining ownership interest is Rochester Gas and Bectric 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 Ccmpany is the operator.

The remaining ownership interests are Long Island Lighting Company (18%). New York State Electric and Gas Corporation (18%). Rochester Gas and Electric Corporation (14%) and Central Hudson Gas and Bectric Corporation (9%) Out-put of Unit 2, which has a capability of 1080,000 kw~ is shared in the same proportions as the cotenants'espective ownership interests.

NIAGARA MOHAWK PO'tVER CORPORATION AND SUBSIDIARY COMPANIES NOTE 4. Capi talization CaPitat Stoch The Company is authorized to issue 150,000,000 slrares of common stock, $ 1 par value; 3,400,000 shares of preferred s

$ 100 par value; 19600,000 shares of preferred stock, $25 par value; and 8,000,000 shares of preference stock, $25 par value.

The table below summarizes changes in the capital stock issued and outstanding and the related capital accounts for 1990, 1991 and 1992:

Preferred Stock Conmon Stock

$ 1 par value Shares Amount*

$100 par value Non-Shares Redeemable'edeemable

$25 par value Capital Stock Premium and Non-Expense Shares Redeemable* Redeemable*

(Net)'anuary 1, 1990:

136,099,654

$136,100 2,586,000

$210,000

$48,600 (a) 12,676,403

$80,000

$236,910 (a) $1,649,285 Redemptions (38,000)

(3,800)

(887,199)

(22,180) 115 Foreign currency translation adjustment (106)

December 31, 1990: 136,099,654 136,100 2,548,000 210,000 44,800 (a) 11,789,204 80,000 214,730 (a) 1,649,294 Issued 914,005

22,850 Redemptions (58,000)

(5,800)

(1,481,204)

(37,030) 340 Foreign currency translation adjustment 678 December 31, 1991: 136,099,654 136,100 2,490,000 Issued 1,059,953 1,060 Redemptions (78,000)

Foreign currency translation adjustment 210,000 39,000 (a) 11,222,005 80,000 200,550 (a) 1,650,312 18,401 (7,800)

(1,366,000)

(34,150) 796 (11,494)

(December 31, 1992:

137,159,607

$137,160 2,412,000

$210,000

$31,200 (a) 9,856,005

$80,000

$166,400(a)

$1,658

" In thousands of dollars (a) Includes sinking fund requirements due within one year.

The cumulative amount of foreign currency translation adjustment at December 31, 1992 was $(2771).

NONREDEEMABLEPREI'ERRED STOCK (Optionally Redeetnable)

The Company has certain issues ofpreferred stock which provide for optional redemption at December 31, as follows:

In thousands ofdollars Redemption price per share (Before adding accumulated dividends)

Series Shares 1992 1991 Eventual 1992 minimum Preferred $100 3.40%

3 60%

3.90%

4.10%

4.85%

5 25%

6.10%

7 72%

par value:

200,000 350,000 240,000 210,000 250,000 200,000 250,000 400,000

$ 20,000 35,000 24,000 21,000 25i000 20)000 25,000 40,000

$20,000 35,000 24,000 21,000 25,000 20,000 25,000 40,000

$103.50 104.85 106.00 102.00 102.00 102.00 101.00 102.36

$103.50 104.85 106.00 102.00 102.00 102.00 101.00 102.36 Preferred $25 par value:

Adjustable Rate Series A 1,200,000 Series C 2,000,000 30>000 50>000 I $290,000 30,000 50,000

$290000 25.75 25.75 25.00

NIAGARA MOHAWK POWER CORPORATION A N D'UBSIDIARY C 0 1)1 P A N I E S MANDATORlLYREDEEMABLEPREFERRED STOCK Company has certain issues of preferred stock which provide for mandatory and optional redemption at, December 31, oivs:

Shares ln thousands ofdollars Redemption price per share (Before adding accumulated dividends)

Eventual Series 1992 1991 1992 1991 1992 minimum Preferred $100 par value:

7 45%

312,000 1 0.60%

330,000 60,000

$ 31,200

$ 33,000 6,000

$102.89

$100.00 Preferred 7 85%

8.375%

8.70%

8 75%

9.75%

$25 par value:

914,005 600,000 1)000,000 1)800,000 342,000 914,005 700,000 1,000,000 3,000,000 408,000 22)850 15,000 25,000 45,000 8,550 22,850 17,500 25,000 75,000 10,200 (e) 25.55 25.75 25.75 25.39 25.00 25.00 25.00 25.00 25.00 Adjustabte Rate Series B 2)000,000 2,000,000 50,000 50,000 25.75 25.00 Less sinking fund and redemption requirements t redeemabte until 1996.

197,600 27,200

( $ 17O4OO 239,550 26,950

$212,600 icsc series reqirirc mandatory sinking f'onds for annual redemption and provide optional sinking funds through which the Company may redeem, at par, a like amount ofadditional shares (limited to 120,000 shares ofthc 745% series and 300,000 shares ofthc 9.75% series). Thc option to redeem additional amounts is not cumulative.

Thc Company's five year mandatory sinking fund redemption rcquircmcnts for preferred stock, in thousands, for 1993 through 1997 are as follows: $27200; $27,200; $27,200; $14,150; and $15,120, rcspcctively.

Long-Term Debt Several scrics of First Mortgage Bonds and Notes were issued to secure a like amount of tax-exempt rcvenuc bonds and notes issued by the iNew YorkState Energy Research and Development Authority (NYSERDA). Approximately $414 millionofsuch notes bear interest at a daily adjustable inter-est rate (with a Company option to convert to other rates including a fixed interest rate which would require the Com-pany to issue First Mortgage Bonds to secure thc debt) which averaged 2.43% for 1992 and 3.45% for 1991 and are supported by bank direct pay letters of credit. Pursuant to agreements bctwecn NYSERDAand the Company, proceeds from such issues

>vere used for the purpose of firtancing the construction of certain pollution control facilitics at the Company's generating facilitics.

Thc $1157 million of tax-cxempt bonds due 2014 ivillbe refinanced at. 7.2% during 1994 pursuant to a forward ling agreement entered into in 1992.

s Payable include a ten-year Swiss franc bond issue

.ilcnt to $50 million in U.S. funds. Simultaneously with the sale of these bonds, the Company entcrcd into a cur-rency exchange agreement to fully hedge against currency exchange rate fluctuations.

,The arrangements with the Oswego Facilitics Trust (Trust) provide financing for the construction of a new cncrgy management system. Thc Trust has a $100 million Direct Pay Letter of Credit. Facility and Revolving Credit Agreemcnt. Trust obligations arc secured by certain assets held by thc Trust. The Company is required to piirchasc, or otherwise arrange for, the disposition of thc Trust assets upon thc termination of the Trust. Thc Lcttcr of Credit Facility and Revolving Credit Agrecrnent of thc Trust require payment of fees which are based upon the amount ofcommercial paper outstanding.

Other long-term debt in 1992 consists of obligations under capital leases of approximately $53.2 million (See Note 9. "Lease Commitmcnts"), a liabilityto thc U.S. Depart-ment of Energy for nuclear fuel disposal of approxiniately

$90.6 million (Scc Note 8. "Nuclear Fuel Disposal Costs" )

and a liability for contract termination of approximately

$14 million.

Certain of the Company's debt securities provide for a mandatory sinking fund for anriual rcdcmption. Thc aggre-gate rnaturitics of long-term debt for thc five years subse-quent to December 31, 1992, including mandatory sinking fund rcdcmption rcquircmcnts of approximately $24 mil-lion per year excluding capital leases arc approximately

$35 million, $319 million, $68 million, $58 million and

$43 million, rcspectivcly.

NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY CO)~IPANIES Series 1992 1991 First mortgage bo 12.68% - 13.06%

8 7/s%

4 5/so/

'*9 '/s%

5 /s/

.*9 5/so/

6 i/4o/,

9 7/s%

6 '/2o/o 10 '/4 10 s/s%

9'/

9 '/2 7 s/so/

9 /4/

7 5/so/

7 s/4 7 s/s%

8 '/4 "9 /2%

8%

9 950/

9 /4/

• • 10.20%

8.35%

8 /s%

• 6 /s'/o

'11 '/4%

• 11 s/s%

"10%

100/

9 )/20/

8 s/4 8'/

'8 7/s%

nds:

1992 1994 1994 1996 1996 1997 1997 1998 1998 1999 1999 1999 2000 2001 2001 2002 2002 2003 2003 2003 2004 2004 2005 2005 2007 2007 2013 2014 2014 2016 2016 2021 2022 2023 2025 150,000 40,000 45)000 40,000 2001000 60,000 100,000 100,000 1501000 65)000 100,000 80,000 80,000 220)000 80)000 300)000 150,000 66,640 30,000 45,600 75,690 40,015 150,000 150,000 165,000 75)000 100,000 150,000 40,000 100,000 45,000 100,000 40,000 200,000 60,000 100,000 100,000 75,000 150,000 65,000 100,000 80,000 80,000 80,000 35,295 55,000 150,000 23,000 66,640 32,000 45,600 75,690 40,015 150,000 100,000 150,000 75,000 Total First Mortgage Bonds 2,757,945 2,663,240 Promissory notes:

'Adjustabie Rate Series due July 1, 2015 December 1, 2023 December 1, 2025 December 1, 2026 March 1, 2027 July 1, 2027 100,000 69,800 75,000 50,000 t 25,760 93,200 100,000 69,800 75,000 50,000 25,760 93,200 Unsecured notes payable:

Medium Term Notes, Various rates, due 1993-2004 Swiss Franc Bonds due December 15, 1995 Oswego Facilities Trust Other Unamortized premium (discount) 87,700 144,200 50,000 90,000 157,829 (8,453) 50,000 96,350 135,688 (2,709)

TOTALLONG-TERM DEBT 3,548)781 Less long-term debt due within one year 57,722 3,500,529 175,501

$3,491,059

$3,325,028 Tax-exempt pollution control related issues

""Retired prior to maturity Long-term debt at December 31, consisted of the following:

In thousands of dollars Additionally, certain other series of mortgage bonds pro-vide for a debt retirement fund whereby payment require-ments may be met, in lieu of cash, by the ccrtificat'dditional property, the waiver of the issuance ofaddi bonds or the retirement of outstanding bonds. The requirements for these series were satisfied by thc certifica-tion of additional property. The Company anticipates that the 1993 requirements for these series will be satisfied by means other than payment in cash. Total annual debt retirement fund requirements for these series, based upon mortgage bonds outstanding at December 31, 1992, are

$4.9 million.

NOTES.

Disclosures about Fair Value of Financial Instrlnients The following methods and assumptions werc used to esti-mate the fair value ofeach class offinancial instruments:

Cash and short-term investments: The carrying amount approximates fair value because of the short maturity ofthe financial instruments.

Long-tenn investments: Thc carrying value and market value are not material to the financial statements.

Cash and short-term investments Mandatorily redeemable preferred stock..............

Long-term debt:

First Mortgage Bonds.........

Medium Term Notes..........

NYSERDAbonds.............

Swiss Franc Bonds...........

Other.

Oswego Facilities Trust........

December 31, 1992 In thousands ofdollars Carrying Fair Amount Value 43,894 43,894 197,600 199,114 2,757,945 87,700 413,760 50,000 104,665 90,000 2,888,022 93,890 413,760 62,374 104,665 90, Mandatorily redeemable preferred stoclu Fair value of '

mandatorily redcemablc preferred stock has been

'mined by one of the Company's brokers or estimat management based on discounted cash flows.

Long-tenn debt: The fair value of thc Company's long-term debt has been estimated by one of the Company's brokers.

The carrying value of NYSERDA bonds, the Oswego Facili-tics Trust and other long-term debt are considcrcd to approximate fair value.

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

40

NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES NOTE 6. Fedmnl and Foreign Income Taxes oncnts ofUnited States and foreign income before income taxes:

1992 In thousands ofdollars 1991 1990 United States Foreign Consolidating eliminations Income betore income taxes

$410)283 18)394 (16,741)

$411,936

$394,596 (6,252)

(11,080)

$377,264

$141,129 19,861 (16,993)

$143,997 Following is a summary of the components of Federal and foreign income tax and a reconciliation beuveen the amount of Federal income tax expense reported in the Consolidated Statements of Income and the computed amount at the statu-tory tax rate:

SUMMARY

ANALYSIS:

In thousands of dollars Components of Federal and foreign income taxes:

Current tax expense:

Federal Foreign Deferred tax expense:

Federal Foreign l

e taxes included in Operating Expenses............

t Federal income tax credits included in her Income and Deductions red Federal and foreign income tax expense (credits) included in Other Income and Deductions............

Total 1992

$119,929 915 120,844 54,858 7,531 62,389 183,233 (31,787)

'4,058 j $155,504 1991

$ 75,452 597 76,049 74,983 7,105 82,088 158,137 (24,734) 492

$133,895 1990

$121,275 (2,495) 118,780 (8,096) 10,430 2,334 121,114 (32,756)

(27,239)

$ 61,119 Components of deferred Federal and foreign Income taxes (Note Depreciation related Investment tax credit.

Alternative minimum tax Construction overheads Recoverable energy and purchased gas costs...........

Unbilled revenues Deterred operating expenses Deferred transmission revenues Nuclear settlement disallowance Reserve for NM Uranium, inc.............

MERIT recovery.

Electric revenue adjustment mechanism................

Opinac reserve for oil and gas properties...............

Bond reacquisition premium.

Other 1):

$ 78,467 (8,067)

(1,197)

(1,798)

(1,926)

(2)600) 10)867 20)099 (390)

(4,263)

(1,248)

(19,706) 7,379 (9,170)

$ 90,897 (8,137)

(27,276)

(1,066) 8,066 (3,097)

(2,179) 6,601 12,865 (512) 9,935 6,859 (13,083) 2,707

$ 84,591 (4,014)

(16,843)

(10,324)

(27,897)

(13,898) 24,146 (6,569)

,,(32,964)

(5,013)

(1,669)

(14,451)

Deterred Federal income taxes (net)

$ 66,447

$ 82,580

$ (24,905) e ncome taxes.

Computed tax

$140,058

$128,270

$ 48,959 Reconciliation between Federal and foreign income taxes and the computed at prevailing U.S. statutory rate on income befor i

R ction (increase) attributable to flow-through of certain tax adjustments:

preciation (37,543) owance for tunds used during construction............

11,205 Deferred investment tax credit amortization.......'.......

8,024 Other

~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~

~ ~ ~ ~.....

2,868 (36,440) 7,540 7,891 15,384 (30,569) 8,728 7,820 1,861 Federal and foreign income taxes.

(15)446)

I $155 504 (5,625)

$133,895 (12,160)

$ 61,119

NIACARA MOHAWK PO)VER CORPORATION AND SUBSIDIARY COMPANIES NOTE 7. Petrsion and Other Retirement Plans The Company and certain of its subsidiaries have non-contributory, defined-benefit pension plans covering sub-stantially all their employees.

Bcncfits arc based on the employcc's years of scrvicc and compensation level. The pension cost was $23.2 million for 1992, $23.9 million for 1991 and $22.8 million for 1990 (of which $6.2 million for 1992, $6.0 million for 1991 and $5.5 million for 1990 was related to construction labor and, accordingly, was charged to construction projects). The Company's general policy is to fund the pension costs accrued with consideration given to the maximum amount. that can bc deducted for Federal income tax purposes. Yo contribution was made to the pen-sion plan during 1991 and 1990. Contributions are intended to provide not only for benefits attributed to service to date but also for those cxpectcd to be earned in thc future.

In both 1992 and 1991, the discount rate and rate of increase in future compensation levels used in determining the actuarial present value of thc projcctcd benefit obliga-tions were 8.25% and 4.25% (plus merit increases),

respec-tively. Thc cxpcctcd long-term rate of return on plan assets was 9.00% in 1992 and 1991.

In addition to providing pension bcncfits, the Company and its subsidiaries provide certain health care and life insurance bcneflts for active and retired employees and dependents.

Under current policies, substantially all of the Company's employees may be eligible for continuation of some of these benefits upon normal or early retirement.

Thcsc benefits are provided through insurance corn whose charges and premiums are based on the claim during the year. The cost of providing these bencli retired employees are provided for in rates and amounted to approximately $16.7 million for 1992, $ 15.0 million for 1991 and $149 millionfor 1990.

In Deceinber 1990, the FASB issued SFAS No. 106 entitled "Employers'ccounting for Postretirement Benefits Other Titan Pensions." This Statement, which the Company will adopt for 1993, requires accrual accounting by einployers for postretircment benefits other than pensions reflccting cur-rently earned benefits. The Company presently accounts for such costs on a cash basis for both active and rctircd employees. The Company cstimatcs unfunded accumulated postretirement benefit obligations other than pensions to be approximately $409 million at January I, 1993 based upon health care cost trend rates of 14% trending down to 6%

and assuming a long-term discount rate of8%. Thc annual cost willbe approximately $66 million and includes amorti-zation of the transition amount related to prior service over a twenty year period. On January 27, 1993, the PSC approved a rate settlement plan which included an incremental allowance for postretireinent benefits of approximately $ 12 million including capital portion. The difference in the postretireinent benefit annual expense compared with thc rate allowance (approximately $31 million) willbe dcfcrrcd.

The PSC is cvpectcd to issue a Statement ofPolicy rcgard-Nct pension cost for 1992, 1991 and 1990 included the followingcomponents In thousands ofdollars Service cost benefits earned during the period.

Interest cost on projected benefit obligation.

Actual return on Plan assets Net amortization and deferral Net pension cost At December 31, 1992

$ 27,100 48,800 (59,600) 6,900 I $ 23200 1991

$ 27,000 43,500 (116,600) 70,000

$ 23,900 1990

$ 25,700 39,100 (7;500)

(34,500)

$ 22,800 Thc following table sets forth thc plan's funded status and amounts recognized in thc Company's Consolidated Balance Slleets:

At December 31, 1992 In thousands ofdollars 1991 Actuarial present vaIue of accumulated benefit obIigations:

Vested benefits.

Non-vested benefits AccumuIaled 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 projected benefit obligations...............

Unrecognized net obligation at January 1, 1987 being recognized over approximately 19 years.

Unrecognized net gain from past experience different from that assumed and effects of changes in assumptions Prior service cost not yet recognized in net periodic pension cost.....

Prepaid pension costs incIuded in current assets

$419,582 46,563 466,145 193,630 659,775 796,843 137,068 35,184 (174,713) 36,092 I $ 33 631

$341,697 4,026 345,723 229,524 575,247 721,132 145,885 37,977 (187,266) 36,281

$ 32,877

NIAGARA IIOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES ing thc accounting for pension and postretircmcnt benefit With respect to postrctiremcnt benefits, thc PSC proposal recommended a transition to fullaccrual in over a period not to exceed five years, with recovery of any resultant deferrals over a period of ten years from the year of adoption. Thc Company can provide no assurance that, the Statement of Policy as ultimately approved by the PSC willbe consistent with the PSC Staff's proposal.

The Emerging Issues Task Force (EITF) rcccntly issued a consensus position permitting utilities to record a regula-tory asset. for differences between allowances in rates and full accrual of postretirement benefits when such deferral is pursuant to a ratemaking plan that provides for a tran-sition to full accrual in rates within five years and recovery of defcrrals within twenty years of adoption. The Company believes that PSC Staff's proposal meets the EITF consen-sus position.

In November 1992, the FASB issued SFAS No.

112 "Employees'ccounting for Postcmploymcnt Benefits" which is effective for fiscal years beginning after December 15, 1993. This Statement requires employers to recognize the obligation to provide postemployment benefits ifthe obliga-tion is attributablc to employccs'ervices already rcndercd, rights to those benefits are vested, payment is probable and the amount of the benefits can be reasonably estimated.

Thc adoption of the rcquircmcnts of this Statement arc not expcctcd to signilicantly impact thc Company's financial condition or results of operations. Any impact of thc State-should be addressed in the ratesctting environment.

NOTE 8. Nuclear Operations UnitI Economic Study: Under the-tcrrns of the 1989 Agrec-mcnt, the Company agreed to prepare and update studies of the advantages and disadvantages ofcontinued operation of Unit I, prior to the start of the next tivo refueling outages.

The first report, which recommcndcd contiimcd operation ofUnit I over the remaining tenn of its license (2009), was filed with the PSC in March 1990.

On November 20, 1992 the Company submitted to the PSC an updated economic analysis which indicated tliat Unit 1 can bc expected to provide value to customers and shareholders through its next fuel cycle, which will cnd in early 1995. The study also indicated tlmt the Unit could con-tinue to provide bcncfits for the full term of its liccnsc if operating costs can be reduced and generating output im-proved above the historical average. The Company is aware of only onc formal response to its study, from IPPNY, which claims that continued operation of Unit 1 is uneconomic.

The Company bclievcs the findings of IPPNY to be flawe.

Thc study analyzed a number of scenarios resulting in break.-even capacity factors, ranging from 44% to 122%.

Thc "base" case assumes a capacity factor of 61%, which is c

existent with the target reflectcd in the Unit I operating

've mcchanisrn, and also future operating and capital lightly lower than historical perlonnance.

While a m; ginal benefit woukl be realized from operating the Unit for at least the next two years (onc fuel cycle), there would be a negative nct present, value in excess of $100 million ifthe Unit werc to be operated over its remaining 17-year license period. Under an "improved performance case," thc Unit is assumed to operate at a 70% capacity factor with future operating and capital costs consistent. with average industry performance. The Company bclicves these goals arc achiev-able for Unit 1. The "improved performance case" results in positive net present value in excess of $100 million if the Unit is operated over its renmining life. Such results are indicative of the volatility of the assumptions and uncer-tainties involved in developing the Unit's economic forecast.

Thc study necessarily relies on a number of significant assuniptions which are subject to uncertainty and could pro-duce a wide range of outcomes. These assumptions include the Unit,'s capacity factor, levels of operating and capital costs, anticipated demand for electricity, anticipated supply of electricity including NUG power, implementation and compliance costs of thc 1990 Clean AirAct and other fed-eral and state cnvironmcntal initiatives, and fuel availability and prices, especially imtural gas. Given the potential for rapid and substantial clmngc in any or all of these assunip-tions, the Company will be developing operational and external measures intended to initiate a prompt periodic reasscssmcnt ofthe economic viabilityofthe Unit.

An agrccmcnt with the PSC allows recovery of all rea-sonable and prudently-incurred sunk costs and costs of retirement, should a prudent decision be made to retire Unit, 1 before carly 1995. Allparties to the 1991 Agrccmcnt reserved thc right to petition the PSC to institute a formal investigation to rcvicw thc prudence of any Company deci-sion to retire Unit 1. Any such decision by the Company willbc made in consultation with governmental and regula-tory authoritics.

The Company's net invcstmcnt in Unit I is approxinmtely

$600 million. Based upon thc Company's 1989 study, the cost of decommissioning Unit I is estirnatcd to be approxi-mately $248 million in 1992 dollars. An update of the study is currently underway as part of thc formal decommission-ing plan discussed above. Thc Company has collected $75.9 million in rates through 1992, of which $43.1 million has been deposited in an cxtcrnal trust, which has ac-cumulated a balance of$46.4 million including earnings on fund invcstmcnts.

Unit I Status: Unit 1 will bc taken out of service in mid-Fcbruary 1993 for an eight ivcck rcfucling outage.

In an August 1992 Safety Evaluation Report, the Nuclear Regulatory Commission (NRC) confirmed thc Company's assessmcnt tlmt. Unit I could operate until at least 2007 with-out making modifications to the plant's torus. Thc torus, a large donut-slmped structure located below thc reactor, is half filled with water. It is a suppressivc pool dcsigncd to rclicvc pressure from thc plant's reactor by converting excess stcam to water.

In November, the Company rcquestcd that thc NRC re-review the asscssmciit to insure that the evaluation of thc torus pcrforrncd by the NRC was consistent witli thc Com-pany's methodology. In the interim, the Company continues to monitor the torus wall thickness in accordance with code rcquircments to ensure corrosion rates do not exceed anti-cipated levels. The NRC has stated tlmt it, could take up to twelve months to complete its rc-review Thickness mcasurcmcnts for the entire torus were per-formed inJanuary 1993. Preliminary results indicate that, wall thickness continues to mcct code requirements. Measuremcnts ofselected areas ofthe torus willbe performed biannually.

NIAGARA MOHAWK POPOVER CORPORATION AND SUBSIDIARY COMPANIES Unit 2 Status: Two cracked low pressure turbine rotor blade/wheel assemblies were removed during the last re-fueling outage. As a result, the output of Unit 2 has been rcduccd by 3% or approximately 37 MW. The next refueling outage is scheduled to begin in September 1993.

Nuclear Plant Decommissioning: Based on a 1989 study, thc cost of decommissioning Unit I, which is expected to begin in thc year 2009, is estimated by'the Company to be approx-imately $548 million at that time ($248 million in 1992 dollars). Thc Company's 41% share of the total cost to decommission Unit 2, which is expected to begin in the year 2027, is estimated by the Company to be approximately

$535 million ($105 million in 1992 dollars). The annual decommissioning allowance reflected in ratemaking is based upon thcsc estimates. Through December 31, 1992, the Company lias rccovercd approximately $86.6 million of decommissioning costs in rates and $39 millionin earnings on the decommissioning trusts for both units. The Com-pany continues to review the estimated reqtiircments for decommissioning and plans to seek rate adjustments when appropriate. Thcrc is no assurance that the decommis-sioning allowance recovered in rates will ultimately aggre-gate a suAicient amount to decommission the units. The Company believes that decommissioning costs, if higher than currently estimated, will ultimately be recovered in the rate process.

The NRC issued regulations in 1988 requiring owners of nuclear power plants to place funds into an cxtcrnal trust to provide for thc cost ofdecommissioning activities of con-taminated portions of nuclear facilitics as >veil as establish-ing minimum amounts that must be available in such a trust for these specified decommissioning activities at the time of decommissioning.

Based upon studies applying the NRC regulations, the Company has estimated that the minimum funding requirements for Unit 1 and its sharc of Unit, 2, respectively, willbe $564 millionand $381 million in future dollars. As ofDcccrnber 31, 1992, the Company lias accurnu-lated in an external trust $46.4 million for Unit I and $ 10.5 million for its sharc of Unit 2, which are included in Other Property and Investments. In 1989 the PSC issued an order requesting comments froin utilities in connection with a generic proceeding to examine thc funding and taxation aspects of accumulating nuclear decommissioning funds in an cxtcrnal trust in response to the NRC regulations. The Company has responded to the order and is awaiting final resolution ofthis matter by the PSC.

Nuclear Liability Insurance: The Atomic Energy Act of 1954, as amended, requires the purcliasc of nuclear liability insurance from the Nuclear Insurance Pools in amounts as determined by the iNRC. At the present time, the Com-pany maintains thc required $200 million of nuclear lia-bilityinsurance.

In August 1988, the Price-Anderson Aincndrnents Act of 1988 (the Act) was enacted, which significantly increased the statutory liabilitylimits for the protection of thc public.

With respect to a nuclear incident at a licensed reactor, thc statutory limit, which is in excess of the $200 million of nuclear liabilityinsurance, was incrcascd froin $710 million to approximately $7.5 billion. This limitis funded by asscss-ments of up to $63 million for each of the 115 presently licensed nuclear reactors in the United States, payab rate not to exceed $10 million per reactor per yca assessmcnts arc subject to periodic inflation indcxin to a 5% surcharge iffunds prove insufficient to pay claims.

Thc Company's intcrcst in Units 1 and 2 could expose it to a potential loss, for each accident, of $88.8 million through assessments of$14.1 millionper 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, tliat insurance and indemnity will cover precautionary evacuations whether or not a nuclear incident actually occurs.

The Act was extended for 15 years with a renewal date of August 15, 2002.

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 $765 million in excess of the $500 million primary nuclear insurance with the Nuclear Insurance Pools (ANI/

MRP) and $1.325 billion, which is also in excess of the $500 million primary and the $765 million excess nuclear insur-ance, with Nuclear Electric Insurance Limited (NEIL).The total nuclear property insurance is $2.59 billion.

iNEIL is a utility industry-owned mutual insurance com-pany chartcrcd in Bermuda with offices in the United States. NEIL also provides insurance coverage against the extra expense incurred in purchasing replacement during prolonged accidental outages. The insuran vides coverage for outagcs for 156 weeks after a 21 waiting period.

NEIL insurance is subject to retrospective premium adjustment for which the Company could be assessed up to approximately $12.4 millionpcr loss.

Low Level Radioactive IYaste: The Federal Low Lcvcl Radio-active Waste Policy Act as amended in 1985 rcqiiired states tojoin compacts or individually develop their own low level radioactive waste burial site. In response to the Federal law, New York State decided to develop its own site because of the large volume oflow level radioactive waste itgenerates.

New York State lias narrowed its selection for potential low level radioactive waste disposal sites to five locations in Cortland and Allegheny counties.

On January I, 1990, Governor Cuomo certified that all of New York State's low level radioactive waste would be man-aged byJanuary 1, 1993. This certification contained a plan of how thc low level radioactive waste will be managed in New York State until a disposal facility is available. Due to public opposition and thc need to rcevaluatc the disposal siting process, the January 1, 1993 date was not attained.

Currently, an extension of access to the Barnwell, South Carolina waste disposal facilitywas made availablc to out-of-region low level radioactive waste generators by thc sta

. of South Carolina, and Ncw York State has elected to

's option through Junc 30, 1994.

The State's management plan includes development of interim storage capability for non-utility waste generators and assumes tliat such facilities should plan for as long as 10 years of interim storage. A low lcvcl radioactive waste management program and contingency plan is under way so 44

NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES that Unit I and Unit 2 willbe prepared to properly handle 4m on-site storage of low level radioactive waste for at 10 year period, ifrequired.

Nuclear Fuel Disposal Cost: In Jarnrary 1983, the Nuclear Waste Policy Act of 1982 (Act) was passed into law. The Act established a cost of $.001 per kilowatt-hour of net genen-tion for current disposal of nuclear fuel and provides for a dctcrmination of the Company's liabilityto thc DOE for the disposal of nuclear fuel irradiated prior to 1983. The Act also provides three payment options for liquidating such liabilityand the Company has elected to delay payment, with intcrcst, until 1998, thc year in which the Company lrad initiallyplanned to ship irradiated fuel to an approved DOE disposal facility. Progress in developing thc DOE facilityhas been slow and it is anticipated that the DOE facility will not be ready to accept deliverics until at least 2010. The Company lras several viable alternatives under consideration tlrat will provide additional storage facilities, as necessary.

Each alternative will likely require NRC approval and may require other regulatory approvals. Thc Company does not believe that the possible unavailability of the DOE disposal facilityuntil 2010 willinhibitoperation ofeither Unit.

Thc Energy Policy Act of 1992 provides for the establish-ment of a federal decontamination and decommissioning fund (o provide for the clean up of DOE uranium process-ing facilities, funded in part by nuclear utilities. The Com-pany estimates that it has about a $25 millionliabilityto this based on prior DOE nuclear fuel processing scrviccs ved. This amount lras been accrued at December 31,

,md is expected to be rccovcred as a fuel expense as provided by the Act. The liability is payable over 15 years and annual assessments willbe indexed for inflation.

NOTE 9. Commitments and Contingencies Facility Estimated Expiration Purchased annual date of capacity capacity Contract in kw.

cost Niagara hydroelectric project...

St. Lawrence hydroelectric project...

Blenheim-Gilboa-pumped storage generating. station'.....

Fi trick-ar plant.........

2007 928,000

$19,320,000 2007 104,000 1,248,000 2002 270,000 7,452,000 year-to-year basis 67,000(a) 10,242,000 1,369,000

$38,262,0 (a) 50OOOkw forsummer of 1993; 7POOOkw for winterof 1993-94 Long-tenn Contracts for the Purdrase of Electric Porver: At January I, 1993, the Company lrad long-term contracts to purchase electric power from the followinggenerating facil-itics owned by the Ncw York Power Authority (NYPA):

The purclrasc capacities shown below arc based on the contracts currently in effect. The estimated annual capacity costs are subject to price escalation and are exclusive of applicable energy charges.

Total cost of purchases under these contracts was approximately $64.4 million, $61.2 million and $57.2 million for thc years

1992, 1991 and 1990, rcspectivcly.

Under the requirements of the Federal Public Utility Regulatory Policies Act of 1978, thc Company is required to purclrasc power generated by NUGs, as dcfincd thcrcin.

Approxintatcly $543 million and $268 million was paid to NUGs in 1992 and 1991 for 8,632,000 rnwhrs and 4,303,000 rnwhrs of cncrgy and associated capacity, respectively.

Through Dcccmber 31, 1992, thc Company has cntcrcd into agrcerncnts with numerous current and prospective inde-pendent producers, including NUGs which, lras substan-tially increased its future purchase power commitments.

The amount of the commitmcnt, and the availablc capacity are dependent upon the completion ofthese projects. Based upon contracts entered into and approved to date, thc Com-pany estimates tlrat it will bc obligated to purclrase power generated by facilities having an aggregate amount ofcapac-ity in each of the following periods: 2,226 iVIW in 1993, 2,309 MWin 1994,2,651 MWin 1995 and 2,651 MWin 1996.

By 1995, the Company will be paying $1.2 billion a year for 2,651 MWofcapacity. Gcnenlly, the Company must only pay for energy delivered.

Construction Program: Thc Company is committed to an ongoing construction program to assure reliable delivery of its electric and gas services. Thc Company prcscntly esti-mates tlrat the construction program for the years 1993 through 1997 will require approximately $2.28 billion, excluding AFC, nuclear fuel and certain overheads capital-ized. For the years 1993 through 1997, the estimates are $412 million, $504 million, $458 million, $457 million and $446 million, respectively. Thcsc amounts are reviewed by man-agement as circurnstanccs dictate.

Lease Commitmeuts: Thc Company Icascs certain property and equipmcnt which meet thc accounting criteria for capitalization.

Such

leases, having a net book value of

$53.2 million and $48.3 million at Deccmbcr 31, 1992 and 1991, rcspectivcly, arc included in the accompanying Con-solidated BaLance Sheets.

Since current rate-making prac-tice treats all leases as operating leases, the capitalization of these leases has no impact on the Company's Consolidated Statements ofIncome. The Company recognizes as a clrarge against income an amount equal to the rental expense allowed for rate purposes. Thc Company's future minilIluln rental conrrnitrncrlts under tllesc capital leases and rlon-canccllable operating leases aggrcgatc approximately $473 million, a substantial portion ofwhich relates to a trmrsmis-sion line facilitywith an "unclapsed term of34 years. Annual future minimum rental commitments for the period 1993-1997 range between $23 millionand $28 million.

Sale of Customer Receivables: Thc Company has an agree-ment whereby it, can sell an undivided interest in a designat-ed pool of customer reccivablcs including accrued unbilled electric revenues up to a maxinnrrn of $200 million. At December 31, 1992 and 1991 respectively, $200 million of receivables had been sold under this agrccment. The undi-

NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES vided interest in thc designated pool of receivables was sold with limited recourse. The agrccmcnt provides for a loss reserve pursuant to which additional customer re-ceivables are assigned to the purchaser to protect thc rccciv-ables sold from bad debts.

To thc extent actual loss cxpericnce of the pool rcccivablcs exceeds the loss rcscrvc, the purcliaser absorbs thc cxccss. For reccivablcs sold, thc Company has rctaincd collection and administrative responsibilities as agent for the purchaser.

As collections reduce previously sold undivided intcrcsts, new receivables are customarily sold.

Anti-trust Action: In 1987, Long Lake Energy Corporation (Long Lake) filed an action asserting claims under Section 2 of the Sherman Act and New York.'s Donnelly Act which alleged that the Company interfered with Long I ~ke's attempts to license hydro-electric projects with the FERC On Junc 26, 1992 thc Company cntercd into an Agrecmcnt with Adirondack Hydro Development Corporation (AHDC),which in turn completed an acquisition ofcertain assets of Long Lake. The Agreement bctwcen thc Company and AHDC provided for thc dismissal ofthc anti-trust case, as well as a lease transaction and long-terin power purchase contract between the Company and AHDC. The Company incurred no loss as a result. ofthc resolution ofthis matter.

Environmental Issues: Thc public utility industry typically utilizes and/or generates in its operations a broad range of potentially hazardous products and by-products. These products or by-products may not have previously been con-sidered hazardous, and may not, bc considered hazardous currently, but may be identified as such by Fcdcral, state or local authoritics in the future. The Company bclicvcs it is handling identified products and by-products in a man-ner consistent with Federal, state and local rcquircmcnts and has implemented an cnvironmcntal audit program to identify any potential areas of concern and assure compli-ance with such rcquircmcnts. Thc Company is also cur-rently conducting a program to investigate and restore, as necessary to meet current cnvironincntal standards, certain properties associated with its former gas manufacturing process and other properties which thc Company has learned inay be contaminated with industrial waste, as well as investigating potential industrial waste sites as to which it may be detcrmincd tliat the Company contributed. The Company has bccn advised that various Federal, state or local agencies currently believe that certain properties require investigation and is in the process of clas

'any of these sites based on available informa enhance inanagement of investigation and remedia f

determined to be necessary.

The Company is aware of 84 sites with which it has been or may be associated, including 42 which are Company-owncd. The Company-owned sites include 24 coal gasifi-cation sites (MGP), 14 industrial waste sites and 4 operating property sites where corrective actions are deemed necessary to prevent, contain and/or remcdiate contamination of soil and/or water in the vicinity. Of these Company-owned sites, 12 are listed on the New York State Registry of Inactive Hazardous Waste Sites and I, Saratoga Springs is on the Fed-eral National Priorities List (NPL). The 42 remaining sites with which the Company lies been or,may be associated are generally industrial waste sites as to which the Company is allcgcd to be a Potentially Responsible Party (PRP) and may be required to contribute some proportionate share towards investigation and clean-up. Additional sites with which the Coinpany has been or may be associated could be identified in thc future as requiring investigation or remediation.

Investigations at each of thc Company-owned sites are designed to (1) determine ifenvironmental contamination problems exist, (2) determine the cxtcnt, rate of movement and concentration of pollutants, (5) ifnecessary, dctcrininc thc appropriate remedial actions required for site rcstoni-tion and (4) where appropriate, identification of other parties whom should bear some, ifnot all, of the f

rcmcdiation. Legal action against such other partie.

essary, will be initiated. After site investigations ha~

completed, the Company expects to be able to determine site-specific rcinedial actions necessary and to estimate thc attendant costs for restoration. Hoivever, since technologies arc still developing and the Company has not yct under-taken any full-scale remedial actions followingEnvironmen-tal Protection Agency (EPA) rcquiremcnts at any identified sites, nor have any detailed remedial designs been prepared or submitted to appropriate regulatory agencies, the ulti-mate cost of rcmcdial actions may change substantially as investigation and remediation progress.

Thc Company has determined that it is probable that 55 of the 42 owned sites willrcquirc some degree of investigi-tion, remediation and monitoring. This conclusion is based upon a number offactors, including the nature of the iden-tified contaminants, thc location and size of the site, the proximityofthe site to sensitive rcsourccs, the status ofregu-NPL Site Name New York State County Number of Known PRPs Total Company's Estimated Cost Estimated Potential Millions Contribution Factor Cfothier Disposal Fulton Terminals Johnstown City Landfill Pollution Abatement Services Rosen Brothers Scrap Yard/Dump Seafand Restoration Site Vofney Municipal Landfill (PAS)

York Oil Co.

Quanta Resources Vofney Municipal Landfill Bern Metal Co., fnc.

Onondaga Drum Site Oswego Oswego Fulton Oswego Cortland St. Lawrence Oswego Franklin Onondaga Oswego Erie Onondaga 31 105 130 105 5

22 105 20 25 unknown unknown unknown

$ 3 4

32 13 32 32 15 15 2

32 32 32

.06

.28

.76

.18 20.00 5.00 4.00 unknown unknown unknown

NIAGARA M 0 H A IV K P 0 1V E R CORPORATION A N D SUBSIDIARY COMPANIES 4

latory investigation and knowlcdgc of activities at similarly si

.d sites. Although the Company has not extensively

~ tcd many of those sites, it lias suIIicient information iate a range ofcost ofinvestigation and remediation.

As a consequence of a preliminary site characterization process completed to date, thc Company has accrued a

liabilityof $195 million for these owned sites, representing the low cnd of the range of cost for investigation and reme-diation. The high end of thc range is estimated at approxi-mately $514 million.

In 1991, the Company completed an Interim Remedial Measures (IRM) initiative at one of its coal gasification sites that was on the New York State Registry. This IRM was thc first test effort in a Company program intended to remove or control waste sources from sites in an effort to eliminate potential threats to human health and the environment, including the cessation ofany associated spread ofcontami-nants from the site. The cost of the IRM as applied to the first site was approximately $3 million, exclusive of ongoing monitoring costs. This particular site was removed from the New York State Registry in October 1991.

The results of this first IRM effort have provided a basis for the Company to further develop and propose a plan to apply thc IRM concept at other qualifying sites. Thc Com-pany and thc New York State Department ofEnvironmental Conservation (DEC) have exccutcd an Order of Consent providing for an investigation and remediation program for 21 former MGP sites. The program provides for a ten-year sc ilc of investigation and remediation activities. The

>y's 1993 rate settlcmcnt includes the estimated costs irst year of this program. Thc Coinpany believes that this proactive approach may allow for morc timely and eco-nomic removal or control ofwastes than application ofregu-latory enforcement actions.

The Company does not currently bclicve that a clean-up will bc required at the 7 remaining Company-owned

sites, although some degree of investigation of these sites is in-cluded in its investigation and remediation program.

With respect to the 42 sites with which thc Company has been or may be associated as a PRP, 26 are included in thc Ncw York State Registry of Inactive Hazardous M',tste Sites and 15 are on the NPL or arc under evaluation for listing.

The Company has reached agrecmcnt with regulatory agen-cies and other PRP's and settled on 7 of these sites through Decernbcr 31, 1992, in an aggregate amount tliat is immater-ial to the Company. Total costs to investigate and remcdiate the remaining 35 with which the Company is associated are cstimatcd to be approximately $492 million. The Company estimates its share of this total at approximately $20 million and this amount has been accrued at Dcccmber 31, 1992.

Of the 15 PRP sites on the NPL for Uncontrolled Haz-ardous Waste Sites as published by the EPA in the Federal Register, onc (Ludlow Landfill) has been settled by the Company for less than $10,000 and 12 are listed on page 46.

Thc remaining two are further discussed below.

E

'mates ofthc Company's potential liabilityfor PRP sites a

'vcd by estimating the total cost of clean-up of the sa then applying the related Company contribution fact to that estimate. Estimates of the total clean-up costs arc detcrmincd by using the Company's investigation to date, ifany, discussions with other PRPs and, where no informa-tion is known at the time of estimate, EPA estimates based on average costs disclosed in the Federal Register ofSeptcm-bcr 25, 1991. The contribution factor is calculated using either the Company's pcrcentagc share of the total,PRPs named, which assumes all PRPs will contribute equally, or the percentage agreed upon with other PRPs through a steering committee or by other means. Actual Company expenditures for these sites arc dependent upon the total cost ofinvestigation and remediation and the ultimate deter-mination of thc Company's share of responsibility for such costs as well as the financial viability of other identiTicd responsible parties since clean-up obligations are joint and several. The Company has dcnicd any responsibility in cer-tain of these PRP sites and is contesting liabilityaccordingly.

In Novcrnbcr 1989, an action was commenced against the Company and six other corporations by the US Department, ofJustice in Federal Court pursiiant to the Comprehensive Environmental Response, Compensation and LiabilityAct.

Thc complaint allcgcs that the dcfcndants are liable for past response costs of $2.3 million and additional ongoing and future response costs incurred by the EPA in investigating and rcrncdiating PCB contamination at the Wide Beach Development Site in Eric County, Ncw York. The Company has reached a monetary scttlcrncnt, at less than $300,000, with thc Department ofJustice and the other defendants which dismisses the Company from the proceeding. An Order on Consent incorporating the settlement terms has been entered with the court, in January 1993 releasing the Company from further liabilityfrom this action.

The EPA advised the Company by letter that it, is onc of 833 PRPs under Supcrfund for the investigation and clean-up of the Maxcy Flats Nuclear Disposal Site in Morehead, Kentucky. The Company has contributed to a study of this site and estimates that the cost to the Company for its sliarc of investigation and remediation based on its contribution factor of 1.3% would approximate $ 1 million.

Thc Company belicvcs that costs incurred in the investi-gation and restoration process for both Company owned sites and sites with which it is associated willbe recoverable in thc ratcsetting process. Rate Agreements since 1991 pro-vide for recovery of anticipated investigation and remedia-tion expenditures, however, the PSC Staff reserves the right to review the appropriateness of thc costs incurred. No costs liavc been clrallengcd to date by the PSC StaK The Company's 1993 rate settlcmcnt includes $35 million for site investigation and remediation, a substantial increase from amounts authorized under thc 1991 Agrccmcnt and rcflcct-ing implementation of the IRM initiative. Based upon management's asscssmcnts that rcmcdiation costs will bc recovered from ratcpaycrs, a regulatory asset has been recorded rcprcsenting thc future recovery of remediation obligations accrued to date.

The Company also agrccd in thc 1991 Agreement to a cost sharing arrangement with respect to one industrial waste site. The Company docs not belicvc that this cost sliaring agreement, as it rclatcs to this one industrial waste site, will have a material eAect on thc Company's financial position or results ofoperations.

The Company is also in the process of providing notices of insurance claims to carriers with respect to the investi~-

tion and remediation costs for manufactured gas plant and industrial waste sites. Thc Company is unable to predict whcthcr such insurance claims willbc successful.

NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES Tax assessments:

Thc Internal Revcime Service (IRS) is cur-rently conducting an examination of thc Company's Fcdcral income tax returns for the years 1987 and 1988 and has sub-mitted a Revenue Agents Report to the Company. The IRS has proposed various adjustincnts to the Company's federal income tax liabilityfor these years which could incrcasc the Federal income tax liability by approximately $83 million before asscssmcnt of penalties and intcrcst. Included in these proposed adjustmcnts are several potentially signifi-cant issues involving Unit 2. Thcsc issues include its tax in-scrvice date, cost basis for invcstmcnt tax credit purposes, partnership short year for depreciation purposes and a pro-posed reclassification of plant costs to "licensing costs", an intangible asset. The Company is vigorously defending its position on each ofthese issues. Pursuant to the 1990 Unit 2 settlement, to the cxtcnt the IRS is able to sustain disallow-ances in those areas, thc Company will have to absorb a

portion of any disallowance which it belicvcs will not have a material impact on the Company's financial position.

Thc Company is at various stages of examination by the State of Ncw York for sales tax and other state taxes. The Company bclicves that the resolution of these cxaininations will not have a material impact, on thc Company's financial condition or results of operations, and that any asscssincnts ultimately sustained will bc recoverablc by thc Company tllfoilglltile fatcscttllig process.

FERC Order 696: In April 1992, the FERC issued Order 6%,

which willrequire interstate pipclincs that offer open access transportation scrviccs to unbundle pipeline sales services from pipclinc transportation service. These changes will enable thc Company to arrange for its gas supply directly with producers, gas markctcrs or pipclincs, at its discretion, as well as arrange for transportation and gas storage services.

As a result of these structural changes, pipelines face "transition" costs from implementation of the order e

0 principal costs arc: unrecovered gas cost that would wise have been billable to pipeline customers unde ously existing rules, costs related to restructuring existing gas supply contracts and costs ofassets needed to implement thc order (such as meters, valves, etc.). Under the Order, pipclines are allowed to recover 100% ofprudently incurred costs from custoiners. Prudence will be deterinincd by the FERC review.

The amount ofrestructuring costs that may be billable to thc Company willbe determined in accordance with pipe-line restructuring plans which have been submitted to FERC for approval. Thcrc are four pipelines to which the Company may have some liability.The Company is actively participating in FERC hearings on these matters, to ensure an equitable allocation of costs.

Based upon information presently available to the Company from the petitions filed by the pipelincs and the Company's participation in settle-ment negotiations, its liabilityfor the pipclincs'nrecovered gas costs could be as much as $56 millionand its liabilityfor pipeline restructuring costs could be as much as $60 mil-lion. Howcvcr, the Company believes its ultimate liabilitywill be less than $64 million in total, based on its assessment of the progress of scttlemcnt negotiations. The Company anticipates these costs willbc primarily reflected in demand charges paid to reserve space on thc various interstate pipelines and willbe billed over a period ofapproximately 7 years, with billings morc heavily weighted to the first s.

The Company is unable to predict the probable out f

current pipclinc restructuring settlements and the a for which it may be ultimately liable or the period over which this liabilitywillbe billed. The Company believes any amounts for which it is ultimately determined to be liable willbe recoverable in the rateset ting process.

NOTE 10.

Quarterly Financial Data (Unaudited)

Operating revcinies, operating income, net income (loss) and earnings (loss) pcr common share by quarters from 1992, 1991 and 1990, respectively, are shown in the following table. Thc Company, in its opinion, has included all adjustments necessary for a fair presentation ofthc results ofoperations for thc quarters. Due to the seasonal nature ofthe utilitybusiness, the annual amounts arc not gcneratcd evenly by quarter during thc year.

Quarter Ended Operating revenues Operating income In thousands of dollars Net income (loss)

Earnings (loss) per common share 1991 1990 LSeeptember 30, 1992 1991 1990 1991 1990 963)629 848,593 781,270 822)530 734,446 682,114 881,427 807,024 737,860

$119,181 117,139 63,531

$ 89)658 102,627 128,191

$137,515 127,159 103 750

$ 41,835 35,111 (104,807)

$ 40,401 40,783 60,128

$ 71,734 57,691 35 756

$.24

.18

(.85) 5.28~

.23

.37

$.46 1991 1990

$1)033,941

$177,972 992,45~178,509 953,475 156,589

$102,462 109,784 91,801

.60 48

NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES In the second quarter of 1992 and the third quarter of 1991, the Company recorded $22.8 million ($.11 pcr common share) 0 million ($.14 per cominon share), respectively, for MERITearned in accordance with thc 1991 Agreement. In the first of 1992 and the fourth quarter of 1992 and 1991, the Company rccordcd $21 million ($.09 per common sharc), $24 n

n ($.09 per common share) and $23 million ($.07 per commbn sharc), respectively, to writeMown its subsidiary invest; ment in oil and gas properties.

In the fourth quarter of 1991 and 1990, the Company accrued $5 million ($.01 per common share) and $15 million ($.07 pcr common share), respectively, relating to its investment in NM Uranium, Inc., resulting in a decrease in net income for each quarter. In the fourth quarter of 1990, the Company reflectcd a loss of$ 140 million ($.68 per common share) relating to nuclear rcplaccmcnt power costs disallowed associated with Unit 1 and Unit 2 outages.

NOTE 11. Inj'orntation 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 seginents and depreciation of such common property have been allocated to thc segments in accordance with practice cstablishcd for regulatory purposes. Iden-tifiable assets include net utility plant, materials and supplies, deferred finance charges, deferred recoverable energy costs and certain other dcfcrred debits. Corporate assets consist of other property and invcstmcnts, cash, accounts receivable, prepaymcnts, unamortized debt expense and other deferred debits.

ln thousands of dollars 1992 1991 1990 Operating revenues:

Electric Gas.

Total.

0 ting income before taxes:

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

as.

$3,147)676 553,851 I $3,701,527 645,696 61,863

$2,907,293 475,225

$3,382,518 644,084 39,487

$2,669,308 485,411

$3,154,719 522,947 50,228 Total Pretax operating income, including AFC:

Electric Gas.

Total 666,269 62,721 662,258 40,244 728,990 702,502 I $

707,559 I

683,571 573,175 543,504 51,085 594,589 Income taxes, included in operating expenses:

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

Gas.

176,901 6)332 152,840 5,297 119,185 1,929 Total Other (income) and deductions.

Interest charges Net income.

Depreciation and amortization:

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

Gas.

Total 300,716 (10,643) 311,639 I $ 256432 I

243,369 255,256 18)834 240,887 17,929 I $

274,090 I

258,816 I

183 233 158,137 121,114 71,728 318,869 82,878 204,417 16,440 220,857 Construction expenditures:

(including nuclear fuel):

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

Gas.

Total Identifiable assets:

lectric.......

Total Corporate assets.

Total assets 442,741 59,503 I $

502,244 I

$7,0001659 783,766 7,784,425 806,110 I $8,590,535 I

445,298 77,176 522,474

$6,760,375 725,553 7,485,928 755,548

$8,241,476 373,232 58,347 431,579

$6,435,401 610,648 7,046,049 719,357

$7,765,406

NIAGARA,MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANlES Market Price ofCommon Stock and Related Stockholder Matters 1992 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter 1991 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter Dividends Paid Per Share

$.16

.20

.20

.20

$.16

.16 Price Range High Low

$19

$17N 19Yi 17Yi 20M 18N 19M 18N 15

$12s/i 15N 14Yi 17 15Yi 18 16Yi Other Stockholder Mattersr The holders of Common Stock are entitled to one vote per share and may not cumtilate their votes for the election ofDirectors. Whenever dividends on Preferred Stock are in default in an amount equivalent to four full quarterly dividends and thereafter until all divi-The Company's common stock and certain of its preferred series are listed on the New York Stock Exchange. The com-mon 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, Sep-tember 30 and December 31. Common stock dividends were paid on February 29, May 31, August 31 and November 30.

The Company presently estimates that, none of the 1992 common or preferred stock dividends will constitute a

return ofcapital and therefore all ofsuch dividends are sub-ject to Federal tax as ordinary income.

The table below shows quoted market. prices and divi-dends per share for the Company's common stock:

1 to 99 100 to 999 1,000 or more 44,910 62,931 7,107 1,466,395 17,440,068 118,253,144 114,948 137,159,607 dends thereon are paid or declared and set aside ment, the holders ol'such stock can elect a majority o the Board of Directors. Whenever dividends on any Preference Stock are in default in an amount equivalent to six fullquar-terly 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 the Board ofDirectors.

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 sliare ofall 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 satis-fied.

The indenture securing the Company's mortgage debt provides that surplus shall be reserved and held unavailable for the payment of dividends on Common Stock to the extent that expenditures for maintenance and repairs plus provisions for depreciation do not exceed 2.25% of depre-ciable property as defined therein. Such provisions have never restricted the Company's surplus.

At year end, about 115,000 stockholders owned common shares of the Company and about 5,300 held preferred stock. The cliart below summarizes common stockholder ownership by size ofholding:

Size of holding (Shares)

Total stockholders Total share d

YEAR END PRICE OF COMMON STOCK RETAINED EARNINGS (MILLIONSOF DOLLARS) 1988 1989 1990 1991 1992

"( j kl

, h-I 1

1988 1989 1990 1991 1992 50

NIAGARA NOkfAIVK PO)VER CORPORATION AN D SUBSIDIARY COMPAN I ES S

cted Financial Data ussed in Management's Discussion and Analysis of Financial Condition and Results of Operations and Notes to Con-s ed Financial Statements, certain of the following selected financial data may not be indicative of the Company's I cond Operations: (000's)

Operating revenues..

Net income.

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 ot 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 future financm uron or rosulrs of oporarrons.

$3,701,527 256,432

$16.33 19'/s 117.1%

4.2%

S 1.61 10 1%

S

.76 47.2%

$2>240>441 290>000 170,400 3,491,059 6,191,900 1991

$3,382,518 243,369

$ 15.54 1'/s 115 0%

3.6%

$ 1.49 10 0%

S

.32 21.5%

$2,115,542 290,000 212,600 3,325,028 5,943,170 100,000 1990

$3,154,719 82,878

$ 14.37 13%

91 4%

P P%

.30 2.1%

S

.00 P P%

$1,955,118 290,000 241,550 3,313,286 5,799,954 40,000 1989

$2,906,043 150,783

$ 14.07 14s/s 1 02.2%

P P%

.78 5.6%

.60 76.9%

$1,914,531 290,000 267,530 3,249,328 5,721,389 50,000 1988

$2,800,453 208,814

$13.87 13 93 7%

9.2%

$ 1.21 8.7%

$ 1.20 99.2%

$1,881,394 290,000 295,510 2,995,748 5,462,652 33,000 Total.

$6,191,900

$6,043,170

$5,839,954

$5,771,389

$5,495,652 Capitalization ratios: (including first mortgage bonds maturing within one year):

Common stock equity 36.2%

preferred stock 7.4 rm debt.

56.4 35 0%

8.3 56.7 33.5%

9.1 57.4 33.2%

9.6 57.2 34 2o/

10.7 55.1 I ratios:

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.

Miscellaneous: (000's)

Gross additions to utilityplant.

Total utilityplant.

Accumulated depreciation and amortization..

Total assets 2.24 2.17 9 7%

1.90 34.1%

19.7 13.5 17.3 14.2 5.9 S

502,244 9>642,262 2,975,977 8,590,535 2.09 2.03 93%

1.77 32.1%

20.0 14.4 16.4 15.5 6.0 522,474 9,180,212 2,741,004 8,241,476 1.41 1.35 52.8%

1.17 36.9%

19.9 14.4 14.4 14.3 1.3 431,579 8,702,741 2,484,124 7,765,406 1.71 1.66 18.3%

36 So/o 19.7 14.4 15.3 14.2 3.6 413,492 8,324,112 2,283,307 7,562,472 2.10 2.06 6.9%

1.67 34 6'/

16.5 15.1 16.1 17.0 5.7 366,142 7,967,625 2,090,170 7,076,041 IS19

$459 TOTALTAXES INCLUDING INCOME TAXES (MILLIONSOF DOLLARS)

$19

$859 S574

$15

$459 S470 93.7%

MARKET/BOOK COMPARISON 115.0o/o 117 1%

102.2/o 91 4%

M9 ms 13.00

$14.38

$13.13

$17,88

$19.13 1988 1989 1990 1991 1992 1988 1989 1990 1991 1992

NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES Owned:

Coal Oil.

Dual Fuel OiliGas............

Nucfear Hydro.

Natural Gas...................

1>285 15.5 1,285 1,294 1>496 18.1 1,961 1,961 700 8.5 400 400 1>059 12.8 1,059 1,051 706 8.5 708 708 108 1 3 164 211 ELECTRIC CAPABILITY Thousands olkilowatts December 31, 1992 1991 1990 GAS STATISTICS Gas sales (Thousands oldskafherms)f Residential Commercial Industrial.

Other gas systems....................

Total sales.......................

Transportation of customer-owned gas....

1992 53,945 22,289 1,772 1>1 90 79,196 65,845 1991 71,729 50,631 78,617 34,242 48,172 49,955 20,226 22,823 1,812 4,116 1,519 1,723 5,354 64.7 5,577 5,625 Total gas delivered..

145,041 122/60 112459 Purchased:

New York Power Authority Hydro............

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

Non utilitygenerators...,

1,302 15.8 1,283 1,278 67

.8 76 63 1,549 18.7 1,027 630 Total capability '...........,...

8,272 100.0 7,963 7,596 Gas revenues (Thousands olde/lars):

Residential Commercial Industrial..

Othergas systems....................

Transportation of customer owned gas....

Miscellaneous.

$354,429 132,609 10,001 4,737 42,726 9,349

$302,900 113,727 8,430 6,964 36,455 6,749

$307,217 128,462 19,322 7,907 22,100 403 Electric peak load.....,......,..

6,205 6,093 5,792

$553,851

$475,225

$485,411 Available capability can be increased during heavy toad periods by purchases frcmneighboring Interconnected systems Hydro station capability is based on average December stream-flaw conditions, ELECTRIC STATISTICS 1992 1991 1990 Gas customers (Average):

Residential.

Commercial Industrial.

Other Transportation.

448,601 39,230 234 1

639 438,581 37.727 260 2

625 431,588 37,011 272 2

567 488,705 477,195 469,440 Electric sales (M>fEon ol kw-hrs.):

Residential....................

Commercial.........,......,

Industrial,...............,...,

Municipalservice...............

Other efectric systems......,

10,392 11,628 11,334 227 3,030 10,321 11,686 11>362 228 3,141 10,310 11,623 11,874 226 1,511 Residential (Average)

Annual dekatherm use per customer......

120.3 Cost to customer per dekatherm...,.....

$6.57 Annual revenue per customer...........

$790.08 Maxirnun day gas sendout {dekatherms).....

905,872 109.8

$6.29

$690.64 852>404 115.7

$6.15

$711.83 714,122 36,611 Electric revenues (Thousands oldollars):

Residential....................

$1,096,418 Commercial.......,...........

1,160,643 Industrial..................,..

628,667 Municipal service...............

50,327 Other electric systems...........

93,283 Miscellaneous.................

118,338 36.738

$ 985,347 1,044,725 556,934 47,566 106,066 166,655 35W4

$ 917,057 978,684 543,365 44,825 69,821 115,556 ELECTRICITYGENERATED AND PURCHASED I992

$3,147>676

$2,907,293

$2,669,308 1,378,484 1,361,961 145,098 145,231 2,283 2,309 3,231 3,158 1>537i346 1,529,096 1,512,659 Electric customers (Average).'esidential....................

1,389,470 Commercial......,..........,.

142,345 Industrial,....................

2,269 Other....

3,262 NATURAL VARIOUS GAS SOURCES 4%

5%

1/oui

~

~

Residential (Average):

Annual kw.hr. use per customer...

Cost to customer per kw.hr.......

Annual revenue per cutomer......

7,479 10.55O

$789.09 7,487 9.55c

$714.80 7,570 8.89C

$673.33 CorPora(e Inforsnation Annual Meeting The annual meeting ofsharehold-ers willbc held at The Desmond Hotel, GGO AlbanyShaker Roa<l, Albany, N.Y. at 10:30 a.m iltesday, 1>lay 4, 1993. A notice ofthe meet-ing, proxy statement and form of proxy willbe sent in early Aprilto holders ofcommon stock.

SEC Form 10.KRePort A copy ofthe company's Form 10-K rcport, filed annually with the Securities and Exchange Commis-sion, is available without charge by writing the Investor Relations Department at 300 Erie Boulevard West, Syracuse, N.Y. 13202.

Shareholder Inquiries Questions regarding shareholder accounts may bc directed to the contpany's Shareholder Services Dcparunent:

(315) 128-G750 (Syracuse)

I-800-9G2423G (Yew York State) 1-800.4 18-5 I50 (clscwhere in continental U.S)

Analyst lnquincs Anal)st irt<luiries should bc dircctcd to Leon T. Mazur,

>>Ianager-Investor Relations, (315) 4285876.

Sfoch Exchange Listings Ticker Symbol: IVA1K Common stock and most preferred series are listed and traded on the New York Stock Exchange.

Boruls are traded on the New York Stock Exchange.

Disbursing Agent Common and Preferred Stocks:

Niagara Mollawk Power Corp.

300 Erie Boulm>ard West Syracuse, N.Y. 13202 Bonds:

Marine >bfidland Bank, NA.

140 Broadway New York, N.Y. 10015

'&ansfer Agenfs and Registrars Common and Preferred Stocks:

CllellllcalB;ink 150 At>est 33rd Street New York, N.Y. 10001 Bonds:

Marine Midland Bank, NA.

140 Broadway New York, N.Y. 10015 52

NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES Directors Officers F.Allyn (8, C, I) t IL Chief Executive Oflicer Wc c I Allyn,Inc., Skaneatclcs Falls, NY Lawlence Burkhardt, HI (I')

Former Executive Vice Prcsidcnt Nudear Operations Douglas hL Costle (A, D, I)

Distinguished Senior Fclfolv, Institute for Sustainable Communitics Vermont Law School South Royal(on, VT Edmund M. Davis (A, 8, D, E)

Partner, I-Iiscock fk Ihrclay Attorneys at-Law, Syracuse, NY WilliamE Davis Vice Chairlnan ofthc Board WilliamJ. Donlon (A)

Chairman ofthe Board and Chief Executive Ofliccr Edward W. Duffy(A, 8, I)

Former Chairman of the Board and Chief Executive Oflice, Marine Midhnd Ihnks, Inc.

Coopclstown, NY John hf. Endrics President Dr. Bonnie Guiton (A, C, D)

D MclntircSchool ofCommerce

'tyofVirginia, Charlouesvillc, VA

. Haehl, Jr.

Former Chairman ofthe Board and Chief Executive Ofliccr hiartha Hancock Northrup (A, Q E)

Homemaker, Syncusc, NY Henry A. Panasci,Jr.

(8, I)

Chairman ofthe Boald and Chief Executive Oflicer Fay's Incorporated, Liverpool, NY Patt i McGillPeterson (D, I)

President, St. Lawrence University Canton, NY Donald ILRieflcr (rl, C, l~I)

Financial hfarkct Consultant Vero Beach, FL Stephen E Schwartz (8, E)

Former IBhfSenior Vice President Palm Beach Gardens, FL John G. Wick (C D, E)

Partner, Falk ft.. Siemer Attornc>mat.Law, Buffalo, NY A. Member of the Executive Committee

8. hfember ofthe Compensation 8:

Succcsslon Conlnllucc C. hfember of the Audit Committee D. Member of the Committee on Corporate Public Policy gc Environmental Affairs bcr of the Finance Committcc Ibcr of thc Nuclear Oversight.

Imittce WilliamJ. Donlon Chairman ofthe Bmld and Chief Excctltive Oflicer WilliamE, Davis Vice Chairman ofthe Bmld (Effcclivc¹vnnbcr 19, 1992)

John hf. Endries President L Ralph Sylvia Executive Vice President, Nudcar David J. Arrington Senior Vice Prcsidcnt Human Resources John P. Hcnnesscy Senior Vice Prcsidcnt Electric Customer Service Gary J. Lavinc Senior Vice President Legal g.. Corporate Relations and Gcnenl Counsel

~

Robert J. Patrylo Senior Vice Prcsidcnt Gas Customer Service John M Powers Senior Vice President Finance and Corponte Services hiichacl P. Ranalli Senior Vice President Electric Supply and Delivery Joseph T. Ash Vice President, Consumer Services Nicholas J. Ashooh Vice President Public AKairs and Corporate Communications (IsffcrsivcAugtrst I, 1992)

Thomas H. Baron Vice President, Fossil Gcncration Harold J. Bogan Secretary (EffcctivcOriolrcr I, 1992) hiichael J. Cahill Vice President, Regional Operations Neil S. Cams Vice President, Nuclear Generation (EffcriivcAugust I, 1992)

Norman E. Crowe> Jr.

Vice Prcsidcnt, Regional Operations Richard F A. Duffy Vice Plesldcnt Public AiTairs and Corporate Communications (Rcsindjuly3I, 1992)

Thomas IL Fair Vice President Environmental AKairs Joseph F. Firlit Vice President, Nuclear Support Edward F. Hoffman Vice President, Power Delivery Darlene D. Kerr Vice President Gas Marketing and Rates Samuel F. Manno Vice Prcsidcnt Purclrasing and Corpontc Services Douglas R. hfcCuen Vice President Government and Regulatory Relations Clement E Nadeau Vice President Po>>cr Tnnsactions and Planning James A. Perry Vice Prcsidcnt, Quality Assunncc Russell E. Perry Vice President, Emplo>ce Relations (Rcsigncd Junc 19, 1992)

Nicholas I Priolctti,Jr.

Vice Prcsidcnt, Financial Planning Arthur W. Roos Trcasllrcr Richard H. Ryczek Vice Presi<fent Gas Customer Scrvicc Operations Jack R. Swartz Vice President, Emplo>cc Relations (EffeciivcAugust I, 1992)

WilliamJ. Syn>>uldt Vice Pscsident, Information Sptcms Steven MTasker Controller Carl D. Terry Vice President, Nuclear Enginccring Andrew hf. Vescy Vice President, Opentions Support Stanley M Wilczek,Jr.

Vice President, Special Projects

Niagara Mohawk Power Corporation 300 Erie Bouievard West Syracuse, New York 13202 BULKRATE US. POSTAGE f NMPC

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