ML18038A146

Niagara Mohawk Power Corp,1985 Annual Rept

ML18038A146
Person / Time
Site:	Nine Mile Point
Issue date:	12/31/1985
From:	Donlon W, Haehl J, Lempges T NIAGARA MOHAWK POWER CORP.
To:	NRC OFFICE OF ADMINISTRATION (ADM), Office of Nuclear Reactor Regulation
References
NUDOCS 8604010251
Download: ML18038A146 (88)

Text

REGULATORY I RMATION DISTRIBUTION SYS (RIDS)

ACCESSION NBR: 8604010251 DOC. DATE: 85/12/31 NOTARIZED:

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Unit 1> Niagara Powe 05000220 50-410 Nine Mile Point Nuclear Station>

Unit 2> Niagara Moha 050004IO AUTH. NAME AUTHOR AFFILIATION HAEHL> J. G.

Niagara Mohawk Power Corp.

LEMPQES> T. E.

Niagara Mohawk P ower Corp.

DONLON, W. J.

Niagara Mohawk Power Corp; RECIP. NAME RECIPIENT AFFILIATION

SUBJECT:

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NIAGARA IYIOHAWKPOWER CORPORATION I'II~N';

NIAGARA '~I MOHAWK THOMAS E, I.EMPG ES VCEPAESOKM~ GCNfRATCN 300 CRI C SOULCVARD WEST SYRACUSE, H.Y. I3EOE March 27, 1986 Director Office of Nuclear Reactor Regulations c/o Distribution Services

Branch, DDC, ADM U.S. Nuclear Regulatory Commission Washington, DC 20555

Dear Sir:

As required in Title 10, Chapter I, Code of Federal Regulations, Section 50.71(b),

and compiled in Regulatory Guide 10;l,.enclosed are ten (10) copies of Niagara Mohawk Power Corporation's 1985 Annual Report.

Cordially, TEL/jrs Enclosures (10)

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NOTICE THE ATTACHED FILES ARE OFFICIAL RECORDS OF THE DIVISION OF DOCUMENT CONTROL.

THEY HAVE BEEN CHARGED TO YOU FOR A LIMITED TIME PERIOD AND MUST BE RETURNED TO THE RECORDS FACILITY BRANCH 016.

PLEASE DO NOT SEND DOCUMENTS CHARGED OUT THROUGH THE MAII. REMOVALOF ANY PAGEOS)

FROM DOCUMENT FOR REPRODUCTION MUST BE REFERRED TO FILE PERSONNEL. ~ cQQg r+~i/es-

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DEADLINE RETURN DATE ao o 0 Mp-RECORDS FACILITYBRANCH 8604010251 ADGCK 5000220 POR

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NEW YORK STATE Serving upstate New York Ranked as one ofthe most prominent investor-owned utilities in the United States, Niagara Mohawk Power Corp. serves an area encompassing more than halfthe land mass ofNew YorkState. Our electric system ex-tends from Lake Erie to New England's borders, to Canada and Pennsylvania, and meets the diversified needs ofnearly 1.4 millioncustomers. Our natural gas system serves 440,000 customers in central, eastern and northern New York,nearly allwithinour electric territory. Two Canadian companies, St. Lawrence Power Co. and Canadian Niagara Power Company, Ltd.,

owned by our subsidimy, Opinac Investments, Ltd.,

provide energy to portions ofOntario. Other sub-sidiaries are Hydra-Co Enterprises, Inc., N MUranium, Inc., Niagara Mohawk Finance, N.V. and Opinac Energy, Ltd. Our corporate headquarters are 300 Erie Boulevard West, Syracuse, N.Y. 13202.

Corporate Mission Niagara Mohawk is an energy company withdiversified interests and resources committed to providing for the current and future needs ofits customers through economical products and services ofsuperior quality.

The Company is dedicated to maintaining an effi-cient, progressive, cost-conscious organization that provides a fairand equitable return to its owners.

The Company recognizes that its most valued re-source is its employees, and that the Company's suc-cess is directly dependent on their efforts. Manage-ment is committed to retaining and motivating tal-ented. productive. effective employees by providing reasonable compensation, incentives and a good working environment.

The Company pursues opportunities to improve the economic climate and well-being ofcitizens, industry and business withinthe markets itserves. Appropri-ate actions are taken to meet socioeconomic respon-sibilities. Such actions include seeking those neces-sary improvements in the regulatory and legislative environment that best serve the interests ofthe Com-pany's customers, employees and owners.

The Company maintains high ethical standards and strives foropen communications withallits con-stituencies.

The Company takes an active role in the develop-ment oftechnologies and opportunities advantageous to its customers and owners. Itis dedicated to main-taining and developing dependable energy resources and delivery systems that are safe and environmen-tallysound.

Management willactively pursue strategies in sup-port ofobjectives to accomplish this mission.

Cover Giant mapboard in new Power Control Center in Syra-cuse displays status ofall principal generating sta-tions, transmission lines and substations in Niagara Mohawk's massive Upstate New Yorkpower network.

Center is described on page 4.

Highlights of 1985 1985 0/

1984 Change Income available forcommon stockholders 351,871,000 S

308,274,000 14.1 Earnings per common share............

42.88 S2.84 1.4 Dividends per common share S2.06 S1.98 4.0 Common shares outstanding(average)

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122,215,000 108,734,000 12.4 Utilityplant(gross)

S 7,640,905,000 S 6,903,184,000 10.7 Construction work in progress ~..... ~....

~ 2,336,188,000 S 1,877,689,000 24.4 Gross additions to utilityplant...

Kilowatt-hoursales Electric customers at end ofyear........

Electric peak load(kflotuatts)...

Natural gas sales(dekatherms) 771,120,000 S

769,846,000 0.2 35,296,000,000 37,086,000,000 (4.8) 1,424,000 1,405,000 1.4 5,862,000 5,526,000

6. 1 108,420,000 114,960,000 (5.7)

Total operating revenues...... ~..........

~ 2,694,940,000 S 2,785,546,000 (3.3)

Contents 2 To our stockholders 4 Managing change in mid-decade 18 Market price ofcommon stock and related stockholder matters 18 Management's discussion and analysis of financial condition 22 Report ofmanagement 23 Consolidated financial statements 23 Reportofindependent accountants 26 Notes to consolidated financial statements 39 Statistics 41 Officers, directors, corporate information Gas customers at end ofyear...........

440,000 436,000 0.9 Maximum day gas sendout(dekatherms) 774,033 772,604 0.2 Earnings and dividends paid per common share Market price ofcommon stock at year end 1985 1984 1983 Dividends

$2.06

$1.98

$1.89 Earning)

$2.88

$2.84

$2.77 1985 1984 1983

$20V2

$15%

1982 1981

$1.76

$1.61

$2.35 1982 1981

$12%

The 1985 revenue dollar And where itwent Residential customers 35ff Commercial customers 32' Industrial customers 21II Allothers 12II

, ~ir Fuel forthe production of electricity 28f!

and electricity purchased Income and other taxes 16tf Gas purchased 154 Wages, salaries, employee benefits 11'ividends to stockholders 11tf Interest and other costs net 9tf Depreciation 6'etained in business 4tf

To om.. stockholders We are pleased to report an increase in earnings by Niagara Mohawk forthe fifthstraight year, as earnings rose to 42.88 per share ofcommon stock in 1985 compared with 42.84 in 1984 on fewer shares.

We are also pleased to note the increase in the annual dividend rate on our common stock during 1985 to 42.08 from the previous 42.00 per-share rate.

Although 1985 saw significant construction progress at the nearly completed Nine MilePoint

-$ ~i'

!I+5)

John G. Haehl, Jr.

WilliamJ. Donlon Nuclear UnitTwo project, we were compelled in early 1986 to defer fuel loading from February-the target established fiveyears ago-until May 1986. Essentially, this was the result ofdelays experienced in finalizingconstruction and con-ducting pre-operational testing priorto fuel load-ing. Currently, however, the fuel has been de-livered to the site and has undergone inspection, and most ofthe plant's operating systems have been successfully tested. The fuel-loading post-ponement has required rescheduling the Unit's commercial startup to early 1987. Extensive dis-cussions regarding cost, schedule, regulatory and financial matters and other important fac-tors on Nine MileTwo are contained in Note 10 to our financial statements, page 33.

In October, we wrote to our stockholders de-scribing a Nine MileTwo cost settlement agree-ment, proposed in a filingwith the N.Y, State Public Service Commission. The proposal seeks to achieve certainty regarding the cost ofthe Unit that willbe borne by customers ofthe utilityco-owners sharing the project, with costs in excess ofthe settlement value to be borne by each co-owner.

Considering all factors, we are confident that, this realistic agreement would be in the best interest ofall parties involved in Nine Mile Twothe co-owners, their customers and stockholders. Given today's regulatory response to the rate impacts ofnew nuclear facilities, the probability ofour entire investment in Nine Mile Two being recovered in rates is remote.-

Moreover, pursuing that action would take sev-eral years for"prudency review" proceedings by the PSC. Such an exhaustive inquirywould itself seriously burden the project at a time when its managem'ent and staff are concentrating their ef-forts and'resources upon operational testing and final preparations forcommercial power service.

The administrative lawjudges recently recom-mended to the PSC that the settlement be re-jected forvarious reasons and that a detailed cost review ofthe Unitbe undertaken. They ac-knowledged however, that the proposal may form a reasonable basis forconcluding the cost review proceedings. The Company willbe strongly op-posing the recommendation to reject the settle-

, ment We expectadecisionbytheCommission in May and shall continue to keep you advised on this matter.

C

Despite the fuel-loading delay, we met a rigor-ous series ofconstruction milestones and ex-perienced a number ofother encouraging de-velopments during the year at Nine MileTwo.

These included a favorable recommendation, withlaiidatoiy references to the plant's quality and safety, from the AdvisoryCommittee on, Reactor Safeguards to the Nuclear Regulatoiy Commission. This is a key step toward achieving a full-powerlicense. Further, in 1985, the Nine MilePoint site became the nation's firstto win approval by the Federal Emergency Management Agency forboth an emergency plan and prompt notification system.

Looking at the future, we remain confident that Nine MileTwo willoccupy a prominent place be-side its well-established partner, Nine MileOne, a nuclear pioneer in service since 1969. Our op-timism is further bolstered by Nine MileOne's excellent performance in 1985, as production capacity reached 92 percent, its highest ever.

Moreover, Nine MileOne was available to meet load 96 percent ofthe entire year, also a station record. This outstanding operating experience has made Nine MileOne the best performing boil-ing water reactor in the world during 1985 in both the capacity and availability categories.

New electric and gas rates to produce an addi-tional 458. 1 millionannually were approved by the PSC and implemented in March 1985. The Company found itnecessary to filea new electric rate increase inApril,including the firstyear ofa proposed phase-in forNine MileTwo. Atrecent public meetings, the PSC indicated that an in-crease in the amount ofNine MileTwo construc-tion workin progress willbe allowed in rates to provide cash flowto cover a portion offinancing costs, and that deferral accounting procedures willbe employed forany Nine MileTwo operating expenses prior to April1987. Aphase-in plan of seven years, possibly to be shortened to five years ifthe proposed cost settlement is ap-proved, would also be allowed. Observing that re-turns in financial markets are decreasing, the PSC set a return on equity of 13.5 percent forthe next rate year ending March 1987, compared to a currently authorized 15.5-percent return.

Featured on the cover ofthis Annual Report, our new system-wide Power Control Center was formallydedicated in Syracuse inJanuary 1986-a bright start forNiagara Mohawk's new year. This state-of-the-art showcase is the heart ofour advanced Energy Management System.

In reviewing the past few years, we can take some satisfaction in our achievements. Niagara Mohawk common stock has become increasingly attractive each year, withyear-end market value rising annually since 1980 and exceeding book value in 1985 forthe firsttime in 13 years. In another encouraging development, the credit rat-ings ofNiagara Mohawk securities were up-graded in May 1985 by one ofthe nation's leading investor service agencies. While energy markets willcontinue to be volatile, interest rates, infla-tion and oilprices are decreasing. These factors all provide a more favorable economic base as we look ahead.

As we begin to leave the Nine MileTwo con-struction era behind us and set a course forthe late 80s and 90s, we willwelcome the more mod-erate overall financing needs, since both capital and external financing requirements willdecline as Nine MileTwo's building costs reach an end.

Our cash-flow situation should strengthen and the Company willalso become better positioned to pursue innovative new options and oppor-tunities forfurther growth. Our two young sub-sidiaries, Hydra-Co Enterprises, Inc., and Opinac Investments, Ltd,imaginative, independent, expanding provide a glimpse ofthe oppor-tunities ahead as we enter this new era ofre-sourcefulness in our Corporate Mission.

On behalf ofthe Board ofDirectors and man-agement, we want to express our gratitude to our stockholders and employees foryour support and loyaltythroughout this eventful year. With you, we look forward to the years ahead.

John G. Haeht,Jr.

Chairman ofthe Board and ChiefBxecntive Ollicer WilliamJ. Don!on President March 10, 1986

Managing change in mid-decade Management's commitment to Niagara Mohawk's corporate mission in the next decade and the century ahead is clearly evident at our new Power Control Center, completed and on-line in 1985. Located in the heart ofNew YorkState, this model ofmodern utilitytechnology willserve as the nucleus forcoordinating the supply and de-liveryofpower throughout our 24,000-square-mile service area.

The new Center is also evidence ofour dedica-tion to management excellence and our con-sumer service-keyed "ThinkCustomer" philoso-phy. Years in the planning, the two-story brick structure is a state-of-the-art, high-tech show-case, utilizingthe most sophisticated elec-tronics and computer equipment. Its focal point is a large illuminated mapboard in the central power control room (featured on our Annual Re-port cover), where major generation and supply interconnections and transmission facilities are constantly monitored. The mapboard is inter-faced with arrays ofcomputers and consoles to provide power dispatchers a constant flowofin-formation on Company-wide operations. Acen-tral Energy Management System (EMS) compu-ter, linked statewide with major utilities in the New YorkPower Pool, automatically monitors customer demand and adjusts generation to pro-vide the lowest-cost electricity to meet custom-ers'nergy demands. Other computers in the Center enable dispatchers to conduct instant bulk-power transmission exchanges and trans-actions withutilities and regional networks outside New YorkState.

ACentral Region control center, with its own mapboard and communications system, also will be situated in the Power Control Center. Similar to the main system-wide facility,this willoperate 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> per day, year-round, to monitor and control transmission and distribution facilities on a Central and Mohawk Region basis. Older system and regional power control centers in Syracuse and other points in the system are being phased out by the new Center and EMS systems.

On an historic note, the new Power Control Center commenced operations in the 20th an-niversary year ofthe dramatic "Northeast Black-out of 1965." More important, many ofthe Cen-ter's complex high-tech controls and safeguards.

can be traced to new developments stemming from research since that memorable date.

Nine MileTwo aears its time Nine MilePoint Nuclear UnitTwoalmost fully constructed at this writing-isapproaching final testing and gradual power ascension, onward to commercial service, now scheduled in January 1987.

The year 1985 was eventful and dynamic for this impressive addition to the nation's nuclear power base and to New YorkState's energy supply.

One ofthe most encouraging developments was a report with strong words ofrecommenda-tion to the NRC from the AdvisoryCommittee on Reactor Safeguards (ACRS) to allow Nine Mile Two to be granted a license to operate up to full power after completion and testing. In its report followinga detailed technical inspection ofthe project, the Committee cited a "clearly evident dedication to both quality and the assurance of quality"and added that "there is a reasonable basis for confidence that the quality ofthe plant willbe adequate... UnitTwo can be operated without undue risk to the health and safety ofthe public," the Committee concluded. The ACRS report willhave a direct bearing upon the NRC's final decision to issue the operating license re-quired prior to the fuel load, currently scheduled for late spring 1986.

The year 1985 was significant at Nine MileTwo formeeting a series ofimportant testing mile-stones. These included the integrated systems flush and reactor pressure-vessel hydrostatic testing which were completed successfully and enabled our project team to continue to guide the unit toward operational readiness.

Remaining tasks at the site, after fuel loading, involve nuclear heatup and testing ofthe reactor and its various components, a sequence of control-room tests and related operating inspec-tions. Aftera series ofpre-arranged, automatic outages and briefshutdowns, further checks and "fine-tuning,"itis slated fora 100-hour run at fullpower in preparation forcommercial service.

In its lifetime, Nine MileTwo should produce electricity equal to more than 400 millionbarrels ofoil, amounting to billions ofdollars in fuel savings.

Niagara Mohawk is managing agent and the major partner in the construction, operation and ownership ofNine MileTwo. The Company's por-tion is 41 percent, with Long Island Lighting Co.

and New YorkState Electric and Gas Corp. hold-ing ownership at 18% each; Rochester Gas and Electric Corp. at 14% and Central Hudson Gas and Electric Corp. at 9%.

More detailed summaries ofNine MileTwo's cost, financing and regulatory developments are presented in the Management Discussion and Analysis on page 21 and in Note 10 to financial, statements on page 33.

Nine MileOne consistent achiever Our Nine MilePoint Nuclear UnitOne distin-guished itselfagain foranother year-the 16th

-forthe 610,000-kilowatt nuclear pioneer-as it

entered the second halfofthe decade ofthe 1980 s.

During 1985, Nine MileOne attained 92 per-cent production capacity its highest ever-and generated 4.9 billionkilowatt-hours, operating more than 96 percent ofthe entire year. In terms ofavailability, this performance ranks the plant as number one ofall nuclear stations ofits type (boilingwater reactor) in the world Compared with fossil-fired stations, nuclear-generated power from Nine MileOne, which went on line in 1969 at an original cost of 4158 million, amounted to a savings to consumers ofsome 4226 millionforoil-firedgeneration, or 463 mil-lion for coal-fired generation in 1985 alone.

Early in 1985, the Nine Milesite became the firstin the U.S. to win approval by the Federal Emergency Management Agency (FEMA)forboth its emergency plan and prompt notification sys-tem. These were again subjected to rigorous test-ing in a formal emergency exercise at Nine Mile One in late 1985 with federal, state and local gov-ernment agencies taking part. The day-long drill, with realism and urgency in a scenario ofsimu-lated mishaps, earned expressions ofapproval and enthusiastic praise from representatives of FEMAand the Nuclear Regulatory Commission forthe utility,state and county performances.

Emergency plans forsimilar, agency-mandated exercises and drills have been prepared forNine MileTwo.

Also ofpositive note at Nine MileOne during the year was a required Systematic Assessment ofLicensee Performance a rigidinspection by NRC experts performed annually at the Unit. Nine MileOne achieved the highest grades possible in Dispatchers at consoles in Power Control Center supervise energy supply and delivery operations to provide lowest-cost electricity for Niagara Mohawk customers.

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seven ofthe eight categories reported (a satisfac-tory middle grade was granted forthe eighth category).

Those who come first Our "ThinkCustomer" campaign, initiated in late 1984, was stepped up in 1985 to instill further employee appreciation ofthe need to maintain the highest quality service to custom-ers everywhere in our business.

"ThinkCustomer" was visiblyprominent throughout the Company and its workforce dur-ing the year. Posters in workplaces, employee seminars and workshops, periodic newsletters, video reminders and other communications and training activities were all part ofthis enthusias-tic, concerted effortto build greater customer rapport.

Asystem-wide survey ofconsumers by a pro-fessional opinion research firmindicates "Think Customer" is more than a slogan and is achiev-ing an impact where itcounts most. Our overall "favorabilityrating," comprised ofattitude in-dicators we have tracked since 1980, rose significantly in 1985.

Exemplifying our "ThinkCustomer" year was the deployment of450 Niagara Mohawk people, including line crews and various support per-sonnel, to assist other utilities in restoring power to the many thousands offamilies and storm victims ofHurricane Gloria in October.

Niagara Mohawk crews dispatched to cities and communities throughout the Northeast, includ-ing Long Island, Connecticut and Massa-chusetts, labored around the clock for nearly two weeks under extreme damage conditions to per-form repairs. Their fine performance brought many warm letters ofgratitude and praise to Niagara Mohawk from hurricane victims and generated appreciative editorial coverage by the news media in communities hitby the storm.

"ThinkCustomer" services Aprime example ofNiagara Mohawk's efforts on behalf ofour customers is the Care 8t Share Energy Fund, which provides assistance to elderly, disabled or handicapped residents by Nine Mile Point Nuclear Unit Two dominates southeast-ern Lake Ontario shoreline in aerial scene of the nearly completed 1.08-million kilowatt installation. At right is Nine Mile Point Unit One, in service since 1969, which set a world's operation record in 1985.

Large turbine assemblies receive final installation ad-justments at Nine Mile Point Nuclear Unit Two project.

High-pressure steam from reactor willactivate turbines, on same shaft as unit's generator, to produce power.

helping to pay fortheir basic energy require-ments.

Care 8r. Share is conducted by Niagara Mohawk in close cooperation with the American Red Cross, which administers the program. Since its inception in 1984, Niagara Mohawk consumers and employees have contributed S240,000, with the Company's stockholders adding $ 1 for each S2 contributed. In addition, S250,000 was donated by our stockholders as seed money to start the fund. The fund's success continues to grow. In 1985 alone, the funds donated to Care &

Share helped some 1,500 needy families pay their energy bills (regardless ofenergy type used), to repair home heating equipment and in-stall weatherization materials. In 1985, Niagara Mohawk received special recognition from the White House for Care R Share as part ofthe Pres-ident's plan to promote involvement by business in community projects. Early in 1986, the Company began offering an employee payroll deduction plan forCare 8r Share.

Special Olympics bring out the best Perhaps the most memorable occasion involving Niagara Mohawk and its'employees taking the lead in a worthy cause was the Summer Games of the 1985 N.Y. State Special Olympics forthe handicapped. Sponsored in part by NMand manned by many Company volunteers, the Games attracted more than 1,000 competitors in three days ofevents at the Syracuse University Carrier Dome and New YorkState Fairgrounds.

Lending our "eyes and ears" Our Radio Watch community service was intro-duced in 1985 to assist police and public safety agencies in emergencies. Personnel operating radio-equipped Company cars and trucks are now providing extra "eyes and ears" on streets served by Niagara Mohawk. Since the start of Radio Watch, a number ofincidents were re-ported by alert NMpersonnel who spotted crimes in progress, suspicious activities, accidents and other emergency situations.

ChildWatch Niagara Mohawk is among many utilities par-ticipating in the coast-to-coast National Child Watch Campaign to help locate missing children and help prevent abductions. In 1985, the Com-pany started mailing leaflets with customer bills featuring photos and descriptions ofabducted children with a toll-free telephone number. NMis working with the U.S. Justice Department, Na-tional Center forExploited Children and other organizations and agencies in this program.

sumer issues. Recommendations from the Council have been helpful to us in creating assis-tance programs forconsumers.

Energy Conservation representative presents package of free lightbulbs to one of 13,000 Niagara Mohawk cus-tomers who received home energy surveys in 1985. Bulbs were given as part of survey promotion campaign.

Involvingconsumers The Consumer AdvisoryCouncil on Energy Affairsbegins its tenth year ofactivityin 1986.

Formed to maintain an open and candid flowof information and attitudes from the customer' side ofthe business, the Council performs a unique function by tracking what the public thinks ofNiagara Mohawk so we can effectively respond and adjust to consumer needs.

The Council's 24 members represent all walks oflifeand meet monthly with NMexecutives for frank discussions ofenergy policies and con-Direct services forconsumers Many other services and support programs were created or continued in 1985, as follows:

~ Savingpower energy conservation surveys of 13,000 consumers'omes, including home energy inspections, withfinancial assistance and low-interest loans from lending institu-tions for qualified applicants to make energy conservation improvements.

~ Energy Conservation Bank forthe needy and elderly in cooperation with county offices of the aging and the State Energy Office.

~ Home Energy Level Payment Plan-helps con-sumers manage winter energy costs. Some 125,000 customers now have their annual energy costs divided into 12 level payments.

~ Deferred Payment Plan for customers with severe financial hardships. Itprovides for a combination ofdown payments and as many as 48 monthly payments to clear remaining balance.

~ Quarterly Payment Plan for Senior Citizens gives customers 62 years or older, with annual service charges ofup to $150, the option of paying their utilitybills on a quarterly basis.

~ Community Conservation Grant Program provides direct funding forinstallation of ceiling/attic insulation and furnace replace-ment and repairs in single-family homes withincertain income guidelines, in coopera-tion with county affices forthe aging.

MONTHLYRESIDENTIALELECTRIC COST FOR 500 KILOWATT-HOURS New YorkCity Philadejp~ia, PA NYStateAvera e notlncludin NM'ewark NJ Hartford, CT Boston MA Cleveland OH Los Angeles CA National Avera e-Portland, ME Nia ara Mohawk Includes fuel and PASNY credit adjustment as appllcablo.

'NM Rate Department as of 12/1/85 "E.E I. Report with rates effective 7/I/85 Allothors supplied by utilitywhich serves city, with rstos and fuol effective 12/I/85

$70.60

$59.75

$58.51

$54.12

$48.68

$48.33

$45.76

$41.36

$40.98

$40.04

$36.27

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" I' 102 Maintaining economic vitality Vigorous economic growth, stemming from a thrivingindustrial and business base, is a top goal ofupstate New Yorkcommunities and-as the utilityserving them energy Niagara Mohawk as well. In 1985, the Company under-took a number ofinnovative economic develop-ment programs to generate such growth.

These include a "New Directions" national ad-vertising campaign to form working partnerships with state and other public and private business associations representing large constituencies.

The over-riding purpose is to attract new busi-ness and industry to the upstate region and offer assistance with expansion plans.

Closely allied with these programs is an ongo-ing project started in 1985 to match emerging new technologies withindustrial customers on our lines. Working in close cooperation with Syracuse University's Institute forEnergy Re-search, jointresearch teams surveyed 1,350 in-dustrial customers in the service area during the year. The intent is to help industries improve productivity, reduce energy usage and cut costs through the possible application ofsuch con-cepts as plasma and laser processing, electron-beam and ultraviolet curing and robotics. Such measures may help certain customers improve r'I.s

<<.'assengers board train in Niagara Frontier Transit Au-thority's new rapid transit system, a nearly $500-million addition to Buffalo scheduled to be fullyoperational in 1986. In lower photo, Armyvehicles bound for Europe are loaded on ocean-going freighter docked at Oswego, a strategic international port in the heart of Niagara Mohawk's service area.

1

their profitabilityand competitiveness.

Once several successful case histories are established through high-tech demonstrations withthese customers, Niagara Mohawk willshare the in-formation so other industries can implement similar modifications and enjoy the resulting benefits.

Asurvey in late 1985 by Niagara Mohawk of nine major U.S. cities across the nation showed that NMindustrial customers pay considerably less forelectricity per month than the average 412,415 versus 414,716, for200,000 kilowatt-hours. This positive point is em-phasized in all our economic development pro-motion and advertising work.

Technicians inspect instruments in watershed monitor-ing research project at Salmon River hydro station, Os-wego County. Data is automatically transmitted via satel-lite and fiber optics to new Power Control Center in Syra-cuse. Two-year study seeks to learn how weather data can be used in coordination of hydro and thermal power plants.

Monochromatic light is used to measure flatness (to within 40-millionths of one inch) of seal ring for reactor coolant pump at Nine Mile Point Nuclear Unit One. Re-sults of five-year seal-technology research by Niagara Mohawk are expected to reduce costs and further refine plant performance.

The "cutting edge" research Research efforts by Niagara Mohawk were espe-ciallyproductive and promising during the year.

Anew emphasis was given to the clean use of coal as we look down the road at generation needs.

Highest prioritywas placed upon development ofthe integrated gasification combined-cycle (IGCC) system as a most promising clean-coal option featuring high-efficiency and extremely lowsulfur-emission characteristics. In this latest power-generation technology, coal is first converted to a raw, virtuallysulfur-free gas. This pure gas is burned in a turbine to generate elec-tricity,and the exhaust heat is captured in a boiler to create steam. The high-pressure steam is then employed in a conventional turbine-generator to produce additional electric power in this combined cycle concept. In 1985, Niagara Mohawk started appraising a proposal foran IGCC system forour Albany Steam Station, with a 200,000-kilowatt demonstration prototype possible in the early 1990s.

Another research project proposal submitted during the year was for design, construction and demonstration by General Electric Company ofa prototype integrated-gasification, steam-injected gas turbine at our DunkirkSteam Station. Such a concept, somewhat similar to IGCC, offers utilities a new coal-to-electricity option with all the advantages ofIGCC but withflexibilityto add smaller lower-cost generation units in the 50,000 to 100,000-kilowatt range as load growth requires. We have completed initialplanning for this project and the U.S. Department ofEnergy is reviewing the proposal. The demonstration is planned forthe late 1980s.

Marked advances and many" firsts" in gas re-search were also noted in 1985. Aggressive ef-forts are under way to find new, low-cost gas energy equipment and services, improved gas distribution and energy management systems and to insure long-term supplies ofnatural gas at S

marketable prices. Compressed natural gas re-search demonstrations are showing increasing promise and potential for CNG as a clean, plenti-fuland comparatively low-cost fuel forvehicles.

Aunique CNG marketing demonstration was un-dertaken in 1985 to test this promise. (See page 14). NMresearchers are also assessing the economic and technical potential ofdairy biomass cogeneration produced by waste at the many hundreds ofdairy farms in our service area.

Niagara Mohawk has received recognition nationally forits pioneering studies ofearth-coupled heat pumps, which apply the earth' stable temperature to draw heat from in winter, and forcooling in the summer. Earth-coupled heat pumps offer a 50 percent year-round energy

savings and a similar energy demand reduction, compared with conventional heating and air conditioning. So effective has this concept proved that we undertook marketing initiatives forthe earth-coupled heat pump during the year.

Additional RRD strides by NMindependently and with others (including the nationwide Elec-tric Power Research Institute, and Gas Research Institute) followin brief:

~ Acidrain involvement by NMin five continu-ing studies related to acid precipitation, primarilyin the Adirondacks.

~ Robotics prototypes under study and test for possible use making visual inspections of transmission facilities and performing tasks at Nine MilePoint nuclear facilities.

~ Satellites and fiber optics now serving in Energy Management System, remote wa-tershed monitoring and other varied com-munications tasks.

~ Wind energy-50 square miles ofwind-turbine site areas were identified in NMservice terri-tory during the year withpotential fortotal bulk-wind power generation of 100,000 kilowatts.

~ Indoor air qualityjointproject by NMwith N.Y. State Energy Research and Development Authoritycompleted in 1985 to investigate in-door air pollution sources.

~ Power "Donut"transmission line monitor-ing system for reduced costs and improved ef-ficiency, invented by NMresearchers and about to be marketed commercially, won both federal and state awards forenergy innovation in 1985.

Research efforts in 1985 alone produced an estimated savings ofsome 430.75 millionin avoided costs forconsumers and improved Com-pany operations, while energy conservation re-search projects saved consumers an additional 47.75 millionin 1985.

Corporate strategic planning Management continues to examine the future through a carefully structured strategic planning process. The process appraises the dynamics of situations facing the business and modifies our Corporate Strategic Plan to provide the direction needed to effectively employ resources. Direc-tion is set forth in our corporate mission state-ment (see inside front cover) and corporate ob-jectives. Strategies define our courses of action how to accomplish these objectives.

During 1985, a survey was conducted to de-termine how the beliefs and expectations ofall

employees fitwiththese objectives and strategies. Results are being integrated into the 1986 update ofthe Corporate Strategic Plan.

The Plan has proved to be a valuable com-munications vehicle both withinthe Company and with outside constituencies. Itemphasizes the long term over the short and provides a common understanding ofwhat the Company wants to happen and how itintends to achieve its objectives.

Working together on strategy development has created a firmcommitment to increased man-agement teamwork, a positive benefit ofour Corporate Strategic Plan.

Managing our hydro resources In planning and managing Niagara Mohawk waterpower resources, 16 hydro projects are slated foreither construction, renovation, or expansion on Northern New Yorkrivers and streams. Together, they willboost the Com'-

pany's hydro output by 113,000 kilowatts.

We are also negotiating contracts withvarious independent small hydro operators in our serv-ice area foran additional 198,800 kilowatts.

Following a 1984 precedent, Niagara Mohawk began seeking "outside" proposals from compet-ing energy developers late in 1985 to construct and operate a hydro project at Union Falls on the Saranac River. Power generated at the proposed 2,600-kilowatt installation willbe sold exclu-sively to NMunder this plan, which entails total renovation ofa hydro plant retired in the 1960s.

The new site is slated for 1988 completion.

Union Falls is the second hydro project in which Niagara Mohawk has sought proposals from private concerns forthe independent con-struction and long-term operation and mainte-nance ofa power station, as this arrangement avoids costs and eliminates development expen-ditures forthe Company. The firstcontract was for a 15,500-kilowatt plant at Glen Park on the Black River. That project is progressing toward its targeted in-service date of 1986 and, pending Federal Energy Regulatory Commission approval, may be upscaled to 29,000 kilowatts.

Another 1985 hydro highlight was observed as the 74,600-kilowatt Rankine Station noted its 80th year ofoperation. This energy pioneer, owned by our subsidiary Canadian Niagara

Power Company, Ltd., is a working landmark above the Horseshoe Falls at Niagara Falls, Ontario.

Fossil-fired station improvements Many modifications were carried out at the Com-pany's fossil-fired stations, reducing costs, up-grading operating efficiencies and improving the environment.

Early in 1986, the boilers ofthe oil-fired Oswego Steam Station units five and six were equipped withigniters to burn natural gas in-stead ofoilat times ofgeneration start-up. This required construction of3.5 miles of 16-inch natural gas pipe line to the units from a gas main south ofOswego including crossing under the bed ofthe Oswego River. The new modification allows the units to be removed from service at night, when electrical demands are low, and brought back on line quickly and economically in the morning. Clean stack emissions are also a feature ofthis project.

Projects reflecting Niagara Mohawk's com-mitment to protection ofwater resources and costing a total of 417 millionwere completed in t

I g+)b l Boiler operation is inspected at Huntley Steam Station near Buffalo in research demonstration that injects lime-stone "fluxingagent" into boiler to permit burning high-fusion coal. Project promises to reduce fuel costs.

Autumn view of Sherman Island Hydro Station near Glens Falls shows curved cofferdam, left, temporarily installed during the year to allow drainage and repairs to 63-year-old concrete dam at 28,800-kilowatt Hudson River site.

Project is among many hydro renovation and mainte-nance activities at NMwaterpower sites.

ELECTRICITYGENERATED ANDPURCHASED BYTYPEOF FUEL,1985 Hydro 29/o Various sources 26%

Coal 19/o Nuclear 15%

Oil 7%

Natural gas 4%

1985 at our Huntley and Albany steam stations.

Both plants were equipped withwastewater treatment facilities, including chemical treat-ment operations. In addition, at Huntley a new groundwater containment and collection system intercepts and purifies all rainwater which per-colates through the plant's coal pile.

In 1985, we embarked with the Electrical Power Research Institute and Empire State Elec-tricEnergy Research Corporation on in-depth investigations ofour fossil-fired units with the goal ofextending their service lives well into the 21st century as much as 20 years beyond their normal 40-year design lifetimes. Using modern metallurgical analysis techniques, we have al-ready determined that this is possible with an older Huntley unit, employing modest upgrading and modernization methods. We plan to perform similar investigations ofall active fossil-fired units and implement a coordinated life-extension program forthem in forthcoming years.

Newest power ties Electricityfrom Nine MilePoint Nuclear Unit Two willbe delivered into the cross-state energy system via two major new 345,000-volt transmis-sion lines. The firstwas completed in 1985 and extends 10 miles southeast to our Volney Sub-station. The second line, planned forspring 1986 completion, willrun from Volney some 65 miles southeast to Marcy Substation near Utica In other transmission activity, existing double-circuit 115,000-volt lines were removed and reconstructed from Massena to Colton in Northern New York, and a 115,000-volt line was constructed from the Olean area to Ellicottville in Western New York.

Outlook for gas continues to brighten For Niagara Mohawk and our natural gas con-sumers the year was a good one. Partial decon-trol ofwholesale gas prices which became effec-13

tive in January 1985 resulted in lower prices and a continuation ofthe favorable supply picture.

During 1985 new regulatory developments oc-curred at the Federal level which may lead to "open" transportation ofthe nation's pipeline system. Niagara Mohawk willtake advantage of any gas supply opportunities that these new regulations may provide to the benefit ofour customers.

Overall, 1985 gas sales fell by six percent, but the decline was due primarilyto a swing from cooler-than-normal weather in 1984 to warmer-than-normal weather in 1985. On a weather-adjusted basis, residential and commercial sales were up four percent from '84 levels.

Industrial sales were strong early in 1985, but were affected by a 20-percent decline in residual oilprices in the spring. Nevertheless, the Com-pany managed to retain 85 percent ofthe alter-nate fuel-sensitive market through the remain-der of 1985.

Looking ahead, preparations fortaking advan-tage ofthe more favorable outlook forgas sales were stepped up in 1985. We have greater oppor-tunityforgrowth than most other major utilities and are looking to expand our marketing efforts to increase our market share.

In related gas activities, our wholesale supplier, Consolidated Gas Transmission Corpo-ration, awarded Niagara Mohawk a new gas-

. marketing technology grant in 1985. The funds willbe used to build a compressed natural gas refueling station foruse by the public and the Company. The fillingstation began supplying Company CNG-fueled trucks and cars in late 0

P SC CANADIAN NIAGARAPOWER tl. LAWIIENCE '@"'POWER COMPN AN%+

Corporate logos identify Niagara Mohawk subsidiaries.

1985, with service to commercial fleet vehicles scheduled in spring 1986.

Hydra-Co growth continues Hydra-Co Enterprises, Inc., a whollyowned, in-dependent subsidiary ofNiagara Mohawk, signed agreements in 1985 tojointlydevelop one cogeneration project and six small-power instal-lations with a combined capacity of 109,300 kilowatts in New Yorkand four other states, in addition to earlier projects.

Anatural gas facilityand hydro project are planned in N.Y. State, while the others involve a geothermal site in Nevada, a wood-fueled genera-W Mobile flat-bed rig is used for erecting transmission line extend-ing from Nine Mile Point Nuclear Unit Two into main power system, while line mechanics, opposite page, attach insulators to the new 345,000-volt circuits. Project was completed in 1985.

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systems to gauge efficiency, productivity, quality and overall effectiveness ofany department seek-ing improvements.

Our CPS approach is a departure from the usu-allyrigid"efficiency"monitoring functions found in some industries and institutions.

Emphasis is placed on the human and positive side upon creative innovation, quality oflife, motivation and the employee's contribution to the Company as a person.

Among successes already noted by CPS is an employee involvement program established withina key department in Syracuse that wished to refine its productivity and creativity. Several "performance action" teams were formed from withinthe department's ranks and met periodi-cally at discussion sessions. They soon iden-tifiedbarriers to creativity and then made spe-cificrecommendations that eliminated the ob-stacles in a short time. So favorable was the out-come ofthis program that CPS plans to intro-duce itto other interested departments through 1986.

The workforce The Company's workforce totalled 11,100 at the end of 1985. About 8,400 or 76 percent are-mem-bers of 12 locals ofthe International Brotherhood ofElectrical Workers (AFI CIO) consisting ofSystem Council U-11. Atwo-year collective bargaining agreement expires on May 31, 1986 and negotiations for a new agreement began early in 1986.

Savings Plan increasing More than 8,900 employees are enrolled in the Company's Employee Savings Fund Plans, 90 percent ofall those eligible. Atthe start of 1985, represented employees became eligible to take advantage ofInternal Revenue Code Section 401-k provisions permitting before-tax Plan con-tributions, to encourage saving to accomplish re-tirement and other long-range goals.

Stock program forour customers During the last 10 months of 1985, more than 7,500 customers purchased 374,000 shares of Company stock under the amended Dividend Reinvestment and Common Stock Purchase Plan. The Plan was amended to allow customers to buy stock from Niagara Mohawk foran invest-ment ofas littleas 425. The Plan provides cus-tomers and shareholders with a unique savings opportunity and has provided needed capital for the Company.

Niagara Mohawk is one ofthe nation's largest utilities and while our stock is held by people from every state, the largest number ofshares are owned by New YorkState residents. One out 16

ofevery four shareholders, or approximately 50,000, are also our customers. The new stock purchase plan allows us to "reach out" to cus-tomers in hopes they willbecome better in-formed about the challenges ofour business and take an extra interest in Niagara Mohawk.

Talking to investors Participation in the Investor tk Financial Relations Department's "Inthe Know"informa-tion program increased over 13 percent to 2900 participants during 1985, the result ofan active communications program tailored especially for investors. Moreover, approximately 1,500 people attended four regional stockholder meetings held withinour service territory. These sessions proved an effective way forour shareholders and Company officials to exchange ideas and infor-mation.

New Nuclear Training Center serves for instructing employees assigned to adjacent Nine MilePoint power plants and contains emergency operations facilities as well as laboratories and classrooms. Below, a licensed nuclear operator tests one of the full-sized replicas of Unit One and Unit Two control rooms in Center.

jIt fly jg I1 Events this year also included a number of meetings and discussions with members ofthe financial community-security analysts, stockbrokers and institutional investors. These opportunities allowed the Company to provide members ofthe investment community with the information they need to make informed decisions and recommendations about our securities.

Confidence in the Company continues to be shown by increased institutional ownership of our common stock, which rose from nine per-cent ofoutstanding shares in early 1983 to 25 percent during 1985. This has changed the mix ofcommon stockholders and provides a more balanced ownership base while stillmaintaining an ownership profile composed primarilyof small stockholders owning fewer than 500 shares.

Plans call forappraising our communication efforts with shareholders and the investment community as well. One such effortwillbe geared to shareholders whose stock is held by nominees. The Securities and Exchange Com-mission adopted a rule, effective January 1, 1986, requiring stockbrokers holding securities in street name forshareholders to disclose to the issuer (e.g. Niagara Mohawk) upon request, the names, addresses and number ofsecurities held, unless the shareholder specifically objects to the disclosure.

We hope our shareholders support our com-munications efforts and we encourage you to be-come a participant in the "Inthe Know"program by calling one ofthe toll-free numbers listed on the inside back cover, or by writingthe Investor R Financial Relations Department in Syracuse.

Dividend Reinvestment Plan revised Niagara Mohawk plans to continue the Com-pany's popular Dividend Reinvestment and Stock Purchase Plan despite expiration at the end of 1985 ofthe federal tax deferral advantage for reinvested dividends.

Atyear end 1985, approximately 77,000 ac-counts, representing 40 percent ofall stockhold-ers, were enrolled in the Plan. This participation provided over 465.7 millionin new equity in 1985, including 416 millionin voluntary cash contributions. Our dividend remains competitive in the marketplace and reinvesting dividends provides an easy and inexpensive means ofin-creasing investment in Niagara Mohawk.

Aprospectus describing the Plan and an authorization form tojoin may be obtained by writingto Niagara Mohawk Power Corporation, Dividend Reinvestment Plan, P.O. Box 7058, Syracuse, New York 13261.

MARKETPRICE OF COMMON STOCK AND RELATEDSTOCKHOLDER MATTERS 1985 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter 1984 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter Dividend paid Price range per share High Low

$.50

$18

$ 16e/e

.52 20e/e 17e/e

.52 21 /e 17/2

.52

- 21 17e/e

$2.06

$.48

$ 16e/e

$12

.50 14e/e 12

.50 15/4 13'/z

.50 17e/4 15

$1.98 Preferred and common stock div-idends were paid on March 31, June 30, September 30 and December 31. During recent years certain percentages of the dividends paid on the common stock were not subject to federal income tax as ordinary income to the recipient, but constituted a return of capital reducing The Company's common stock and cer-tain of its preferred series are listed on the New York Stock Exchange.

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

The ticker symbol is "NMK".

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

the tax basis of the applicable shares.

However, the Company estimates that none of the 1985 common or preferred stock dividends will constitute a return of capital and therefore they are taxable as ordinary income.

While the Company intends to con-tinue the practice of paying cash div-idends quarterly, declarations of future dividends are necessarily dependent upon future earnings, financial re-quirements and other factors, including restrictions in governing instruments.

The holders of Common Stock are en-titled to one vote per share and may cumulate their votes for the election of Directors. Whenever dividends on Pre-ferred Stock are in default in an amount equivalent to four full quarterly div-idends and thereafter until all dividends thereon are paid or declared and set aside for payment, the holders of such stock can elect a majority of the Board of Directors. Whenever dividends on any Preference Stock are in default in an amount equivalent to six full quar-terly dividends and thereafter until all dividends thereon are paid or declared and set apart for payment, the holders of such stock can elect two members to the Board of Directors. No dividends on Preferred Stock are now in arrears and no Preference Stock is now outstand-ing.

Upon any dissolution, liquidation or winding up of the Company's business, the holders of Common Stock are enti-tled to receive pro rata all of the Com-pany's assets remaining and available for distribution after the full amounts to which holders of Preferred and Prefer-ence Stock are entitled have been satis-fied.

The indenture securing the Com-pany's mortgage debt provides that surplus shall be reserved and held un-available for the payment of dividends on Common Stock to the extent that expenditures for maintenance and re-pairs plus provisions for depreciation do not equal 2.25/o of depreciable property as defined. Such provisions have never restricted the Company's surplus.

At year end, about 191,000 stockhold-ers owned common shares of Niagara Mohawk and about 8,600 held pre-ferred. The chart below summarizes common stockholder ownership by size of holding:

Size of holding Total Total shares (Shares) stockholders held 1 to 99 54,059 1,748,796 100 to 999 126,969 31,246,560 1,000 or more 9,749 93,932,984 190,777 126,928,340 MANAGEMENT'S DISCUSSION AND ANALYSISOF FINANCIALCONDITION AND RESULTS OF OPERATIONS Results of operations.

For 1985, earn-ings per share increased 1.4%%d to $2.88 against $2.84 for 1984. The 1985 earn-ings represent increases of 4.0%%d and 9.1/o over 1983 and 1982 earnings per

share, respectively, even though the number'of shares outstanding grew steadily over the three-year period.

The increase in the Company's earn-ings per share for 1985 over 1984 re-sulted from improved margins on sales despite a decline in electric and gas sales and revenues and a decrease in

$25.8 million also improved earnings but was partially offset by a $38.6 million increase in interest and preferred dividend requirements.

Further, a

$32.5 million refund to customers ordered by the New York State Public Service Commission (PSC) resulted in $.05 and $.10 per share charges against income in 1985 and 1984, respectively (see Note 11 of Notes EARNED RATE OF RETURN ON COMMON EQUITY 14 7o/

15 0/o 15 IP/o 14.9/o the Company's authorized return on 135/

to Consolidated Financial Statements).

The Company achieved a

15.0%%d rate of return on common equity in 1985 as compared with 14.9/o in 1984 and 15.0/0 in 1983. The PSC-approved rate of return on equity is currently 15.5/o as compared to 16/o authorized at December 31, 1984 and 15.4/o at December 31, 1983.

The followingdiscussion and analysis highlights items having a significant ef-fect on operations during the three-year period ended December 31, 1985, but may not be indicative of future opera-common equity. The decrease in elec-tric revenues is principally due to de-creased sales to other electric systems, while gas revenues decreased as a re-sult of lower sales volume attributable to milder weather and competition with oil. Other income, representing interest on Nine Mile Unit No. 2 construction advances made on behalf of the Long Island Lighting Company (LILCO) and an increase in Allowance for Funds Used During Construction (AFC) of 18 1981 1982 1983 1984 1985 tions or earnings.

It should be read in conjunction with the Notes to Consoli-dated Financial Statements and other firiancial and statistical information ap-pearing elsewhere in this report.

Electric revenues increased

$235.7 million or 12.7'/o over the three-year period despite a dramatic reversal in sales to other electric systems during 1985.

This increase is largely attributable to increased base rates and increased sales to ultimate consumers,

Electric revenues Increase (decrease) from prioryear In millions ofdollars 1985 1984 1983 Total

~

I offset somewhat by decreased revenues attributable to fuel and purchased power cost recoveries as indicated in the table below:

32,890 32 640 34,732 37,066 35,296 ELECTRIC SALES Millionsof Kw.-hrs, Increase in base rates

. $ 659 Fuel and purchased power cost revenues...

(4.5)

Sales to ultimate consumers...............

11.9 Sales to other electric systems.............

(107.9)

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

(3.5)

$ (38.1)

$ 69.1

$ 68.5

$203.5 (86.3) 2.6 (88.2) 56.1 21.0 89.0 68.7 63.7 24.5 3.1 7.3 6.9

$110.7

$163.1

$235.7 Total

.. 100.ty/o (1.8)%

(4.8)%

5.5o/o 6.P/o 8.8/o 6.4%

Gas revenues increased

$65.4 million or 12.3% over the three-year period. As shown by the table below, over half of this rise is attributable to higher costs for purchased gas which were recovered from customers during 1983 through the purchased gas adjustment clause, offset by decreases in 1984 and 1985. The re-mainder of the increase is attributable primarily to higher base rates.

Increase (decrease) from prioryear In millions ofdollars Gas revenues 1984 1983 Total 1985 Electric kilowatt-hour sales were 35.3 billion in 1985, a decrease of 4.8% from 1984, reflecting the effects of increased competition which has reduced the Com-pany's effectiveness in the resale market resulting in decreased sales to other electric systems (see Electric and Gas Statistics Electric Sales appearing on page 40). Details of the changes in electric revenues and kilowatt-hour sales by customer group are highlighted in the table below:

1985

% Increase (decrease) from prioryear

'/o of Electric 1985 1984 1983 Class of service Revenues Revenues Sales Revenues Sales Revenues Sales Residential..........

30.9o/o 6.6o/o 0.4%

4.1%

4.3o/o 8.2/o 1.2/o Commercial..........

33.8 5.0 1.7 2.4 3.7 4.8 0.6 Industrial............

20.9 (0.4)

(2.8)

(0.5) 3.1 3.7 4.8 Municipal service.....

1.8 3.7 (1.6) 3.8 (2.4) 4.5 (2.3)

Total to ultimate consumers.........

87.4 4.2 (0.4) 2.3 3.6 5.7 2.3 Other electric systems 9.4 (35.5)

(24.1) 29.2 23.1 37.1 34.3 Miscellaneous.......

3.2 (5.0)

4.5

12.0 1S61 1982 1983 1984 1985 GAS SALES Millioosof dekatherrha 109.6 109.7 103.2 115.0 108.4 1981 1S82 1983 1984 1985 TOTALELECTRIC ANDGAS OPERATING REVENUES Milllonsofdollars 0

2,695 Increase inbase rates........

Purchased gas cost increases Gas sales S

8.2 8.7

$ 10.3 (21.6)

(23.3) 79.2 (39.2) 57.1 (14.0)

S (52.6)

$ 42.5

$ 75.5 S 27.2 34.3 3.9

$ 65.4 Residential Commercial..

Industrial....

49.3o/o (5.9)%

(4.4)%

3.1%

5.7o/o 14.9o/o (8.1)%

24.7 (6.2)

(3.2) 1.0 3.6 13.7 (6.1) 22.3 (14.6)

(10.8) 21.1 27.3 14.6 (1.1)

Total to ultimate consumers.........

96.3 (8.1)

(6.0) 6.5 10.7 14.5 (5.9)

Other gas systems....

3.1 (5.2) 1.6 24.9 32.0 2.4 (8.7)

Miscellaneous.......

0.6 (11.5)

8.7

14.2 Total

.. 100.0o/o (8.1)%

(5.7)%

7.(P/o 1 1.4%

1 4.P/o (6.0)%

Gas sales were 108.4 million dekatherms in 1985, a 5.7% decrease from 1984 (see Electric and Gas Statistics-Gas Sales appearing on page 40). The decrease for 1985 reflects decreased sales in all classes of service, particularly in the industrial class where competition with oil resulted in a 10.8% decrease in sales. Milder weather led to decreased sales in the residential and commercial classes. Changes in gas revenues and dekatherm sales by customer group are detailed in the table below:

1985

% Increase (decrease) from prioryear

%of Gas 1985 1984 1983 Class of service Revenues Revenues Sales Revenues Sales Revenues Sales 1981 1982 1983 1984 1985 In summary, total operating revenues increased

$301.1 million, or 12.6% over the three-year period.

On March 14, 1985, the PSC approved rate increases to provide the Company additional annual revenues of

$49,312,000 (2.6%) for electric and

$8,826,000 (1.3%) for natural gas. The rates are based on a 15.5% return on common equity and provide for the cur-rent recovery of finance charges accru-ing on $320 million of Construction Work in Progress (CWIP) associated with the Nine Mile Point Nuclear Station Unit No. 2. These new rates became ef-fective March 18, 1985 and represent 47% of the rate relief requested by the 19

Company. In March 1984, the PSC had approved rate increases providing addi-tional annual revenues of $86,350,000 (4.9%) for electric and $9,144,000 (1.4%)

for natural gas.

Further rate action, initiated in April 1985, presently seeks an annual electric rate increase of $156.7 million (8.2%),

including $91.6 million related to the first year of a proposed three year rate phase-in of Nine Mile Point Nuclear Sta-tion Unit No. 2. In December 1985, PSC Administrative Law Judges recom-mended a rate increase of $39.6 million (2.1%) encompassing a phase-in plan for the Unit. The Company and other parties have filed exceptions to many of the Judges'ecommendations.

While a formal opinion is expected in March 1986, the PSC tentatively decided at re-cent public meetings that an additional amount of GWIP related to the Unit would be allowed in rates.

Operating expenses of the Unit, if any, would be subject to deferral accounting proce-dures and not be considered in rates prior to April 1987. The methodology to be utilized in the rate implementation of the phase-in plan for the Unit was also approved and the length of the phase-in period was set at seven years, with the possibility of a reduction to five years if the settlement offer is approved. In ad-dition, a return on common equity of 13.5% will be authorized for the rate year ending March 1987. This reduction in the authorized return on common equity, when taken by itself, would be expected to result in a downward pres-sure on earnings.

In 1985, electric fuel and purchased power costs decreased 11.1% to $759 million from $853 million in 1984 and

$883 million in 1983. This decrease is the result of a $96.9 million decrease in actual fuel and purchased power costs incurred during the year, partially offset by a $2.6 million net increase in costs deferred and recovered through the op-eration of the fuel adjustment clause.

Fuel costs at the Company's generating stations decreased

$83.5 million. Re-duced demand and increased low cost generation from the Nine Mile Point Nuclear Station Unit No.

1 enabled the Company to reduce higher cost fossil fuel generation by 13.3% and related fuel costs by 20.2%. Purchased power decreased

$13.4 million as a result of a 2.8% decrease in kilowatt-hour pur-chases and a slight decrease in the av-erage cost per kilowatt purchased (see Electric and Gas Statistics Electricity Generated and Purchased appearing on Page 40).

The total cost of gas purchased de-creased 9.1% in 1985, after having in-creased 5% in 1984 and 15% in 1983.

The decrease for 1985 is the result of a 2.2% decrease in dekatherms pur-chased to meet customer demand, combined with lower rates charged by the Company's supplier and an increase in amounts refunded by the supplier.

The Company's net cost per dekatherm purchased decreased to $3.68 in 1985 from $3.96 in 1984 and $4.06 in 1983.

Through the energy and purchased gas adjustment

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

The Company has implemented revisions to its fuel ad-justment clause consistent with PSC di-rectives, which essentially provide for partial pass-through of fuel and pur-chased power cost fluctuations from those forecast in rate proceedings, with the Company absorbing a specific por-tion of increases or retaining a portion of decreases to a maximum of $15 mil-lion per rate year (see Note 1 of Notes to Consolidated Financial Statements).

TOTALTAXES INCLUDING INCOMETAXES ssdeonsordoears 410 424 317 342 243 1981 1982 1983 1984 1985 Other operation and maintenance ex-"

'enses increased 2.8% in 1985, 7.0% in 1984, and 10.4% in 1983, primarily as a result of increases in wages and as-sociated benefits and higher costs charged by suppliers. Effective June 1, 1984, the Company entered into a two-year labor agreement providing for wage increases of 5.25% in the first year and 5.50% in the second year. The in-crease in other operation and mainte-nance expenses in 1984 also included costs relating to the refueling of Nine Mile Point Nuclear Station Unit No. 1 in the spring of 1984. The next refueling outage for this unit is scheduled for the Spring of 1986.

Depreciation and amortization ex-pense for 1985 increased 6.7% over 1984, principally from normal plant growth and increases in depreciation rates applied to certain classes of assets.

Total Federal and foreign income taxes for 1985 were comparable to 1984 since taxable income remained rela-tively constant.

The increase in taxes other than income taxes in the three year period is due principally to higher property taxes resulting from property additions.

AVERAGECOST OF ATON OF COAL ANDA BARRELOF OIL BURNED

$50.76

$50.88

$50.68

$49.16

$47.44 Ton of coal

$30.84

$30 67

'31 16

$33.35 Barrel of oil 1981 19S2 1983 1984 1985 494 6 508.3 353'6 364.0 462.4 326,1 376.4 258.1 Olher o 418.9 290.1 eratio 118.3 Mainte 128.8 ance 136.3 141.0 144 3 1981 1982 1983 1984 1985 MAINTENANCEANDOTHER OPERATION EXPENSE Millionsof dollars The $25.8 and $43.7 million increases in total AFC for 1985 and 1984, respec-tively, result from increased overall levels of plant construction, principally Nine Mile Point Nuclear Unit No. 2, de-spite lower AFC rates and the inclusion of $320 million of CWIP in rate base.

The increase in Other income and deductions other items (net) is primar-ily the result of the interest earned on the advances made for LILCO.

Interest expense and preferred stock dividend requirements increased as a result of new issuances to raise the cap-ital necessary to fund the Company's 20

" fconstruction program. The weighted average Iong-term debt interest rate and preferred dividend rate increased to 10.57/o and 9.79/o, respectively, from 10.23/o and 9.17%%d, respectively, in 1984.

The rate of inflation continued to be moderate in 1985. The Company is especially sensitive to inflation because of the large amount of capital it must raise to finance its construction pro-gram and because its prices are regu-lated using a rate base that reflects the historicai cost of utility plant. Inflation information in Note 13 of the Notes to Consolidated Financial Statements in-dicates the approximate effect of infla-tion of certain aspects of the Company's operations and financial position.

Financial Position, Liquidity and Capi-tal Resources.

During recent years in-ternal funds from operations have been insufficient to meet the Company's cap-ital requirements and therefore, large amounts of new capital from external sources have been necessary.

The Company's overall requirements consist of amounts for the Company's construction program, construction and other advances for LILCO, working capital needs, maturing debt issues and sinking fund provisions on outstanding debt and preferred stock. Sources and uses of funds to meet these require-ments during the past three years are reported in the Consolidated Statement of Changes in Financial Position on page 25.

The Company maintained continued financial strength during 1985. During the year, the market price for the Com-pany's common stock rose above the book value. In addition, credit ratings for first mortgage bonds, pollution con-trol bonds and preferred stock were up-graded by Moody's Investors Service in May 1985.

Capital structure at year-end was 45.8/o long-term debt, 11.5/o preferred stock and 42.7/o common equity, repre-senting a continued improvement in the common equity ratio. This position is indicative of the Company's corporate goal of maintaining a strong equity-based capitalization of 40-45/o common equity. However, the Company's cap-italization structure and earnings could be adversely impacted by accounting proposals currently under considera-tion by the Financial Accounting Stan-dards Board (see Note 10 of Notes to Consolidated Financial Statements).

Coverage of fixed charges decreased slightly to 3.07 at year-end, but re-mained at approximately the 3x level for the fourth consecutive year and close to the corporate goal of maintaining at least a 3.25 coverage ratio. The cover-age ratio, excluding AFC, decreased to 2.37 as financing costs not currently re-covered in rates continue to accumulate at an increasing rate as the Nine Mile Two project nears completion. AFC for the year 1985 amounted to 53.2%%d of the balance available for common stock as compared with 52.4'/o in 1984.

During 1985 funds needed to pay for the Company's overall construction re-quirements amounted to $583,804,000 and were provided 24.4'/o from internal sources and 75.6/o from external financ-ing.

Construction and other capital re-quirements.

During the period 1983-85, expenditures for construction and nu-clear fuel, including related AFC and overheads capitalized, have increased from $691.5 million to $769.8 million to

$771.1 million. The principal project presently under construction is the Nine Mile Point Nuclear Station Unit No. 2 (Unit) (see Note 10 of Notes to Consoli-dated Financial Statements).

The Com-pany is a 41/o owner and had invested about $1.9 billion, including AFC and overheads capitalized, in the project through December 31, 1985. Expendi-tures for construction of this plant have averaged approximately 51'/o of total construction requirements during the period 1983 to 1985. During 1985, the Company's 41%%d share of such expendi-tures was approximately 55'/o of its overall construction program require-ments.

Total capital requirements have also increased particularly in 1984 and 1985 as the Company made advances to the Unit on behalf of LILCO. As described below, however, a positive development occurred late in 1985.

Pursuant to an agreement entered into in August 1984, the Company had been advancing funds for LILCO's 18/o ownership share of the Unit.

By November 18, 1985, the Company had received all of the $250 million LILCO General and Refunding Bonds au-thorized by such agreement, which, to-gether with other unsecured obligations of LILCO reached a total in 1985 of

$306.4 million. Under an agreement with LILCO signed in December

1985, the Company received $144.9 million of proceeds from the sale of $150 million principal amount of pollution control bonds issued to finance a portion of LILCO's 18/o share of the pollution con-trol facilities at the Unit. For approxi-mately the next three years, the Com-CAPITALIZATIONRATIOS 46.4'/o Long-te 47.5O/o m debt 45.3/o 46.5'/o 45.8'/o 12.9o/o Prefer e 40.74/

Commo 11 5Jo d

41 fP/o equity 12.6'/o 42.1o/o 11.5/0 42,ty/o 11.5o/

42.7/o 1981 1982 1983 1984 1985 pany is guaranteeing LILCO's obliga-tion to repay the banks which provided letter of credit support for this financ-ing. The Company used $59.9 million of these funds to reduce LILCO obliga-tions referred to above and the balance will be applied to LILCO's remaining construction obligations for the Unit in-curred on or after November 18, 1985 up to a maximum of $85 million. Construc-tion cost requirements in excess of amounts provided under the LILCO agreements, which would total approx-imately $17 million under the present cost estimate and the currently scheduled commercial operation date, would continue to be an obligation of LILCO. Also, the Company is working with its investment bankers in the de-velopment of a plan to sell $140 million of the LILCO General and Refunding Bonds early in 1986, thereby further re-ducing its financial exposure to LILCO and its own need to sell securities (see Note 11 of Notes to Consolidated Fi-nancial Statements for a further discus-sion of the LILCO agreements).

The 1986 estimate for construction additions and nuclear fuel, including AFC and overheads capitalized, is ex-pected to be $746 million reflecting the current cost estimate for the Unit. Debt and preferred stock retirements and other requirements will add approxi-mately another

$ 174 million to the Company's capital requirements for a total of $920 million. This forecast of capital requirements, in particular as it relates to the AFC component, will be dependent on the rate decision to be rendered in March 1986 and the cost settlement agreement presently under consideration by the PSC.

On September 18, 1985, the Company and the other cotenants, together with the Staff of the PSC, filed a joint motion with the PSC seeking approval of a set-tlement agreement to dispose of the PSC's cost review proceeding regard-21

ing the Unit. Among other things, the proposed settlement caps the Unit's total recoverable cost at $4.45 billion with cotenant shareholders absorbing costs in excess of this amount and pro-vides that allowed amounts would be phased into each cotenant's rates on reasonable terms and income tax ben-efits associated with the disallowed costs would be reserved for sharehold-ers (see Note 10 of Notes to Consoli-dated Financial Statements).

Liquidityand resources.

During 1985, the Company raised approximately

$584,100,000 through external sources, consisting of $400,000,000 of debt,

$75,000,000 of preferred

stock,

$185,300,000 of common stock from the issuance of 10,079,366 shares through a combination of public sales and sales through its Dividend Reinvestment, Employee Savings Fund and Employee Stock Ownership Plans and net reduc-tions of $29,900,000 under intermediate term bank revolving credit obligations and $46,300,000 in short-term debt.

$250 million of the 1985 debt financing was issued to secure tax exempt pollu-tion control bonds, of which $100 mil-lion was used to refund previously is-sued pollution control bonds.

The Company also completed approxi-mately $28,000,000 of capital lease financing. Approximately $143 million of the total 1985 external financing was used for debt and preferred stock re-funding and retirement.

External financing for 1986 is ex-pected to approximate

$388 million, excluding capital'lease financing but including additional funds needed to complete the construction of the Nine Mile Project. This amount will be in-creased by up to $140 million if the planned sale of the LILCO General and Refunding Bonds is not completed. At December 31, 1985, construction re-lated short-term debt was $2,195,000 and obligations under bankers accep-tances for fuel inventory financing were

$5,000,000, for a total of $7,195,000. Un-expended proceeds from the issuance of tax-exempt revenue bonds and notes totaled $79.9 million at December 31, 1985, of which $56.5 million was with-drawn in January 1986.

Ordinarily, construction related short-term borrowings are refunded with permanent securities on a continu-ing basis.

Bank credit arrangements, which total $573 million (including $445 million of revolving credit and term loan agreements and a $100 million Bankers Acceptance Facility Agreement) are used by the Company to enhance flexi-bility as to the type and timing of its security sales. The unsecured debt limi-tation imposed by the Company's Char-ter is $700 million.

In general, the Company has a strong capital structure, adequate short and in-termediate term bank borrowing capa-bility and has been able to access the permanent capital markets with flexibil-ANNUALEXTERNALFINANCING BYTYPE Miliioosofdollars 583.1 291.8 614.3 374.7 584.1 323.8 346.0 186.7 Debt 101.3 424.9 259.7 145.2 171.3 189.6 185.3 mom~

20.0 120.0 Preferl od, 50.0 75.0 1981 1982 1983 1984 1985 ity. Earnings coverage of interest charges has been well in excess of mortgage indenture restrictions for the issuance of first mortgage bonds and over $1.5 billion of property is available to support the issuance of first mortgage bonds.

However, continua-tion of this degree of financial strength is dependent on a number of events, in-cluding the ultimate cost of the Nine Mile Point Nuclear Station Unit No. 2, the rate phase-in plan for the Unit, the PSC"s ultimate determination in respect of the Unit's allowable cost, the resolu-tion of accounting matters under con-sideration by the PSC and the Financial Accounting Standards Board and adequate rate relief.

REPORT OF MANAGEMENT m

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

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

To meet its responsibilities with respect to financial informa-.

tion, management maintains and enforces a system of internal accounting controls, which is designed to provide reasonable assurance, on a cost effective basis, as to the integrity, objec-tivity and reliability of the financial records and protection of assets.

This system includes communication through written'olicies and procedures, an organizational structure that pro-'ides for appropriate division of responsibility and the training of personnel. This system is also tested by a comprehensive internal audit program. In addition, the Company has a Code of Conduct which requires all employees to maintain the highest level of ethical standards and requires key management employees to formally affirm their compliance with the Code.

The financial statements have been examined by Price Waterhouse, the Company's independent accountants, in ac-cordance with generally accepted auditing standards.

As part of their examination, they made a study and evaluation of the Company's system of internal accounting control. The purpose of such study was to establish a basis for reliance thereon in determining the nature, timing and extent of other auditin'g procedures that were necessary for expressing an opinion as to whether the financial statements are presented fairly. Their examination resulted in the expression of their opinion which follows this report. The independent accountants'xamination does not limit in any way management's responsibility for the fair presentation of the financial statements and all other in-formation, whether audited or unaudited, in this Annual Report.

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

Price Waterhouse and the Company's internal auditors have free access to meet indi-vidually with the Audit Committee at any time, without man-agement present.

22

CONSOLIDATED STATEMENTOF INCOME AND RETAINED EARNINGS NIAGARAMOHAWKPOWER CORPORATION ANDSUBSIDIARYCOMPANIES For the year ended December 31, 1983 Operating revenues:

Electric Gas Operating expenses:

Operation:

Fuel for electric generation Electricity purchased Gas purchased Other operation expenses Maintenance Depreciation and amortization (Note 2)....

Federal and foreign income taxes (Note 9).

Othertaxes Operating income Other income and deductions:

Allowance for other funds used during construction (Note 1)

Federal income taxes (Note 1)

Other items (net) (Note 11)

Income before interest charges Interest charges:

Interest on long-term debt.

Other interest Allowance for borrowed funds used during construction (Note 1)

Net income Dividends on preferred stock Balance available for common stock Dividends on common stock Retained earnings for the year 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 per share of common stock.................

$2,096,404 598,536 2,694,940 391,382 367,406 411,801 364,010 144,312 150,627 173,471 280,643 2)283,652 411,288 141,320 26,708 53,110 221,138 632)426 260,271 6,721 (45,996) 220,996 411,430 59,559 351)871 252 218 99,653 742,462

).:$ 842,115 122,215 2.88 2.06

$2,134,470 651,076 2,785,546 476,040 377,052 452,960 353,660 140,987 141,150 181,767 269,204 2,392,820 392,726 122,354 33,460 8,591 164,405 557,131 224,099 12,440 (39,142) 197,397 359,734 51,460 308,274 216,493 91,781 650,681 742,462 108,734 2.84 1.98

$2,023,728 608,587 2,632,315 501,328 381,703 432,898 326,057 136,338 127,390 117,089 254,797 2,277,600 354,715 85,350 31,511 9,994 126,855 481,570 189,006 12,598 (32,443) 169,161 312,409 42,109 270,300 185,642 84,658 566,023 650,681 97,685 2.77 1.89 REPORT OF INDEPENDENTACCOUNTANTS To the Stockholders and the Board of Directors York State Public Service Commission with respect to its in-of Niagara Mohawk Power Corporation

,,vestment in the Unit will have, in the aggregate, a material We have examined the consolidated balance sheets of Niag-;effect on its financial position or results of operations.

ara Mohawk Power Corporation and its subsidiaries as of De-In our opinion, subject to the effects on the 1985 and 1984 cember 31, 1985 and 1984 and the related consolidated state-

'financial statements of such adjustments, if any, that might ments of income and retained earnings and of changes in fi- "'have been required had the outcome of the uncertainties dis-nancial position for each of the three years in the period ended cussed in the preceding paragraph been known, the consoli-December 31, 1985. Our examinations were made in accord-

. dated financial state'ments examined by us present fairly the ance with generally accepted auditing standards and accord-

"'financial position of Niagara Mohawk Power Corporation and ingly included such tests of the accounting records and such its subsidiaries as of December 31, 1985 and 1984 and the other auditing procedures as we considered necessary in the results of their operations for each of the three years in the circumstances.

period ended December 31, 1985 in conformity with generally The Company is a 41% participant in the construction of the accepted accounting principles consistently applied.

Nine Mile Point Nuclear Station Unit No. 2 (Unit). As a result of the uncertainties discussed more fullyin Note 10, management Syracuse, New York is unable to predict whether regulatory actions by the New February24,1986 23

CONSOL)DATED BALANCESHEET NIAGARAMOHAWKPOWER CORPORATION ANDSUBSIOIARYCOMPANIES At December 31, ln thousands of dollars 1985 1984 24 ASSETS Utilityplant, at original cost (Notes 1, 3 and 10)

Less accumulated depreciation and amortization (Note 2)

Net utilityplant Other property and investments (Note 7)

Advances on behalf of Nine Mile Point Nuclear Unit No. 2 cotenant, including deferred supplemental payments (Note 11)

Current assets:

Cash, including time deposits of $7,521 and $7,367, respectively......

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

Materials and supplies, at average cost:

Coal and oil for production of electricity Other Prepayments Deferred debits:

Unamortized debt expense Deferred recoverable energy costs...

Extraordinary property losses Deferred finance charges(Note 1)

Other CAPITALIZATIONANDLIABILITIES Capitalization (Note 7):

Common stockholders'quity:

Common sto'ck, issued 126,928,340 and 116,848,974 shares, respectively Capital stock premium and expense Retained earnings.

Non-redeemable preferred stock Redeemable preferred stock Long-term debt Total capitalization Current liabilities:

Short-term debt (Note 4)

Long-term debt due within one year Sinking fund requirements on redeemable preferred and preference stock (Note 7)

Accounts payable Payable on outstanding bank checks Customers'eposits Accrued taxes Accrued interest Accrued vacation pay.

Gas supplier refunds payable to customers Cotenant prepayments to Nine MilePoint Nuclear Unit No. 2 project fund (Note 11)

Other Deferred credits:

Mandated refunds to customers (Note 11)

Accumulated deferred Federal income taxes (Note 9)

Deferred finance charges(Note 1)

Other Commitments and contingencies (Notes 3, 10 and 11)

$7,640,905 1,629,437 6,011,468 146)487 232,847 44,933 283,962 64,454 65,450 20,931 479,730 64,260

32) 520 1,709 25,055 19,761 143,305

$7,013,837 126,928 1,519,577 842,115 2,488>620 290,000 379,850 2,643,094 5,801,564 7,195 65,465 13,050 186,887 63,340 7,829 7)560 76,157 25,945 11,381 84,904 25,937 575,650 80,000 515,554 25,055 16,014 636,623

$7,013>837

$6,903,184 1,501,282 5,401,902 112,730, 130,881 32)639 282,232 96,474 62,018 13,874 487,237 52,658 16,253 10,838 20,902 100,651

$6,233,401 116,849 1,347,806 742,462 2,207,117 240,000 367,900 2,395,471 5,210,488 53,516 63,837 19,601 183,039 59,352 6,640 23,446 66,261 24,555 6,244 310 30,593 537,394 90,191 374,364 20,964 485,519

$6,233,401

'ONSOLIDATEDSTATEMENT OF CHANGES IN FINANCIALPOSITION NIAGARAMOHAWKPOWER CORPORATION ANDSUBSIDIARYCOMPANIES For the year ended December 31, FINANCIALRESOURCES WERE PROVIDED BY:

Operations:

Net income Charges (credits) to income not requiring (not providing) working capital Depreciation and amortization.

Allowance forfunds used during construction....

Amortization of nuclear fuel Provision for deferred Federal income taxes (net)

Other Outside financing:

Sale of common stock Sale of preferred stock Sale of mortgage bonds Issuance of other long-term debt.

Net borrowings under revolving credit facilities (Note 7)..

Increase (decrease) in short-term debt.................

Other sources:

Deferred recoverable energy costs Mandated refunds to customers (Notes 9 and 11)..

Repayment of construction advances............

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

Other investments Unamortized debt expense (Increase) decrease in working capital other than short-term debt (see below).........

Miscellaneous (net)

Total resources provided FINANCIALRESOURCES WERE USED FOR:

Construction additions, including capital leases Nuclear fuel Allowance for funds used during construction...

Net additions..

Advances on behalf of Nine Mile Point Nuclear Unit No. 2 cotenant Reduction of long-term debt.

Reduction of preferred and preference stock.......

Dividends.

Total resources used (Increase) decrease in working capital other than short-term debt:

Cash Accounts receivable Coal and oil for production of electricity...............

Other materials and supplies Long-term debt due within one year Accounts payable Payable on outstanding bank checks Accrued taxes and interest Gas'supplier refunds due customers Cotenant prepayments to Nine Mile Point Nuclear Unit No. 2 project fund Other (net).

1985

$411,430 150>627 (187,316) 25,448 141,206 (4,707) 536,688 185,270 75,000 175,000 225,000 (29,880)

(46,321) 584,069 (16>267)

(10,191) 38,481 (32,775)

(11,602) 92,084 (9,331) 50,399

$1,171,156

$718,903 52>217 (187,316) 583,804 135,808 126,717 13,050 311,777

$1,171,156

$(12,294)

(1,730) 32,020 (3,432) 1,628 3,848 3,988 (5,990) 5,137 84,594 (15,685)

$ 92,084 ln thousands ofdollars 1984

$359,734 141,150 (161,496) 17,612 116,265 (10,821) 462,444 189,626 50,000 319,250 81,618 5,060 (31,247) 614,307 9,480 (9,273)

(27,495)

(8,128) 38,964 3,643 7,191

$1,083,942

$746,910 22,936 (161,496) 608,350 120,060 67,005 20,574 267,953

$1,083,942

$ (1,440)

(8,156)

(564)

(5,764) ',

33,685 (2,213)

(17,119) 27,440 (8,989)

(2,507) 24,591

$38,964 1983

$312,409 127,390 (117,793) 11,856 80,850 (4,972) 409,740 171,269 120,000 200,000 15,135 83,900 (7,237) 583,067 47,560 (5,793)

(22,421)

(22,670) 159 (29,455)

(13,618)

(46,238)

$946,569

$677,155 14,309 (117,793) 573,671 130,829 14,318 227,751

$946,569

$ (11,816)

(44,827) 46,243 (2,148)

(39,348) 7,501 15,556 (7,362) 1,934 (494) 5,306

$ (29,455) 25

NOTES TO CONSOL(DATED FINANC(ALSTATEMENTS NOTE 1. Summary of Significant Accounting Policies The Company is subject to regulation by the New York State Public Service Commission (PSC) and the Federal Energy Regulatory Commission (FERC) with respect to its rates for service and the maintenance of its accounting records. The Company's accounting policies conform to generally accepted accounting principles, as applied to regulated public utilities, and are in accordance with the accounting requirements and ratemaking practices of the regulatory authorities.

Principles of Consolidation:

The consolidated financial statements include the Company and its wholly-owned sub-sidiaries. All significant intercompany balances and transac-tions have been eliminated. Assets and liabilities of foreign subsidiaries are translated into U.S. dollars at the exchange rate in effect at the balance sheet date. Revenue and expense accounts are translated at the average exchange rate in effect during the year. Currency translation adjustments are recorded as a component of equity and do not have a significant impact on financial condition.

UtilityPlant: The cost of additions to utility plant and of re-placements of retirement units of property is capitalized. Cost includes direct material, labor, overhead and an allowance for funds used during construction (AFC). The cost of current re-pairs and maintenance is charged to expense. Whenever utility plant is retired, its original cost, together with the cost of re-moval, less salvage, is charged to accumulated depreciation.

The following table summarizes the components of Utility Plant:

At December 31, In thousands of dollars 1985

/o 1984 Electric plant...............

Nuclear fuel (Note 3)........

Gas plant...................

Common plant..............

Construction work in progress

$4,302,280 369I126 517,995 115,316 2>336,188 56

$4,083,042 5

316,909 7

494,628 2

130,916 30 1,877,689 Total utilityplant..

$7)640)905 100

$6 903 184 Allowance for Funds Used During Construction: The Com-pany capitalizes AFC in amounts equivalent to the cost of funds devoted to plant under construction. AFC rates are de-termined in accordance with FERC and PSC regulations. The Company computes AFC at a rate which is reduced to reflect the income tax effect of the borrowed funds component of AFC for all additions to electric utilityplant. The AFC rates in effect December 31, 1985 were 12.40/o and, net of tax, 10.25/o. AFC is segregated into its two components, borrowed funds and other funds, and is reflected in the Interest Charges section and the Other Income and Deductions section, respectively, of the Consolidated Statement ot Income.

Effective April 1985, pursuant to a PSC authorization, the Company discontinued accruing AFC on $320 million of con-struction work in progress (CWIP) for which a cash return is being allowed through inclusion in rate base of that portion of the investment in the Nine Mile Point Nuclear Station Unit No. 2 (Unit). Amounts equal to the AFC which is no longer accrued on the CWIP included in rate base are being accumulated in deferred debit and credit accounts and, at the time the Unit commences commercial operation and is placed in rate base, the balance in the deferred credit account will be available to reduce future revenue requirements over a period substantially shorter than the life of the Unit. The balance in the deferred debit account willbe amortized and recovered in rates over the life of the Unit.

Depreciation, Amortization and Nuclear Generating Plant Decommissioning Costs: For accounting purposes, deprecia-tion is computed on the straight-line basis using the average or remaining service lives by classes of depreciabie property. In addition, certain costs associated with the discontinued Ster-ling Nuclear Station (See Note 2) are being amortized over shorter periods as approved by the PSC. For Federal income tax purposes, the Company computes depreciation using ac-celerated methods and shorter allowable depreciabie lives.

Estimated decommissioning costs (costs to remove the plant from service in the future) of the Company's Nine Mile Point Nuclear Station Unit No. 1 are being recovered in rates through an annual allowance and charged to operations through depreciation charges.

The Company continues to review the estimate and requirements for decommissioning and plans to seek rate adjustments when appropriate. There is no assurance that the decommissioning allowance willultimately aggregate a sufficient amount to decommission the plant. The Company believes that decommissioning costs, if higher than currently estimated, will ultimately be recovered in the rate process, al-though no such assurance can be given. Based on a study completed in 1985, the cost of decommissioning, which is ex-pected to begin in the year 2005, is estimated to be approxi-mately $553,000,000 at that time ($193,600,000 in 1985 dollars).

Through December 31, 1985, the Company has recovered

$19,100,000 of decommissioning costs in rates. The Company's 41'/o share of costs to decommission Nine Mile Point Nuclear Station Unit No. 2 beginning in the year 2027, is estimated to be approximately $923,000,000 ($93,300,000 in 1985 dollars). Pro-vision to commence recovery based upon currently estimated decommissioning costs over the lifeof these plants is expected to be considered in the Company's next rate proceeding.

Amortization of Nuclear Fuel: Amortization of the cost of nuclear fuel is determined on the basis of the quantity of heat produced for the generation of electric energy. The cost of disposal of nuclear fuel, which presently is $.001 per kilowatt-hour of net generation, is based upon a contract with the U.S.

Department of Energy. These costs, which are associated with generation at Nine Mile Point Unit No. 1, are charged to operat-ing expense and recovered from customers through base rates or through the fuel adjustment clause.

Revenues:

Revenues are based on cycle billings rendered to certain customers monthly and others bi-monthly. The Com-pany does not accrue revenues for energy consumed and not billed at the end of any fiscal period. The Company's tariffs include electric and gas adjustment clauses under which energy and purchased gas costs, respectively, above or below the levels allowed in approved rate schedules, are billed or credited to customers. The Company, as authorized by the PSC, charges operations for energy and purchased gas cost in-creases in the period of recovery. The PSC has periodically authorized the Company to make changes in the level ofallowed energy and purchased gas costs included in approved rate schedules.

As a result of such periodic changes, a portion of energy costs deferred at the time of change would not be recov-ered under the normal operation of the electric adjustment clause. However, the Company has been permitted to amortize and bill such portions to customers, through the electric ad-justment clause, over 36 months from the effective date of each change. The Company has implemented, beginning April 1984, revisions to its fuel adjustment clause consistent with the PSC's 26

Opinion in a proceeding which reviewed the Company's electric fuel adjustment clause. The revisions essentially provide for partial pass-through of fuel cost fluctuations from those fore-cast in rate proceedings with the Company absorbing a specific portion of increases or retaining a portion of decreases to a maximum of $15 million per rate year.

Federal Income Taxes:

In accordance with PSC require-ments, the tax effect of book and tax timing differences is flowed through unless authorized by the PSC'to be deferred.

The Company provides deferred taxes on certain benefits realized from depreciation, on deferred energy and purchased gas costs, on nuclear fuel disposal costs accrued prior to April 7, 1983, on nuclear generating plant decommissioning costs, on certain construction overheads and on certain other items (see Note 9). In conformity with ratemaking practices of the PSC, the Company has not provided deferred taxes on approx-imately $1.5 billion of other tax deductions which include cer-tain depreciation differences and various construction over-heads deductible currently fortax purposes and capitalized for accounting and ratemaking purposes. The Company claims 10 percent investment tax credit and defers the benefits of such credits as realized in accordance with PSC directives. For pur-poses of computing capital cost recovery deductions and nor-malization, the asset basis is reduced by one-half of the credit claimed for expenditures made subsequent to 1982. For proj-ects specified in the AFC section above, the imputed tax ben-efit of the borrowed funds component of AFC has been cred-ited to Other Income and Deductions. The tax effect of General and Refunding Bond interest and supplemental payments is recorded in Other Income and Deductions (see Note 11).

Amortization of Debt Issue Costs: The premium or discount on long-term debt issues is amortized ratably ovei the lives of the issues (see Note 7).

Pension Plans: The cost of pension plans is based upon cur-rent costs, amortization of unfunded past service benefits over periods ranging from 15 to 40 years and amortization over 15 years of unfunded past service benefits arising from plan amendments.

The Company's policy is to fund pension costs accrued (see Note 8).

In December 1985, Statement of Financial Accounting Stan-dards No. 87 "Employers'ccounting for Pensions" was is-sued and is effective for fiscal years beginning after December 15, 1986. The adoption of the requirements of this statement is not currently anticipated to have a significant impact on the results of operations or financial position of the Company as shown in the Consolidated Financial Statements.

NOTE 2. Depreciation and Amortization The total provision fordepreciation and amortization, includ-ing amounts charged to clearing accounts, was $151,817,000 for 1985, $142,500,000 for 1984 and $128,976,000 for 1983. The provisions include approximately $9,500,000, $10,200,000 and

$9,200,000, respectively, resulting from the PSC allowed re-covery of the amortization of costs associated with the discon-tinued Sterling Nuclear Station. The percentage relationship between the total provision for depreciation and average de-preciable property was 3.0/o in 1985, 2.9/o in 1984 and 2.8/o in 1983. The Company makes depreciation studies on a continu-ing basis and, upon approval by the PSC, periodically adjusts the rates of its various classes of depreciable property.

NOTE 3. N M Uranium, Inc.

During 1976, through a wholly-owned subsidiary, N M Uranium, Inc. (NMU), the Company purchased a 50 percent undivided interest in uranium deposits and associated mining equipment to be held by a jointly-owned mining venture. Ac-quisition of this interest was made primarily to provide a more assured future supply of nuclear fuel. The investment in the subsidiary, which includes costs incurred since acquisition and AFC accrued through March 31, 1981, has been reduced by the proceeds from the sale of uranium, net of tax, and trans-fers to the Company and is included in the consolidated finan-cial statements as part of the nuclear fuel component of utility plant (see Note 1). Such investment, excluding amounts being reviewed in the Company's current rate proceeding (including inventory with a spot market value of approximately

$22,600,000 at January 1, 1986 and 1985), totaled $73,800,000 at December 31, 1985 and $87,500,000 at December 31, 1984.

In 1978, the PSC issued an order approving the Company's investment in NMU. This approval was subject to the condition that rates which the PSC willapprove in the future will reflect the cost of NMU uranium at the lower of cost or the market price. The PSC also stated that the reasonableness of the Company's future uranium costs will be judged with reference to costs of uranium under "currently" available long-term con-tracts and in the spot market. Subject to PSC approval, the comparison of cost to market will be on an aggregate basis over the life of the project.

In connection with the Company's March 1984 rate decision, the PSC allowed $38.37 per lb. as the cost of approximately 300,000 lbs. of NMU uranium utilized in the 1984 reload of the Company's Nine Mile Point Nuclear Unit No. 1. This price rep-resents the average United States delivery price, as reported by the U.S. Department of Energy (DOE), for all uranium during 1982 including long-term contracts and spot market price set-tlements. The Company's cost of this NMU uranium was $42.14 per lb., inclusive of AFC prior to April 1, 1981. The differential between the Company's cost of this NMU uranium and that amount allowed to be recovered in rates charged to customers has been deferred subject to the PSC approval of the compari-son of cost to market on an aggregate basis over the life of the project.

In connection with the Company's current rate proceeding, the PSC is reviewing approximately 590,000 lbs. of NMU uranium transfers to the Company valued at appioximately

$23.0 million using appropriate DOE prices. The cost to the Company of this uranium is approximately $26.3 million.

Since regulatory restrictions exist on the extent to which the costs of uranium produced by this mining operation may be allowed in future rates, management is continually evaluating the status of the Company's investment to assure maximum recovery. Based upon current forecasts of DOE average deliv-ery prices and the Company's uranium requirements through 1991, it is presently anticipated that the mining process will be completed and all production will be utilized.

NOTE 4. Bank Credit Arrangements At December 31, 1985, the Company had $573 million of bank credit arrangements, including the Oswego Facilities Trust, with 38 banks. These credit arrangements consisted of

$445 million in long-term commitments under Revolving Credit and Term Loan Agreements,

$10 million in short-term com-mitments under Credit Agreements, $18 millionin lines of cred-it and $100 million under a Bankers Acceptance Facility Agreement. The Revolving Credit and Term Loan Agreements extend through 1990. At the option of the Company, the in-terest rate applicable to borrowings under these agreements is based on the prime rate or at specified increments over the rates applicable to certificates of deposit or, in certain agree-ments, eurodollar deposits.

All of the other bank credit 27

arrangements are subject to review on an ongoing basis with interest rates negotiated at the time of use. The Company also issues commercial paper.

Unused bank credit facilities are held available to support the amount of commercial paper out-standing, including amounts currently issued in connection with Interest Rate Exchange Agreements (see Note7).

The Company pays fees for substantially all of its bank credit arrangements.

The Bankers Acceptance Facility Agreement, which is used to finance the fuel inventory for the Company's generating stations, provides for the payment of fees only at the time of issuance of each acceptance.

Amounts outstanding under Interest Rate Exchange Agree-ments and Revolving Credit and Term Loan Agreements to-taled $100 million at December 31, 1985 and are recorded as long-term debt.

Additional bank credit arrangements in connection with the Company's guarantee of certain obligations of LILCO are dis-cussed in Note 11.

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

Operating revenues:

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

Gas Total ln thousands ofdollars 1985 1984 1983

$2,096>404

$2,134,470

$2,023,728 598,536 651,076 608,587

$2,694,940

$2,785,546

$2,632,315 NOTE 6. Information Regarding the Electric and Gas Businesses The Company is engaged in the electric and natural gas util-ity businesses.

Certain information regarding these segments is set forth in the followingtable. General corporate expenses, property common to both segments and depreciation of such common property have been allocated to the segments in ac-cordance with practice established for regulatory purposes.

Identifiable assets include net utility plant, materials and supplies and deferred recoverable energy costs. Corporate as-sets consist of other property and investments, cash, accounts receivable, prepayments, unamortized debt expense and other deferred debits.

AtDecember 31:

Short-term debt:

Commercial paper....

Notes payable Bankers acceptances 2,195 5,000

$ 8,000 3,516 42,000 ln thousands ofdollars 1985 1984 584,759 574,493 471,804 Total Operating income before taxes:

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

529,659 511,842 420,600 Gas................

55,100 62.651 51,204 S

7195 Weighted average ln'tefest rate (a)....

7.93/o

$ 53,516 9 67/0 Pretax operating Income, Including AFC:

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

S 716,719 672,964 538,097 Gas....................

55,356 63,025 51.500 S 45,607 (a) Excluding compensating balances and fees.

For year ended December 31:

Dailyaverage outstanding..........

Dailyweighted average interest rate(a) 8.31o/o Maximum amount outstanding..... 4182,818

$ 87,271 10.4S /o

$228,893 Total...................

Income taxes................

Other income and deductions Interest charges.............

Net income 735,989 181,767 42,051 236,539 589,597 117,089 41,505 201,604 772>075 173>471 79,818 266,992 S

411,430 359,734 S

312,409 NOTE 5. Jointly-Owned Generating Facilities The following table reflects the Company's share of jointly-owned generating facilities at December 31, 1985. The Com-pany is required to provide financing for the unit in process of construction and for any additions to the units in service. The Company's share of expenses associated with the Roseton units and Oswego Steam Station Unit No. 6 are included in the appropriate operating expenses in the Consolidated Statement of Income.

ln thousands ofdollars Percentage Construction owner-Utility AccumuIated work in ship plant depreciation progress Roseton Steam Station Units No.1 and 2(a)...

25

$ 82,880

$25,328 405 Oswego Steam Station Unit No.6(b)..........

76

$259,190

$40,408 599 Nine Mile Point Nuciear StationUnitNo.2(c)(d).

41

$1,917,956 (a) The remaining ownership interests are Central Hudson Gas and Electric Corporation, the operator of the plant (35'/o) and Consoli-dated Edison Company of New York, Inc. (40/o).

(b) The Company is the operator. The remaining ownership interest is Rochester Gas and Electric Corporation (24/o).

(c) The remaining ownership interests are Long Isfand Lighting Com-pany (18'/o), New York State Electric and Gas Corporation (18/o),

Rochester Gas and Electric Corporation (14%), and Central Hud-son Gas and Electric Corporation (9%%d) (see Note 10).

(d) Excludes amounts spent for nuclear fuel and certain costs as-sociated with non.generating facilities being constructed in con-nection with the Unit.

Depreciation:

Electric Gas Total Construction expenditures (including nuclear fuel):

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

Gas Total Identifiable assets:

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

Gas Total........

Corporate assets Total assets 137,630 S

128,521 115,075 12,997 12,629 12,315 S

150,627 141,150 127,390 S

749>912 734,706 654,020 21,208 35,140 37,444 771,120 769,846 S

691,464

$5>756 586

$5 155 372

$4 443 154 444,070 432,113 429,133 6,200,656 5,587,485 4,872,287 813,181 645,916 485,285

$7,013,837

$6,233,401

$5,357,572 28

'hlOTE 7. Capitalization CAPITALSTOCK The followingtable summarizes the shares of capital stock authorized, issued and outstanding At December 31, 1985 1984 1983 Common stock, $ 1 par value:

Authorized..................

Issued &outstanding.........

150,000,000 150,000,000(a) 125,000,000 126,928,340 116,848,974 104,010,003 Preferred stock, $100 par value:

Authorized...................

Issued &outstanding..........

Preferred stock, $25 par value:

Authorized...................

Issued &outstanding..........

3,400,000 3,318,000 19>600>000 14,044,000 3,400,000 3,342,510 19,600,000(a) 11,210,000 3,400,000 3,370,240 9,600,000 9,376,000 Preference stock, $25 par value:

Authorized...................

Issued &outstanding..........

4>000>000 4,000,000 0

520,000 4,000,000 760,000 Common stock

($ 1 par value)

Shares Amount'on-Redeem-Redeem-Shares able'ble*

Non-Redeem-Redeem-Shares able'ble*

(a) Increased authorizations approved by shareholders.

The table below summarizes changes in capital accounts for 1983, 1984 and 1985:

Preferred and Preference Stock

$ 100 par value

$25 par value Capital stock Premium and Expense (Net)'alance January 1, 1983 Sales in1983............

Issued to stock purchase plans in 1983...........

Redemptions............

Foreign currency translation adjustment Balance December 31,1983 Sales in 1984.............

Issued to stock purchase plans in1984............

Redemptions.............

Foreign currency translation adjustment...

Balance December 31,1984 Safes in1985.............

Issued to stock purchase plans in 1985............

Redemptions.............

Foreign currency translation adjustment....

(41,680)

(4,168)

(326,000) 104,010,003 104,010 3,370,240 210,000 127,024(o)10,136,000 6,534,400 6,534 2,000,000 6,304,571 6,305 (27,730)

(2,773)

(406,000) 116,848,974 116,849 3,342,510 210,000 124,251(a)11,730,000 4,465,600 4,465 3,000,000 5,613,766 5,614 (2,451)

(686,000)

(24,510) 93,832,151

$93,832 3,161,920 $210,000

$106,192(a) 6,662,000 5,000,000 5,000 250,000 25,000 3,800,000 5,177,852 5,178 (8,150) 80,465 607 (6,114) 30,000 223,400(a) 1>174,382 50,000 87,878 (10,150) 87,117 555 (2,126) 30,000 263,250(a) 1,347,806 50,000 25,000 74,216 (17,150) 99,535 442 (2,422)

$ 166,550(o)

$1,020,795 30,000 65,000 78,629 Balance December31,1985 126,928,340

$126,928 3,318,000 $210,000

$121,800(o)14,044,000

$80,000

$271,100(a) $1,519,577

• Inthousands of dollars (a) Includes sinking fund requirements due within one year NON-REDEEMABLE PREFERRED STOCK (Optionally Redeemable)

The Company has certain issues of preferred stock which provide for optional redemption as follows:

ln thousands ol dollars At December 31, 1985 1984 Redemption price per share (Before adding accumulated dividends)

Eventual 1983 December 31, 1985 minimum Preferred $100 par value:

3.40% Series; 200,000 shares..

3.60% Series; 350,000 shares..

3.90% Series; 240,000 shares..

4.10% Series; 210,000 shares..

4.85% Series; 250,000 shares..

5.25% Series; 200,000 shares..

6.10% Series; 250,000 shares..

7.72% Series; 400,000 shares..

Preferred $25 par value:

Adjustable Rate Series A; 1,200,000 shares...........

Adjustable Rate Series C; 2,000,000 shares...........

$ 20,000 35,000 24,000 21,000 25,000 20,000 25,000 40,000 30,000 50,000

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

$ 20,000 35,000 24,000 21,000 25,000 20,000 25,000 40,000 30,000 30,000

$103.50 104.85 106.00 102.00 102.00 102.00 101.00 105.44 (a)

(b)

$103.50 104.85 106.00 102.00 102.00 102.00 101.00 102.36 25.00 25.00

$290,000

$240,000

$240,000 (a) Not redeemable until 1988.

(b) Not redeemable until 1990.

29

MANDATORILYREDEEMABLE PREFERRED STOCK The Company has certain issues of preferred and preference stock which provide for mandatory and optional redemption as follows:

\\

Redemption price per share (Before adding accumulated dividends) ln thousands of dollars Eventual At December 31, 1985 1984 1983 December 31, 1985 minimum Preferred $100 par value:

7.45% Series; 438,000, 456,000, and 474,000 shares..

10.13% Series; 250,000 shares.

10.60% Series; 280,000, 286,510 and 296,240 shares 12.75% Series; 250,000 shares.

Preferred $25 par value:

8.375% Series; 1,300,000, 1,400,000 and 1,500,000 shares 9.75%Series;804,000,870,000and936,000shares....

9.75% Series (second); 1,020,000 shares............

10.13% Series; 1,000,000 shares.....................

10.75% Series; 1,600,000 shares 12.25% Series; 700,000 shares.

12.50/o Series; 620,000 shares.

12.75% Series; 1,000,000 shares.....................

15.00/o Series; 800,000 shares.

Adjustable Rate Series B;2,000,000shares............

Preference $25 par value:

7.75% Series; none, 520,000 and 760,000 shares.......

$ 43,800 25,000 28>000 25,000 32,500 20,100 25,500 25,000 40,000 17,500, 15>500 25,000 20,000 50,000 35,000 21,750 25,500 25,000 40,000 17,500 15,500 20,000 50,000 37,500 23,400 25,500 25,000 40,000 17,500 15,500 20,000 26.32 26.29 26.63 (a)

(a)

(c)

(c) 28.20 28.28 (d) 25.00 25.00 25.00 25.00 25.00 25.00 25.00 25.00 25.00 25.00 13,000 19,000

$ 45,600

$ 47,400

$104.57

$100.00 25,000 25,000 (a) 100.00 28,651 29,624 107.95 102.65 25,000 25,000 (h)

(b)

Less sinking fund requirements 392,900 13,050 387,501 19,601 350,424 11,950 (a) Not redeemable until 1988.

(b) Entire issue to be redeemed at par value June 30, 1991.

(c) Not redeemable until 1991.

(d) Not redeemable until 1989.

$379,850

$367,900

$338,474 These series require mandatory sinking funds for annual redemption and provide optional sinking funds through which the Company may redeem, at par, a like amount of additional shares (limited to 120,000 shares of the 7.45% series and 300,000 shares of the 9.75% series). The option to redeem additional amounts is not cumulative.

The Company's five-year mandatory sinking fund redemption requirements for preferred stock are as follows:

No. of shares Commencing 1986 ln thousands ofdollars 1987 1988 1989 1990 Preferred $100 par value:

7.45% Series..........

10.13% Series..........

10.60% Series........

~

~

Preferred $25 par value:

8.375% Series........

9.75% Series...

~

~

~

~

~

~

9.75% Second Series 10.13% Series.........

10.75% Series.........

12.25% Series.........

12.50/o Series.........

15.00% Series

~

~

~

~.

~

~

~

18,000 25,000 20,000 100,000 66,000 204,000 100,000 320,000 43,060 38,139 40,000

-6/30/77 12/31/87 3/31/80 4/1/83 10/1/80 4/1/86 12/31/87 6/30/89 3/31/87 3/31/87 3/31/87

$1,800 2,000 2,500 1,650 5,100

$ 1,800 2,500 2,000 2,500 1,650 5,100 2,500 1,077 953 1,000

$ 1,800 2,500 2,000 2,500 1,650 5,100 2,500 1,077 953 1,000

$ 1,800 1,875 2,000 2,500 1,650 5,100 1,875 8,000 1,077 953 1,000

$ 1,800 2,500 2,000 2,500 1,650 5,100 2,500 8,000 1,077 953 1,000

$13,050

$21,080

$21,080

$27.830

$29.080 30

LONG-TERM DEBT Long-term debt and long-term debt due At December 31 ~

within one year consisted of the following:

In thousands ofdollars 1985 1984 In thousands oidollars At December 31 ~

1985 1984 First mortgage bonds:

10Vs% Series due September 1,1985....

3%% Series due May 1, 1986..........

4r/s% Series due September 1 ~ 1987....

3r/s%Serlesdue June1,1988.........

14r/s% Series due August 11, 1988......

12%

Series due March 1,1989........

9Vs% Series due October 1, 1989......

4'%eries due April1, 1990..........

15%

Series due March 1,1991

........'4V4%SeriesdueMay1,1991 4'/z% Series due November 1, 1991 12.73% Series due February 1, 1992.....

13.06% Series due February 1

~ 1992.....

12.73% Series due February 20, 1992...

12.68% Series due February 28, 1992...

15>/2% Series due March 1, 1992........

15V4%Seriesdue June1,1992.........

11%

Seriesdue May1,1993..........

12V2% Series due March 1, 1994........

4%% Series due December 1,1994....

5~/s%SeriesdueNovember1,1996 6>/4%SeriesdueAugust1,1997 6>/~% Series due August 1, 1998.......

12Vs% Series due March 1, 1999........

9>/e%Seriesdue December1,1999....

12.95% Series due October 1, 2000.....

7%% Series due February 1, 2001......

7%% Series due February1,2002......

7'%eries due August 1, 2002.......

8>/4% Series due December 1, 2003....

9>/~% Series due December 1, 2003....

9.95% Series due September 1 ~ 2004...

10.20% Series due March 1, 2005.......

8.35% Series due August 1, 2007......

8%% Series due December 1, 2007....

• 13V2%Series due April1,2012..........

8 30,000 50,000 50,000 50,000 20,000 13,000 50,000 38,650 90,000 40,000 20>000

'50,000 10,000

'0,000 50>000 58,500 50,000 13,000 40,000 45,000 40,000 60,000 17>000 75,000 80>000 65,000 80,000 80,000 80>000 50,000 95,000 35,000 71,050 44>000 25,800

$ 47,000 30,000 50,000 50,000 50,000 20,000 13,000 50,000 38,650 100,000 40,000 50,000 62,500 50,000 13,000 40,000 45,000 40,000 60,000 17,000 75,000 80,000 65,000 80,000 80,000 80,000 50,000 100,000 36,500 71,600 46,000 30,000 16%

SeriesdueAugust1,2012 12r/s%Seriesdue November1,2012........

12r/s% Series due March 1,2013............

12V~% Series due June 15,2013............

'11>/4% Series due July 1,2014..............

• 11%% Series due October 1, 2014..........

'r/s%Serlesdue November1,2025........

Paul Smith's Electric Light&Power &

Railroad Company first mortgage bonds:

5'/z% Series due Ma 1, 1985..............

3,046 100,000 100,000 50,000 75,690 40>015 75,000 3,046 100,000 100,000 50,000 100,000 56,250 450 Total First Mortgage Bonds...

Promissory Notes:

" 8%SeriesAdue June1,2004...

2,129,751 2,069,996 46,600 46,600

'Adjustable Rate Series due July1,2015.....

'Adjustable Rate Series due December1,2025 Notes payable:

'Variable Rate Pollution Control Notes.......

17% Eurodollar Guaranteed Notes due September15,1989.................

7.8125% Adjustable London Interbank Offered Rate due September 15, 1989.....

Swiss Franc Bonds due December 15, 1995..

15.02% Unsecured Notes due 1990.........

Notes, Interest Rate Exchange Agreement...

Revolving credit and loan agreements............................

Revolving credit agreement, Oswego Facilities Trust.................

Other Unamortized premium 100,000 75,000 54,950 46,705 46,705 9,000 50,000 50,000 50,000 17,000 50,000 50,000 25>000 25,080 99,875 1,548 25,010 97,095 1,952 TOTALLONG-TERM DEBT................

2,708,559 2.459,308 Less long-term debt due within one year....

i 65,465 63,837 62,643,094

$2,395,471

'ax-exempt pollution control related issues Several series of First Mortgage Bonds and Notes were issued to secure a like amount of tax-exempt revenue bonds and notes issued by the New York State Energy Research and De-velopment Authority (NYSERDA). During 1985, $250,000,000 of these pollution control securities with maturities ranging from 30-40 years were issued. $175,000,000 bear interest at a daily adjustable interest rate (with a Company option to convert to a fixed interest rate) and are supported by bank direct pay letters of credit. $75,000,000 are at a fixed rate of 87/s% and are se-cured by the Company's first mortgage bonds. Pursuant to agreements between NYSERDA and the Company, trust funds have been established with the proceeds from the bond and note issues. Such proceeds are to be used for the purpose of constructing certain pollution control facilities at the Com-pany's generating facilities. Unexpended proceeds in the trust funds amounted to $79,916,000 at December 31, 1985 and are recorded in Other Property and Investments.

Notes Payable include a ten-year Swiss franc bond issue equivalent to $50,000,000 in U.S.,funds. Simultaneously with the sale of these bonds, the Company entered into a currency exchange agreement to fullyhedge against currency exchange rate fluctuations.

During 1984, the Company entered into seven-year Interest Rate Exchange Agreements for $75,000,000, of which

$25,000,000 was for Oswego Facilities Trust (Trust). The agreements require the Company to make fixed rate payments which calculated on a semi-annual bond basis, are equivalent to 12.25%, and in exchange, receive a LIBOR-based floating rate payment from a bank. The Company generally uses its own commercial paper notes as the source of funding for

$50,000,000 and Trust notes for $25,000,000. The related inter-est expense is recorded on a net basis.

The arrangements with the Trust provide financing for the construction of a new energy management system. The Trust has a $40,000,000 Direct Pay Letter of Credit Facility and Re-volving Credit Agreement, $25,000,000 of which is subject to an Interest Rate Exchange Agreement, which is available through December 31, 1990, and is used to support its commercial paper obligations. All such obligations are secured by certain assets held by the Trust. The Company is required to purchase, or otherwise arrange for, the disposition of the Trust assets upon the termination of the Trust. The Letter of Credit Facility and Revolving Credit Agreement of the Trust require payment of fees which are based upon the amount of commercial paper outstanding.

Other tong-term debt consists of obligations under capital leases of $41,896,000 and the liabilityto the U.S. Department of Energy for nuclear fuel disposal of $57,979,000.

31

Certain of the Company's Mortgage Bonds provide for a mandatory sinking fund for annual redemption. The Company's'ive-year mandatory sinking fund redemption requirements for First Mortgage Bonds are as follows:

Principal In thousands ofdollars amount Commencing 1986 1987 1988 1989 1990 10.20/o Series due March 1, 2005......

8.35% Series due August 1, 2007.....

8Vs% Series due December 1, 2007...

9.95% Series due September 1, 2004 14~/s% Series due August 11, 1988.....

12.95% Series due October 1, 2000....

9~/~% Series due December 1, 2003...

124% Series duo March 1, 1999.......

$1,500 750 2,000 5,000 16,000 5,333 2,941 1,700 3/1/78 8/1/82 12/1/83 9/1/85 8/11/86 10/1/66 12/1/87 3/1/90

$ (a)

(a) 2,000 5,000 16,000 5,333 S 1,500 550(a) 2,000 5,000 17,000 5,333 2,941

$ 1,500 750 2,000 5,000 17,000 5,333 2,941 S 1,500 750 2,000 5,000 5,333 2,941 S 1,500 750 2,000 5,000 5,333 2,941 1,700

$26,333

$34,324

$34,524

$17,524

$19,224 (a) Requirements, or a portion thereof, have been met by advance purchases.

Additionally, certain other series of mortgage bonds provide for a debt retirement fund whereby payment requirements may be met, in lieu of cash, by the certification of additional prop-erty, the waiver of the issuance of additional bonds or the re-tirement of outstanding bonds.

The 1985 requirements for these series were satisfied by the certification of additional property. The Company anticipates that the 1986 requirements for these series willbe satisfied by other than payment in cash.

Total annual debt retirement fund requirements for these series, based upon mortgage bonds outstanding December 31, 1985, are $7,850,000.

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

Substantially all of the Com-pany's employees may become eligible for these benefits if they reach retirement age while working for the Company.

These benefits are provided through an insurance company whose premiums are based on the benefits paid during the year. The cost (insurance premiums) of providing these ben-efits amounted to approximately

$7,500,000 for 1985 and

$6,000,000 for 1984.

Total

$433,000

$382,000 Net assets available for plan benefits.....

$583,000

$455,000 The weighted average assumed rate of return used in deter-mining the actuarial present value of accumulated plan ben-efits was 8% in 1985 and 7% in 1984.

The above table summarizes accumulated plan benefits at-tributable to employee wage levels and service rendered through December 31, 1985 and 1984. These amounts do not take into consideration expected future service, wage in-creases and associated actuarial assumptions.

These addi-tional factors and assumptions are considered in determining the funding requirements of the Company's ongoing pension plans, based upon an approved actuarial cost method, and are in conformity with generally accepted actuarial principles and practices.

NOTE 8. Pension and Other Retirement Plans The Company and its subsidiaries have non-contributory pension plans covering substantially all their employees. The total pension cost was $42,100,000 for 1985 and 1984 and

$40,000,000 for 1983 (of which $13,400,000 for 1985,

$11,400,000 for 1984 and $12,200,000 for 1983 was related to construction labor and, accordingly, was charged to construc-tion projects).

Studies indicate that the accumulated plan benefits, as de-termined by consulting actuaries, and plan net assets for the Company's plans at December 31, 1985 and 1984 are as fol-lows:

In thousands ofdollars 1985 1984 Actuarial present value of accumulated benefits:

Vested

$409,000

$361,000 Non-vested 24,000 21,000 NOTE 9. Federal and Foreign Income Taxes Income Tax Refund:

In September 1981, the Company re-ceived a refund of Federal income tax, including interest there-on, amounting to $9,943,000, net of Federal income taxes on the interest portion of the refund. The refund resulted from the allowance of certain deductions for the loss of water rights at Niagara Falls in connection with the redevelopment of Niagara power by the Power Authority of the State of New York. As part of the Company's March, 1983 rate decision, the PSC ordered that one-half of the refund be passed on to ratepayers over a two-year period and the remaining one-half be retained by the Company. Accordingly, one-half of the amount has been re-funded to customers and the remaining one-half is included in the Consolidated Statement of Income for 1983. In July 1983, the Company filed a suit seeking to annul the PSC's decision to share the refund with ratepayers.

In October 1985, the Court of Appeals upheld the PSC's original decision. No further appeal is contemplated by the Company.

Components of United States and foreign income before in-come taxes:

In thousands ofdollars 1985 1984 1983 United States.................

$551,907

$499,285

$388,051 Foreign..

17,516 18,326 19,989 Consolidating eliminations....

11,230 9,570)

(10,053)

Income before income taxes..

$558,193

$508,041

$397,967 Following is a summary of the components of Federal and foreign income tax and a reconcilation between the amount of Federal income tax expense reported in the Consolidated Statement of Income and the computed amount at the statu-tory tax rate:

32

kummary Analysis:

ln thousands ofdollars 1985 1984 1983 Components of Federal and foreign income taxes:

Current tax expense: Federal.

Foreign Deferred Federal income tax expense Income taxes included in Operating Expenses Federal income tax expense included in Other Income and Deductions Federal income tax credits included in Other Income and Deductions...

$ (21,329) 7,746 (13>583) 187,054 173,471 19,140 (45,648)

$ 17,713 8,498 26,211 155,556 181,767 5,831 (39,291)

$ (4,566) 9,294 4,728 112,361 117,089 (31,511)

Total.

$146,763

$148,307

$85,578 Components of deferred Federal Income taxes(Note 1)r Depreciation.

Cost of removal of property Investment tax credit Construction overheads Recoverable energy and purchased gas costs..........

Necessity certificates.

Nuclear tuel disposal cost Sterling abandonment Other Deferred Federal income taxes (net)

Reconciliation between Federal and foreign income taxes and the tax computed at prevailing U.S. statutory rate on Income before Income taxes:

Computed tax Reduction attributable to flow-through of certain tax adjustments:

Depreciation.

Allowance forfunds used during construction Taxes, pensions and employee benefits capitalized for accounting purposes..

Real estate taxes on an assessment date basis Deferred taxes provided at other than the statutory rate.

Other......

Federal and foreign income taxes.

$38,822 295 36>507 17,973 6>472 (700) 41,148 (3,769) 4,458

$141,206

$256,769 (16,274) 86>166 5>113 6>062 13>855 15,084 110,006

$146,763

$52,130 870 54,900 6,756 (2,458)

(700) 3,100 (1,566) 3.233

$116,265

$233,699 (14,926) 74,288 11,896 (406) 12,143 2,397 85,392

$148,307

$22,185 2,479 51,163 (22,523)

(700) 20,746 188 7,312

$80,850

$183,074 (6,431) 54,185 22,376 3,590 10,457 13,319 97,496

$ 85,578 NOTE 10. Nine Mile Point Nuclear Station Unit No. 2 Nine Mile Point Nuclear Station Unit No. 2 (the Unit), a nu-clear power plant being constructed and to be operated by the Company and shared with other utilities, is the only major generating facility currently under construction by the Com-pany. Ownership is shared by the Company (41%) ~ Long Island Lighting Company (LILCO) (18%), New York State Electric &

Gas Corporation (18%), Rochester Gas and Electric Corpora-tion (14%), and Central Hudson Gas & Electric Corporation (9%). Output of the Unit, which will have a projected capability of 1,084,000 kw., is to be shared in the same proportions as the cotenants'espective ownership interests.

Construction Status-Cost and Schedule:

As 1985 came to a close, construction activities at the Unit fell short of what was planned and, as a result, certain key milestones necessary for fuel load were not achieved. As a result, the previously an-nounced February 24, 1986 fuel load date willnot be met. Cur-rent assessments indicate that the fuel load will be ac-complished within ten weeks of the February 24, 1986 date, although no such assurance can be provided. The delay in achieving fuel load will result in a proportionate delay in achieving the October 1986 commercial operation date. The Company has recently completed a revised cost estimate for the Unit, incorporating the impact of the delay in achieving fuel load and current financing cost assumptions, and now esti-mates the total Unit cost will be $5.526 billion (comprised of construction costs of $3.827 billion and AFC of $1.699 billion) with commercial operation now expected to commence January 1987. In January 1985 the cost of the Unit had been estimated to be $5.35 billion (comprised of construction costs of $3.577 billion and AFC of $1.773 billion).The increased cost of the Unit is primarily attributable to delays incurred in com-pleting construction and the consequential effects upon the pre-operational test schedule.

The decline in the amount of AFC included in the current estimate is primarily attributable to the partial inclusion of the Unit's cost in rate base for three of the cotenant companies. The Company's 41% share of the total estimate is approximately $2.287 billion and, as of December 31, 1985, the Company has invested approximately $1.918 bil-lion, including AFC and overheads capitalized.

The primary emphasis of the construction efforts on the Unit is directed towards that work necessary to support the start-up and tests required for fuel load and commercial operation.

Canatom, Inc., independent consultants retained by the PSC, indicated during 1985 that, in their opinion, there could be a delay of four to six months in the October 1986 commercial operation date of the Unit. Also, in a routine analysis for pur-poses of forecasting staffing requirements for licensing ac-tivities, the Staff of the Nuclear Regulatory Commission issued a memorandum in October 1985, indicating its belief that a fuel load date of late 1986 is more probable for the Unit. Certain cotenants in the Unit have also expressed their belief that the previously scheduled commercial operation date of October 1986 may be subject to a delay of up to six months. The Com-pany believes that its revised construction schedule, incor-porating the current delay in fuel load, is achievable and ap-propriate for scheduling the remaining completion effort.

Construction activities early in 1986 include two key mile-stones necessary for fuel load; the loss of power test and the integrated leak rate test. However, as delays have previously occurred with respect to the Unit, the Company can provide no assurance as to the precise date or dates on which various construction milestones, as well as fuel load and commercial operation, will be accomplished.

Any delay in achieving the January 1987 commercial operation date is estimated to add a minimum of approximately $60 million each month to the total cost of the Project (approximately $25 million with respect to the Company's 41%%d share), the major portion of which would be attributable to financing costs. Under either the Cost Set-tlement Proposal discussed below or the $5.4 billion ceiling placed on the Unit by the PSC on July 18, 1984, the Company does not expect the additional costs arising as a result of the delay in fuel load and commercial operation, or costs arising as a result of further delays, if any, to be recoverable through rates.

Cost Settlement Proposal:

In connection with a 1982 PSC proceeding discussed below, which concluded that comple-tion of the Unit is warranted, the PSC stated that it would apply a strict standard of prudence for all costs incurred in complet-ing the project. On July 3, 1985, the PSC issued an Order estab-lishing a proceeding to investigate the appropriateness of costs relating to the construction of the Unit. The Order con-tained an Ordering Clause which required the cotenants to respond within 120 days to specific directives concerning fac-tors which contributed to increases in the cost of the Unit and to provide written descriptions of the programs and techniques employed by the cotenants in managing the project. The Order-ing Clause was suspended pending the resolution of the joint motion discussed below.

On September 18, 1985, the Company and the other coten-ants, together with the Staff of the PSC, filed a joint motion with the PSC seeking approval of an agreement titled "Speci-fications of Terms and Conditions of Offer of Settlement" (Set-tlement) that, if approved by the PSC, would constitute a com-plete disposition of the cost review proceeding. The Settlement has been approved by the PSC Staff and by the management and board ot directors of each of the five cotenants.

The Settlement submitted to the PSC contains the following key terms and conditions:

The maximum amount of the Unit's expenditures to be included in the cotenants'ate bases would be $4.45 bil-lion, and disallowed expenditures would not be less than

$900 millionwith amounts, ifany, above the January 1985 completion cost estimate of $5.35 billion being for the account of the cotenants, except in the case of an "ex-traordinary event" as discussed below. The allowed cost of $4.45 billion will be reduced by the financing costs "prepaid" by ratepayers as a result of rate base inclusion of a portion of the Unit's cost prior to completion. The current cost estimate of $5.526 billion reflects the benefit of about $126 million related to such "prepaid" financing costs, thereby indicating a total disallowance of approx-imately $1.202 billion to be appropriately proportioned to the respective cotenant ownership interests. The Com-pany's share of the disallowed amount is expected to approximate

$490 million, reduced to approximately

$330 million net of federal income tax.

'The cotenants may request from the PSC an upward adjustment of the $4.45 billion cap based only on the occurrence of an "extraordinary event" as contemplated in prior PSC orders concerning the Unit. At the time the agreement was entered into, the cotenants stipulated that they were not then aware of any basis for such a claim.

The rate phase-in of each cotenant's share of a(lowed

~'nit costs is to be included in rate base over a reasonable period, together with accumulated deferred carrying costs on the portion of allowed Unit cost that has not yet been included in rate base.

Appropriate income tax deductions and credits appli-cable to the Unit's completion cost will be allocated to the disallowed costs and reserved for shareholders.

The provisions of the Settlement would be in full satis-faction of the penalty and incentive provisions of the PSC's prior Incentive Rate of Return (IROR) and "cap" orders, discussed below, relating to the Unit.

The cotenants agree not to challenge the legal validity of either the IROR or "cap" orders previously issued by the PSC. In addition, each cotenant would waive any and all claims it may have against any other cotenant con-cerning the design, engineering or construction of the Unit.

On February 24, 1986, the Administrative Law Judges in the proceeding recommended to the PSC that the Settlement be rejected and a detailed cost review of the Unit be undertaken.

While they indicated that although, in their view, the methods used to justifythe Settlement were not sufficiently compelling to warrant its adoption, they also stated that the Settlement may, nevertheless, provide a reasonable basis for concluding the cost review proceeding. Comments responding to their recommen-dations are scheduled to be filed by April 1, 1986 with a decision from the PSC expected in May. Should the PSC ultimately adopt the recommendation of the Administrative Law Judges, a

resumption of the detailed cost review proceeding ordered on July 3,1985, would be expected.

The Company is unable to predict whether or not the PSC willapprove the Settlement or, if approved, to what extent the approval of the Settlement may be appealed.

Under current generally accepted accounting principles, the Company will continue to capitalize all costs, including AFC, associated with the Unit through completion, with recognition over the life of the Unit of disallowed costs resulting from the Settlement. (See discussion below regarding potential changes being consid-ered by the Financial Accounting Standards Board (FASB)).

In December 1985 the PSC issued an Order to LILCO disal-lowing a portion of the cost of LILCO's Shoreham Nuclear Sta-tion. The PSC ordered an immediate write-offof the disallowed amount for ratemaking purposes, but delayed implementation of such a write off pending a submission of an accounting plan for regulatory accounting purposes by LILCO. The Company understands that LILCO intends to ask to reopen the proceed-ings and may seek to stay any write off. The Company is unable to predict whether or not LILCOwill be successful or whether the Company will receive a similar order.

Ratemaking and Financial Accounting Recognition: On April 16, 1982, the PSC, atter an extensive proceeding, issued an opinion and order which stated that completion of the Unit is warranted and indicated the PSC's intention to closely monitor construction activities. Full time PSC Staff are resident on site and, along with PSC retained consultants, monitor the Unit's construction progress and issue periodic reports. The PSC, in 1982, also adopted an incentive rate of return (IROR) program in connection with the remaining construction costs of the Unit which would be implemented as part of the rate proceeding for each cotenant that considers rate,-recognition of the Unit's completion cost. On July 18, 1984, the PSC issued an opinion and order which amended the IROR program to also include a

$5.4 billion ceiling on the Unit's final allowable cost. Under the amended IROR Program, costs incurred in excess of $4.6 bil-lion, but less than $5.4 billion, are required to be borne by 34

cotenant shareholders to the extent of 20/o of the variation in revenue requirements, with costs in excess of $5.4 billionto be borne in total by the cotenant shareholders.

Although it cur-rently appears, assuming a completion cost of $5.526 billion as currently projected, that the imposition of an IROR induced penalty over the expected life of the Unit will not have a mate-rial effect on the Company's financial position or results of operations, no such assurance can be provided. As indicated above under "Cost Settlement Proposal," the approval of the Settlement by the PSC would render the IROR and Cap Orders inoperative.

Based upon the current high cost of large, base-load generating facilities, legislators, regulatory commissions and utilitycompanies nationwide have ordered or are considering the phase-in of these costs over a period of years. In accor-dance with current generally accepted accounting principles, Unit operating and financing costs may be deferrable under a phase-in plan for recovery in the future. In connection with the Company's rate decision dated March 14, 1985, the PSC di-rected the Company to submit, with its next rate filing, rate moderation plans that would phase in the rate impact of the Unit over 3, 5 and 7 year periods. On April 19, 1985 the Com-pany included in a rate case filing applicable to the rate year ended March 31, 1987, one-third of its investment in the Unit with a preference expressed for phasing in the remaining por-tion of the Unit's cost over the two succeeding rate years end-ing March 31, 1988 and 1989. The Staff of the PSC and the Company are in agreement on the methodology to be utilized in the rate implementation of a phase-in plan including recov-ery of deferred costs and carrying charges over the operating life of the Unit. The aspect of the phase-in plan which is pres-ently not agreed upon is whether such plan should be a 3 year phase-in, as proposed by the Company, or a 5 to 7 year phase in as proposed by Staff. The Staff 5 year phase-in is premised on PSC approval of the Settlement discussed above, while their 7 year phase-in presumes no disallowance of plant costs.

The Administrative Law Judges in the proceeding, in their Recommended Decision issued in December 1985, have rec-ommended adopting the PSC Staff's 5 to 7 year phase-in pro-posal. Despite the currently scheduled commercial operation of the Unit in January 1987, the PSC at their public meeting on February 5, 1986 tentatively decided not to commence the phase-in plan during the rate year ended March 31, 1987. A portion of the Unit willcontinue to be reflected as construction work in progress in rate base until that time. However, the PSC adopted the phase-in methodology proposed by the Company and Staff which includes deferral accounting procedures for the Unit's operating costs should they be incurred prior to April 1, 1987. The PSC is still deliberating the length of the phase-in period and the Company is unable to predict at this time over what period of time the phase-in will ultimately be ordered or when it will commence.

The FASB is currently reviewing, among other things, the fi-nancial accounting recognition of disallowed project costs and rate phase-in plans for major capital additions. The FASB has issued for public comment an Exposure Draft concerning these issues and expects to issue a final statement effective for calen-dar year 1987. The Exposure Draft proposes, among other things, rules requiring the immediate write-offagainst income of disallowed costs when it becomes probable such costs will not be recovered in the rate making process and prohibiting the deferral of any costs under a phase-in plan ifthey willnot be fully recovered in rates within ten years from the commencement of the phase-in plan. The Exposure Draft would also require re-troactive application of the accounting requirements included therein and would allow the adoption of such requirements to be reflected in the financial statements of the Company through a restatement of prior periods.

The Company is unable to predict whether the foregoing changes in financial recognition requirements willbe adopted,

, the ratemaking implications of any changes or the impact thereof, if any, on its financial condition or results of opera-tions. However, should the Exposure Draft be adopted in its present form, the Company would be required to write-off ap-proximately $490 million reduced to approximately $330 mil-lion net of federal income taxes. The accounting period to which this write-off would be charged is dependent upon the implementation requirements ultimately adopted by the FASB.

Proposed Legislation: The Governor of the State of New York in January 1985 and 1986, in his annual "Message to the Legislature", indicated he was committed to enacting legisla-tion to, among other things, phase in prudent costs of the Unit, clarify the applicability of the "used and useful" principle as it applies to nuclear units and affirm the PSC's authority to set a cap on total construction expenditures and establish incentive rate of return programs.

In March 1985, the Governor's pro-posals were introduced in the Assembly of the New York State Legislature.'The Assembly legislation would, among other things, establish a $5.1 billion cap on the total construction expenditures for the Unit recoverable in rates, mandate a

phase-in period for cost recovery of not less than five years, clarify the "used and useful" principle to prevent recovery of the cost of nuclear units which do not commence commercial operation and eliminate future construction work in progress allowances for nuclear units. In June 1985, legislation was in-troduced into the Senate which would, among other things, authorize a phase-in of up to five years and direct the Power Authority of the State of New York to purchase LILCO's share of the Unit. The Senate and the Assembly have not reached agreement on any such proposed legislation. The Company is unable to predict whether or not any of the proposed legisla-tion, or additional legislation which may be submitted, will ul-timately be enacted or, if enacted, to what extent they may be subject to legal challenge. Likewise, the overall impact on the Company's financial condition and results of operations of the adoption of any such proposals cannot be predicted.

Emergency

Response

Plan:

Unlike other nuclear plants which have encountered widely publicized local resistance with respect to the development of emergency plans in the event of a nuclear incident, the Federal Emergency Manage-ment Agency approved the Nine Mile Point Emergency Re-sponse Plan (Plan) on February 1, 1985. The Plan encompasses all emergency preparedness activities, including the Emergency Notification System, at Nine Mile Point. Subject to certain testing, the Unit will come under this Plan when it be-gins operation. The Unit is located between two currently operating nuclear plants and the Company has received sub-stantial cooperation from local authorities in connection with the continuing development of this emergency plan.

Nuclear Regulatory Commission-Audits and Licensing:

In April 1985, the Staff of the NRC concluded an assessment of the Unit's overall construction program. The assessment cov-ered the sixteen months ended January 1985 and concluded that notable improvements in management of the project had been made since their 1983 review. Certain areas reviewed by the NRC were noted as being minimallysatisfactory and requir-ing increased NRC and Company attention. The Company ad-dressed the NRC recommendations in a response submitted to the NRC on May 14, 1985. Many of the NRC's recommen-dations had already been adopted and were in the process of 35

implementation before the assessment was received and a

number have already been completed. The Company does not expect that the implementation of these recommendations will materially affect either cost or scheduled completion of the Unit.

As part of the Company's effort to further assure the ade-quacy of installed hardware for its intended use in the Unit, the Company initiated a hardware assessment program in the last quarter of 1984. The final results of this assessment were pre-sented to the NRC Region I during June and July 1985. Based on the evaluation of the inspection results and the corrective actions taken, the Company has concluded that no significant deficiencies exist on installed hardware, and no further reinspection should be required.

On March 11, 1985, the full committee of the Advisory Com-mittee on Reactor Safeguards, an independent committee whose members are selected by the NRC, after completion of its technical review of the Unit, issued a favorable recommen-dation to the NRC as to the ability of the Unit to be operated safely at full power.

Lateiin 1985, the NRC raised questions concerning the en-gineering design of parts of the primary containment at the Unit. The Company and its contractors responded to these NRC questions in early January 1986. Late in January 1986, the NRC indicated that although the engineering design in ques-tion meets substantially all licensing criteria, the Company had not yet demonstrated to the satisfaction of the NRC that the engineering design related to this specific area would be adequate under certain abnormal operating conditions. The NRC indicated that the Company may be able to receive a

schedule exemption, thus allowing licensing, fuel load and commercial operation to take place as currently planned. The Company is applying for a schedule exemption and believes such exemption will be granted, however, no such assurance can be provided.

A number of nuclear power plant construction projects in the United States have encountered substantial delays, licensing difficulties and cost escalation due to a variety of factors. Also, completion of the Unit consistent with its present schedule and cost estimate and the issuance of an operating license could be adversely affected by a wide variety of industry and plant specific construction, operating, regulatory, legislative, economic and other factors.

Although the outcome of the remaining regulatory licensing proceedings relating to the completion of the Unit cannot be predicted with certainty, the Company believes an operating license will be issued upon completion of construction since the Unit is being designed and constructed to meet applicable regulatory requirements.

Notwithstanding the company's belief that an operating license will be issued, if statutory or regulatory restrictions or prohibitions as to the use of nuclear power develop which af-fect the Unit, the Company believes that it would be permitted to amortize its investment in this project, net of any costs disal-lowed, and any related cancellation charges against income and to recover such net investment and related carrying costs through rates over a period of years, although no such assur-ance can be provided.

Note 11. Commitments and Contingencies Construction Program:

At December 31, 1985, substantial construction commitments existed, including those for the Company's share of Unit No. 2 at the Nine Mile Point Nuclear Station. The Company presently estimates that the construc-tion program for the years 1986 through 1990 will require ap-36 proximately $1,712 million, excluding AFC, nuclear fuel and certain overheads capitalized. By years the estimates are $454 million, $314 million, $316 million, $297 million and $331 mil-lion, respectively.

Long-term Contracts for the Purchase of Electric Power: At January 1, 1986 the Company had long-term contracts to pur-chase electric power from the following generating facilities owned by the New York Power Authority (NYPA):

Expiration Purchased Estimated date of capacity annual contract in kw.

capacity cost Niagara hydroelectric project..

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

FitzPatrick-nuclear plant.........

1990 1,111,332

$13,336,000 2002 550,000 (a) 7,220,000 year-to-167,000 (b) 12,664,000 year basis 1,626,332

$33,420,000 (a) In accordance with this contract NYPA has notified the Company that it intends to withdraw up to 260,000 kw of the Company's pur-chase rights effective March 1, 1986, (b) 50,000 kw for summer of 1966; 14,000 kw, for winter of 1986-87.

The purchase capacities shown above are based on the con-tracts currently in effect. The estimated annual capacity costs are subject to price escalation and are exclusive of applicable energy charges.

Mandated Refunds to Customers:

As part of the Company's March 1984 rate decision, the PSC ordered the refund of ap-proximately $96 million of previously collected nuclear fuel disposal costs over a five-year period. The Company had col-lected in rates approximately $146 million for the disposal of nuclear fuel irradiated prior to 1983. The refund represents the amount these previously collected costs were in excess of the company's liabilityas of March 31, 1984 to the U.S. Department of Energy for nuclear fuel disposal under the Nuclear Waste

'olicy Act. At December 31, 1985, $80 million remains to be refunded and is recorded in deferred credits.

Litigation: In August 1983, the PSC instituted a proceeding to investigate the Company's operating practices and certain other matters that it is alleged may have resulted, among other things, in excessive fuel adjustment charges in previous periods; and, further, to determine whether and to what extent remedial action with respect to any such matters is proper under the PSC's-regulations or otherwise. In March 1985, the PSC ordered the refund of approximately $32.5 million, which incorporates interest charges, over a twelve month period. The Company charged 1984 and 1985 earnings for $20.0 million and $12.5 million, respectively, net of taxes. The Company has appealed this decision to the Supreme Court, Appellate Di-vision, Third Department. Oral argument was held in January 1986. The Company is unable to predict the outcome of this matter.

Advances on Behalf of Nine Mile Point Nuclear Unit No. 2 Cotenant: In August 1984, the Company and Long Island Light-ing Company (LILCO)entered into an agreement (LILCO Bond Agreement) providing for the issuance by LILCOof up to $250 million in General and Refunding Bonds (the LILCO Bonds) to evidence and secure LILCO's repayment obligation for funds advanced by the Company on behalf of LILCOfor its 18%%d own-ership in the'Unit.

The LILCO Bonds mature on August 1, 1993, with mandatory quarterly sinking fund payments beginning November 1, 1989, and carry a stated interest rate of 0.5%%d.TheLILCOBond Agreement also requires supplemental payments at the rate of 0

18.5% on the LILCO Bonds issued to the Company. Although interest and supplemental payments are due quarterly, the LILCO Bond Agreement provides that supplemental payments may be deferred and evidenced by the issuance of unsecured notes equivalent to such deferred supplemental payments. The unsecured notes bear interest at 19/o, which may also be de-ferred and added to the principal of the unsecured notes. Sub-sequent to the earlier of (i) commencement of commercial op-eration of the Unit, (ii) August 1, 1987, or (iii) assignment by LILCO of any of its interest in the Unit to a third party, the supplemental payments and interest payments on the unse-cured notes willbe payable in equal quarterly installments over a maximum period of four years. Interest and supplemental payments on the LILCO Bonds along with interest on the unse-cured notes amounted to $40.6 million for 1985.

On December 31, 1985, the Company and LILCOentered into a second agreement (Capital Funds Agreement) whereby the Company provided its guarantee for a period of approximately three years through March 31, 1989, of up to $165 million of LILCO's reimbursement obligations to Citibank, N.A., and Bankers Trust Company as issuers of,letters of credit providing credit enhancement for LILCO's tax exempt debt. On De-cember 31, 1985 LILCOissued $150 million principal amount of such tax-exempt pollution control bonds. $144.9 million of the proceeds from the sale of the bonds was paid to the Company on December 31, 1985, and applied as follows: (i) repayment of

$25 million of the LILCO Bonds, (ii) repayment of $34.9 million of the unsecured notes, and (iii) $85 million to be applied to LILCO's share of cash construction costs for the Unit com-mencing November 18, 1985 through completion of the Unit.

After being reduced by $13.6 millionfor advances plus interest through December 31, 1985, the proceeds provide the Com-pany with $71.4 million at December 31, 1985, to be applied against future LILCO cash advance requirements.

Construc-tion cost requirements in excess of amounts provided under the LILCO agreements, which would total approximately $17 million under the present cost estimate and the currently scheduled commercial operation date would continue to be an obligation of LILCO under the Basic Agreement entered into in September 1975. The Company has agreed to waive interest and supplemental payments on a principal amount of LILCO Bonds equal to the daily unused portion of such $71.4 million as construction continues during 1986. LILCO's portion of cash construction costs subsequent to December 31, 1985, are presently estimated to be $88 million.

The Company expects LILCOto honor its obligations in con-nection with the bonds throughout the next three years while the guarantee is in effect. The Company has arranged for four-year term loans with the letter of credit banks to fund its guarantee obligation, if needed.

Also, the Company has re-quested an $85 million third mortgage from LILCO which would serve as partial security in the event its guarantee is required to be honored. LILCO is required to pay fees to the Company in connection with the guarantee.

At December 31, 1985, the Company held $225 million in LILCO Bonds and $7.2 million in unsecured notes and re-corded a current liabilityfor the $71.4 million construction ad-vance from LILCO.

If all supplement payments were deferred by LILCO, and as-suming the Company sells $140 million of the LILCO Bonds, the outstanding unsecured note balance would be approxi-mately $63 million at the currently scheduled commercial operating date of the Unit. The acquisition of the LILCO Bonds and unsecured notes was approved by the PSC and the FERC in October 1984.

Dec. 31, 1985 1964 1983 Sept.30, 1985 1964 1963

$661>237 675,069 658,733

$554>779 606,437 562,707

$84,791 81,165 76,824

$73>095 66,421 72,309

$91>724

$.61 59,708

.39 64,081

.52

$79>503

$.52 64,636

.66 62,376

.52 June 30, 1965 1984 1963 March 31

~ 1965 1964 1963

$637,724

$100,036 696,325 101,319 651,467 92,266

$841,200

$153,366 607,695 123,601 759,386 113,296

$96,758

$.67 94,197

.77 79,027

.72

$143,445

$1.11 121,193 1.04 106,925 1.03 NOTE 13. Supplementary Information to Disclose the Effects of Changing Prices (Unaudited)

With increasing governmental deficit spending, the threat of inflation resulting in a decline in the purchasing power of the dollar and its negative impact on all sectors of the economy continues. The Company's consolidated financial statements are based on historical events and transactions when the pur-chasing power of the dollar was substantially different from the present. The effects of inflation on most utilities, including Niagara Mohawk, are most significant in the areas of deprecia-tion and utilityplant and amounts owed on borrowed funds.

In recognition of the fact that users of financial reports need to have an understanding of the effects of inflation on a busi-ness enterprise, the following supplementary information is supplied for the purpose of providing certain information about the effects of both changes in specific prices and gen-eral inflation. It should be viewed as an estimate of the approx-imate effect of inflation, rather than as a precise measure.

Current cost amounts reflect the changes in specific prices of plant from the date the plant was acquired to the present.

The current cost of utility plant, net of accumulated deprecia-tion and amortization;>represents the estimated cost of replac-ing existing plant assets in kind. Since existing utility plant is not expected to be replaced precisely in kind due to technolog-The LILCO Bond and Capital Funds Agreements do not in any way modify LILCO's obligations associated with its 18'/o owner-ship interest in the Unit, pursuant to the Basic Agreement en-tered into in September 1975, which remains in full force and effect. Also, neither agreement precludes participation in the Unit by another party or the sale of LILCO Bonds.

Irrespective of the LILCO Bond and Capital Funds Agreements, under certain circumstances it is possible that the Company would be unable to recover in full the advances made on behalf of LILCO, whether secured, unsecured or otherwise.

However, the Company believes that the LILCO Bond and Capital Funds Agreements provide the best security available at this time and the ultimate recoverability of the LILCO advances has been and will be substantially enhanced by such agreements.

NOTE 12. Quarterly Financial Data (Unaudited)

Operating revenues, operating income, net income and earn-ings per common share by quarters for 1985, 1984 and 1983 are shown in the following table. The Company, in its opinion, has included all adjustments necessary for a fair presentation of the results of operations for the quarters. Due to the seasonal nature of the utilitybusiness, the annual amounts are not gen-erated evenly by quarter during the year.

In thousands ofdollars Operating Operating Net Earnings per revenues income income common share 37

ical changes, current cost does not necessarily represent the replacement cost of the Company's utilityplant. The portion of the accumulated amortization relating to disposal costs of nu-clear fuel wa's not used in the calculation of current costs but rather reclassified to a monetary liability. In most cases, cur-rent costs were determined by indexing surviving plant dollars by the Handy-Whitman Index of Public Utility Construction Costs. However, when an account could not be indexed by Handy-Whitman, other appropriate indices were used. The cur-rent year's provision for depreciation and amortization on the current cost amount of utilityplant was determined by applying the Company's average annual depreciation rates to the in-dexed plant amount.

Fuel inventories, the cost of fuel used in generation, and electricity and gas purchased have not been restated from their historical cost in nominal dollars. The recovery of energy and purchased gas costs, in base rates or through the operation of the Company's electric and gas adjustment clauses, is limited to historical costs.

For this reason fuel inventories and de-ferred recoverable energy costs are effectively monetary assets.

Income taxes have not been adjusted.

The Company is subject to the jurisdiction of regulatory commissions in the determination of a fair rate of return on its investment. Current ratemaking policy provides for the recov-ery of historical costs. Therefore, any difference between the historical cost of utilityplant stated in terms of current cost not presently includible in rates as depreciation, is reflected as an increase (reduction) to net recoverable cost. While the ratemaking process gives no recognition to the current cost of replacing utility plant, based. on past practices, the Company believes it will be allowed to earn on the increased cost of its net investment when replacement of facilities actually occurs.

To properly reflect the economics of rate regulation in the Statement of Income from Continuing Operations, the increase (reduction) of net utilityplant to net recoverable cost should be adjusted by the gain from the decline in purchasing power of net amounts owed on borrowed funds. During a period of infla-tion, holders of monetary assets suffer a loss of general pur-chasing power while holders of monetary liabilities experience a gain. The gain from the decline in purchasing power of net amounts owed is primarily attributable to the substantial amount of debt which has been used to finance utility plant.

Since the depreciation on this plant is limited to the recovery of historical costs, the Company does not have the opportunity to realize a holding gain on debt and is limited to recovery only of the embedded cost of debt capital.

Statement ofincome from continuing operations adjusted forchanging prices for the year ended December 31, 1985 In thousands ofdollars

(.

Conventional Current cost historical cost average 1985 dollars Operatin revenues Fuel forelectric generation Electricity purchased Gas purchased.

Depreciation and amortization Other operating and maintenance expenses Federal and foreign income taxes Interest charges.

Other income and deductions net.

Income from continuing operations (excluding adjustment to net recoverable cost)

Increase in specific prices of utilityplant held during year' Adjustment to net recoverable cost Effect of increase in general price level.

Excess of increase in specific prices over increase in general price level after adjustment to net recoverable cost Gain from decline in purchasin power of net amounts owed Net

$2,694,940 391,382 367,406 411,801 150,627 788,965 173,471 220,996 221,138 2,283,510 411,430

$2,694,940 391,382 367,406 411,801 435,955 788,965 173,471 220,996 (221,138) 2,568,838 126,102 395,969 196,509 (542,791) 49,687 106,734 156,421

'At December 31, 1985, current cost of utility plant, net of accumulated depreciation, was $11,042,802 while historical cost or net cost recoverable through depreciation was $6,011,468.

Five year comparison of selected supplementary financial data adjusted for effects of changing prices.

In thousands ol average 1985 dollars For the year ended December 31 ~

1985 1984 1983 1982 1981 Operatin revenues Current cost Informatioru Income (loss) from continuing operations (excluding adjustment to net recoverable cost)

Income(loss) percommonshare(afterdividendrequirementson preferred stock and excluding adjustment to net recoverable cost)

Excess (deficiency) of increase in general price level over increase in specific prices after adjustment to net recoverable cost..........

Net assets at year end at net recoverable cost General Informatloru Gain from decline In purchasing power of net amounts owed Cash dividends declared per common share Market price per common share at year end Average consumer price index

$2,694,940

$2,884,934

$2,842,265

$2,667,842

$2,543,911 S

126,102 95,876 86,160 86,710 22,640 S

.54

.39

.41

.51 S

(.22)

(49,687)

(41,189)

S (58,876)

S (39,736) 151,488

$2,734,488

$2,462,217

$2,319,145

$2.083,335

$1,909,088 S

106,734 113,679 S

95,573 S

89,776 204,355 S

2.06 2.05 2.04 S

1.96 1.90 20.50 17.99 17.01 17.41 14.64 322.2 311.2 298.4 289.1 272.4 38

p o

'~RELETfFD FlNANCIALDATA j

I t~ (

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

Dividend payout ratio Capitalization: (000's)

Common equity Non-redeemable preferred stock Redeemable preferred stock Long-term debt 1985 1984 1983 1982 1981

$19.61 20'/2 104.P/o 10.1%

$ 2.88 15.tP/o

$ 2.06 71.P/o

$18.89 17%

92.(P/o 11.P/o

$ 2.84 14.PYo

$ 1.98 69.7Yo

$18.55 153/4 84.9/o 12.2'/o

$ 2.77 15.(P/o

$ 1.89 68.2/o

$17.91 155/8 87.2'/o 11.P/o

$ 2.64 14.7Yo

$ 1.76 66.7'/o

$17.36 12%

71.3o/o 13.P/o

$ 2.35 13.P/o

$ 1.61 68.P/o

$2,488,620

$2,207,117

$1,929,073

$1,680,650

$1,457,934 290,000 240,000 240,000 210,000 210,000 379,850 367,900 338,474 262,792 254,748 2,643,094 2,395,471 2,048,548 1,881,441 1,663,671

$2,694,940

$2,785,546

$2,632,315

$2,393,771

$2,150,718 411,430 359,734 312,409 268,534 220,643 Total First mortgage bonds maturing within one year 5,801,564 5,210,488 4,556,095 30I000 47,450 25,000 4,034,883 3,586,353 65,000 Total

$5,831,564

$5,257,938

$4,581,095

$4,099,883

$3,586,353 Capitalization ratios: (inciuding first mortgage bonds maturing within one year):

Common stock equity Preferred stock Long-term debt 42.7Yo 11.5 45.8 42.(P/o 11.5 46.5 42.1%

12.6 45.3 41.(P/o 40.7'/o 11.5 12.9 47.5 46.4 Financial ratios:

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

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

Ratio of AFC to balance available for common stock..

Ratio of earnings to fixed charges and preferred stock dividends Other ratios-% of operating revenues:

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

Maintenance and depreciation Total taxes Operating income Balance available for common stock..............

3.07 2.37 53.2/o 2.36 43AYo 10.9 15.7 15.3 13.1 3.11 2.43 52.4%

2.39 46.P/o 10.1 14.7 14.1 11.1 2.98 2.40 43.P/o 2.35 50.(P/o 10.0 13.0 13.5 10.3 2.95 2.42 41.tP/o 2.32 49.8o/o 10.5 13.2 13.2 9.6 2.63 2.16 38.P/o 2.10 52.7o/o 10.3 11.2 12.6

8.7 Miscellaneous

(000's)

Gross additions to utilityplant Total utilityplant Accumulated depreciation and amortization Total assets 771,120 769,846 691,464 594,469 457,415 7)640,905 6,903,184 6,165,711 5,516,532 4,985,315 1,629,437 1,501,282 1,486,196 1,389,112 1,304,436 7,013,837 6,233,401 5,357,572 4,781,767 4,220,234

ELECTRIC ANDGAS STATISTICS ELECTRIC CAPABILITY Thousands ofkilowatts AtJanuary 1 ~

1986 1985 1984 ELECTRIC STATISTICS 1985 r.

1984 1983 Thermal:

Coal fuei Huntley, Niagara River..

Dunkirk, Lake Erie.....

Total coal fuei..

Residual oiifuel Albany, Hudson River".

Oswego, Lake Ontario..

Roseton, Hudson River Middie distillate oiifuel 20 Combustion turbine and diesel units........

Total oiifuel Nuclear fuel Nine Mile Point, Lake Ontario....

Purchased firmcontract Power Authority-FitzPatrick, Lake Ontario......

Totainuciear fuei...

Total thermal sources...

715 9

715 715 555 7

555 550 1,270 16 1,270 1,265 400 5

400 400 1,736 22 1,736 1,736 300 4

300 300 310 4

310 310 2,746 35 2,746 2,746 610 8

610 610 8167 2

138 139 777 10 748 749 4,793 61 4,764 4,760 550 7

550 550 209 3

63 63 Hydro:

Owned and leased hydro stations (83).

695 9

695 695 Purchased-firm contracts PowerAuthorityNiagaraRiver....

1,111 14 1,118 1,118 Power Authority-St. Lawrence River..............

115 115 Power Authority Blenheim-Gilboa Pumped Storage Plant...........

Other Electric sales(Millions ofkw-hrs.)

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

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

Industrial..................

Municipal service..........

Other electric systems......

8>976 9,907 10,886 241 5,286 35,296 Electric customers(Average)

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

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

Industrial.>..................

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

Residential (Average)

Annual kw-hr. use per customer............

Cost to customer per kw-hr..

Annual revenue per customer............

1,273,969 134,787 2,490 3,315 1 >414>561 7,046 7.21/

$508.26 Electric revenues(Thousands ofdollars)

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

647,507 Commercial...............

708,517 Industrial..................

437,292 Municipal service..........

39,238 Other electric systems......

196,104 Miscellaneous.............

67,746

$2>096>404 8,944 9,739 11,194 245 6,964 37,086 607,527 674,929 438,920 37,846 303,968 71,280

$2,134,470 1,259,077 133,234 2,522 3,279 1,398,112 7,104 6.79ff

$482.52 8,578 9,387 8'0,860 251 5,656 34,732 583,645 658,960 441,219 36,466 235,257 68,181

$2,023,728 1,245,590 131,803 2,594 3,257 1,383,244 6,887 6.80II

$468.57 Total h dro sources...

Other purchases..

Totalcapability',565 33 2,541 2,541 445 6

400 400 7,803 100 7,705 7,701 GAS STATISTICS 1985 1984 1983 Electric peak load during year 1985 5,862 1984 1983 5,526 5,625

• Available capability can be increased during heavy load periods by purchases from neighboring interconnected systems.

Hydro station capability is based on average December stream-flow conditions.

-Has capability to burn natural gas (as well as oil) as a fuel.

49,519 27,892 32,755 4,794 46,865 26,921 25,736 3,631 108,420 114,960 103,153 Gas sales(Thousands ofdekatherms)

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

47,328 Commercial...............

27,006 Industrial..................

29,213 Other gas systems..........

4,873 Thermal:

Generated Coal............

Oil............,.

Nuclear.........

Natural gas......

Purchased Nuclear from Power Authority..

7,409 19 7,863 20 7,873 21 2,866 7

3,754 9

4,313 11 4,932 13 3,635 9

2,802 7

1,624 4

2,103 5

1,839 5

825 2

878 2

790 2

ELECTRICITYGENERATED ANDPURCHASED Millionsofkw-hrs.

1985 1984 1983 Gas customers(Average)

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

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

Industrial.................

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

404,116 32>603 485 2

437>206 Gas revenues(Thousands ofdollars)

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

$295,060 Commercial...............

147,751 Industrial..................

133,446 Other gas systems..........

18,691 Miscellaneous.............

3,588

$598,536

$313,536 157,469 156,307 19,708 4,056

$651,076 400,878 32,106 502 2

433,488

$304,157 155,858 129,056 15,783 3.733

$608,587 398,597 31,697 524 2

430,820 Total thermal Hydro:

Generated.........

Purchased from Power Authority..

Totaih dro....

17,656 45 18,233 45 17,617 46 3,496 9

3,803 9

3,527 9

7,815 20 8,312 21 7,587 20 11,311 29 12,115 30 11,114 29 Total generated and purchased 39,213 100 40,588 100 38,352 100 Other purchased power-various sources......

10,246 26 10,240 25 9,621 25 Resldentlal(Average)

Annual dekatherm use per customer........

Cost to customer per dekatherm.......

Annual revenue per customer........

Maximum day gas sendout dekatherms 117.1 123.5 117.6

$6.23

$6.33

$6.49

$730.14

$782.12

$763.07 774,033 772,604 754.061 40

r Directors James Bartlett Formerly Executive Vice President, Syracuse Edmund M. Davis (A, B, E)

Partner, Hiscock 8s Barclay, attorneys-at-law, Syracuse WilliamJ. Donlon President, Syracuse Edward W. Duffy(A,B, C)

Former Chairman ofthe Board and Chief Executive Officer, Marine Midland Banks, Inc., a bank holding company, Buffalo John G. Haehl, Jr. (A)

Chairman ofthe Board and Chief Executive Officer, Syracuse Edwin F. Jaeckle (A, B)

Senior Partner, Jaeckle, Fleischmann 8s Mugel, attorneys-at-law, Buffalo (Resigned February 28, 1985)

Lauman Martin Consultant (formerly Senior Vice President and General Counsel), Syracuse Baldwin Maull(A,B)

Corporate Director, New York Martha Hancock Northrup (D)

Homemaker, former President, Crouse-Irving Memorial Hospital Board, Syracuse Frank P. Piskor(A, C, D)

President Emeritus, St. Lawrence University, Canton Donald B. Riefler(E)

Chairman, Sources and Uses ofFunds Committee, Morgan Guaranty Trust Company ofNew York, New York Lewis A. Swyer(B, C, D)

Chairman, L. A. Swyer Co., Inc., builders and construction managers, Albany John G. Wick(D,E)

Partner, Falk 6s Siemer, attorneys-at-law, Buffalo A. Member ofthe Executive Committee B. Metnber ofthe Compensation Committee C. Member ofthe AuditCommittee D. Member ofthe Committee on Corporate Public Policy E. Member ofthe Finance Committee Officers John G. Haehl, Jr.

Chairman ofthe Board and Chief Executive Officer WilliamJ. Donlon President Richard C. Clancy Senior Vice President (RetiredJanuary 31, 1985)

John M. Endries Senior Vice President John M. Haynes Senior Vice President John P. Hennessey Senior Vice President Charles V. Mangan Senior Vice President James J. Miller Senior Vice President John H. Terry Senior Vice President, General Counsel and Secretary Richard F. Torrey Senior Vice President James F. Aldrich Vice President-Regional Operations Anthony J. Baratta, Jr.

Vice President-Controller Michael J. Cahill Vice President-Regional Operations Robert M. Cleary Vice President-Regional Operations Gerald J. Currier Vice President-Consumer Services KermitE. Hill Vice President-Public Affairs and Corporate Communications Edward F. Hoffman Vice President-Fossil Generation Raymond Kolarz Vice President-Regional Operations (Retired December 31, 1985)

Thomas E. Lempges Vice President-Nuclear Operations Donald L MacVittie Vice President-Fossil Generation (Retired December 31, 1985)

Samuel F. Manno Vice President-Purchasing and Materials Management Eugene J. Morel Vice President-Risk Management James F. Morrell Vice President-Corporate Planning James A. Perxy Vice President-Quality Assurance John W. Powers Vice President-Treasurer Michael P. Ranalli Vice President-Engineering (Non-nuclear)

Kenneth A. Tramutola Vice President-Gas Christopher D. Turner Vice President-Corporate Development Perzy B. Woods, Jr.

Vice President-Employee Relations Herman B. Noll Assistant General Counsel Nicholas L Prioletti, Jr.

Assistant Controller Adam F. Shaffer Assistant Controller Henry B. Wightman, Jr.

Assistant Controller Harold J. Bogan Assistant Secretary Joseph F. Cleary Assistant Secretary Frederick C. McCall,Jr.

Assistant Secretary ArthurW. Roos Assistant Treasurer Richard N. Wescott Assistant Treasurer Corporate Information Dividend Reinvestment Plan Shareholders desiring information on enrolling in the Dividend Reinvestment and Stock Purchase Plan should write or call our Shareholder Sexvices Department, 300 Erie Boulevard West, Syracuse. NY13202.

Telephone Inquiries We maintain a toll-free telephone inquiryservice for stockholders. Callers from outside New YorkState may dial 1+800+448-5450. The number forNew York residents is 1+800+962-3236.

Annual Meeting The annual meeting ofstockholders willbe held May 6, 1986 at the Company's main office in Syracuse. Anotice ofmeeting, proxy statement and form ofproxy willbe sent to holders ofcommon stock in early ApriL Disbursing Agent Preferred, Preference and Common Stocks:

Niagara Mohawk Power Corporation 300 Erie Boulevard West. Syracuse, N.Y. 13202 Transfer Agents Preferred Stock and Preference Stock:

Marine Midland Bank, N.A., 140 Broadway, New York, N.Y. 10015 Common Stock:

Morgan Guaranty Trust Company ofNew York, 30 W. Broadway, New York, N.Y. 10015 Stock Exchanges Common and Certain Preferred Ser fest

, Listed on New YorkStock Exchange Common Stock: Also traded on Boston, Cincinnati, Midwest, Pacific and Philadelphia stock exchanges.

Bonds: Traded on New Yorkand Luxembourg stock exchanges.

Ticker symbol: NMK Form 10-K Report Acopy ofthe Company's Form 10-K report filedannually with the Securities and Exchange Commission is available after March 31, 1986 by writingJohn W. Powers, Vice President-Treasurer at, 300 Erie Boulvard West, Syracuse, N.Y. 13202 The tntonnetlcn in this report is not given in connection withthe saic of. or ofter to buy. any secvrity Printed In U SA.

41

H T NIAGARA U MOHAWK 300 Erie Boulevard West Syracuse, New York 13202 The upper Raquette River flows serenely at Jamestown Falls, St. Lawrence County. Adirondack watersheds supply nearly a billionkilowatt-hours of hydro power yearlyclean, renewable energy for our customers at reasonable cost.

NIAGARAMQHAWKPQWER CGRPGRATIQN ANNUALREPQRT 1986

'"fjlxe Mixe Mxlle'll'mo coxxstvzctxoxx em xs nmxly lbekxndl us. We xxoev face Qxe futuxe wAtlhz fimoai resolve, dledlxcatedl to pxotecthxg sxxdl zeiunfoxchxg the AHfiixxaxxcxajl stxexxgxjh ofoux conxpaxxy... "

Serving upstate Nevr York Our Corporate Mission Ranked as one the most prominent investor-owned utilities in the United States, Niagara Mohawk Power Corp. serves an area encompassing more than half the land mass ofNew York State. Our electric system extends from Lake Erie to New England's borders, from Canada to Pennsylvania, and meets the diversified needs ofmore than 1.4 millioncustomers. Our natural gas system serves 445,000 customers in central, east-ern and northern New York, nearly all withinour electric territory. Two Canadian companies, St. Lawrence Power Co.

and Canadian Niagara Power Company, Ltd., owned by our subsidiary, Opinac Investments, Ltd., provide energy to portions ofOntario. Other subsidiaries are Hydra-Co Enter-prises, Inc., N M Uranium, Inc., Niagara Mohawk Finance, N.V. and Opinac Energy, Ltd. Our corporate headquarters are at 300 Erie Boulevard West, Syracuse, N.Y. 13202.

~ ELECTRIC LJ SERVICE AREA Sy

~

NEW YORK STATE Niagara Mohawk is an energy company with diversified interests and resources committed to meeting customers'eeds through econom-ical products and services ofsuperior quality.

We are dedicated to providing a fairand equitable return to shareholders. In this period ofincreasing competition and chang-ing regulation, we willstrive to be the low-cost supplier ofreliable energy while develop-ing and marketing new products.

The dedicated, well-trained men and women ofNiagara Mohawk are the company's most valuable resource. The company's suc-cess is directly dependent on their efforts.

Management remains committed to retaining and motivating this talented, productive, ef-fective work force by providing reasonable compensation, incentives and a good working environment.

Niagara Mohawk seeks ways to improve the economic climate and well-being ofcitizens, industry and business within the com-munities itserves, and advocates regulatory and legislative changes that best serve the interests ofcustomers, employees and owners.

The company maintains high ethical stan-dards and strives foropen communications with all its constituencies.

Niagara Mohawk is dedicated to maintain-ing and further developing dependable energy resources and delivery systems that are safe, environmentally sound and technologically advanced.

Management willactively pursue strategies in support ofobjectives to accomplish this mission.

NATURALGAS D SERVICE AREA NEW YORK STATE

NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES Highlights of 1986 1966 1985 Change Total operating revenues Income available forcommon stockholders...............

Earnings per common share Dividends per common share Common shares outstanding (average)

Utilityplant (gross)..

$ 2,660,319;000

$ 2,694,940,000 (1.3) 344,048,000 351,871,000 (2.2)

$2.71

$2.88 (5.9)

$2.08

$2.06 1.0 12?,0?6,000 122,215,000 4.0

$ 8,445,993,000

$ 7,640,905,000 10.5 Electric peak load (kilowatts) 5,724,000 5,862,000 (2.4)

Natural gas sales (dekatherms)...

95,94?,000 108,420,000 (11.5)

Natural gas transported (dekathef7ns)...........

Gas customers at end ofyear 4,868,000 445,000 440,000 1.1 Construction work in progress...

$ 2,820,044,000

$ 2,336,188,000 20.7 Gross additions to utilityplant..

774,062,000 771,120,000 0.4 Kilowatt-hour sales............

34,347,000,000 35,296,000,000 (2.7)

Electric customers at end ofyear.

1,443,000 1,424,000 1.3 Contents 2 To our stockholders 4 Theyearinreview 11 Market price ofcommon stock and related stockholder matters 12 Management's discussion and analysis of financial condition 17 Consolidated financial statements 21 Notes to consolidated financial statements 33 Report ofindependent accountants 33 Report ofmanagement 34 Statistics 36 Directors, officers, corporate information Maximum day gas sendout (dekatherms)...........

~.

786,165 774,033 1.6 EARNINGS ANDDIVIDENDS PAID PER COMMONSHARE RANGE ANDYEAR END MARKET PRICE OF COMMON STOCK

$2.64

$2.77

$1.76

$189

$ 1.98

$2.84

$2.06

$2.88

$2.08

$2.71 DIVIDENDS EARNINGS

$ 15%

p

$ 15rA

$ 15y<

$ 1749

$20%

$ 16V4 ATYEAR END

$25yr RANGE

$2tr/e

$ 17V4

$161'15y 1982 1983 1984 1985 1986 1982 1983 1984 1985 1986 1986 REVENUE DOLLAR Residential customers 38II Commercial customers 34II Industrial customers 19II Allothers 9II ANDWHERE ITWENT Fuel forthe production of electricity 25tf and electricity purchased Income and other taxes 18II Gas purchased 13II Wages, salaries,employeebenefits 12II Dividends to stockholders 128 Interest and other costs-net I 1 if Depreciation 6II Retained In business

2 NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES To our stockholders:

Earnings were $2.71 per share ofcommon stock in 1986, compared with $2.88 per share in 1985. This decrease resulted primarilyfrom a reduction early in 1986 in earnings return on common equity allowed by the N.Y. State Public Service Commission from the 15.5 percent previously authorized to 13.5 percent.

We are especially concerned about this continued lowering ofauthorized return and early in 1987, as ongoing rate-case proceedings neared completion, we reinforced our petitions to the commission to grant us a fair return on equity. Recommendations by other parties in the rate case thus far have been signifi-cantly below the average return granted to utilities in other states-leaving you, our shareholders, at a severe disadvantage.

Maintaining the dividend Atthe year end, we were pleased to pay our 148th consecutive dividend on our common stock since Niagara Mohawk's consolidation in 1950. Every effort is being made to maintain the current stock dividend level, despite pending regulatory uncertainties and the many challenges we face in bringing Nine Mile Point Nuclear UnitTwo to operational readiness.

Our determination to achieve authorized earnings levels is evidenced by an extensive austerity program, initiated in 1986 with additional measures likelyto followthis year. A freeze on management salaries and the size ofthe workforce, abolition ofvacant positions, reduced overtime, redemption ofhigh-cost debt and other securities, and tightening ofexisting cost constraints-these and other restrictions prevail throughout our business.

Nine MileTwo operation delayed by faulty valves We were disappointed in February when difficulties encountered withmain steam-isolation valves com-pelled us to postpone the commercial operation date ofthe Nine MileTwo project. At this writing,every avenue is being pursued to rectify these problems, enabling us to expeditiously proceed toward produc-tion offirst power forour customers. Atpress time, the effect ofthe situation on the project schedule re-mains under continuing assessment.

Stockholders willbe kept advised ofdevelopments.

We have every confidence that Nine MileTwo, once in service, willearn recognition as a quality addition to New York State's energy picture. With the unit on line and in rates, Niagara Mohawk's residential elec-tric rates willcontinue to be the lowest among the state's major utilities, a fact in which we can take justifiable pride. As you know, Niagara Mohawk's share in the project is 41 percent.

Asettlement agreement for Nine MileTwo, pro-posed jointlyby Niagara Mohawk and the unit's co-tenants, was approved in early October by the Public Service Commission. The agreement "caps" costs re-

NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES 3

coverable through customer rates at $4.16 billion.

Niagara Mohawk's share ofcosts disallowed would amount to approximately $ 1 billion,before reduction forfederal income tax benefits. Both the timing and the amount ofloss to be written offby the company are contingent upon pending regulatory decisions, loan covenants and finalcompletion cost.

Rate recognition ofthe Nine MileTwo project and implementation ofthe cost settlement have been in-tegral parts ofour pending electric rate case, before the PSC since April 1986. We do not expect a final decision from the PSC on the rate case until March 1987, but we shall continue to keep stockholders in-formed through periodic reports. (More detailed dis-cussions ofNine MileTwo and related financial and regulatory affairs are presented on pages 4, 13, 29.)

Leading the way withinnovation Our financing activities in 1986 were highlighted by innovation, with impressive results. A"reverse dutch auction" tender offer (first-ever by a utility)resulted in the cost-effective retirement of $ 153 millionof high-coupon bonds (some as high as 15'/4 percent).

Cash proceeds from the sale/leaseback ofa newly con-structed high-voltage transmission facilitywere also used to retire high-cost long-term debt by another

$ 114 million,while a $6-millionreduction was achieved in preferred stock dividends through calls and refundings during the year.

Creative innovations our patented Power Donut' system and our PCB-removal process, for instance, discussed on page 6 are generating practical bene-fits forboth the company and others in the energy industry. In all planning, we are intent on seeking new and better concepts, sometimes venturing to new frontiers oftechnology. The tangible results and pros-pects are discussed in the followingpages-achievements which have earned Niagara Mohawk national recognition as a company ofinnovators. In the same bold spirit, we have embarked upon new marketing, diversification and competitive ventures to position ourselves for tomorrow's opportunities.

Confidence in our future Our confidence in charting a steady course through these often frustrating but ever-challenging times is rooted in the proven resourcefulness and resilience of the men and women ofNiagara Mohawk. The Nine MileTwo construction era is nearly behind us. We now face the future with a firmresolve, dedicated to protecting and reinforcing the fullfinancial strength ofour company and providing our customers the quality energy service they expect, at the lowest pos-sible price.

Our heartfelt thanks are extended to our stockhold-ers for their support, and to our fellow employees for their sacrifices, hard work and continuing loyalty.

al r$

rJ:

John G. Haehl, Jr.

Chairman ofthe Board and ChiefExecutive Officer 1VilliantJ. Donlon President February 27, 1987 John G. Haehl, Jr.

WilliamJ. Donlon

4 NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES The year in review Nine MileTwoapproaching its time A long-awaited milestone took place in October 1986 at the Nine MilePoint Nuclear UnitTwo project when the U.S. Nuclear Regulatory Commission issued a low-power license and loading ofthe plant's uranium fuel was completed in 14 days one week ahead of schedule.

However, recurring problems with the unit's eight main steam-isolation valves subsequently required delaying initialstartup operations and, in late Feb-ruary, extensive tests ofthe valves were still in prog-ress. The tests willhelp determine whether to modify the valves or replace them altogether, and until this situation is resolved the date ofthe plant's commer-cial service remains pending.

Once this condition is corrected, the unit is scheduled to "go critical"withinitialnuclear fission achieved. Five weeks oftesting at low power willthen followand, after issuance ofa full-power license by the NRC, its output willbe brought up to 150,000 kilowatts. This willgradually be stepped-up to full power capacity during a series ofpower ascension tests and inspections.

With Nine MileTwo an operating nuclear station (the 104th to be licensed in the United States), this 1.08-million kilowatt addition to our power system and the New YorkPower Pool willmark the culmina-tion ofa long and arduous course. The project will serve nearly four millioncustomers ofits five par-ticipating utilitesthis decade and next, and well into the next century ahead. Nine MileTwo repre-sents modern nuclear technology, epitomizing the state of the art.

In October, 1986, an emergency exercise, involving New York State and Oswego County representatives and observed by the Nuclear Regulatory Commission, was conducted at Nine MileTwo. The realistic day-long drill,in which a radiological accident at the plant was simulated, was a requirement for licensing and received approval from the NRC.

Operation ofthe new plant willbe the responsibil-ityofa staff ofmore than 200 highly trained specialists, including 36 who hold senior reactor operator licenses and 24 withreactor licenses. Most of these professionals have extensive backgrounds in the U.S. nuclear industry.

Looking ahead, the station is scheduled for a 10-week shutdown for maintenance and NRC inspections in late 1988. Itwillthen be brought back on line until its first scheduled outage for refueling in 1989.

During its lifetime, Nine MileTwo is expected to generate electricity equivalent to more than 400 mil-lion barrels ofimported oil,withbillionsofdollars in fuel savings.

Niagara Mohawk is principal partner and manag-ing agent ofthe project, owning 41% ofNine Mile Two. Long Island Lighting Co. and New York State Electric and Gas Corp. hold 18% each; Rochester Gas and Electric Corp. 14% and Central Hudson Gas and Electric Corp. 9%.

Further information in more detail on Nine Mile Two's costs, financing and regulatory developments are presented in the Management Discussion and Analysis on page 13 and in Note 10 to financial state-ments on page 29.

Nine MileOne continuing nuclear leadership Our Nine MilePoint Unit One was cited by the Utility Data Institute in 1986 as the third lowest-cost nuclear power producer and fourth lowest-cost steam-electric plant in the nation.

During the year, this pioneering nuclear develop-ment, designed and engineered in-house by Niagara Mohawk, and in service since 1969, produced 3.1 bil-lion kilowatt-hours ofelectricity, representing a sav-ings of $72 millionand $37 millionrespectively, com-pared withoiland coal-fired power generation.

Early in the year, Unit One "coasted down" to 70 percent ofits rated power before shutdown and the start ofits scheduled biennial refueling and mainte-nance. While 200 ofits 532 uranium fuel bundles were replaced withfresh inserts, the most significant facet ofthe shutdown was replacement ofmore than 246 miles oftubing used to condense steam from the unit's turbine. Some 13,000 ofthese 100-foot long, IV4-inch tubes were part ofUnit One's original equipment in use since 1969. The15-week outage also enabled the plant staff to complete many other routine replacements and additions.

Nine MileOne lived up to its reputation as a de-pendable power performer by remaining available for generation 90 percent ofthe time since its return to service after the refueling outage. The next such out-age is not scheduled until spring 1988.

Also during 1986, our Nuclear Division moved from our corporate headquarters in downtown Syracuse to new leased offices in the suburban Town ofSalina, just north ofSyracuse, due to a need for additional office space.

Cost-containment campaign started In autumn, the company announced its most sweep-ing cost-containment program in more than a decade, the result ofserious financial problems imposed upon

NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES 5

Niagara Mohawk by recent inadequate rate-case awards and the settlement ofthe Nine MilePoint Nuclear UnitTwo prudency case.

The austerity campaign thus far includes a freeze on management salaries and an ongoing review in all departments to consolidate and reduce the size ofthe workforce. Operation review teams also were formed to identify additional areas ofpotential improve-ments in costs and revenues. In addition, a plan for unpaid personal leaves, part-time work arrange-ments, reduction ofnon-emergency overtime work and other belt-tightening measures were undertaken.

The program emphasizes that every effort possible must be made so that the company can continue to provide quality service to customers at the lowest possible cost and to protect the interests ofNiagara Mohawk stockholders.

Life-extension for fossil-fueled stations Throughout the year, the Fossil Generation Depart-ment continued a life-extension program at our coal and oil-firedgenerating plants. The long-term objec-tive is to lengthen the useful lifeofexisting generating

'nits to defer the need for new generation capacity.

Studies by Niagara Mohawk's Research and De-velopment Department, the Empire State Electric Research Corp. and Electric Power Research Institute have determined that it can be far more cost-effective to refurbish and modernize existing plants than to install new units.

The life-extension entails performing detailed in-spections ofcritical components ofeach unit. Their remaining years are assessed, and a dollar/time schedule is formulated to implement the improve-

= ments and repairs needed to lengthen their operation.

Late in 1986, special computer software went into service to help fossil station operators upgrade the on-line efficiency ofeach generating unit at coal, oilor gas-fired power stations. Specific data (temperatures, ELECTRICITYGENERATED ANDPURCHASED BYTYPE OF FUEL, 1966 Hydro 31%

Various sources 25%

Coal 16/o Oil 1B'/o Nuclear 11%

Natural gas 1%

pressures, fuel-consumption rates, etc.) are automati-cally collected from each unit and continuously transmitted to Energy Management System compu-ters in Syracuse. This data is processed and guidance information instantly transmitted and displayed in the control room to help make proper adjustments and "fine-tuning" refinements on the units while they continue to operate.

Ahigh-water hydro year Abnormally high rainfall enabled our hydroelectric stations to generate 4.1 billionkilowatt-hours in 1986, the highest in 10 years and a welcome development forconsumers. The abundant waterpower generation helped hold other electric power-production costs down, thus reducing fuel-adjustment charges on cus-tomers'ills.

Niagara Mohawk operates 77 hydro stations on up-state New Yorkwaterways, more than any other util-ityin the free world. During the year, we continued to pursue plans to renovate or develop various hydro installations for a total of 150,000 kilowatts by the late 1990s. By 1995 we must relicense 11 hydro facilities encompassing 35 individual power plants.

One application seeks to re-develop five separate power installations on the Oswego River alone.

Atyear end, a new 32,000-kilowatt hydro facility was completed and brought on line at Glen Park on the Black River. Itwas the first project where Niagara Mohawk sought "outside" proposals from private concerns for the independent construction and long-term operation ofa power facility,an arrangement that offers the company avoided costs and eliminates development costs. Energy produced at Glen Park is sold exclusively by a private developer under contract to Niagara Mohawk. Asimilar agreement with a sec-ond private developer, Synergics, Inc. ofMaryland, was reached in 1986, involvingconstruction and op-eration ofa 2,600-kilowatt plant slated for 1987 startup at Union Falls on the Saranac River.

Afisheries-keyed research venture, being watched nationwide, was initiated on the Salmon River in Oswego County in 1986 by Niagara Mohawk with the U.S. Fish and WildlifeService, N.Y. State Department ofEnvironmental Conservation and Empire State Electric Research Corp. The program focuses upon salmon and trout habitat, while examining stream-flowhydraulics, temperatures and other river charac-teristics with the objectives of more efficient and cost-effective methods offisheries management on hydro waterways. Acomputer model is a part ofthis effort, in which a number ofother U.S. utilities in-

6 NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES volved in the licensing and operation ofhydro plants have expressed interest.

Energy research ventures Another year ofsolid research gains was again achieved by Niagara Mohawk in 1986. Working inde-pendently on "in-house" projects and jointlywith other energy interests, including the nationwide Elec-tric Power Research Institute and Gas Research Insti-tute, a number ofexploratory projects progressed to practical utilityapplications. At the same time, ac-tivities were broadened in various research areas.

One project demonstrating both environmental and economic promise was the successful development of a solution to the problem ofprocessing polychlori-nated biphenyls (PCBs). In a procedure patented by Niagara Mohawk in 1986, PCB-contaminated oil used in electrical transformers can now be recovered for re-use in "clean" forma welcome breakthrough in toxic waste technology.

This novel concept has been demonstrated and ap-proved forcommercial use by both the U.S. Environ-mental Protection Agency and N.Y. State Department ofEnvironmental Conservation. Achemical process, the project involves a mobile treatment unit that can be transported from site-to-site to remove PCBs. Pres-ently, Niagara Mohawk is negotiating with several prominent hazardous-waste contracting firms to sell the rights ofthis new technology, making its benefits available to other utilities and industry.

A similar research venture was initiated in 1986 to remove toxic waste from soils. With support from several industry groups, Niagara Mohawk is evaluat-ing a number ofinnovative techniques for the on-site remediation oftoxic waste. Initialwork in 1986 looked at one approach for biological treatment. This process focuses on enhancing the natural biodegrada-tion by growing harmless organisms and injecting them into the soil to cause unwanted chemicals to decompose naturally, but at a highly accelerated rate.

Also during the year, an experimental "clean coal" power-plant research project planned jointlyby Niagara Mohawk with the N.Y. State Energy Re-search and Development Authority and other energy innovators at the company's Dunkirk Steam Station was selected forfunding support by the U.S. Depart-ment ofEnergy. Planned is a 5,000-kilowatt demon-stration unit at the western New Yorksite, among nine major concepts named by the department as the most promising choices to undergo large-scale test-ing. The new unit willtest a simplified gas-from-coal concept to generate power, using a steam-injected turbine. The most attractive feature is the project's ability to function economically and reliably withvir-tually no sulfur emissions from the plant's stack, a primary goal in efforts to reduce acid rain concerns.

The demonstration is also intended to reduce the number ofcomponents normally used to make such a concept workable. Construction ofthe unit willbegin in late 1987, withoperation scheduled for 1990-91.

New power control center in western New York Further evidence ofour dedication to meeting future energy needs economically and efficientlywas the ac-tivation in late December ofa new Regional Power Control Center in Buffalo, the latest addition to Niag-ara Mohawk's extensive Energy Management Sys-tems (EMS). The center is similar to our main Power Control Center in Syracuse but is responsible solely forhigh-voltage transmission and distribution facilities in western New York. The center is equipped with a 100-foot wide dynamic mapboard and the most modern electronics and computer facilities for anticipating and dispatching energy to nearly one-half millioncustomers in western New York. Asimi-lar control center is presently under construction in Watertown for the Northern Region and another is planned for the Capital Region in Albany. Their design and function willfollowthose ofthe western Power Control Center.

Significant power transmission projects during the year included completion ofa 345,000-volt transmis-sion line to carry power from the new Nine MilePoint Nuclear UnitTwo from our Volney station some 65 miles southeast to Marcy near Utica. This double cir-cuit links Nine MileTwo with Niagara Mohawk's cross-state energy system and the New Yorkpower grid. The sale and leaseback ofthe Volney-Marcy line to a private firmfor $ 128 millionwas consummated in November. Proceeds from this transaction were applied to reduce high-cost debt.

In conjunction with transmission technology and Niagara Mohawk's diversification efforts to broaden its earnings sources, the company formed a 50-50 joint venture corporation with Product Development Services, Inc. ofFairfield, Conn., to market a one-of-a-kind line-monitoring concept invented and patented through our research program. The new firm, NITECH, Inc. willsell, install and provide sup-port services forour Power Donut'" system, a trademark used by Niagara Mohawk for this equip-ment. The Power Donut sensor so named for its shape automatically measures vital conditions af-fecting load-carrying capacity oftransmission lines,

NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES voltage, temperature, current and environmental conditions in which the lines function. Such data is relayed from the device to power control facilities, allowing dispatchers to more effectively utilize exist-ing transmission facilities and equipment. Three U.S.

utilities have installed these Power Donut systems and three others placed orders withNITECHby the year end.

An eventful and promising year fornatural gas Expansion ofthe Army's Fort Drum in northern New Yorklargest "stateside" militarybase-expansion here in the U.S. in more than 40 years resulted in construction ofa major new linkin our natural gas system in 1986, Niagara Mohawk's largest gas project since the early 1960s.

The base is being enlarged to accommodate the re-located 10th Division(LightInfantry) with the popu-lation in and around Fort Drum expected to more than double to some 30,000 by 1990. To meet antici-pated gas demands, the company has installed more than 20 miles ofpipeline in the area and further plans are under way to extend gas service to communities west and north ofthe nearby CityofWatertown.

Also in 1986, the company purchased approxi-mately 25 percent ofits gas supply in the "spot" mar-ket for the firsttime as the result offederal changes opening pipelines for transportation. These pur-chases, combined with declining rates, have lowered costs to our more than 445,000 gas customers. While "spot" purchases have been conducted on a tempo-rary basis, they likelywillbecome a permanent way ofacquiring a portion ofgas supplies forour custom-ers in the years ahead.

We are also progressing with plans for a new Gas Energy Management System employing the latest techniques and technologies forobtaining cost-effective gas supplies. Scheduled forimplementation in 1988, the concept willinclude computerized flow modeling, remote-control ofselect gas facilities, monitoring and control ofpeak load periods, main-replacement priorities, computerized property rec-ords, records-information dispatch and other auto-mated functions. Serving as the hub for all these op-erations willbe a new Gas Energy Management Con-trol Center, similar to and located near our electric EMS Control Center in Syracuse. Targeted foropera-tion by the 1988 heating season, the center willover-see the 6,300 miles ofpipelines and all regulator sta-tions in the Niagara Mohawk gas system.

In 1986, Niagara Mohawk gas researchers devel-oped a unique "mechanical main tee." This plastic tee connector willbe used to attach plastic gas service laterals to gas mains and should reduce installation costs considerably. The patented device willbe intro-duced for nationwide distribution in May 1987.

New oil and gas ventures in western Canada Our young Canadian subsidiary, Opinac Energy, Ltd.,

posted another impressive year after successfully drilling 17 new oil wells and 36 new natural gas wells in 1986. These and other drillingventures have been pursued jointlyby Opinac with other industry partners working in the western provinces.

Opinac produced more than $ 1 million(U.S.) of crude oiland natural gas during the year, with plans calling for an expenditure of $ 11 millionforcontinua-tion ofthis exploration and development program in the western Canada sedimentary basin in British Col-umbia, Alberta, Saskatchewan and Manitoba in 1987.

Since its formation in 1983, Opinac-based in Cal-gary, Alberta has discovered and developed more than 50-billion cubic feet ofnatural gas and 1.2-millionbarrels ofproven crude-oil reserves with a combined value ofmore than $21 million.

As with all Niagara Mohawk subsidiaries, Opinac is fullyindependent and not subsidized in any way by the customers ofits parent corporation. This joint exploration company and three other Canadian firms are subsidiaries ofOpinac Investments, Ltd. of Toronto, itself a whollyowned Niagara Mohawk sub-sidiary. The others are Canadian Niagara Power Company, Ltd., which generates and distributes power to a portion ofOntario's Niagara Peninsula; St. Lawrence Power Company, distributor ofelectric-ity to Cornwall, Ontario; and Opinac Holdings, Ltd.

Rewarding year forHydra-Co A banner year with increasing national perspective was reported by our whollyowned Hydra-Co Enter-prises, Inc., an independent cogeneration subsidiary ofNiagara Mohawk. In 1986 alone, some 61,000 kilowatts ofhydroelectric production were brought on line in New York State and a 5,000-kilowatt gas-fired cogeneration plant was completed at LittleFalls by Hydra-Co with various energy partners. Other projects are planned across the nation.

A major project announced in 1986 by Hydra-Co under a joint agreement with th'e Babcock &Wilcox Company is the proposed rehabilitation ofthe former AlliedChemical Company's power-generating plant in Solvay, near Syracuse. When completed in 1988 the coal-fired facility willhave an 80,000-kilowatt capacity, its total cost estimated at $ 87 million.

NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES In Maine, Hydra-Co is planning development of some 77,000-kilowatts in both hydro and wood-fueled cogeneration. Regulatory action is pending on Hydra-Co power projects to yield some 6,300 kilowatts in Vermont and New York State, while cogeneration agreements are being negotiated in New Jersey and Oklahoma. Other hydro plants are envisioned by the subsidiary in California, Oregon and New England.

Hydra-Co, based in Syracuse, was formed in 1981 to participate in the development, ownership and opera-tion ofcogeneration, alternate-energy and small power-production installations.

Vitalityin the economy Success with a special economic development rate (EDR) created especially forelectric industrial and commercial customers in 1985 led to the introduction ofa similar rate for gas customers in 1986.

Economic development rate incentives have been widely accepted by area industry and in several instances have been the key to encouraging firms to remain in our service area rather than moving elsewhere.

The electric EDR has already been utilized by 54 separate accounts with 49 companies in our 37-county service territory. This has produced a more-than 192.6-million kilowatt-hour increase in sales-or added revenues totaling nearly $ 12 millionyearly.

Also significant, along with this energy sales growth, is the resulting growth in employment, with some 3,100 new jobs resulting in upper New YorkState.

During the year, our Economic Development De-partment took part in a number ofpositive new inno-vations to retain businesses and attract new firms to upstate New York. Among these are an "incubator business" initiative to assist those getting offto a start; a computerized inventory ofavailable building sites and industrial parks; and a venture-capital "network" for matching skills and business prospects withentrepreneurial firms seeking prospects in the regions we serve.

Thinking customer Strong emphasis was maintained throughout the year on our "ThinkCustomer!" campaign aimed at helping the many persons and communities we serve. To this end, seven new consumer-oriented initiatives were under way or in final planning in 1986, as follows:

o Consumer advocates in the Capital, Central and Frontier Regions willwork withcustomers having difficultypaying bills by counseling and referring them to available human-service agencies.

o Senior ombudsman willdirectly assist elderly customers with their energy problems with the company.

o Energy conservation programs fornon-profit agencies willprovide funds and staff support to community foundations to assist them in securing State Energy Office funds for energy conservation programs.

o Senior I.D. program encourages customers 60 years and over to register with the company for special protection, relative to their energy needs.

4 Heat/Cold Stress Program a locally focused pro-gram conducted jointlywithcoalitions ofagencies to disseminate health information on stress from summer and winter weather extremes.

o Large-print bills for visually impaired provides upon request, billswithabove-normal sized type forcustomers withvisual problems.

4 Energy Savgo Abingo-like game withenergy-saving tips, created forwidespread use by senior citizen groups and other organizations.

Assistance programs already available to customers increased in popularity during the year. Among these are our Community Conservation Grant, Energy Con-servation Bank, Home Energy Level Payment, Third Party Notification, LifeSupport and Extended Pay-ment Plan programs. These, no doubt, contributed to improved favorability ratings accorded the company in a series ofcustomer attitude surveys in recent years.

One ofour most positive and visible assistance pro-grams is the Care &Share Energy Fund. Itassists the elderly, disabled or those experiencing a medical emergency by helping them pay for their emergency energy needs. In conjunction withthe American Red Cross which administers Care &Share directlythe fund has helped some 2,770 needy families pay energy bills and make essential home energy improvements.

This program is solely supported by contributions from our stockholders, customers and employees.

Under Niagara Mohawk's Savingpower campaign, some 24,000 customers highest for any year and for any other utilityreceived home energy conservation surveys by the company's specially trained techni-cians in 1986. Many customers followed through by obtaining financial assistance and low-interest loans from lending institutions to implement needed con-servation improvements.

NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES 9

t MONTHLYRESIDENTIALELECTRIC COST FOR 500 KILOWATT-HOURS ew York Clt P iladel la P NYStateAv

. notlncludn NM'ak NJ Clevela d OH Ha ttord C B sto MA ation vera e-Los An ele CA Nla ara Mo aw lncfudes fuel and PASNV credit adlustmenl as applicable.

'NM Rate Department I/87.

"U.S. Department of Energy 10/BB.

Allother supptled by utilitywhich serves city, with rates and fuel effective 1/87.

$65.05 58.75 55.42 54.12 47.57 46.80 45.79 40.75 39.43 37.60 Wherever possible, our customer communications make note ofthe fact that Niagara Mohawk's residen-tial electric rates remain the lowest among New York State's major utilities.

People in the mainstream Afar-reaching self-evaluation and action process in-volving all employees is in progress and has become a principal theme in Niagara Mohawk's total future planning. Evolving into our People-Related Values Program, this is the outgrowth ofa 1985 survey of more than 8,000 employees representing nearly 76 percent ofthe workforce the firstemployee survey ever at Niagara Mohawk.

The immediate response to the survey's findings was revision ofour Corporate Mission Statement and Strategic Plan to more accurately stress the impor-tance ofemployee contributions to the company's success. Aspecial task force on people-related values was formed, with 50 employees recruited from both union and management to address employee concerns and make specific recommendations to management.

Teams were also organized to pursue specific prob-lems and find answers to them. Members were drawn from a cross-section ofthe company. Areas ofconcern included decision-making, employee communications and recognition, teamwork and development. Pres-ently, we are creating a management model intended to foster improved communication ofNiagara Mohawk's mission and purpose at all levels, step-up employee commitment through more decisive decision-making and encourage a higher leadership profile withinwork groups. Asteering committee was appointed by senior management to track implemen-tation and progress ofthis extensive employee relations and participation effort through 1987 and the coming years.

At the end of 1986, Niagara Mohawk's workforce totaled approximately 11,400. About 8,600 or 76 per-cent are members of 12 local unions forming System Council U-11 ofthe International Brotherhood of Electrical Workers (AFL-CIO).

Management changes in 1986 included the election ofGerald D. Garcy to vice president power con-tracts, and Richard E.A. Duffyto vice president public affairs and corporate communications, suc-ceeding Kermit E. Hill,who retired. Attorney Gary J.

Lavine was elected assistant general counsel.

We were deeply saddened in November over the death ofJames F. Aldrich, vice president-regional operations.

Strategy forcompetition diversity Competition and regulatory challenges are altering the business environment for the nation's utilities as never before. Niagara Mohawk is responding to this shifting climate with positive and dynamic measures for both the stockholder and the consumer.

The company recognizes, above all, the need to re-main competitive by providing continuing low-cost energy service ofthe highest quality. But at the same time we are exploring the possibilities ofextending our "core business" to other related services, markets and ventures. Recent tangible results ofexpansion/

diversification are our Power Donut'monitoring system currently being nationally advertised and marketed by NITECH; the sale oftechnology rights forour patented PCB-removal concept; heat pump

10 NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES research/development/promotion; and the creation and growth ofNiagara Mohawk energy subsidiaries in both the U.S. and Canada.

Our guiding document for the future is our Corpo-rate Strategic Plan, amended to emphasize competi-tive opportunities.

Various levels ofmanagement and all departments take part in the collective strategic planning process by evaluating situations facing Niagara Mohawk and adjusting the plan forproper direction to best employ our resources. Direction is set forth in our Corporate Mission Statement (see inside front cover) and in published corporate objectives.

Alldepartments working together on strategic planning have helped to solidifythe spirit of teamwork-itselfa substantial reward from our Corporate Strategic Plan as we view the century ahead.

Investor communications a two-way exchange An increasingly diverse mixofinstitutional and in-dividual investors owns Niagara Mohawk common stock. To meet their growing needs for information in this media age, our Investor Relations Department has intensified "two-way"communications with stockholders and the investment community.

A prime example was the marked rise in the popu-larityofour toll-free telephone service available to all shareholders. This channel provides direct access to account information and quick answers to questions on the company's operations and related matters. In addition, regional stockholders meetings, rotated yearly throughout our service territory, continue to be an effective means ofcommunication and promote an informal, person-to-person exchange ofideas between management and shareholders. Further, the company has re-vamped its "Inthe Know"publications pro-gram. "Inthe Know" is specifically tailored to indi-vidual investors and supplements information routinely provided in our annual and quarterly re-ports. Stockholders interested in more comprehensive information about the company can join the growing number of"Inthe Know"readers by calling the toll-free number listed on the inside back cover or by writ-ing the Investor Relations Department in Syracuse.

As we continue to face challenging times, our com-munication efforts with the investment community continue to receive the support and endorsement of senior management. In addition to direct, personal contact with institutional investors, a number of broker and security analyst meetings were held throughout the U.S. in 1986. These sessions provided members ofthe investment community the opportu-nity to obtain first-hand from company leaders the information needed to make informed, factual rec-ommendations about our securities.

Dividend Reinvestment Plan popular in '86 Participation in our Dividend Reinvestment and Common Stock Purchase Plan is a popular method to increase stock ownership in Niagara Mohawk. At year-end 1986, some 66,600 plan participants held approximately 10.7 millionshares ofthe company's common stock, representing 8.4 percent ofthe out-standing common shares. One ofthe features ofthe plan allows customers ofNiagara Mohawk to buy stock through the company and become plan partici-pants. Since this modification in April1985, some 7,700 customers have purchased about 600,000 com-mon shares. Despite recent changes to federal tax legislation, this allows shareholders a unique, cost-effective savings method.

In the firstquarter of 1986, in response to changing capital needs, the company made a number of changes in the plan. However, the plan remains in effect and all holders ofNiagara Mohawk common or preferred stock are eligible and invited to participate.

In the past, stock added to each participant's divi-dend reinvestment plan account was newly-issued shares purchased directly from the company. Effec-tive March 1, 1986, Niagara Mohawk appointed an agent to purchase shares ofstock on the open market forparticipants'ccounts.

The purchase price ofthe stock allocated to plan participants is the average price paid by the agent on the open market. In addi-tion to the reinvestment ofdividends, the plan allows optional cash payments up to $5,000 per calendar quarter to be applied toward the purchase ofaddi-tional common stock. Allbrokerage fees and commis-sions associated with the purchase ofshares in the open market continue to be paid by the company.

Acopy ofthe new plan prospectus, which discusses the changes in greater detail, was mailed to plan par-ticipants in February 1986. Ifyou have any questions about the plan or wish to obtain a copy ofthe prospec-tus, please call our Shareholder Services Department at the appropriate toll-free number foryour area.

NIAGARA MOHAWK POWER CORPORATION AN D SUBSIDIARY COMPANIES Market Price ofCommon Stock and Related Stockholder Matters 1986 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter 1985 Dividend paid Price range per share High Low

$.52

$247/8

$1%5

.52 25'/2 193/4

.52 247/8 19V4

.52 19'/8 15'/2

$2.08 1st Quarter

$.50

$ 18

$ 1 &Vs 2nd Quarter

.52 203/8 175/8 3rd Quarter

.52 217/8 171/2 4th Quarter

.52 21 175/8

$2.06 The Company's common stock and cer-tain of its preferred series are listed on the New York Stock Exchange. The common stock is also traded on the Boston, Cin-cinnati, Midwest, Pacific and Philadelphia stock exchanges.

The ticker symbol is "NMK",

Preferred and common stock dividends were paid on March 31, June 30, Sep-tember 30 and December 31. The Com-pany presently estimates that none of the 1986 common or preferred stock div-idends will constitute a return of capital and therefore they are subject to Federal income tax as ordinary income.

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

While the Company intends to con-tinue the practice of paying cash div-idends quarterly, declarations of future dividends are necessarily dependent upon future earnings, cash flow and fi-nancial requirements which the Com-pany cannot predict with certainty and which could be adversely affected by ratemaking uncertainties as more fully discussed below and in Note 10 of Notes to Consolidated Financial State-ments. Also, other factors, including re-strictions in governing instruments, may affect the declaration and payment of future dividends.

The holders of Common Stock are en-titled to one vote per share and may cumulate their votes for the election of Directors. Whenever dividends on Pre-ferred Stock are in default in an amount equivalent to four full quarterly divi-dends and thereafter until all dividends the'reon are paid or declared and set aside for payment, the holders of such stock can elect a majority of the Board of Directors. Whenever dividends on any Preference Stock are in default in an amount equivalent to six fuii quar-terly dividends and thereafter until all dividends thereon are paid or declared and set apart for payment, the holders of such stock can elect two members of the Board of Directors. No dividends on Preferred Stock are now in arrears and no Preference Stock is now outstand-ing.

Size of holding Total Total shares (Shares) stockholders held 1 to 99 50,773 100 to 999 113,825 1,000 or more 9,904 174,502 1,618,039 28,415,426 97,107,529 127,140,994 Upon any dissolution, liquidation or winding up of the Company's business, the holders of Common Stock are enti-tled to receive pro rata all of the Com-pany's assets remaining and available for distribution after the full amounts to which holders of Preferred and Pref-erence Stock are entitled have been satisfied.

The indenture securing the Com-pany's mortgage debt provides that surplus shall be reserved and held un-available for the payment of dividends on Common Stock to the extent that expenditures for maintenance and re-pairs plus provisions for depreciation do not equal 2.25% of depreciable property as defined. Such provisions have never restricted the Company's surplus.

At year end, about 175,000 stockhold-ers owned common shares of Niagara Mohawk and about 7,900 held preferred stock. The chart below summarizes common stockholder ownership by size of holding:

RANGE ANO YEAR END MARKET PRICE OF COMMON STOCK

$ 1515

$ 15V4

$ 17%

$20Va

$ 1&a ATYEAR ENO

$2515 RANGE

$ 15Vs 1982 1983 1984 1985 1988

12 NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES Management's Discussion and Analysis ofFinancial Condition and Results ofOperations RESULTS OF OPERATIONS For 1986, earnings per share decreased 5.9% to $2.71 against

$2.88 for 1985.

The 1986 earnings represent decreases of 4.6% and 2.2'/o from 1984 and 1983 earnings per share, respectively.

The average number of shares outstanding has increased approximately 30% over the three-year period.

The decrease in the Company's earn-ings per share for 1986 from 1985 re-sulted from a decrease in the Com-pany's authorized return on common equity. The Company achieved a 13.65%%d rate of return on common equity in 1986 as compared with 15.0'/o in 1985 and 14.9% in 1984. The PSC-approved rate of return on equity, which is currently 13.5% as compared to 15.5% authorized at December 31, 1985 and 16% at De-cember 31, 1984, averaged 14.0% for 1986.

The followingdiscussion and analysis highlights items having a significant ef-fect on operations during the three-year period ended December 31, 1986. It may not be indicative of future operations or earnings. It should be read in conjunc-tion with the Notes to Consolidated Fj-nancial Statements and other financial and statistical information appearing elsewhere in this report.

Electric revenues increased

$108.0 million or 5.3% over the three-year period. The increase is largely attribut-able to increased base rates and in-creased sales to ultimate consumers, offset somewhat by decreased revenues attributable to fuel and purchased power cost recoveries and the decrease in sales to other electric systems as in-dicated in the table below:

ELECTRIC SALES 32.640 34.732 37.086 MilliOh$Of Kwhr+

35.296 1982 1986 1983 1984 1985 14.7 /o 15.O/o 14.9'/o EARNED RATE OF RETURN ON COMMON EQUITY 15.0/o Electric revenues Increase (decrease) from prioryear in millionsoldollars 1966 1985 1984 Total 13.8/o Increase in base rates

$ 46.4 Fuel and purchased power cost revenues...

12.6 Sales to ultimate consumers...............

67.4 Sales to other electric systems.............

(100.3)

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

9.3

$ $ $.4

$ 65.9

$ 69.1

$ 181.4 (4.5)

(86.3)

(78.2) 11.9 56.1 135.4 (107.9) 68.7 (139.5)

(3.5) 3.1 '.9 Si38.1)

$ 110.7,

$108.0 1982 1983 1984 1985 1986 Electric kilowatt-hour sales were 34.3 billion in 1986, a decrease of 2.7% from 1985 and 7.4% from 1984, reflecting the effects of increased competition which has reduced the Company's effectiveness in the resale market resulting in decreased sales to other electric systems (see Electric and Gas Statistics Electric Sales appearing on page 35). Details of the changes in electric revenues and kilowatt-hour sales by customer group are highlighted in the table below:

1966

% Increase (decrease) from prior year

%%dof Electric 1966 1985 1984 Class of service Revenues Revenues Sales Revenues Sales Revenues Sales Residential...........

32.9/o 8.5%%d 4.3/o 6.6/o 0.4%

4.1%

4.3'/o Commercial..........

36.0 8.2 4.7 5.0 1.7 2.4 3.7 Industrial.............

21.1 2.6 (0.8)

(0.4)

(2.8)

(0.5) 3.1 Municipal service.....

1.9 4.6 (2.9) 3.7 (1.6) 3.8 (2.4)

Total to ultimate consumers.........

91.9 6.9 2.5 4.2 (0.4) 2.3 3.6 Other electric systems 4.5 (51.1)

(32.3)

(35.5)

(24.1) 29.2 23.1 Miscellaneous........

3.6 13.7

(5.0)

4.5 Total

...100.IP/o 1.7'/o (2.7)%

(1.8)%

(4.8)%

5 5%

6.8'/o

NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES 13 Gas revenues Increase (decrease) from prioryear fn millionsofdoffars 1986 1985 1984 Total Increase in base rates...........

3.0 8.2 8.7 19.9 Purchased gas adjustment clause (20.0)

(21.6)

(23.3)

(64 9)

Gas sales volume...............

(53.0)

(39.2) 57.1 (35.1)

$ (70.0)

$ (52.6)

$ 42.5

$ (80.1)

Gas revenues decreased

$80.1 million or 13.2/o over the three-year period. As shown by the table below, this decrease is attributable to lower costs for purchased gas coupled with reduced volume offset by higher base rates.

109.7 103.2 115.0 Millionsof deka therm s 108.4 100.8 95.9 conr co Lrr lal CI Gas sales were 95.9 million dekatherms in 1986, an 11.5% decrease from 1985 (see Electric and Gas Statistics Gas Sales appearing on page 35). The decrease for 1986 reflects a 46.7% decrease in sales in the industrial class because of com-petition with oil and the ability of customers to purchase gas directly from produc-ers. The Company transported 4.9 million dekatherms for customers purchasing gas directly from producers and expects such transportation activities to increase with corresponding reductions in gas revenues. Revenues from the transportation of customer-owned gas are included in miscellaneous gas revenues. Changes in gas revenues and dekatherm sales by customer group are detailed in the table below:

1982 1983 1984 1985 1986 2.394 2,632 2,786 2 695 2,660 TOTALELECTRIC ANDGAS OPERATING REVENUES Millionsof dollars 1986

% Increase (decrease) from prioryear

%of Gas 1986 1985 1984 Class of service Revenues Revenues Sales Revenues Sales Revenues Sales Residential Commercial..

Industrial....

56.P/o 0.6o/0 4.4%

(5.9)%

(4.4)%

3.1%

5.7o/o 27.0 (3.3) 0.8 (6.2)

(3.2) 1.0 3.6 13.0 (48.7)

(46.7)

(14.6)

(10.8) 21.1 27.3 Total to ultimate consumers.........

96.2 (11.8)

(10.9)

(8.1)

(6.0) 6.5 10.7 Other gas systems....

2.7 (23.5)

(23.6)

(5.2) 1.6 24.9 32.0 Miscellaneous.......

1.1 68.6

(11.5)

8.7 1982 1983 1984 1985 1986 Total

... 100.9/o (11.7)% (11.5)%

(8.1)%

(5.7)%

7.0o/o 11.4%

On March 12, 1986, the PSC approved a 2.1% electric rate increase to provide the Company additional annual rev-enues of $39,974,000.

The rates are based on a 13.5% return on common equity and provide for the current re-covery of finance charges accruing on

$680 million of Construction Work in Progress (CWIP) associated with the Nine MilePoint Nuclear Station Unit No.

2 (Unit). These new rates became effec-tive March 17, 1986 and represent 26%

of the revised rate relief requested by the Company. In March 1985, the PSC had approved rate increases providing additional annual revenues of

$49,312,000 (2.6%) for electric and

$8,826,000 (1.3%) for natural gas.

On August 23, 1986, in connection with a second-stage filing involving rates approved March 12, 1986, the PSC approved additional annual electric revenues of $7,475,000 for items which were not considered in the March 1986 decision. The new rates became effec-tive August 29, 1986.

Rate action, initiated in April 1986, presently seeks

$181.7 million (9.9%)

additional electric revenues based upon forecast operations for the rate year ending March 31, 1988. The application includes $133.1 million for the first year of a four-year phase-in of the Com-pany's 41% share of the Unit into rates.

In December 1986, PSC Administrative Law Judges recommended a rate in-crease of $ 130.8 million (7.1%). The Company is unable to predict what amount of rate relief will ultimately be granted. The PSC opinion is expected in March, 1987. No adjustment to gas rates is being requested at this time.

In 1986, electric fuel and purchased power costs decreased 11.4% to $672 million from $759 million in 1985 and

$853 million in 1984. This decrease is the result of a $121.9 milliondecrease in fuel and purchased power costs in-curred during the year, partially offset by a $35.0 million net increase in costs deterred and recovered through the op-eration of the fuel adjustment clause.

Fuel costs incurred at the Company's generating stations decreased

$81.8 million as a result of reduced demand and lower oil prices. The cost of pur-chased power decreased

$40.1 million as a result of a 3.5% decrease in kilowatt-hour purchases and a 7.5% de-crease in the average cost per kilowatt purchased (see Electric and Gas Statistics-Electricity Generated and Purchased appearing on Page 35).

The total cost of gas purchased de-creased 17.8% in 1986 and 9.1% in 1985, atter having increased 5% in 1984. The decrease for 1986 is the result of a 14.0% decrease in dekatherms pur-chased to meet customer demand,

NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES AVERAGECOST OF ATON OF COAL ANDA BARRELOF OILBURNED MAINTENANCEANDOTHER OPERATION EXPENSE Millionsof dollars TOTALTAXES INCLUDING INCOMETAXES Millionsoi dollars

$50.76

$29.67

$30.67

$50.68

$49 16

$33.35

$31.16

$45.84

$18.00 418.9 290.1 462.4 326.1 494.6 353.6 546.8 508.3 397.7 364.0 CI co o

I 317 410 424 482

~rCt Lrr co sd 1288 136.3 141.0 149.1 1982 1983 1984 1985 1986 1982 1983 1984 1985 1986 1982 1983 1984 1985 1986 combined with lower rates charged by the Company's principal supplier and spot market purchases. The Company's net cost per dekatherm purchased de-creased to $3.52 in 1986 from $3.68 in 1985 and $3.96 in 1984.

Through the energy and purchased gas adjustment

clauses, costs of fuel, purchased power and gas purchased, above or below the levels allowed in ap-proved rate schedules, are billed or credited to customers. The Company's fuel adjustment clause provides for par-tial pass-through of fuel and purchased power cost fluctuations from those forecast in rate proceedings, with the Company absorbing a specific portion of increases or retaining a portion of decreases to a maximum of $15 million per rate year.

Other operation and maintenance ex-penses increased 7.6% in 1986, 2.8% in 1985, and 7.0% in 1984, primarily as a result of increases in wages and as-sociated benefits and higher costs charged by suppliers. Effective June 1,

1984, the Company entered into a two-year labor agreement providing for wage increases of 5.25% in the first year and 5.50% in the second year. A new three-year contract providing for annual wage increases of 4.1%, 4.5% and 4.7%,

respectively, became effective June 1,

1986. The increase in other operation and maintenance expenses in 1984 and 1986 also includes scheduled mainte-nance costs relating to the refueling of Nine Mile Point Nuclear Station Unit No.

1 in those years. The next refueling out-age for this unit is scheduled for the Spring of 1988.

Depreciation and amortization ex-pense for 1986 increased 3.1% over 1985 and 10.0% over 1984, principally from normal plant growth and increases in depreciation rates applied to certain classes of assets.

Total Federal and foreign income taxes for 1986 rose 21.8% as net taxable income and the dollar amount of items on which deferred taxes are provided increased.

The increase in taxes othBf than income taxes in the three-year period is due principally to higher prop-erty taxes resulting from property addi-tions.

The $21.5 million decrease in total Allowance for Funds Used During Con-struction (AFC) for 1986 results from lower AFC rates and an increase in the amount of CWIP included in rate base from $320 million to $680 million effec-tive April 1, 1986, despite increased overall levels of plant construction, principally the Unit.

The decrease in other income and deductions-other items (net) is primar-ily the result of the reduction in the in-terest earned on the advances made for LILCO (see Note 11 of Notes to Consoli-dated Financial Statements).

Interest expense and preferred stock dividend requirements increased slightly as a result of new issuances to raise the capital necessary to fund the Company's construction program offset by a reduction in high coupon se-curities. The weighted average long-term debt interest rate and preferred dividend rate paid in 1986 decreased from 10.30% and 8.85% in 1985, respec-tively, to 9.82'/o and 8.20%, respectively, as a result of the Company's refinancing efforts.

Effects of Changing Prices. The rate of inflation continued to be moderate in 1986. The Company is especially sensi-tive to inflation because of the large amount of capital it must raise to fi-nance its construction program and be-cause its prices are regulated using a rate base that reflects the historical cost of utility plant.

The Company's consolidated finan-cial statements are based on historical events and transactions when the pur-chasing power of the dollar was sub-stantially different from the present. The effects of inflation on most utilities, in-cluding Niagara Mohawk, are most sig-nificant in the areas of depreciation and utilityplant. The Company could not re-place its utilityplant and equipment for the historical cost value at which they are recorded on the books. In addition, the Company would probably not re-place these assets with identical ones due to technological advances and reg-ulatory changes which have occurred.

In light of these considerations, the de-preciation charges in operating ex-penses do not reflect the current cost of providing service. The Company, how-ever, will seek additional revenue to cover the costs of maintaining service as assets are replaced.

During a period of inflation, holders of monetary assets suffer a loss of gen-eral purchasing power while holders of monetary liabilities experience a gain.

The gain from the decline in purchasing power of net amounts owed is primarily attributable to the substantial amount of debt which has been used to finance utility plant. Since the depreciation on this plant is limited to the recovery of historical costs, the Company does not have the opportunity to realize a hold-ing gain on debt and is limited to recov-ery only of the embedded cost of debt capital. The table on the following page presents selected financial data re-stated for the effects of changing prices in average 1986 dollars:

NIAGARA MOHAWK POWER CORPORATION AND SU'BSIDIARY COMPANIES 15 1986 1985 1984 Operating Revenues ($000's)....

Gain from decline in purchasing power on net amounts owed ($000's).......

Per Common Share:

Cash dividends declared......

Marketpriceatyearend......

Average Consumer Price Index..

FINANCIALPOSITION, LIQUIDITYA Financial Position. During recent years internal funds from operations have been insufficient to meet the Com-pany's capital requirements and there-fore, large amounts of new capital from external sources have been necessary.

The Company's overall requirements consist of amounts for the Company's construction program, working capital needs, maturing debt issues and sink-ing fund provisions on outstanding debt and preferred stock and are affected by its refinancing efforts. Sources and uses of funds to meet these require-ments during the past three years are reported in the Consolidated Statement of Changes in Financial Position on page 20.

The Company's key financial indi-cators remained constant in 1986. Capi-tal structure at year-end was 47.0%

long-term debt, 10.5% preferred stock and 42.5% common equity. This posi-tion is indicative of the Company's cor-porate goal of maintaining a strong equity-based capitalization of 40-45%

common equity. However, the strength of the Company's capitalization struc-ture and earnings will be adversely im-pacted upon the adoption of new ac-counting rules, which will require an immediate write-off of Unit disallowed costs, and the recognition of the Set-tlement Agreement in rates (see Note 10 of Notes to Consolidated Financial Statements).

Coverage of fixed charges decreased slightly to 2.98 at year-end, but remained at approximately the 3x level for the fifth consecutive year and close to the corpo-rate goal of maintaining at least a 3.25 coverage ratio. The coverage ratio excluding AFC improved slightly to 2.42 as financing costs not currently reco-vered in rates decreased, primarilyas the result of $680 million of CWIP in rate base. AFC for 1986 amounted to 48.2/o of the balance available for common stock as compared with 53.2/0 in 1985 and 52.4% in 1984.

$2,660,319

$2,746,798

$2,940,448 36,418 108,788 115,867 2.08 2.10 2.09 16.75 20.89 18.34 328.4 322.2 311.1 ND CAPITALRESOURCES During the year, the market price for the Company's common stock fell below the book value after having shown substantial improvement in 1985. In addition, credit ratings for first mortgage bonds, pollution control bonds and preferred stock were low-ered by rating agencies because of the delays and related cost increases ex-perienced at the Unit.

Continued delays in the Unit's com-pletion, and the related increases in costs coupled with a prospective write-off of disallowed Unit costs of ap-proximately $ 1 billion ($626 million net of tax at a 46% rate), recent reductions in the authorized rate of return on common equity experienced by the Company and other New York State utilities and uncertainty regarding the ratemaking treatment relative to the im-plementation of the Settlement Agree-ment, are expected to have a negative impact on the financial condition and results of operations of the Company

and, in turn, could jeopardize the maintenance of the current common stock dividend level.

Construction and Other Capital Re-quirements.

Annual expenditures for the years 1984-1986 for construction and nuclear fuel, including related AFC and overheads capitalized, were $769.8 million, $771.1 million and $774.1 mil-lion, respectively. The principal project presently under construction is the Unit (see Note 10 of Notes to Consolidated Financial Statements).

The Company is a 41% owner and had invested about

$2.4 billion, including AFC and over-heads capitalized, in the Unit and Unit related projects through December 31, 1986. Expenditures for construction of the Unit have averaged approximately 51% of total construction requirements during the period 1984 to 1986.

Total capital requirements in 1986 in-creased due to refinancing efforts and, in 1984 and 1985, as the Company made 47>5o/o 45.6/

46 5'/

45 8'/

47 0'/o X

CL c5 ~

O~

AO 11.5%

41.0/o 12.6o/o 42.1o/

11,5%

42.0%

11.5%

42.7/o 10 5o/o 42.5oo 1982 1983 1984 1985 1986 Og OO advances for construction of the Unit on behalf of LILCO. As described in Note 11 of Notes to Consolidated Financial Statements, however, LILCO repaid such obligations in December 1986.

The 1987 estimate for construction additions and nuclear fuel, including AFC and overheads capitalized, is ap-proximately $550 million and approxi-mately 28% of this estimate is for the Unit.'ebt and preferred stock retire-ments, the amount due under the Co-tenant Agreement and other require-,

ments are expected to add approxi-mately another

$468 million to the Company's capital requirements for a total of $1.018 billion.

Complete estimates of the Company's capital requirements and resources for the years 1987 through 1991 are being reviewed by the Company to take into consideration, among other things, the impact of the Settlement Agreement, the $ 171 million to be paid by the Com-pany to the cotenant companies upon commercial operation of the Unit pur-suant to the Cotenant Agreement, the impact of the Tax Reform Act of 1986 (Tax Act), the Financial Accounting Standards Board's ("FASB") Exposure Draft concerning proposed changes in accounting for income taxes and the January.1987 cost estimate of the Unit.

The FASB Exposure Draft would re-quire, among other things, adjustment of net deferred tax liabilities or assets for the net change in the tax rates paid by the Company. However, the Tax Act prohibits rapid reduction of excess de-ferred taxes relating to accelerated de-preciation occasioned by the reduction of the corporate tax rate. The Tax Act contains numerous other provisions likely to affect the Company. The most significant changes relate to a reduc-tion in the marginal corporate income tax rate, increased minimum tax provi-CAPITALIZATIONRATIOS

16 NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES sions and the elimination of the invest-ment tax credit. The Tax Act when ini-tially considered in the rate setting pro-

cess, is likely to create a reduction in internal generation of cash.

However, reductions in the Company's cash gen-eration and coverage ratios would also likely be addressed in the rate setting process. To the extent any such nega-tive impacts are not adequately consid-ered in rates, a corresponding loss of cash flow, if experienced, could be ex-pected to increase the Company's ex-ternal financing requirements and pos-sibly lower credit ratings and may im-pact the common stock dividend rate.

Liquidity and Resources.

During 1986, the Company raised approximately

$780,500,000 through external sources, consisting of

$598,900,000

debt,

$75,000,000 of preferred

stock,

$4,600,000 of common stock from the issuance of 212,654 shares, and net in-creases of $9,000,000 under inter-mediate term bank revolving credit ob-ligations and $93,000,000 in short-term debt. The Company also completed ap-proximately $22,000,000 of capital lease financing, received

$225,000,000 from the sale and redemptions of the LILCO General and Refunding Bonds it held and

$ 128,000,000 from a sale and leaseback of a transmission facility. In addition to sinking fund and scheduled retirements, during 1986 the Company retired prior to maturity $381 million of high-coupon long-term debt and $47 million of preferred stock. A portion of the funds needed to complete these re-demptions were obtained from the sale by the Company of LILCO General and Refunding Bonds and the transmission facility. These early retirements of high coupon securities contributed to a re-duction in the estimated year-end aver-age cost of capital. Using the maximum rates payable on variable rate securities the year-end average cost of long-term debt decreased from 10.57% to 9.76%

and the preferred dividend rate de-creased from 9.79% to 9.43%.

During 1986, funds needed to pay for the Company's overall construction re-quirements amounted to $774,100,000, including AFC, and were provided 29%

from internal sources and 71% from ex-ternal financing.

External financing for 1987 is ex-pected to approximate $687 million, in-cluding funds needed to complete the construction of the Unit, pay amounts due under the Cotenant Agreement and ANNUALEXTERNAL FINANCINGBYTYPE 583.1 291.8 614.3 374.7 Millionsol dollars 780.5 700.9 584.1 323.8 r

Clo Cd g

rs:

CL os 424.9 259;7 50.0 189.6 75.0 185.3 75.0 1982 1983 1984 1985 1986 refund debt and preferred stock ex-pected to be retired prior to maturity.

The Company expects to secure the majority of its capital needs from tradi-tional financing sources.

However, it will continue to explore and utilize, as appropriate, other methods of financ-ing. Recent adoption by the FASB of amendments with respect to financial accounting recognition of disallowed Unit costs, together with the anticipated charge against earnings based on the Settlement, may prohibit or severely re-strict the Company's ability to borrow under revolving credit agreements, and for a period of approximately twelve months, issue Preferred Stock or First Mortgage Bonds under its Indenture on the basis of additional property. There are currently no tests or restrictions on the Company's ability to issue Prefer-ence Stock. In addition, the 1986 reduc-tion of the credit ratings on the Com-pany's First Mortgage Bonds and Pre-ferred Stock, with the possible adverse effect on the rates of interest and div-idend rates that may be required on fu-ture issues of such securities, may also reduce the Company's financing flexi-bility and adversely affect its capital structure and financial position. Not-withstanding these possible limitations on its financing capacity and flexibility, the Company believes that available sources of financing, including as of December 31, 1986, approximately $566 million principal amount of First Mortgage Bonds issuable on the basis of retired bonds (to the extent not re-quired for other purposes) and $ 100 million aggregate par value of Prefer-ence Stock, will be sufficient to satisfy the Company's external financing needs for.1987.

Ordinarily, construction related short-term borrowings are refunded with permanent securities on a continu-ing basis.

Bank credit arrangements, which total $673 million (including $450 million of revolving credit and term loan agreements,

$ 123 million in lines of credit and a $100 million Bankers Ac-ceptance Facility Agreement), are used by the Company to enhance flexibility as to the type and timing of its perma-nent security sales. Further increases in the costs of the Unit, implementation of the Settlement and recent changes in financial accounting standards could affect the Company's ability to access certain of its bank credit arrangements.

Certain of these agreements, as well as other agreements of the Company, con-tain representations and covenants which, if not met or re-negotiated, re-quire the Company to provide security in the form of First Mortgage Bonds or prevent the Company from making new borrowings under such agreements (see Notes 4 and 11 of Notes to Consoli-dated Financial Statements).

Any se-curity provided in the form of First Mortgage Bonds may diminish the amount of First Mortgage Bonds availa-ble for issuance on the basis of retired bonds. The unsecured debt limitation imposed by the Company's Charter is

$700 million declining to 10% of capitalization plus $50 million after 1988. This limitation on unsecured debt together with certain restrictions on secured financing may limit the Com-pany's ability to complete certain types of financing.

In general, the Company has had a strong capital structure, adequate short and intermediate term bank borrowing capability and has been able to access the permanent capital markets with flex-ibility. Earnings coverage of interest charges may remain in excess of mortgage indenture restrictions for the issuance of First Mortgage Bonds and over $1.3 billion of property is available to support the issuance of First Mortgage Bonds. However, continua-tion of this degree of financial strength is dependent on a number of factors, including the ultimate cost of the Nine Mile Point Nuclear Station Unit No. 2, the rate phase-in plan for the Unit, the methodology adopted by the PSC in implementing the Settlement Agree-ment, the adoption of Statement of Fi-nancial Accounting Standards No. 90 (see Note 10 of Notes to Consolidated Financial Statements) and adequate rate relief.

NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES Consolidated Statement of Income and Retained Earnings Operating revenues:

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

Gas For the year ended December 31, 1966

$2,131,833 528,486 2,660,319 In thousands ofdollars 1985

$2,096,404 598,536 2,694,940 1984

$2,134,470 651,076 2,785,546 Operating expenses:

Operation:

Fuel forelectric generation Electricity purchased Gas purchased Other operation expenses.......

Maintenance Depreciation and amortization Federal and foreign income taxes Othertaxes Operating Income Other income and deductions:

Allowance for other funds used during construction Federal income taxes Other items (net) (Note 11)

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 forthe year Retained earnings at beginning of year..

Retained earnings at end of year 319,834 352,126 338,634 397,714 149,124 155,311 211,237 295,165 2,219,145 441,174 121,932 32,293 37,539 191,764 632,938 264,054 14,880 (43,861) 235,073 397,865 53,817 344,048 264,312 79,736 842,115 921,851 391,382 367,406 411,801 364,010 144,312 150,627 173,471 280,643 2,283,652 411,288 141,320 26,708 53,110 221,138 632,426 260,271 6,721 (45,996) 220,996 411,430 59,559 351,871 252,218 99,653 742,462 842,115 476,040 377,052 452,960 353,660 140,987 141,150 181,767 269,204 2,392,820 392,726 122,354 33,460 8,591 164,405 557,131 224,099 12,440 (39,142) 197,397 359,734 51,460 308,274 216,493 91,781 650,681 742,462 Average number of shares of common stock outstanding (ln thousands)

Balance available per average share of common stock..

Dividends per share of common stock.................

127,076 2.71 2.08 122,215 2.88 2.06 108,734 2.84 1.98

() Denotes deduction

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

1986 ln thousands ofdollars ASSETS Utilityplant, at original cost (Note 1):

Electric plant Nuclear fuel (Note 3)

Gas plant.

Common plant Construction work in progress (Note 10)

Total utilityplant Less accumulated depreciation and amortization Net utilityplant Other property and investments Advances on behalf of Nine Mlle Point Nuclear Unit No. 2 cotenant, including deferred sup plemental payments (Note 1 1)

Current assets:

Cash, including time deposits of $78,389 and $7,521, respectively.....

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

Materials and supplies, at average cost:

Coal and oil for production of electricity Other Prepayments Deferred debits:

Unamortized debt expense Deferred finance charges (Note 1)

Deferred recoverable energy costs Extraordinary property losses Other

$4,559,389 392,662 544)447 129,451 2,820,044 8,445,993 1,763,443 6,682,550 76,504 175,979 289,350 43,504 73,015 21,109 602,957 118,209 83,951 9,935 37,097 249,192

$7,611,203

$4,302,280 369,126 517,995 115,316 2,336,188 7,640,905 1,629,437 6,011,468 146,487 232,847 44,933 283,962 64,454 65,450 20,931 479,730 64,260 25,055 32,520 1,709 19,761 143,305

$7,013,837

NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES 19 CAPITALIZATIONANDLIABILITIES At December 31, 1966 ln thousands ofdollars 1985 Capitalization (Note 7):

Common stockholders'quity:

Common stock, issued 127,140,994 and 126,928,340 shares, respectively Capital stock premium and expense Retained earnings...

Non-redeemable preferred stock Redeemable preferred stock Long-term debt Total capitalization Current liabilities:

Short-term debt (Note 4)

Long-term debt due within one year Redemption and sinking fund requirements on redeemable preferred stock (Note 7).

Accounts payable Payable on outstanding bank checks Customers'eposits Accrued taxes Accrued interest Accrued vacation pay.

Gas supplier refunds payabie to customers Cotenant prepayments to Nine MilePoint Nuclear Unit No. 2 project fund (Note 11)

Due to cotenants under Cotenant Agreement (Note 10)......

Other Deferred credits:

Accumulated deferred Federal income taxes Mandated refunds to customers (Note 11)

Deferred finance charges(Note 1)

Other Commitments and contingencies (Notes 3, 10 and 11) 127,141 1,522>499 921,851 2,571>491 290>000 347,470 2,799,605 6,008,566 100,212 93>914 60,380 141,338 59,512 8,645 10,232 68,759 28,234 2,846 1,096 171,100 24,231 770,499 648>641 63>229 83,951 36,317 832,138

$7,611,203 126,928 1,519,577 842,115 2,488,620 290,000 379,850 2,643,094 5,801,564 7,195 65,465 13,050 186,887 63,340 7,829 7,560 76,157 25,945 11,381 84,904 25,937 575,650 515,554 80,000 25,055 16,014 636,623

$7,013,837

20 NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES Consolxdated Statement of Changes in Financial Position For the year ended December 31 ~

FINANCIALRESOURCES WERE PROVIDED BY:

Operations:

Net income Charges (credits) to income not requiring (not providing) working capital,

Depreciation and amortization.

Allowance for funds used during construction....

Amortization of nuclear fuel Provision for deferred Federal income taxes (net)

Other Outside financing:

Sale of common stock Sale of preferred stock Sale of mortgage bonds Issuance of other long-term debt Net borrowings under revolving credit facilities Increase (decrease) in short-term debt.........

Other sources:

Deferred recoverable energy costs Mandated refunds to customers(Note

11).............

Sale of LILCOGeneral and Refunding Bonds(Note 11)

Repayment of construction advances(Note

11)........

Sale/leaseback of transqission facility................

Other investments Unamortized debt expense (Increase) decrease in working capital other than short-term debt (see below)..............

Miscellaneous (net)

Total resources provided FINANCIALRESOURCES WERE USED FOR:

Construction additions, including capital leases Nuclear fuel.

Allowance forfunds used during construction...

Net additions Amounts accrued under Cotenant Agreement(Note 10)..

Advances on behalf of Nine MilePoint Nuclear Unit No. 2 cotenant (Note 11)

Reduction of long-term debt.

Reduction of preferred and preference stock...........

Dividends Total resources used (Increase) decrease In working capital other than short-term debt:

Cash Accounts receivable Coal and oil for production of electricity...............

Other materials and supplies Long-term debt due within one year...................

Redemption and sinking fund requirements on redeemable preferred stock............

Accounts payable Payable on outstanding bank checks..................

Accrued taxes and interest Gas supplier refunds due customers..................

Cotenant prepayments to Nine Mile Point Nuclear Unit No. 2 project fund Due to cotenants under Cotenant Agreement(Note 10)

Other (net) 1966 397,865 155,311 (165,793) 18>257 133>743 539,383 4>603 75,000 500,000 98>900 8>959 93,017 780,479 22,585 (16,771) 140,000 92,847 128,000 72>596 (53,949)

(21,395)

(11,133) 352,780

$1,672,642 750,526 23,536 (165,793) 608,269 171,100 467,764 107,380 318,129

$1,672,642

$ (131,046)

(5,388) 20>950 (7,565) 28,449 47,330 (45,549)

(3>828)

(4,726)

(8,535)

(83,808) 171,100 1,221 (21,395) fn thousands, ofdollars 1985 411,430 150,627 (187,316) 25,448 141,206 (4,707) 536,688 185,270

'5,000 175,000 225,000 (29,880)

(46,321) 584,069 (16,267)

(10,191) 38,481 (32,775)

(11,602) 92,084 (9,331) 50,399

$ 1

~171,156 S

718,903 52,217 (187,316) 583,804 135,808 126,717 13,050 311,777

$1,171,156 (12,294)

(1,730) 32,020 (3,432) 1,628 (6,551) 3,848 3,988 (5,990) 5,137 84,594 (9,134) 92,084 359,734 141,150 (161,496) 17,612 116,265 (10,821) 462,444 189,626 50,000 319,250 81,618 5,060 (31,247) 614,307 9,480 (9,273)

(27,495)

(8,128) 38,964 3,643 7,191

$ 1,083,942 746,910 22,936 (161,496) 608,350 120,060 67,005 20,574 267,953

$1,083,942 (1,440)

(8,156)

(564)

(5,764) 33,685 7,651 (2,213)

(17,119) 27,440 (8,989)

(2,507) 16,940 38,964

NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES 21 Notes to Consolidated Financial Statements NOTE 1. Summary of Significant Accounting Policies The Company is subject to regulation by the New York State Public Service Commission (PSC) and the Federal Energy Regulatory Commission (FERC) with respect to its rates for service and the maintenance of its accounting records. The Company's accounting policies conform to generally accepted accounting principles, as applied to regulated public utilities, and are in accordance with the accounting requirements and ratemaking practices of the regulatory authorities.

In December 1986, Statement of Financial Accounting Stan-dards No. 90, "Regulated Enterprises Accounting for Aban-donments and Disallowance of Plant Costs" was issued by the Financial Accounting Standards Board (FASB) and is required to be adopted not later than 1989. (See Note 10-Nine Mile Point Nuclear Station Unit No. 2 for a detailed discussion of the effects of this pronouncement).

Principles of Consolidation:

The consolidated financial statements include the Company and its wholly-owned sub-sidiaries. All significant intercompany balances and transac-tions have been eliminated. Assets and liabilities of foreign subsidiaries are translated into U.S. dollars at the exchange rate in effect at the balance sheet date. Revenue and expense accounts are translated at the average exchange rate in effect during the year. Currency translation adjustments are recorded as a component of equity and do not have a significant impact on financial condition.

Utility Plant: The cost of additions to utility plant and of re-placements of retirement units of property is capitalized. Cost includes direct material, labor, overhead and an allowance for funds used during construction (AFC). The cost of current re-pairs and maintenance is charged to expense. Whenever utility plant is retired, its original cost, together with the cost of re-moval, less salvage, is charged to accumulated depreciation.

Allowance for Funds Used During Construction:

The Com-pany capitalizes AFC in amounts equivalent to the cost of funds devoted to plant under construction. AFC rates are de-termined in accordance with FERC and PSC regulations. The Company computes AFC at a rate which is reduced to reflect the income tax effect of the borrowed funds component of AFC for all additions to electric utilityplant. The AFC rates in effect December 31, 1986 were 11.02% and, net of tax at the current statutory rate of 46%, 8.90%. AFC is segregated into its two components, borrowed funds and other funds, and is reflected in the Interest Charges section and the Other Income and Deductions section, respectively, of the Consolidated State-ment of Income.

Effective April 1985, pursuant to a PSC authorization, the Company discontinued accruing AFC on $320 million of con-struction work in progress (CWIP) for which a cash return is being allowed through inclusion in rate base of that portion of the investment in the Nine Mile Point Nuclear Station Unit No. 2 (Unit). This amount was increased to $680 million in April 1986.

Amounts equal to the AFC which is no longer accrued on the CWIP included in rate base are being accumulated in deferred debit and credit accounts and, at the time the Unit commences commercial operation and is placed in rate base, the balance in the deferred credit account could be available to reduce future revenue requirements over a period potentially shorter than the life of the Unit. It is currently expected that the balance in the deferred debit account will be amortized and recovered in rates over the life of the Unit.

Depreciation, Amortization and Nuclear Generating Plant De-commissioning Costs: For accounting purposes, depreciation is computed on the straight-line basis using the average or remaining service lives by classes of depreciable property. In addition, certain costs associated with the discontinued Ster-ling Nuclear Station (See Note 2) were amortized over shorter periods as approved by the PSC. For Federal income tax pur-poses, the Company computes depreciation using accelerated methods and shorter allowable depreciable lives.

Estimated decommissioning costs (costs to remove the plant from service in the future) of the Company's Nine Mile Point Nuclear Station Unit No. 1 are being recovered in rates through an annual allowance and charged to operations through de-preciation charges.

Based on a study completed in 1986, the cost of decommissioning Nine Mile Point Nuclear Station Unit No. 1, which is expected to begin in the year 2005, is estimated to be approximately $442,000,000 at that time ($211,700,000 in 1986 dollars). Through December 31, 1986, the Company has recovered $23,200,000 of decommissioning costs in rates. The Company's 41% share of costs to decommission Nine Mile Point Nuclear Station Unit No. 2 which is expected to begin iri the year 2027, is estimated to be approximately $565,000,000

($108,100,000 in 1986 dollars). The annual allowances for re-covery, based upon currently estimated decommissioning costs over the life of these units, are under consideration in the Company's current rate proceeding. The Company continues to review the estimated requirements for decommissioning and plans to seek rate adjustments when appropriate. There is no assurance that the decommissioning allowance will ulti-mately aggregate a sufficient amount to decommission the units. The Company believes that decommissioning costs, if higher than currently estimated, willultimately be recovered in the rate process, although no such assurance can be given.

Amortization ol Nuclear Fuel: Amortization of the cost of nu-clear fuel is determined on the basis of the quantity of heat produced for the generation of electric energy. The cost of disposai of nuclear fuel, which presently is $.001 per kilowatt-hour of net generation, is based upon a contract with the U.S.

Department of Energy. These costs, which are associated with generation at Nine Mile Point Unit Nuclear Station No. 1, 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 rendered to certain customers monthly and others bi-monthly. The Com-pany does not accrue revenues for energy consumed and not billed at the end of any fiscal period. The Company's tariffs include electric and gas adjustment clauses under which energy and purchased gas costs, respectively, above or below the levels allowed in approved rate schedules, are billed or credited to customers.

The Company, as authorized by the PSC, charges operations for energy and purchased gas cost increases in the period of recovery. The PSC has periodically authorized the Company to make changes in the level of al-lowed energy and purchased gas costs included in approved rate schedules. As a result of such periodic changes, a portion

22 NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES ot energy costs deferred at the time of change would not be recovered under the normal operation of the electric adjust-ment clause.

However, the Company has been permitted to amortize and billsuch portions to customers, through the elec-tric adjustment clause, over 36 months from the effective date of each change.

The Company's electric fuel adjustment clause provides for partial pass-through of fuel cost fluctua-tions from those forecast in rate proceedings with the Com-pany absorbing a specific portion ot increases or retaining a portion of decreases to a maximum of $15 millionper rate year.

Federal Income Taxes: In accordance with PSC requirements, the tax effect of book and tax timing differences is flowed through unless authorized by the PSC to be deferred. The Company provides deferred taxes on certain benefits realized from depreciation, on deferred energy and purchased gas costs, on nuclear fuel disposal costs accrued prior to April 7, 1983, on nuclear generating plant decommissioning costs, on certain construction overheads and on certain other items (see Note 9). In conformity with ratemaking practices of the PSC, the Company has not provided deferred taxes on approxi-mately $ 1.6 billion of other tax deductions which include cer-tain depreciation differences and various construction ov'er-heads deductible currently tor tax purposes and capitalized for accounting and ratemaking purposes.

The Company has claimed 10 percent investment tax credit and deferred the ben-.

efits of such credits as realized in accordance with PSC direc-tives. For purposes ot computing capital cost recovery deduc-tions and normalization, the asset basis is partly reduced by the credit claimed. The imputed tax benefit of the borrowed funds component of AFC and the tax effect of LILCO General and Refunding Bond interest and supplemental payments are recorded in Other Income and Deductions (see Note 11).

Amortization of Debt Issue Costs: The premium or discount and debt expenses on long-term debt issues and on certain debt retirements prior to maturity, are amortized ratably over the lives ot the related issues and included in interest on long-term debt (see Note 7).

Pension Plans: The cost of pension plans is based upon cur-rent costs, amortization of unfunded past service benefits over periods ranging from 15 to 40 years and amortization over 15 years of unfunded past service benefits arising from plan amendments.

The Company's policy is to fund pension costs accrued (see Note 8).

In December 1985, Statement of Financial Accounting Stan-dards No. 87 "Employers'ccounting for Pensions" was is-sued by the FASB and is effective for fiscal years beginning after December 15, 1986. The adoption of the requirements of this statement is not currently anticipated to have a significant impact on the results of operations or financial position of the Company as shown in the Consolidated Financial Statements.

NOTE 2. Depreciation and Amortization The total provision fordepreciation and amortization, includ-ing amounts charged to clearing accounts, was $ 156,494,000 for 1986, $151,817,000 for 1985 and $142,500,000 for 1984. The provisions include approximately $2,800,000, $9,500,000 and

$10,200,000, respectively, resulting from the PSC allowed re-covery of the amortization of costs associated with the discon-tinued Sterling Nuclear Station. The percentage relationship between the total provision for depreciation and average de-preciable property was 3.0% in 1986 and 1985 and 2.9% in 1984. The Company makes depreciation studies on a continu-ing basis and, upon approval by the PSC, periodically adjusts the rates of its various classes of depreciable property.

NOTE 3. N M Uranium, Inc.

'During 1976, through a wholly-owned subsidiary, N M Uranium, Inc. (NMU), the Company purchased a 50 percent undivided interest in uranium deposits and associated mining equipment to be held by a jointly-owned mining venture. Ac-quisition of this interest was made primarily to provide a more assured future supply of nuclear fuel. The investment in the subsidiary, which includes costs incurred since acquisition and AFC accrued through March 31, 1981, has been reduced by the proceeds from the sale of uranium, net of tax, and trans-fers to the Company and is included in the consolidated finan-cial statements as part of the nuclear fuel component of utility plant. Such investment totaled $82,200,000 at December 31, 1986 and $73,800,000 at December 31, 1985.

In connection with the Company's rate decisions in March 1984 and March 1986 the PSC has allowed, as the cost of ap-proximately 790,000 lbs. of NMU uranium utilized in the 1984 and 1986 reloads of the Company's Nine Mile Point Nuclear Unit No. 1 and approximately 107,000 lbs. utilized for a portion of the initial core at Nine Mile Point Nuclear Unit No. 2, a price which represents the average United States delivery price for the year, as reported by the U.S. Department of Energy (DOE).

The total allowed value of these transfers using DOE prices is approximately $30.5 million while the Company's cost is ap-proximately $39.4 million. The differential between the Com-pany's cost of'this NMU uranium and that amount allowed to be recovered in rates charged to customers has been deferred subject to the PSC approval of the comparison of cost to mar-ket on an aggregate basis over the life of the project. The Com-pany anticipates that, based upon present DOE forecasts of average delivery prices, substantially all of its investment will be recovered, although no such assurance can be provided.

NOTE 4. Bank Credit Arrangements At December 31, 1986, the Company had $673 million of bank credit arrangements, including the Oswego Facilities Trust, with 34 banks. These credit arrangements consisted of

$450 million in commitments under Revolving Credit and Term Loan Agreements,

$10 million in short-term commitments under Credit Agreements,

$113 million in lines of credit and

$100 million under a Bankers Acceptance Facility Agreement.

The Revolving Credit and Term Loan Agreements extend through 1990 although the revolving credit periods under the agreements for $135 million of the $450 million expire in 1987.

At the option of the Company, the interest rate applicable to borrowings under these agreements is based on the prime rate or at specitied increments over the rates applicable to certifi-cates of deposit or, in certain agreements, eurodollar deposits.

Allof the other bank credit arrangements are subject to review on an ongoing basis with interest rates negotiated at the time of use. The Company also issues commercial paper. Unused bank credit facilities are held available to support the amount of commercial paper outstanding, including amounts currently issued in connection with Interest Rate Exchange Agreements (see Note 7). $215 million of the Revolving Credit and Term Loan Agreements contain representations and covenants which, if not met or re-negotiated, would prevent the Company

NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES 23 AtDecember 31:

In thousands ofdollars 1986 1985 from making new borrowings under such agreements and re-quire the Company to begin scheduled repayment over three years of amounts outstanding.

The Company pays fees for substantially all of its bank credit arrangements.

The Bankers Acceptance Facility Agreement, which is used to finance the fuel inventory for the Company's

,generating stations, provides for the payment of fees only at the time of issuance of each acceptance.

Amounts outstanding under Interest Rate Exchange Agree-ments and Revolving Credit and Term Loan Agreements to-taled $100 million at December 31, 1986 and are recorded as long-term debt.

Additional bank credit arrangements in connection with the Company's guarantee of certain obligations of LILCO are dis-cussed in Note 11.

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

Operating revenues:

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

Gas In thousands ofdollars 1986 1985 1984

$2,131,833

$2,096,404

$2,134,470 528,486 598,536 651,076 NOTE 6. Information Regarding the Electric and Gas Businesses The Company is engaged in the electric and natural gas util-ity businesses.

Certain information regarding these segments is set forth in the following table. General corporate expenses, property common to both segments and depreciation of such common property have been allocated to the segments in ac-cordance with practice established for regulatory purposes.

Identifiable assets include net utility plant, materials and supplies, deferred finance charges and deferred recoverable energy costs. Corporate assets consist of other property and investments, cash, accounts receivable, prepayments, unamor-tized debt expense and other deferred debits.

Short-term debt:

Commercial paper....

Notes payable Bankers acceptances Weighted average interest rate (a)..

For earendedDecamber31:

$100>212 8.33%

7,195 7.93o/o

..S 72>000 212 2,195 28,000 5,000 Total

$2,660,319

$2,694,940

$2,785,546 Operating Income before taxes:

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

S 596,864 529,659 511,842 Gas 55,547 55,100 62,651 S

652,411 584,759 S

574,493 Total Dailyaverage outstanding......

Dailyweighted average interest rate(a)

Maximum amount outstandin (a) Excluding fees.

.. $197,557 6.6ty/o

.. 4396,115

$ 45,607 8.31%

$ 182.818 Total...................

818,204 Income taxes................

211,237 Other Income and deductions.

69,832 Interest char es.............

278,934 772,075 173,471 79,818 266,992 735,989 181,767 42,051 236,539 Pretax operating Income, Including AFC:

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

762,362 716,719 S

672,964 Gas 55,842 55,356 63.025 NOTE 5. Jointly-Owned Generating Facilities The following table reflects the Company's share of jointly-owned generating facilities at December 31, 1986. The Com-pany is required to provide financing for the unit in process of construction and for any additions to the units in service. The Company's share of expenses associated with the Roseton units and Oswego Steam Station Unit No. 6 is included in the appropriate operating expenses in the Consolidated Statement of Income.

In thousands ofdollars Percentage Construction owner-Utility Accumulated work in ship plant depreciation progress Nat income 397,865 411,430 359,734 Depreciation:

Electric.....

Gas Total S

141,663 137,630 128,521 13,648 12,997 12,629 155,311 150,627 141,150 Construction expenditures (including nuclear fuel):

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

S 734,348 S

749,912 S

734,706 Gas 39,714 21,208 35,140 Total S

774,062 771,120 S

769,846 Roseton Steam Station Units No. 1 and 2(a)...

25

$ 83,199

$27,513 738 Oswego Steam Station Unit No. 6(b)..........

76

$260,099

$47,961 631 Nine MilePoint Nuclear Station UnitNo. 2(c)(d).

41

$2,263,700 (a) The remaining ownership interests are Central Hudson Gas and Electric Corporation, the operator of the plant (35%) and Consoli-dated Edison Company of New York, Inc. (40%).

(b) The Company is the operator. The remaining ownership interest is Rochester Gas and Electric Corporation (24%).

(c) The remaining ownership interests are Long Island Lighting Com-pany (18%), New York State Electric and Gas Corporation (18%),

Rochester Gas and Electric Corporation (14%), and Central Hud-son Gas and Electric Corporation (9%) (see Note 10).

(d) Excludes amounts spent for nuclear fuel, unshared internal Com-pany charges, certain costs associated with non-generating facilities being constructed in connection with the Unit and ac-crued amounts due under the Cotenant Agreement.

Identifiable assets:

Electric..........

Gas Total........

Cor orate assets Total assets

$6,424,656

$5,756,586

$5,155,372 468,299 444,070 432,113 6,892,955 6,200,656 5,587,485 718,248 813,181 645,916

$7,611,203

$7,013,837

$6,233,401

24 NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES NOTE 7. Capitalization CAPITAL STOCK The following table summarizes the shares of capital stock authorized, issued and outstanding:

At December 31 ~

1986 1985 1984 Common stock, $1 par value:

Authorized Issued &outstandin 150,000,000 127,140,994 150,000,000 126,928,340 150,000,000 116.848.974 Preferred stock, $100 par value:

'uthorized Issued &outstanding............

Preferred stock, $25 par value:

Authorized Issued &outstanding...........

Preference stock, $25 par value:

Authorized Issued &outstandin 3,400,000 3,260,000 19,600,000 14,874,000 4,000,000 0

3,400,000 3,400,000 3,318,000 3.342.510 19,600,000 19,600,000 14,044,000 '1,210,000 4,000,000 4,000,000 0

.520,000 The table below summarizes changes in capital accounts for 1984, 1985 and 1986:

Common Stock

($ 1 par value)

Preferred and Preference Stock

$100 par value

$25 par value on-on-Redeem-Redeem-Redeem-able'ble'hares able*

Capital Stock Premium Redeem-Expense able'Net)*

Balance January 1, 1984 Sales in 1984.............

Issued to stock purchase plans in 1984............

Redemptions.............

Foreign currency translation ad'ustment...

104,010,003 $ 104,010 3,370,240

$210,000 6,534,400 6,534 6,304,571 6,305 (27,730)

$127,02/a) 10,136,000 2,000,000 (2,773)

(406,000)

(10,150) 87,117 555 (2,126)

$30,000

$223,40/'e)

$1,174,382 50,000 87,878 Balance December 31, 1984 Salesin1985.............

Issued to stock purchase plansin1985............

Redemptions.............

Foreign currency tr'anslation adjustment...

116,848,974 116,849 3,342,510 4,465,600 4,465 5,613,766 5,614 (24,510) 210,000 124,251(a) 11,730,000 30,000 3,000,000 50,000 (2,451)

(686,000)

(17,150) 99,535 442 (2,422) 263,250fa) 1,347,806 25,000 74,216 Balance December 31,1985 Salesin1986.............

Issued to stock purchase plans in1986............

Redemptions.............

Foreign currency tran'slation ad'ustment....

126,928,340 126,928 3,318,000 60,354 61 152,300 152 (58,000)

(5,800)

(2,170,000)

(54,250) 2,821 437 603 210,000 121,80+a) 14,044,000 80,000 271,100(a) 1,519,577 3,000,000 75,000 (939)

Balance December31,1986 127,140,994 $ 127,141 3,260,000

$210,000

$ 116,00ga) 14,874,000

$80,000

$291,850(e)

$ 1,522,499

'In thousands of dollars.

(e) Includes sinking fund requirements due withinone year.

NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES 25 NON-REDEEMABLE PREFERRED STOCK (Optionally Redeemable)

The Company has certain issues of preferred stock which provide for optional redemption as follows:

At December 31, Redemption price per share (Before adding accumulated dividends)

In thousands of dollars Eventual 1986 1985 1984 December 31, 1986 minimum Preferred $100 par value:

3.40% Series; 200,000 shares..

3.60% Series; 350,000 shares..

3.90% Series; 240,000 shares..

4.10% Series; 210,000 shares..

4.85% Series; 250,000 shares..

5.25% Series; 200,000 shares..

6.10% Series; 250,000 shares..

7.72% Series; 400,000 shares..

Preferred $25 par value:

Adjustable Rate Series A; 1,200,000 shares...........

Adjustable Rate Series C; 2,000,000 shares...........

$ 20,000 35,000 24,000 21,000 25,000 20,000 25,000 40,000 30,000 50,000

$ 20,000 35,000 24,000 21,000 25,000 20,000 25,000 40,000 30,000 50,000

$ 20,000 35,000 24,000 21,000 25,000 20,000 25,000 40,000 30,000

$103.50 104.85 106.00 102.00 102.00 102.00 101.00 105.44 (a)

(b)

$ 103.50 104.85 106.00 102.00 102.00 102.00 101.00 102.36 25.00 25.00 (a) Not redeemable until 1988.

(b) Not redeemable until 1990.

$290,000

$290,000

$240,000 MANDATORILYREDEEMABLE PREFERRED STOCK The Company has certain issues of preferred and preference stock which provide for mandatory and optional redemption as follows:

At December 31, Redemption price per share (Before adding accumulated dividends)

In thousands of dollars 1986 1985 1984 December 31, 1986 minimum Preferred $100 par value:

7.45% Series; 420,000,438,000, and 456,000 shares...

10.13/o Series; 250,000 shares 10.60% Series; 240,000,280,000 and 286,510 shares..

12.75% Series; 250,000 shares Preferred $25 par value:

8.375% Series; 1,200,000, 1,300,000 and 1,400,000 shares 8.75% Series; 3,000,000 shares 9.75%Series; 738,000, 804,000 and 870,000shares 9.75% Series (second); 816,000 and 1,020,000 shares 10.13/o Series; 1,000,000 shares 10.75% Series; 1,600,000 shares 12.25% Series; 700,000 shares.

12.50/o Series; 620,000 shares 12.75% Series; none and 1,000,000 shares.............

15.00'/o Series; none and 800,000 shares..............

Adjustable Rate Series B;2,000,000shares.............

Preference $25 par value:

7.75% Series; none and 520,000 shares..............

30,000 75,000 18,450 20,400'5,000 40>000 17,500 15,500 50,000 32,500 20,100 25,500 25,000 40,000 17,500 15,500 25,000 20,000 50,000 35,000 21,750 25,500 25,000 40,000 17,500 15,500 20,000 50,000 13,000

$ 42I000

$ 43,800

$ 45,600 25,000 25,000 25,000 24,000 28,000 28,651 25I000'5,000 25,000

$104.33 (a) 107.95 26.21 (b) 26.1625 26.22 (a)

(a)

(c)

(c)

(d)

$100.00 100.00 102.65 25.00 25.00 25.00 25.00 25.00 25.00 25.00 25.00 25.00 Lesssinkin fundandredem tionrequirements..

407,850 60,380 392,900 387,501 13,050 19,601 (a) Not redeemable until 1988.

(b) Not redeemable until 1992.

(c) Not redeemable until 1991.

(d) Not redeemable until 1989.

'Series called for redemption January 19, 1987.

$347,470

$379,850

$367,900

26 NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES These series require mandatory sinking funds for annual redemption and provide optional sinking funds through which the Company may redeem, at par, a like amount of additional shares (limited to 120,000 shares of the 7.45% series and 300,000 shares of the 9.75% series). The option to redeem additional amounts is not cumulative.

The Company's five-year mandatory sinking fund redemption requirements for preferred stock are as follows:

No. of shares Commencing In thousands ofdollars 1987

'988 1989 1990 1991 Preferred $100 par value:

7.45% Series..........

10.13/o Series..........

10.60% Series..........

Preferred $25 par value:

8.375% Series.........

~

8.75% Series 9 75o/o Series...........

10.13/o Series...........

10.75% Series..

~ ~ ~.

~

~

~

~

~

12.25% Series...........

12.50/o Series...........

Ad ustable Rate Series B.

18,000 25,000 20,000 100,000 600,000 66,000 100,000 320,000 43,060 38,139 50,000 6/30/77 12/31/87 3/31/80 4/1/83 12/31/92 10/1/80 12/31/87 6/30/89 3/31/87 3/31/87 9/30/93

$ 1,800 2,500 2,000 2,500 1,650 2,500 1,077 953

$ 1,800 2,500 2,000 2,500 1,650 2,500 1,077 953

$ 1,800 1,875 2,000 2,500 1,650 1,875 8,000 1,077 953

$ 1,800 2,500 2,000 2,500 1,650 2,500 8,000 1,077 953

$ 1,800 2,500 2,000 2,500 1,650 2,500 8,000 1,077 953

$14,980

$14,980

$21,730

$22.980

$22,980 LONG-TERM DEBT Long-term debt and long-term debt due within one year consisted of the following:

In thousands ofdollars At December 31, 1986 1985 In thousands ofdollars At December 31 ~

1986 1985 First mortgage bonds:

3Vs% Series due May 1,1986.........

4r/s% Series due September 1, 1987...

3Vs%Seriesdue June1,1988........

14Vs% Series due August 11, 1988.....

12%

Series due March 1, 1989.......

9Vs% Series due October 1, 1989.....

4s/4% Series due April 1, 1990.........

15%

Series due March 1, 1991.......

14s/4% Series due May 1, 1991.........

4>/s% Series due November 1, 1991 12.73/o Series due February 1, 1992....

13.06% Series due February 1, 1992....

12.73% Series due February 20,1992..

12.68% Series due February 28, 1992..

15Vs%Seriesdue March1,1992.......

15s/4% Series due June 1,1992........

11%

Series due May1,1S93.........

12Vs% Series due March 1, 1994.......

Br/s% Series due August 1, 1994......

4Vs% Series due December 1, 1994...

9Vs% Series due October 1, 1996.....

5r/s%SeriesdueNovember1,1996 6>/4% Series due August 1, 1997......

6Vs% Series due August 1, 1998......

12Vs% Series due March 1, 1999.......

9>/s% Series due December 1, 1999...

12.95% Series due October 1, 2000....

7s/s% Series due February 1, 2001.....

7Vs% Series due February 1, 2002.....

774% Series due August 1,2002......

8V4% Series due December 1,2003...

SVs% Series due December 1,2003...

9.95% Series due September 1, 2004..

10.20% Series due March 1,2005......

8.35% Series due August 1 ~ 2007.....

8Vs%SeriesdueDecember1,2007 13Vs% Series due April 1, 2012.........

16% Series due August 1,2012........

50,000 50,000 34,000 20,000 13,000 50>000 40>000 20>000 50,000 10,000 20,000 25,045 23,346 50>000 150,000 40,000 100,000 45,000 40,000 60,000 75,000 69>334 65,000 80,000 80,000 80>000 50>000 90,000 35,000 71,050 42,000 25,760 3>016

$ 30,000 50,000 50,000 50,000 20,000 13,000 50,000 38,650 90,000 40,000 20,000 50,000 10,000 20,000 50,000 58,500 50,000 13,000 40,000 45,000 40,000 60,000 17,000 75,000 80,000 65,000 80,000 80,000 80,000 50,000 95,000 35,000 71,050 44,000 25,800 3,046 12r/s% Series due November 1, 2012 12'/s% Series due March 1,2013.....

12Vs% Series due June 15, 2013.....

'11V4% Series due July 1,2014.......

11%% Series due October 1,2014...

10/oSeriesdue June1,2016........

10/oSeriesdueNovember1,2016 8~/s% Series due November 1 ~ 2025 Total First Mortgage Bonds.........

Promissory notes:

'%SeriesAdue June1,2004.......

'Adjustable Rate Series due July 1, 2015 December 1, 2025 December 1, 2026 Notes payable:

17% Eurodollar Guaranteed Notes due September 15,1989.................

Adjustable London Interbank Offered Rate due September 15, 1989.....

Intermediate Notes, Various rates, due 1989-1992 Swiss Franc Bonds due December 15, 1995..

15.02/o Unsecured Notes due 1990.........

Notes, Interest Rate Exchange Agreement...

Revolving credit and loan agreements Revolving credit agreement, Oswego Facilities Trust.................

Other Unamortized remlum discount TOTALLONG-TERM DEBT.............

Less lon -term debt due within one ear Tax-exempt pollution control related issues 79,355 69,530 75,690 40,015 150>000 100,000 75,000 100,000 100,000 50,000 75,690 40,015 75,000 2>246,141 2,129,751 46,600 46,600 100,000 75,000 50,000 100,000 75,000 48,900 50,000 50,000 50,000 46,705 9,000 50,000 50,000 50,000 25,000 25,000 34,039 25,080 117,906 99,875 6

1,548 2,893,519 2,708,559 93,914 65,465

$2,799,605

$2,643,094

NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES 27 Several series of First Mortgage Bonds and Notes were issued to secure a like amount of tax-exempt revenue bonds and notes issued by the New York State Energy Research and De-velopment Authority (NYSERDA). $225,000,000 bear interest at a daily adjustable interest rate (with a Company option to con-vert to a fixed interest rate) which averaged 4.38% for 1986 and are supported by bank direct pay letters of credit. Pursuant to

'agreements between NYSERDA and the Company, trust funds have been established with the proceeds from the bond and note issues. Such proceeds are to be used for the purpose of constructing certain pollution control facilities at the Com-pany's generating facilities. Unexpended proceeds in the trust funds amounted to $2,238,000 at December 31, 1986 and are recorded in Other Property and Investments.

Notes Payable include a ten-year Swiss Franc Bond issue equivalent to $50,000,000 in U.S. funds. Simultaneously with the sale of these bonds, the Company entered into a currency exchange agreement to fullyhedge against currency exchange rate fluctuations.

The Company has Interest Rate Exchange Agreements ex-tending into 1991 for $75,000,000, including $25,000,000 for Oswego Facilities Trust (Trust). The agreements require the Company to make fixed rate payments which, calculated on a semi-annual bond basis, are equivalent to 7.53%, and, in ex-change, receive a LIBOR-based floating rate payment from a bank. The Company generally uses its own commercial paper notes as the source of funding for $50,000,000 and Trust notes for $25,000,000. The related interest expense is recorded on a net basis.

The arrangements with the Trust provide financing for the construction of a new energy management system. The Trust has a $50,000,000 Direct Pay Letter of Credit Facility and Re-volving Credit Agreement, $25,000,000 of which is subject to an Interest Rate Exchange Agreement and is used to support its commercial paper obligations. All such obligations are se-cured by certain assets held by the Trust. The Company is required to purchase, or otherwise arrange for, the disposition of the Trust assets upon the termination of the Trust. The Letter of Credit Facility and Revolving Credit Agreement of the Trust require payment of fees which are based upon the amount of commercial paper outstanding.

Other long-term debt in 1986 consists of obligations under capital leases of $56,180,000 and a liabilityto the U.S. Depart-ment of Energy for nuclear fuel disposal of $61,726,000.

Certain of the Company's debt securities provide for a mandatory sinking fund for annual redemption. The Company's five-year mandatory sinking fund redemption requirements are as follows:

Principal amount Commencing 1987 In thousands ofdollars 1988 1989 1990 1991 First Mortgage Bonds:

10.20% Series due March 1, 2005......

6.35% Series due August 1, 2007.....

8Vs% Series due December 1, 2007...

9.95% Series due September 1, 2004 14~/s% Series due August 11, 1966.....

12.95% Series due October 1, 2000....

9'%eries due December 1

~ 2003...

Promissory Notes:

6% Series Adue June 1,2004........

81,500 750 2,000 5,000 17,000 5,333 2,941 500 3/1/78 8/1/82 12/1/83 9/1/65 6/11/66 10/1/86 12/1/87 6/1/90 8 1,500 550(a) 2,000 5,000 17,000 5,333 2,941 8 1,500 750 2,000 5,000 17,000 5,333 2,941 8 1,500 750 2,000 5,000 5,333 2,941 8 1,500 750 2,000 5,000 5,333 2,941 500 8 1,500 750 2,000 5,000 5,333 2,941 500 (a) A portion of the requirements have been met by advance purchases.

$34,324

$34,524

$ 17,524

$16,024

$18,024 Additionally, certain other series of mortgage bonds provide for a debt retirement fund whereby payment requirements may be met, in lieu of cash, by the certification of additional property, the waiver of the issuance of additional bonds or the retirement of outstanding bonds. The 1986 requirements for these series were satisfied by the certification of additional property. The Com-pany anticipates that the 1987 requirements for these series will be satisfied by other than payment in cash. Total annual debt retirement fund requirements for these series, based upon mortgage bonds outstanding December 31, 1986, are $7,050,000.

NOTE 8. Pension and Other Retirement Plans.

The Company and its subsidiaries have non-contributory pension plans covering substantially all their employees. The total pension cost was $44,300,000 for 1986 and $42,100,000 for 1985 and 1984 (of which $ 15,600,000 for 1986, $13,400,000 for 1985 and $11,400,000 for 1984 was related to construction labor and accordingly, was charged to construction projects).

Studies indicate that the accumulated plan benefits, as de-termined by consulting actuaries, and plan net assets for the Company's plans at December 31, 1986 and 1985 are as fol-lows:

Total Net assets available for lan benefits..

8501,000

$433,000 8677,000

$563,000 The weighted average assumed rate of return used in deter-mining the actuarial present value of accumulated plan ben-efits was 7~/~% in 1986 and 8% in 1985.

In thousands ofdollars 1986 1985 Actuarial present value of accumulated benefits:

Vested

$471,000

$409,000 Non-vested 30,000 24,000

28 NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES The table on page 27 summarizes accumulated plan benefits attributable to employee wage levels and service rendered through December 31, 1986 and 1985. These amounts do not take into consideration expected future service, wage in-creases and associated actuarial assumptions.

These addi-tional factors and assumptions are considered in determining the funding requirements of the Company's ongoing pension plans, based upon an approved actuarial cost method, and are in conformity with generally accepted actuarial principles and practices.

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

Substantially all of the Com-pany's employees may become eligible for these benefits if they reach retirement age while working for the Company.

These benefits are provided through an insurance company whose premiums are based on the benefits paid during the year. The cost (insurance premiums) of providing these ben-efits amounted to approximately

$7,900,000 for 1986,

$7,500,000 for 1985 and $6,000,000 for 1984.

Components of United States and foreign income before in-In thousands ofdollars 1986 1985 1984 United States..............

Foreign Consolidatin eliminations

$570,113 14,311 7,61

$551,907

$499,285 17.516 18,326 11,230 9,570 Income before income taxes

$576,809

$558,193

$508,041 Following is a summary of the components of Federal and foreign income tax and a reconcilation between the amount of Federal income tax expense reported in the Consolidated Statement of Income and the computed amount at the statu-tory tax rate:

NOTE 9. Federal and Foreign Income Taxes Income Tax Reform: In October 1986, the Tax Reform Act of 1986 (Act) was signed into law. One of the provisions of the Act lowered the statutory corporate Federal income tax rate from 46% to 34% effective July 1, 1987. The deferred Federal income taxes below relating to book/tax timing differences have been provided at the current statutory rate of 46%.

Summary Analysis:

In thousands ofdollars 1986 1985 1984 Components of Federal and foreign Income taxes:

Current tax expense: Federal.

Forei n

Deferred Federal income tax expense Income taxes included In Operating Expenses........................

Federal income tax expense included In Other Income and Deductions Federal income tax credits included in Other Income and Deductions. '..

Total

$ 24,959 6,767 31,726 179,511 211>237 13,475 45,768

$178,944

$ (21,329) 7,746 (13,583) 187,054 173,471 19,140 45,848

$146,763

$ 17,713 8,498 26,211 155,556 181,767 5,831 39,291)

$148,307 Components of deferred Federal Income taxes(Note 1)t Depreciation Investment tax credit Construction overheads Recoverable energy and purchased gas costs Gain on disposition of property.

Nuclear fuel disposal cost.

Reacquisition of bonds Sterling abandonment Other Deferred Federal income taxes net

$ 50,399 48,252 26,111 (9,309)

(15,374) 15,700 (1,243) 19,207

$133,743

$ 38,822 36,507 17,973 6,472 41,148 4,601 (3,769) 548)

$ 141,206

$ 52,130 54,900 6,756 (2,458) 3,100 1,477 (1,566) 1,926

$ 116,265 Reconciliation between Federal and foreign income taxes and the tax computed at prevailing U.S. statutory rate on Income before Income taxes:

Com uted tax

$265,332

$256,769

$233,699 Reduction attributable to flow-through of certain tax adjustments:

Depreciation Allowance forfunds used during construction Taxes, pensions and employee benefits capitalized foraccounting purposes..

Real estate taxes on an assessment date basis Deferred taxes provided at other than the statutory rate.

Other (18,235) 76>266 1,645 4>074 7,210 15,428 (16,274) 86,166 5,113 6,062 13,855 15,084 (14,926) 74,288 11,896 (406) 12,143 2,397 Federal and forei n income taxes 86,388

$178,944 85,392 110,006

$146,763

$148,307

NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES 29 NOTE 10. Nine Mile Point Nuclear Station Unit No. 2 Nine Mile Point Nuclear Station Unit No. 2 (Unit), a nuclear power plant being constructed and to be operated by the Company and shared with other utilities, is the only major generating facility currently under construction by the Com-pany. Ownership is shared by the Company (41%), Long Island Lighting Company (LILCO) (18%), New York State Electric &

Gas Corporation (18%), Rochester Gas and Electric Corpora-tion (14%), and Central Hudson Gas 8 Electric Corporation (9%). Output of the Unit, which will have a projected capability of 1,084,000 kw., is to be shared in the same proportions as the cotenants'espective ownership interests.

The recovery of costs associated with the Unit is being af-fected by the Cost Settlement Agreement and the implementa-tion of such Agreement for ratemaking purposes as discussed below. Also, recent changes in generally accepted accounting principles will require the recognition of the loss associated with disallowed plant costs by the year 1989. Under the terms of the Cost Settlement Agreement, the loss to the Company would approximate $626 million, net of Federal income taxes at a 46% rate, and could increase as described more fullyunder "Ratemaking and Financial Accounting Recognition" below.

Construction Status-Cost and Schedule: On October 31, 1986, the Company obtained a low power license from the Nuclear Regulatory Commission (NRC), which included a schedule exemption to permit the loading of fuel to take place. The fuel loading process has been successfully completed. The Com-pany is presently awaiting the approval by the NRC of certain engineering analyses related to repairs made to the Unit's eight main stream isolation valves (MSIV's) that verify their con-tinued suitability for operation. The Company anticipates the NRQ will approve the Company's findings and recommenda-tions and allow the power ascension program to proceed, al-though no such assurance can be provided. Once approval is

obtained, Unit start-up will be initiated leading to planned commercial operation in September 1987.

As a result of the MSIV engineering analysis and repair, coupled with the NRC review and a consequent change in the estimated commercial operation date to September 1987, the completion cost of the Unit is currently estimated to be $5.878 billion (comprised of construction costs of $4.059 billion and AFC of $1.819 billion), representing an increase of $91 million as compared to the November 1986 cost estimate which as-sumed a July 1987 commercial operation date. In addition to incorporating the current timetable for power ascension and commercial operation, this cost estimate considers each co-tenants current estimate for financing cost rates and the inclu-sion of construction work in progress (CWIP) included in rate base for three of the cotenants. The increase in the cost of the Unit is primarily attributable to delays occasioned by the en-gineering analyses and repairs to the MSIV's coupled with the required NRC approval. The Company's 41% share of the total estimate is approximately $2.417 billion, exlusive of the $ 171 million of payments (described below) to be made by the Com-pany to the cotenants and, as of December 31, 1986, the Com-pany has invested approximately $2.3 billion in the Unit, includ-ing AFC and overheads capitalized. As discussed below, the Company will be required to write off a portion of this invest-ment, which includes AFC currently reflected in income and AFC which will accrue to income to the extent permitted by applicable generally accepted accounting principles. (See Ratemaking and Financial Accounting Recognition regarding changes in financial accounting recognition adopted by the Financial Accounting Standards Board (FASB) in December 1986.)

During 1987, the primary activity at the Unit willbe the power ascension program leading to commercial operation. However as delays have previously occurred with respect to the Unit, the Company can provide no assurance as to the precise date commercial operation will be accomplished.

Any delay in achieving the September 1987 commercial operation date is estimated to add a minimum of approximately $60 millioneach month to the total cost of the Unit (approximately $25 million with respect to the Company's 41% share).

Under the Cost Settlement discussed below, the Company does not expect the additional costs arising under the current estimate, or addi-tional costs arising as a result of further delays, if any, to be recoverable through rates.

Cost Settlement:

In connection with an extensive 1982 PSC proceeding, which concluded that completion of the Unit is warranted, the PSC stated that it would apply a strict standard of prudence for all costs incurred in completing the Unit. On July 3, 1985, the PSC ordered the establishment of a proceed-ing (Case No. 29124) to investigate the prudence of costs in-curred for the construction of the Unit.

On September 18, 1985, the Company and the other coten-ants, together with the Staff of the PSC, filed a joint motion with the PSC seeking approval of an agreement entitled "Specifications of Terms and Conditions of Offer of Settle-ment" (Settlement) that, ifapproved by the PSC, would consti-tute a complete disposition of Case No. 29124 and establish, among other things, an allowed cost for the Unit of $4.450 billion.

On June 26, 1986, the PSC decided not to accept the Settle-ment as proposed and ordered the cotenants to inform the PSC whether they would agree to a settlement of the proceed-ing using a $4.160 billion cost allowance. On July 15, 1986, the cotenant companies notified the PSC that they would accept a Settlement modified only for a change in the allowable cost to

$4.160 billion from that amount originally proposed of $4.450 billion. In addition, in order to induce settlement among the cotenants, the Company entered into an agreement with the other cotenant companies (Cotenant Agreement) whereby it will reimburse the cotenant companies, upon commercial op-eration of the Unit, for $ 171 million representing their respec-tive ownership shares of the $290 millionincremental disallow-ance. This obligation willnot cause a reallocation of ownership interests in the Unit.

On September 10, 1986, the PSC approved the Settlement which contained the following key terms and conditions:

The maximum amount of the Unit's expenditures to be included in the cotenants'ate bases would be $4.160 billion, and disallowed expenditures would not be less than$ 1.190 billion with amounts, if any, above the January 1985 completion cost estimate of $5.350 billion being forthe account of the cotenants, except in the case of an "extraordinary event" as discussed below. The al-lowed cost of $4.160 billionwillbe reduced by the financ-ing costs "prepaid" by ratepayers as a result of rate base inclusion of a portion of the Unit's cost prior to comple-tion.

The cotenants may request from the PSC an upward adjustment of the $4.160 billion cap based only on the occurrence of an "extraordinary event" as contemplated

30 NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES in prior PSC orders concerning the Unit. At the time the agreement was entered into, the cotenants stipulated that they were not then aware of any basis for such a claim.

The rate phase-in of each cotenant's share of allowed Unit costs is to be included in rate base over a reasonable period, together with accumulated deferred carrying costs on the portion of allowed Unit cost that has not yet been included in rate base.

Appropriate income tax deductions and credits appli-cable to the Unit's completion cost will be allocated to the disallowed costs and reserved for shareholders.

The provisions of the Settlement would be in full satis-faction of the penalty and incentive provisions of the PSC's prior Incentive Rate of Return (IROR) and "cap" orders relating to the Unit.

The cotenants agree not to challenge the legal validity of either the IROR or "cap" orders previously issued by the PSC. In addition, each cotenant would waive any and all claims it may have against any other cotenant con-cerning the design, engineering or construction of the Unit.

Based upon the proposal adopted by the PSC, the January 1987 cost estimate of $5.878 billion,which reflects the benefits of approximately $273 million of prepaid financing costs, re-sults in the disallowance of $1.991 billion of the total Unit cost.

The Company's share of the disallowed amount (including the impact of the Company's 41% share of the $290 million de-crease in the allowed cost amounting the $ 119 million,and the

$ 171 million payment to the cotenants under the Cotenant Agreement) would be approximately $ 1 billion. The disallow-ance to the Company would increase by its proportionate share of the cost of any further delays in the commercial opera-tion of the Unit and might be further increased dependent on the ultimate PSC decision as to the costs covered by the Set-tlement. Also, the magnitude of the loss to the Company would be affected by the implementation requirements that may ulti-mately be ordered by the PSC. (See "Ratemaking and Financial Accounting Recognition.")

Several intervening parties petitioned for rehearing of the Settlement. Such petitions were denied and these intervenors have indicated that they will take legal action to overturn the PSC's approval and require the PSC to resume the proceeding investigating the prudence of costs incurred for construction of the Unit. The Company is unable to predict whether such legal action will be taken, or if taken, the results thereof.

Ratemaking and Financial Accounting Recognition: In connec-tion with the Company's pending rate filing, the Staff of the PSC on August 22, 1986, proposed adjustments to the Com-pany's original rate case filing to incorporate the terms of the Settlement.

The Staff's implementation requirements, which include among other things an expansion of costs covered by the Settlement, ifultimately sustained, would result in a greater level of disallowed Unit costs to be considered in the rate set-ting process.

Also, the Staff has proposed the adoption of ratemaking methodologies which the Company believes are contrary to the terms and intent of the Settlement. These in-clude the recognition of tax benefits at a 34% rate rather than a 46% rate, the discounting of tax benefits, exclusion from rate base of unrealized tax benefits and a departure from prevailing ratemaking methodologies used in developing capital struc-ture. These proposals, if adopted, would have a further detri-mental impact on the financial condition and results of opera-tions of the Company. A decision on the Company's pending rate filing, which will include Settlement implementation re-quirements, is expected in March 1987. The Company willcon-tinue to oppose the Staff's proposals and cannot predict whether such proposals will ultimately be adopted and sustained In December 1986, the FASB issued Statement of Financial Accounting Standards No. 90 "Regulated Enterprises Accounting for Abandonments and Disallowances of Plant Costs", an amendment of FASB Statement No. 71 (SFAS No.

90). Among other things, this statement requires that when it becomes probable that part of the cost of a generating facility will be disallowed for ratemaking purposes and a reasonable estimate of the amount of the disallowance can be made, the estimated amount of the probable disallowance shall be de-ducted from the reported cost of the plant and recognized as a loss. Also, once adopted the statement would prohibit the capitalization of an allowance for funds used during construc-tion (AFC) unless it is probable that such AFC will be includa-ble as an allowable cost for ratemaking purposes. The FASB is continuing to review the financial accounting recognition for rate phase-in plans. In the case of the Company, the applica-tion of this statement is generally required no later than 1988.

However, the effective date of SFAS No. 90 may be delayed until 1989 if its adoption would cause a violation or probable future violation of a restrictive clause in an existing loan inden-ture or other agreement and relief from such restrictive clause is being actively pursued (see Note 4).

Based upon the Company's interpretation of the terms and conditions of the Settlement discussed above, the Company would be required to write-off approximately $ 1 billion, re-duced to approximately $626 million, net of Federal income taxes at a 46% rate. The amount of this write-offcould increase by approximately $200 million, net of Federal income taxes, should the PSC adopt all of the PSC Staff's positions previ-ously described. These amounts do not take into consideration any delay in commercial operation beyond September 1987.

The accounting period to which a write-offwould be charged is dependent upon the Company's decision with respect to the timing of adoption of SFAS No. 90. If SFAS No. 90 had been in effect in 1986 and 1985, the net of tax loss would have been allocated to each of those years. Therefore, reported 1986 and 1985 balance available for common stock would have been, on a pro-forma basis, approximately $61 million and $65 million, respectively, and pro-forma earnings per share would have been $.48 per share and $.53 per share, respectively.

Based upon the current high cost of large, base-load generating facilities, legislators, regulatory commissions and utilitycompanies nationwide have ordered or are considering the phase-in of these costs over a period of years. In accor-dance with current generally accepted accounting principles, Unit operating and financing costs may be deferrable under a phase-in plan for recovery in the future. The Staff of the PSC and the Company are in agreement on the methodology to be utilized in rate implementation of a phase-in plan, including recovery of deferred costs and carrying charges over the operating life of the Unit.

The PSC has adopted the phase-in methodology proposed by the Company and Staff. The PSC also adopted a phase-in period for the Unit of seven years, noting that a five-year phase-in period would be reasonable in the event of a disallow-ance of cost in the magnitude contemplated by the Settlement discussed above. In connection with the Company's currently

NIAGARA MOHAWK POWER CORPORATION AND SU'BSIDIARY COMPANIES 31 pending rate proceeding, the Staff has proposed a five-year phase-in of allowed Unit costs. The Company is unable to pre-dict at this time over what period of time the phase-in will ultimately be ordered or when it will commence. A portion of the Unit's cost ($680 million) is presently being reflected as CWIP in rate base.

Also, in April 1982, the PSC adopted an incentive rate of return (IROR) program in connection with tlie remaining con-struction costs of the Unitwhich would be implemented as part of the rate proceeding for each cotenant that considers rate recognition of the Unit's completion cost. In July 1984, the PSC issued an opinion and order which amended the IROR pro-gram to also include a $5.4 billion ceiling on the Unit's final allowable cost. Under the amended IROR program, costs in-curred in excess of $4.6 billion, but less than $5.4 billion, are required to be borne by cotenant shareholders to the extent of 20% of the variation of revenue requirements, with costs in excess of $5.4 billion to be borne in total by the cotenant shareholders. As indicated above under "Cost Settlement," the approval of the Settlement by the PSC and the ability of the PSC's adoption of the Settlement to sustain judicial challenge would render the IROR and "cap" orders inoperative.

Nuclear Regulatory Commission-Audits and Licensing: In May 1986, the Staff of the Nuclear Regulatory Commission (NRC) concluded an assessment of the Unit's overall construction program. The assessment covered the twelve months ended January 1986 and concluded that management of the project was satisfactory in all areas, although increased management attention to certain items was recommended.

The Company addressed the NRC recommendations in a response submitted to the NRC on June 30, 1986. Most of the actions recom-

mended, as described in the Company's

response, were al-ready initiated and, in some cases, completed prior to receipt of the report from the NRC. The Company does not expect that the implementation of the remaining recommendations will materially affect either cost or scheduled completion of the Unit.

A number of nuclear power plant construction projects in the United States have encountered substantial delays, licensing difficulties and cost escalation due to a variety of factors. Also, the issuance of a fullpower operating license and achievement of commercial operation could be adversely affected by a wide variety of industry and plant specific construction. operating, regulatory, legislative, economic and other factors, including recent international events. Although the outcome of the re-maining regulatory licensing proceedings relating to receipt of a full power license cannot be predicted with certainty, the Company believes a full power operating license willbe issued since the Unit is designed and constructed to meet applicable regulatory requirements.

Long-term Contracts for the Purchase of Electric Power: At January 1, 1987, the Company had long-term contracts to purchase electric power from the following generating facilities owned by the New York Power Authority (NYPA):

Facility Niagara hydroelectric project..

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

Fitzpatrlck-nuclear plant.........

Expiration Purchased Estimated date of capacity annual contract in kw.

capacity cost 1990 1,111,332

$ 13,336,000 2002 270,000 6,156,000 year-to-153,000 (a) 14,686,000 ear basis Lease Commitments:

The Company leases certain property and equipment which meet the accounting criteria for capitali-zation. Such leases, having a net book value of $56.2 million and $41.9 million at December 31, 1986 and 1985, respectively, are included in UtilityPlant in the accompanying Consolidated Balance Sheets.

Since current ratemaking practice treats all leases as operating leases, the capitalization of these leases has no impact of the Company's Consolidated Statement of Income. The Company recognizes as a charge against income an amount equal to the rental expense allowed for rate pur-poses. The Company's future minimum rental commitments under these capital leases and non-cancellable operating leases aggregate'approximately

$634 million,a substantial por-tion of which relates to a 41-year operating lease of a transmis-sion line facility. Annual future minimum rental commitments for the period 1987-1991 range between

$23 million and $32 million.

Mandated Refunds to Customers:

As part of the Company's March 1984 rate decision, the PSC ordered the refund of ap-proximately $96 million of previously collected nuclear fuel disposal costs over a five-year period. The Company had col-lected in rates approximately $146 million for the disposal of nuclear fuel irradiated prior to 1983. The refund represents the amount by which these previously collected costs are in excess of the Company's liability as of March 31, 1984 to the U.S.

Department of Energy for nuclear fuel disposal under the Nu-clear Waste Policy Act. At December 31, 1986, $63.2 million remains to be refunded and is recorded in Deferred Credits.

1,534,332

$34,178,000 (a) 61,000 kw for summer of 1987; 59,000 kw for winter of 1987-88.

The purchase capacities shown above are based on the con-tracts currently in effect. The estimated annual capacity costs are subject to price escalation and are exclusive of applicable energy charges.

NOTE 11. Commitments and Contingencies Construction Program: At December 31, 1986, substantial con-struction commitments existed, including those for the Com-pany's share of Unit No. 2 at the Nine Mile Point Nuclear Sta-tion. The Company presently estimates that the construction program for the years 1987 through 1991 willrequire approxi-mately $1.572 billion, excluding AFC, nuclear fuel and certain overheads capitalized. By years the estimates are $330 million,

$317 million, $296 million, $315 million and $314 million, respectively.

Litigation: In 1983, the PSC instituted a proceeding to investi-gate the Company's operating practices and certain other mat-ters that it was alleged may have resulted, among other things, in excessive fuel adjustment charges during the years 1977 to 1982, and further, to determine whether and to what extent remedial action with respect to any such matters is proper under the PSC's regulations or otherwise.

In 1985, the PSC ordered the Company to refund approximately $31.9 million over the twelve months ending April 30, 1986. The Company appealed this decision to the Supreme Court, Appellate Divi-sion, Third Department which, in March 1986, held that the

32 NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES PSC could not order refunds arising from rates charged prior to June 21, 1981, when certain public service laws were adopted. The PSC was directed to recalculate the amount of the refund and take action to correct for additional amounts refunded by the Company. Under this decision a substantial portion of the amounts refunded by the Company would be recovered from ratepayers.

The PSC has appealed this deci-sion to the Court of Appeals and a decision is expected in 1987.

The Company is unable to predict the outcome of this matter.

Advances on Behalf of Nine Mile Point Nuclear Unit No. 2 Co-tenant: In August 1984, the Company and Long Island Lighting Company (LILCO)entered into an agreement providing for the issuance by LILCOof up to $250 millionin General and Refund-ing Bonds (LILCO Bonds) and $150 million in unsecured notes to evidence and secure LILCO's repayment obligation for funds advanced by the Company on behalf of LILCOfor its 18%

ownership in the Unit.

The LILCO Bonds were fully issued by November 1985 and under the terms of a second agreement (Capital Funds Agree-ment), the Company provided its guarantee for a period of approximately three years through March 31, 1989, of up to

$165 million of LILCO's reimbursement obligations in connec-tion with $150 million principal amount of tax-exempt pollution control bonds issued by LILCO on December 31, 1985. The guarantee of the Company contains certain representations which, should the Company be unable to meet, require it to provide security in the form of First Mortgage Bonds. The Company expects LILCOto honor its obligations in connection with the LILCO tax-exempt bonds throughout the period while the guarantee is in effect. The Company has arranged for four-year term loans to fund its guarantee obligation, if needed. The Company has an interest of $85 million in LILCO's third mortgage, which serves as partial security in the event its guarantee is required to be honored. LILCO is required to pay fees to the Company in connection with the guarantee.

In 1985, the Company received $ 146.7 million of the pro-ceeds from the sale of the LILCO tax-exempt bonds and applied $25 million against the LILCO Bonds, $36.7 million against unsecured notes and $85 million to LILCO's share of cash construction costs for the Unit commencing November 18, 1985. After being reduced by $13.6 million for advances plus interest through December 31, 1985, the proceeds pro-vided the Company with $71.4 million at December 31, 1985.

This balance was applied against subsequent LILCOcash con-struction obligations until fully expended in September

1986, at which time LILCO resumed making cash payments for its portion of cash construction costs. The Company agreed to waive interest and supplemental payments on a principal amount of LILCO Bonds equal to the daily unused portion of such $71.4 million.In May 1986, the Company sold $140 million of the LILCO Bonds to a single-purpose trust, which trust is-sued certificates to a limited number of institutional investors.

On December 30, 1986, the LILCO Bonds held by the Company and related unsecured notes, together with the LILCO Bonds held by the single-purpose trust were repaid and at December 31, 1986, LILCO's obligations to the Company have been fully satisfied. However, the Company's guarantee obligation under the Capital Funds Agreement remains in effect. Interest and supplemental payments on the LILCO Bonds and unsecured notes amounted to $27.1 millionfor 1986, $40.8 millionfor 1985 and $ 10.9 million for 1984 and are included in other income and deductions other items in the Consolidated Statement of Income.

Quarter ended Dec. 31, 1986

$637,896 1985 661,237 1984 675,089

$104>633 84,791 81,185

$84,698

$.57 91,724

.61 59,708

.39 Sept. 30, 1986

$554,546 1985 554,779 1984 606,437

$92,640 73,095 86,421

$74,909 79,503 84,636

$.49

.52

.66 June 30,1986

$636,859 1985 637,724 1984 696,325

$ 97>585 100,036 101,319

$85,535

$.56 96,758

.67 94,197

.77 March 31

~ 1986

$831,018 1985 841,200 1984 807,695

$146>316 153,366 123,801

$152>723

$1.08 143,445 1.11 121,193 1.04 NOTE12. Quarterly Financial Data (Unaudited)

Operating revenues, operating income, net income and earn-ings per common share by quarters for 1986, 1985 and 1984 are shown in the following table. The Company, in its opinion, has included all adjustments necessary for a fair presentation of the results of operations for the quarters. Due to the seasonal nature of the utilitybusiness, the annual amounts are not gen-erated evenly by quarter during the year.

ln thousands ofdollars Operating Operating Net Earnings per revenues income income common share

NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES 33 Report ofIndependent Accountants Price Vaterhouse To the Stockholders and the Board of Directors of Niagara Mohawk Power Corporation We have examined the consolidated balance sheets of Niagara Mohawk Power Corporation and its subsidiaries as of December 31, 1986 and 1985, and the related consoli-dated statements of income and retained earnings and of changes in financial position for each of the three years in the period ended December 31, 1986. Our examinations were made in accordance with generally accepted auditing standards and accordingly included such tests of the ac-counting records and such other auditing procedures as we considered necessary in the circumstances.

As described in Note 10, the Financial Accounting Stan-dards Board issued Statement of Financial Accounting Standards No. 90 "Regulated Enterprises Accounting for Abandonments and Disallowances of Plant Costs" which provides, among other things that the cost of a generating facility disallowed for ratemaking purposes, be recognized as a loss. Application of this Statement is required not later than 1989.

The Company is a 41% participant in the construction of Nine Mile Point Nuclear Station No. 2 (Unit). As a result of continuing uncertainties discussed in Note 10, management is unable to predict whether further regulatory actions by the New York State Public Service Commission with respect to its investment in the Unit will have, in the aggregate, a

material effect on its financial position or results of opera-tions.

In our opinion, subject to the effects on the 1986, 1985 and 1984 financial statements of such adjustments, if any, that might have been required had the outcome of the un-certainties discussed in the preceding paragraph been known, the consolidated financial statements examined by us present fairly the financial position of Niagara Mohawk Power Corporation and its subsidiaries as of December 31, 1986 and 1985 and the results of their operations and changes in their financial position for each of the three years in the period ended December 31, 1986 in conformity with generally accepted accounting principles consistently applied.

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

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

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

This system includes communication through written policies and procedures, an organizational structure that pro-vides for appropriate division of responsibility and the training of personnel. This system is also tested by a comprehensive internal audit program. In addition, the Company has a Code of Conduct which requires all employees to maintain the highest level of ethical standards and requires key management employees to formally affirm their compliance with the Code.

The financial statements have been examined by Price Waterhouse, the Company's independent accountants, in ac-cordance with generally accepted auditing standards. As part of their examination, they made a study and evaluation of the Company's system of internal accounting control. The purpose of such study was to establish a basis for reliance thereon in determining the nature, timing and extent of other auditing procedures that were necessary for expressing an opinion as to whether the financial statements are presented fairly. Their examination resulted in the expression of their opinion which appears on this page. The independent accountants'xamina-tion does not limit in any way management's responsibility for the fair presentation of the financial statements and all other information, whether audited or unaudited, in this Annual Re-port.

The Audit Committee of the Board of Directors, consisting of'hree directors who are not employees, meets regularly with management, internal auditors and Price Waterhouse to re-view and discuss internal accounting controls, audit examina-tions and financial reporting matters. Price Waterhouse and the Company's internal auditors have free access to meet indi-vidually with the Audit Committee at any time, without man-agement present.

Syracuse, New York January 28, 1987

34 NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES Selected Financial Data As discussed in Management's Discussion and Analysis of Financial Condition and Results of Operations and Notes to Consolidated Financial Statements, certain of the following selected financial data may not be indicative of the Company's future financial condition or results of operations.

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

Dividend payout ratio 1966

$2,660,319 397,865

$20.23 163/4 82.PYo 12.4%

$ 2.71 13.6o/o

$ 2.08 76.P/o 1985

$2,694,940 411,430

$ 19.61 20'/2 104 5%

10.1%

$ 2.88 15 tP/o

$ 2.06 71.5o/o 1984

$2,785,546 359,734

$18.89 17%

92 tP/o 11.5o/o

'2.84 14.P/o

$ 1.98 69.7Yo 1963

$2,632,315 312,409

$18.55 1574 84.PYo 12.P/o

$ 2.77 15.lP/o

$ 1.89 68.2Yo 1982

$2,393,771 268,534

$ 17.91 15%a 87.F/o 11.5o/o

$ 2.64 14.7Yo

$ 1.76 66.7o/o Capitalization: (000's)

Common equity Non-redeemable preferred stock Redeemable preferred stock Long-term debt

$2,571,491 2901000 347,470 2,799,605

$2,488,620 290,000 379,850 2,643,094

$2,207,117 240,000 367,900 2,395,471

$1,929,073 240,000 338,474 2,048,548

$1,680,650 210,000 262,792 1,881,441 Total First mortgage bonds maturing within one year Total Capitalization ratios: (inciuding first mortgage bonds maturing within one year)

Common stock equity.

Preferred stock Long-term debt 6,008,566 50,000

$6,058,566 5,801,564 30,000

$5,831,564 42.7/o 11.5 45.8 42.5o/o 10.5 47.0 5,210,488 47,450

$5,257,938 42.(P/o 11.5 46.5 4,556,095 25,000

$4,581,095 42.1%

12.6 45.3 4,034,883 65,000

$4,099,883 41.tP/o 11.5 47.5 Financial ratios:

Ratio of earnings to fixed charges.

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

Ratio of AFC to balance available for common stock..

Ratio of earnings to fixed charges and preferred stock dividends Other ratios-% of operating revenues:

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

Maintenance and depreciation Total taxes Operating income Balance available for common stock..............

Miscellaneous: (000's)

Gross additions to utilityplant Total utilityplant Accumulated depreciation and amortization Total assets 2.98 2.42 48.2/o 2.35 38.P/o 11.4 18.1 16.6 12.9 774,062 8,445,993 1,763,443 7,611,203 3.07 2.37 53.P/o 2.36 43 4%

10.9 15.7 15.3 13.1 771,120 7,640,905 1,629,437 7,013,837 3.11 2.43 52 4%

2.39 46.9o/o 10.1 14.7 14.1 11.1 769,846 6,903,184 1,501,282 6,233,401 2.98 2.40 43.6o/o 2.35 50.(P/o 10.0 13.0 13.5 10.3 691,464 6,165,711 1,486,196 5,357,572 2.95 2.42 41.tP/o 2.32 49.8o/o 10.5 13.2 13.2 9.6 594,469 5,516,532 1,389,112 4,781,767

NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES Electric and Gas Statistics ELECTRIC CAPABILITY AtJanuary 1, 1987 1986 1985 ELECTRIC STATISTICS 1986 1985 1984 Thermal:

Coal fuel Huntley, Niagara River..

Dunkirk, Lake Erie.....

715 10 555 8

715 715 555 555 Total coal fuel...

Residual oilfuel Albany, Hudson River-.

Oswego, Lake Ontario..

Roseton, Hudson River.

Middle distillate oilfuel 20 Combustion turbine and diesel units........

Total oilfuel Nuclear fuel Nine Mlle Point, Lake Ontario Purchased-firm contract Power Authority-FitzPatrick, Lake Ontario...

Total nuclear fuel..

Total thermal sources..

1,270 18 1,270 1,270 400 6

400 400 1,563 23 1,736 1,736 299 4

300 300 237 3

310 310 2,499 36 2,746 2,746 610 9

610 610 153 2

167 138 763 11 777 748 4,532 65 4,793 4,764 Hydro:

Owned and leased hydro stations (77).

684 Purchased-firm contracts Power Authority-Niagara River....

1,111 Power Authority-St. Lawrence River..............

Power Authority-Blenhelm-Gilboa Pumped Storage Plant...........

Other 10 695 695 16 1,111 1,118 115 270 4

262 4

550 550 209 63 Total h dro sources..

Other urchases..

Total capability'.

2,327 34 2,565 2,541 80 1

445 400 6I939 100 7,803 7,705 Electric eak load durin ear 1986 5,724 1985 1984 5,862 5,526 Available capability can be increased during heavy load periods by purchases from neighboring interconnected systems.

Hydro station capability is based on average December stream-flow conditions.

• • Has capability to burn natural gas (as well as oil) as a fuel.

Electric sales(Millionsofkw-hrs)

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

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

Industrial..................

Municipal service..........

Other electrics stems......

9,359 10,374 10,801 234 3,579 Electric customers(Average)

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

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

Industrial..................

Other ResIdentIal(Average)

Annual kw-hr. use per customer............

Cost to customer per kw-hr..

Annual revenue per customer............

1,291,111 136,304 21481 3,282 11433)178 7,249 7.50it

$543.96 GAS STATISTICS 1986 Gas sales(Thousands ofdekatherms)

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

49,430 Commercial...............

27,218 Industrial..................

15,575 Other as systems..........

3,724 Totalsales..........

Transportation of customer-owned as..

95,947 4,868 34,347 Electric revenues(Thousands ofdollars)

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

702,309 Commercial...............

766,815 Industrial..................

448,855 Municipal service..........

41,031 Other electric systems......

95,809 Miscellaneous.............

77,014

$2,131,833 8,976 9,907 10,886 241 5,286 35,296 647,507 708,517 437,292 39,238 196,104 67,746

$2,096,404 1,273,969 134,787 2,490 3,315 1,414,561 7,046 7.21'508.26 1985 47,328 27,006 29,213 4,873 108,420 8,944 9,739 11,194 245 6,964 37,086 607,527 674,929 438,920 37,846 303,968 71,280

$2,134,470 1,259,077 133,234 2,522 3,279 1,398,112 7,104 6.79tf

$482.52 1984 49,519 27,892 32,755 4,794 114,960 ELECTRICITYGENERATED ANDPURCHASED Millionsofkw-hrs.

1986 1985 1984 Thermal:

Generated Coal...........

Oil.............

Nuclear........

Natural gas.....

Purchased-Nuclear from Power Authorlt Total thermal Hydro:

Generated........

Purchased from Power Authorit Totalh dro...

6,140 16 7,409 19 7,863 20 5,811 16 2,866 7

3,754 9

3,147 8

4,932 13 3,635 9

177 1

1,624 4

2,103 5

1,284 3

825 2

878 2

16,559 44 17,656 45 18,233 45 4I140 11 3,496 9

3,803 9

7,683 20 7,815 20 8,312 21 11,823 31 11,311 29 12,115 30 Total generated and urchased 37,639 100 39,213 100 40,588 100 Other purchased power various sources......

9,257 25 10,246 26 10,240 25 108,420 114,960

$295,060 147,751 133,446 18,691 3,588

$313,536 157,469 156,307 19,708 4,056

$528,486

$598,536

$651,076 Gas customers(Average)

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

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

Industrial................

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

4071546 33,248 465 2

441I261 404,116 32,603 485 2

437,206 400,878 32,106 502 2

433,488 Residential(Average)

Annual dekatherm use percustomer........

Cost to customer perdekatherm.......

Annual revenue per customer........

Maximum day gas sendout dekalherms 121.3 117.1 123.5

$6.01

$6.23

$6.33

$728.39

$730.14

$782.12 786,165 774,033 772,604 Total gas delivered.....

100,815 Gas revenues(Thousands ofdollars)

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

$296,853 Commercial...............

142,807 Industrial..................

68,476 Other gas systems..........

14,300 Miscellaneous.............

6,050

36 NIAGARA MOHAWK POWER CORPORATION Directors James Bartlett Former Executive Vice president, Syracuse Edmund M. Davis (A, B, E)

Partner, Hiscock &Barclay, attorneys-at-law, Syracuse WilliamJ. Donlon President, Syracuse Edward W. Duffy (A, B, C)

Former Chairman of the Board and Chief Executive Officer, Marine Midland Banks, Inc., a bank holding company, Buffalo John G. Haehl, Jr. (A)

Chairman ofthe Board and Chief Executive Officer, Syracuse Lauman Martin Consultant (formerly Senior Vice President and General Counsel), Syracuse Baldwin Maull (A, B)

Corporate Director, New York Martha Hancock Northrup (D)

Homcmakcr, former President, Crouse-Irving Memorial Hospital Board, Syracuse Frank P. Piskor (A, C, D)

President Emeritus, St. Lawrence University, Canton Donald B. Riefler (E)

Chairman, Sources and Uses ofFunds Committee, Morgan Guaranty Trust Company ofNcw York, New York Lewis A. Swyer (a, C, D)

Chairman, L>. Swyer Co., Inc., builders and construction managers, Albany John G. Wick (D, E)

Partner, Falk &Siemcr, attorneys-at-law, Buffalo A. Member ofthe Executive Committee B. Mcmbcr ofthe Compensation Committee C. Member ofthe Audit Committee D. Member ofthe Committee on Corporate Public Policy E. Member ofthe Finance Committee Officers John G. Haehl, Jr.

Chairman ofthe Board and ChiefExecutive OQicer WilliamJ. Donlon President John M. Endries Senior Vice President John M. Haynes Senior Vice President John P. Hennessey Senior Vice President Charles V. Mangan Senior Vice President James J. Miller Senior Vice President (Retired January 31, 1987)

John H. Terq Semor Vice President, General Counsel and Secretary Richard F. Torrey Senior Vice President James F. Aldrich Vice Ptesidcnt-Regional Operations (Deceased ¹ncmber 14, 1986)

Anthony J. Baratta, Jr.

Vice PresidcntMntrollcr Michael J. Cahill Vice president-Regional Operations Robert M. Cleary Vice President-Regional Operations Gerald J. Currier Vice Ptesident~nsumer Services Richard EA,. DuKy Vice Ptesident-Public Alfairs and Corporate Communications (EffectiveNovember 1, 1986)

Gerald D. Garcy Vice President-Power Contracts (EffectiveMay 6, 1986)

Kermit E. Hill Vice president-Public Affairs and Corporate Communications (Retited October 31, 1986)

Edward F. Hoffman Vice President-Fossil Generation Thomas E. Lempges Vice President-Nuclear Operations Samuel F. Manno Vice President-Purchasing and Materials Management Eugene J. Morel Vice President-Risk Management James F. Morrell Vice President-Corporate Planning James A. Perry Vice President-Quality Assurance John W. Powers Vice President-Treasurer Michael P. Ranalli Vice President-Engineering (Non-nuclear)

Kenneth A.Tramutola Vice President-Gas Christopher D. Turner Vice President-Corporate Development Perry B. Woods, Jr.

Vice President-Employee Relations Gary J. Lavine Assistant General Counsel (EffectiveAugust 1, 1986)

Herman B. Noll Assistant General Counsel Nicholas L. Prioletti, Jr.

Assistant Controller Adam F. Shaffer Assistant Controller Henry B. Wightman, Jr.

Assistant Controller Harold J. Bogan Assistant Secretary Joseph F. Cleary Assistant Secretary Frederick C. McCall, Jr.

Assistant Secretary ArthurW. Roos Assistant Treasurer Richard N. Wescott Assistant Treasurer

Corporate Information Investor InquIries Shareholder inquiries:

Shareholder Services Department, (315) 474-1151, Ext. 4150 (Syracuse); 1-800-962-3236 (New YorkState); 1-800-448-5450 (elsewhere incontinental U.S.)

Analyst inquiries:

Investor Relations Department, (315) 428-3134 Dividend Reinvestment Plan Shareholders desiring information on enrolling in the Dividend Reinvestment and Common Stock Purchase Plan should call or writeour Shareholder Services Department at P.O. Box 7058, Syracuse, N.Y. 13261.

Annual Meeting The annual meeting ofshareholders willbe held in the auditorium ofthe Company's main office in Syracuse, N.Y.on Tuesday, May 5, 1987. Anotice ofthe meeting, proxy statement and form ofproxy willbe sent to holders ofcommon stock in early April.

Form 10-K Report Acopy ofthe Company's Form 10-K report filedannually with the Securities and Exchange Commission is available after March 31, 1987, by writingthe Investor Relations Department at 300 Erie Boulevard West, Syracuse, N.Y. 13202.

Disbursing Agent Prefened and Common Stocks:

Niagara Mohawk Power Corporation 300 Eric Boulevard West, Syracuse, N.Y. 13202 Transfer Agents and Registrars Preferred Stock: (through July I, 1986)

Marine Midland Bank, NA., 140 Broadway, New York, N.Y. 10015 Preferred and Corrrrnon Stock:

Morgan Shareholder Services Trust Company ofNew York, 30 West Broadway, New York, N.Y. 10015 Stock Exchanges Common stock and Certain Preferred Series:

Listed and traded on the New YorkStock Exhange.

Common Stock: Also traded on the Boston, Cincinnati, Midwest, Pacific and Philadelphia stock exchanges.

Bonds: Traded on the New Yorkand Luxembourg stock exchanges.

Trading Symbol: NMK The tntorrnation in this repen is nol given in connection with the sale ot. or otter to buy. any security.

printed in U.S.A.

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