ML20036B498

1992 Annual Rept, for Nmpns,Units 1 & 2

ML20036B498
Person / Time
Site:	Nine Mile Point
Issue date:	12/31/1992
From:	Catacosinos W LONG ISLAND LIGHTING CO.
To:
Shared Package
ML17058B768	List: ML17058B767 ML17058B769 ML17058B770 ML17058B771 ML17058B772 ML20036B498
References
NUDOCS 9305240311
Download: ML20036B498 (52)

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,, > 3;gs c Territory served by long Island lighnny Company The Long Island Lighting Company's 6,500 employees provide electric ond gas service to more than I million customers in Nossou and Suffolk Counties and the Rockaway Peninsula in Queens County.

LILCO's service territory covers 1,230 square miles with a population of approximately 2.7 million people.

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1992 Highlights Public Service Commission opproved common

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stock dividend reinvestment plan First mortgage and general and refunding bonds a

upgraded one notch above investment grade Common stock trading at a 21-year high Common stock quarterly dividend increased to 43.5 cents P

On the cover: Long Island's 1,180 uniles of coastline ob some of the world's best recreatson to swimmers, booters and water sports enthusiasts.

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To Our Sharoowners in 1992, LILCO continued its trend of improving its financial performance. Earnings for the year were $238 million, or $2.14 per common share, with quarterly stock dividends increasing to 43.5 cents per share on October 1,1992.

LILCO's improved financial position resulted in f avorable actions by the rating agencies. In

! 992, the Company's principal securities were upgraded for the third consecutive year, a show of confidence that allowed LILCO to refinance higher cost securities, saving the Company and our customers more than $17 million a year in interest expense.

In November,1992, the Public Service Commission (PSC) approved a 4.1 percent j

increase in LILCO's electric rates, consistent with the 1989 Shoreham settlement. The Commission also approved a separate 7.1 percent increase in the Company's natural gas rates, that will 1

allow us to expand natural gas service to more customers. Both increases became eff ective December 1,1992.

Reshaping LILCO For the past several years, LILCO has been i

examining its business to prepare the Company for success in the 1990s and beyond. A blueprint for the future was developed and, in 1992, LILCO moved forward with a three-year reorganization designed to position the Company to meet the i

challenges of the changing marketplace.

LILCO is committed to becoming a premier service organization, and has embarked on o O

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program to change its corporate culture. More Company does business. Decreases in defense than just moving boxo around on on organiza-spending and a nationwide recession have slowed tional chart, we are seeking to fundamentally local economic growth, but there are pockets of change the way we do business.

growth in Long Island's emerging technology industries. ULCO, along with Long Island's Business Units government and business communities, introduced The reorganization divides the Company's on economic development compaign to help activities into three business units - Electric, boost the region's economy.

Natural Gos and Energy Conservation - aliowing In addition to forgeting new ond growing each to concentrate on the energy service they businesses, the campaign also promotes higher are providing. In July,1992, the Electric Business education and tourism on Long Island. These Unit was formed, with the Natural Gas and efforts have yielded significant results, with Conservation Units scheduled to be formed by LILCO economic development specialists helping the end of 1993.

more than 175 businesses stort up, expand or relocate to Long Island.

Customer Service in addition to dividing the Company into Meeting the Challenge key competitive units, LILCO's reorganization Facing both a changing industry and business incorporates two vital customer service elements.

environment, LILCO has worked throughout later this year, we will be opening a "one-call 1992 to position itself to meet the challenges of a center" in Melville, providing a single point of more competitive marketplace. We seek a future contact for customers conducting any type of in which LILCO becomes a model of service business with LILCO. We will also be regionalizing excellence end efficiency.

the electric and gas businesses into four On behalf of LILCO's Board of Directors 1

geographic locations to bring these services and Officers, I would like to thank you for your closer to the customer. Both steps are designed continued confidence in our leadership.

to improve LILCO's ability to respond to customer needs more efficiently and effectively.

Sincerely, O C.>h w &

Crswing Long Island in 1992, we not only developed a blueprint William J. Cotocosinos for LILCO's future, we helped mop out Long Chairman and Chief Executive Officer Island's economic future. As the utilityindustry changes, so does the environment in which our O

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To meet new challenges, utilities notionwide are chering the way they do business. Rapidly changing technology, more sophisticated customer demands, non-utility generating facilities, and increasing environmental regulations all point to a new era in the utility industry.

In 1992, the Long Island Lighting Company examined and discorded old utility paradigms and began to implement new strategies for success. While stillin its infancy, the fromework goes beyond simple changes in business practice to a new ideology for each and every employee - on understanding of LILCO's role in providing services to long Island and Meeting L tO C ange.

the importance of each employee in the Company's success. In short, a blueprint for the future.

Meeting the Competition The driving force behind changes at LILCO, and at utilities nationwide, is competition. Despite lingering public perception of the monopolistic power company, non-utility generation has grown tremendously in the last decade.

A recent industry study indicated that non-utility generators are currently contributing 43,114 megawatts of installed copocity to the U.S. electric supply, which represents eight percent of current U.S. electric capacity.

In addition, non-utility generators have 65,690 megawatts in the pipeline - and the numbers are O

Almost 50 percent of New York's nursery crops, such as shade trees, are produced on long Island 0

increasing s hese new generating facilities are beginnii,3 to present some formidable competi-tion. In 1992,9.8 percent of the electricity delivered

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by LILCO was produced by non-utility generators.

LILCO's natural gas business is also functioning in an increasingly competitive market. With the northeast region the last national stronghold for home heating oil companies, natural gas' recent in-roads into this market have caused a multi-million dollar advertising campaign from a coalition of oil heat dealers.

How then con traditional utilities survive? The answer lies in looking at ourselves in a non-traditional way - as a competitive business.

to compete. g Through a reorganization into distinct business units a

- Electric, Natural Gas and Energy Conservation -

LILCO has begun io restructure itself to meet the I

competitive challenge. More importantly, however, y~.

the Company is changing its attitudes and perceptions, recognizing that future success is dependent upon cost-conscious management and close attention to increasingly sophisticated customer demands.

Adopting and Evolving Containing co.ts and providing unpara!!eled customer service are not mutually exclusive. In 1992, LILCO began to implement " cost-management" as opposed to simple cost-cuMing. By taking on integrated approach to business planning, the Company is O

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eliminating costs that do not coritribute to the value of services provided to our customers.

A key element of this new approach is integrated resource planning, which considers oil available options to meet long Island's long-term energy needs, includ-ing demand. side management, independent power producers and co-generation facilities, energy purchases from other utilities, and fuel substitution in our own plants. LILCO's plan combines these elements to provide cost-effective service in on environmentally acceptable manner.

Equally important in building the Company's competitive edge is on investment in our human Meeting

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resources. To enhance employee effectiveness, LILCO worked over the lost year to bring each employee

on boord"in terms of the Company's strategic plan.

Employees panicipated in empowerment workshops to prepare them to become port of the Company's future. Employee views were also sought on ways to improve service and increase productivity.

With this change taking place in corporate culture, employees are adopting a service orientation that includes personalinvolvement and responsibility for achieving corporate objectives.

Looking Outside Whi!e internalimprovements were on impor1ont pon of llLCO's growth in 1992, external forces O

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Long Island's agricultural hentage ranges from Irvesrock and grarn in colonoal times to pararoes, sod and voneyards toacy O

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f4 played on equally vital role. The passage of the Clean

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.j Air Act Amendments and the National Energy Security Act have brought environmental concerns to the Uf

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forefront of utility planning.

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Air quality in porticular was a key environmental C ~

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concern in 1992, with motor vehicle emissions a primary focus of the new legislation. Since electricity and natural gas are currently the two leading alternative fuels for motor vehicles, LILCO is in o unique position to help Long Islanders respond to emissions concerns.

In 1992, LILCO was active in pursuing both

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alternative fuel options. With natural gas vehicles Meeting to preserve. 7 (NGVs) o more immediate clean air solution, the

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Company began adding NGVs to our own fleet, as a'-

well as providing information and assistance to other Long Island businesses. In December,1992, we completed construction of the Island's first company-owned natural gas refueling station, commissioned by the Metropolitan Suburban Bus Authority.

LILCO is also supporting fur ther developments in battery technology for electric vehicles, to make these zero-emission vehicles wide!y usable in the future. In October,1992, we held a joint forum with represen-totives of major U.S. cor manufacturers to discuss technology issues, production challenges, and local and national legislation.

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LILCO's commitment to energy conservation expanded in 1992 as well, taking a more compre-hensiw approach to decreasing residential energy use through programs such as the New York State Energy-Star (NYSE-Star) program. As a NYSE-Star participant, LILCO provides incentives to residential developers who build homes that for exceed the state energy construction code.

Involvement and Innovation in 1992, LILCO encouraged economic growth by spearheading an economic development campaign depicting Long Island's innovative business atmosphere, Meeting

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excellent colleges and universities, and diverse cultura! and tourism options. The Company's effods were part of the New Long Island Partnership, a coalition of businesses and government agencies, working to attract, retain and expand businesses on the Island.

I The effort has been successful. Since its inception, more than 70 companies have been involved with the economic development program, helping Long Island add or retain more than 7,000 jobs and $2 bi!! ion in annual sales.

Encouraging innovation is another method for generating economic growth. In the case of LILCO's Long Island Research and Development Initiative O

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More than 80 buorechnology componnes compruse long Islandh newest most rapidly growing industry 0

there was an additional benefit - developing technologies that improve LILCO service.

In February,1992, LILCO awarded more than

$3.5 million in funding to long Island institutions for 27 winning research and development projects, ranging from expert computer systems to gas leak detection devices to robotics. These projects, currently in various stages of development, represent approximately

$5 million worth of work that will be performed locally.

Direction for the Future Change, particularly change of ingrained beliefs and behaviors, takes time. The progress made in Meeting:

tO SUCCee altering both LILCO's organization and culture will continue in 1993 and beyond. But the groundwork has been laid for forging a new, competitive business from the c!d util;ty model.

LILCO will remain focused on providing unparalleled service to all Long Islanders. In 1993, that willinclude the completion of our "one-call center," a single point of contact for all LILCO customer transactions.

And we will continue to seek innovation and impro,'ement in technology and service as we grow and evolve to meet the challenge of the future.

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long Island oRers a weatrh of educational opportunrtoes woth 19 s

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Financial Roviow i

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Overview

. The refinancing of a significant amount of the Company's securities os a result of very favorable The year 1992 represents the fourth consecutive year of long-term interest rates.

continued impr ovement in the Company's financio! health-The refinancing of approximately $1.5 billion of The financial viability of the Company had been jeopardized higher-cost securities which significantly lowered the in the post by the controversy concerning the Shoreham Company's cost of debt and preferred stock. These Nuclear Power Station (Shorehom) and the federo!

1992 refinancings will result in more than $17 million Rocketeer Influenced and Corrupt Orgonizations Act (RICO in annual cash sovings through lower interest and Act) litigation. T he 1989 Settlement between the Company preferred stock dividend expenses.

and the State of New York (State) was designed to eliminate Since the 1989 Settlement become effective, the the contioversy over Shoreham by providing for, omong Company's aggressive refinancing progrom has other mot >ers, the transfer of Shorehom to on ogency of the resulted in onnual cash savings of opproximately State and reciting the intention to return the Company to

$70 million through lower interest and prefer red stock investment grode financial cond; tion by providing rote dividend expenses.

increases in each year from 1989 through 1998. The The elimination of all of the Company's outstanding Company's f noncial recovery begon in 1989 following the bank debt of approximately $446 million.

1989 Settlement and a class action settlement (Class The conversion of $400 million of variable rate Settlement) entered into between the Company and its I x-exemP securities to a 30-year fixed annual t

rotepayers to resolve the RICO Act litigation.

rote of 7.15%.

The improvement in the Company's financial condition is

. The issuance of $200 million of low-cost tax-exempt evidenced, in part, by the elevation of the Company's First securities resulting in substantial savings for the Mortgage Bonds and General and Refunding Bonds (G&R Company's ratepoyers since these secuntie carry Bonds) to one notch above " minimum investment grode" significantly lower interest rates than toxoble Nonds.

and the elevaSon of the Company's unsecured debt and

. The addition of opproximately 10,000 new gas.poce preferred stock to "mir imum investment grade.,

heating customers for the third consecutive year.

Other significant events in 1992 included:

. An increase in gas rates of 7.1 % effective December

. The trans er of ownership cd Shoreham to on ogency 1,1992.

f of the State on February 29,1992.

• Approval, by the New York State Public Service Investrnent Rating Commission (PSC), of the second annual electric rate increase of 4.1% effective December 1,1992, under The Company's securities are rated by Moody's Investors the three-year electric rate plan opproved in 1991.

Service, Inc. (Moody's), Standard and Poor's Corpor ation This three-year rote plan follows the receipt of electric (S& P), Fitch investors Service, Inc. (Fitch) and Duff and rate increases in each of the years 1989 through 1991.

Phelps (D&P).

+ The reinstatement of the Company's Automatic Since 1989, the rating agencies have significontly upgraded Dividend Reinvestment Plan beginning with the their rotings on the Company's First Mortgage Bonds and October 1,1992 common stock dividend payment.

G&R Bonds to one level above " minimum investment grade" l

• An increase in the Company's common stock quarterly and the Company's debentures and preferred stock to dividend from 423 cents per quarter to 43% cents per

" minimum investment grade."

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The chart below indicates the current ratings for each of the Earnings for common stock in 1992 were 52.14 per Company's principal securities and the minimum investment common shore compared to $2.15 per common shore grade ratings used by each agency.

in 1991. The 1992 results reflect a significant improve-

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ment in the Company's gas business earnings. The l

Company's electric business earnings were lower in First Mortgage Bonds Boo 2 BBB BBB BBB 1992 as a result of the lower o!! awed rcte of return G&R Bonds Boo?

BBB BBB BBB which is prescribed by the PSC.

Debentures Boo 3 BBB-- BBB-BBB-Preferred Stock boo 3 BBB-BBB-BB 4

• The common stock troded on overoge at a twenty-one year high.

Minimum investment Grade Boo 3 BBB-BBB-BBB-1 e

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1 Rrta Matters moderation plan provided for in the RMA. The RMC has provided the Company with a substantia! omount of non.

Electric Pursuant to the 1989 Settlement, the Company cash earnings since the 1989 Settlement become effective.

received electric rote increases contempleted by the Rote The RMA was designed to provide rote increases suff..icent to Moderation Agreement (RMA), o constituent document of rec ver the RMC within a ten-year period. The RMC balance the 1989 Settlement discussed below, for each of the three hos inm osed as the difference between revenues resulting rote years in the period ended November 30,1991. In k m the implementation of the rate mooerotion plan response to the Company's rote filing in December 1990, the vided for m the RMA and revenue requirements under pr PSC approved the Long Island Lighting Company Rote _

c nventi n I r tem king, together with a carrying charge i

making and Performance Plan (LRPP)in November 1991, equ It the oHowed rate of return on rote base, hos been which provides for annual electric rate increases of 4.15%,

deferred. The RMC balance will subsequently decrease and,is 4.1% and 4.0% effective December 1,1991,1992 and expected to be fully amortized by November 30,1999, as 1993, respectively. Effective December 1,1992, the deferred revenue requirements are recovered.

Company began receiving the second of the three annual electric rate increases provided for within the LRPP. The LRPP The LRPP was designed to be consistent with the RMA's long-provides for on ollowed return on common equity from term goals including: (i) the recovery of the BFC (ii) the electric operations of 11.6%.

recovery of the RMC in opproximately ten years; (iii) the Company's return to investment grade financial condition One principal objective of the LRPP is to reassign risk so that nd (iv) the Company s rece:pt of odequate and timely rate the Company assumes the responsibility for risks within the relief. Although the LRPP provides for slightly lower annual contrel of management, whereos risks largely beyond the electric r te incre ses than enginally anticipated in the 1989 control of monogement would be ossumed by the rotepayers.

Settlement, the Company believes that it will still fully recover One of the maior components of the LRPP provides for o the RMC within o ten-year period principally as a result of revenue reconciliation mechanism that reduces the impact on earnings of experiencing electric soles that are above or below changes in the original ossumptions. The revenues assumed by the LRPP are odequate to provide the Company with the LRPP forecast by providing o fixed annual net margin level (defined as sales revenues, net of fuel and gross receipts rec very f its revenue requirements under conventional taxes) that the Company will receive over the three rote years r tem king and recovery of the RMC balance over the under the LRPP. Another component of the LRPP o!!ows the rem inder of the ten-year period. However, actuoi revenues y differ fr m those assumed for this period. The original n

Company to earn for each rate year up to 60 additional basis points, or forfeit up to 38 basis points, of the allowed ssumptions underlying the RMA included projections of return on common equity as a result of its performance within future revenues, operating expenses and required rates of certain incentive and/or penalty programs. The LRPP also return. Since then, the Company has experienced interest r te5, Perotions and mmntenance expenses, non-Shoreham contains a mechonism whereby earnings in excess of the oUowed rate of return on common equity, excluding the pr Perty taxes and fuel expenses that ore lower than those impacts of the various incentive and/or penalty programs, rigin !!y nticip ted. As a result, omounts deferred in the RMC have been less than expected.

are shared equally between rotepayers and shoreowners.

Fr funher discussion of the 1989 Settlement and Rote In conjunction with the 1989 Settlement, the PSC outhorized M tiers, see Notes 2 and 3 of Notes to finanoel Statements.

the recognition of a regulatory asset known as the Financial Resource Asset (F RA). The F R A consists of two components, Gas In November 1992, the PSC approved a gas rote the Bose Financi' {omponent (BFC) and the Rote Moderofion inctease of 7.1%, or $35.7 million onnually, effective Component (RML).The RMA provides for the full recovery of December 1,1992, with on allowed return on comrnon the F R A. The RMA, by its terms, spetities that the FR A is,

the Company received a gas rate increase of 4.1% effective equity from gas operations of 11.0%. In November 1991, being created to provide the Company odequate tinonaal indiac for the period 1989 ihrough 1999 and to resture the December 1,1991, Company's debt securities to investment grode levels os determined by independent roting agencies.

On December 31,1992, the Company filed on opplication with the PSC seeking gas rate relief for the three rate years The BFC, os..tially established, represents the present value beginning December 1,1993. The Company hos requested ini j

of the future net-ofter-tax cash flows which the RMA provided a gas rate increase of 6.7%, or $37.7 million in additional j

the Company for its financial recovery. The BFC was granted revenues to become effective for the first rate year under rote base treatment under the terms of the RMA and is this filing. The Company's filing also includes a proposed included in the Cc,mpany's revenue requirements through on methodoiogy for determining rate increases, not to exceed omortization inc(uded in rates c ver forty years on a straight-opproximately $30 million annually, for the subsequent line basis beg:nning July 1,1989.

second and third rate years. This filing reflects the Company's The RMC reflects the difference between the Company's latest projections of capital expenditures, operations and revenue requirements under conventional rotemoking and maintenance expenses and the continued expansion of its the revenues resulting from the implementation of the rote gas business.

O 1

l

Results of Operations Earnings for 1990 included 10 cents per common shore a+tributobte to o change in the Cc,mpany's method of Earnings Summary results of earnings for the years 1992, recognizing gas revenues. Effective January 1,1990, the 1991 and 1990 were os follows:

Company's revenues included estimated consumption of gas delivered to customers, but not yet billed at month end, (In rnilhons oidohors and shores except earnogs per share) resulting in the full occruoi of all unbilled ges revenues. The 1992 1991 1990 cumulative effect of this accounting change increased 1990 ngs h ne y 2 mEcm, net o% eks. N Eet income

$ 302 $ 306 $ 319 e

Company d;d not earn in excess of its o!! owed rote of return Earnings for Common Stock

$ 238 $ 239 $ 251 for the rate year ended November 30,1990.

Earnings per Common Shore

$ 2.14 $ 2.15 $ 2.26 Average Shores Outstanding 111.4 111.3 111.3 Revenues Total r evenues in 1992, including revenues from recovery of fuel costs, wer e $2.6 bill;on, which represents on AfC & RMC included increase of $74 mi' lion or 2.9% over 1991 revenues. Total in Net income

$ 60 $ 183 $ 214 revenues for the Company's electric and gas operotions for AFC & RMC - % of Net income 20%

60 %

67 %

the years 1992,1991 and 1990 were os follows:

% dudes the effecr f on octounting change for urbihed gas revenun o

For oli periods, net income, earnings for common stock and (In mdirom olduhws) 1992 1991 1990 ect nings per common share include non-cosh allowance for Electric

$ 2,195 $ 2,197 $ 2,5 funds used during construction (AFC) and the RMC.

Gas 427 351 361 The earnings in the electric business were lower in 1992 when Total Revenues

$ 2,622 $2,548 $ 2,457 compared to 1991. This lower level of earnings in the electric business was offset by the significant increase in the gcis Electric in 1992, electric revenues decreased $2 miUion business earnings in 1992.

when compared to 1991. Revenues in 1991 had incteased The increase in the gas business earnings was the result of SM mE n r 4.8% over 1990. The changes in the level of higher revenues and continued cost containment programs.

revenues when compared to the prior year resulted from the The higher gas revenues were due to the 1992 gas rate f U *i"9 I C'

'5 increase and the Company's oggressive gas expansion progrom, which has resulted in on increase in the number of

--- guggg gas space heating customers.

'92/'97 6

Rote Inaeoses

$ 85 5 114 The electric business earnings for 1992 were lower os a result Sales Volumes (74)

(7) of the lower allowed rote of return of 11.6% in 1992 w hen gg

,g g

g compared to tne ollowed rote of return of 12.75%,n 1991.

i The allowed rate of return is prescribed by the PSC.

Total

$ (2)

S 101 incentives earned for electric operations provided 6 cents per Rote increases lhe Company received electrit rate increases share in 1992 ond 12 cents per shore in 1991. In addition, of 4.1% effective December 1,1992, and 4.15% effective for the rate year ended November 30,1992, the Company December 1,1991. These rate increases provided $85 earned $16.2 million, net of tax effects,in excess of its million in odd.tional revenues for 1992 when compared to allowed rote of return on common equity which,in octordance 1991. A 5.0% rote increase effective December 1,1990, with the i RPP, was shared equally between rotepoyer s and provided $114 million in additional revenues for 1991 whe n shoreowners. These excess earnings were generated cn a compared to 1990.

result of a reduction in operations and maintenonce expenses n

ums The deaeose in revenue from sales volumes and the effect of a decrease in capital expenditures included in rote base.

w s pnm rily rtributable to cooler weather experienced in the summer of 1992 when compared to the some period m The dectease in earnings for common stock for 1991 of 1991. The Company's current electric rate structure, discussed opproximately $12 million, or 11 cents per shore, compared above under the heading " Rote Matters," provides for a with 1990, was primarily attributoble to increases in revenue reconciliation mechanism which reduces the impact non fuel operations and maintenance expenses, operating on earnings of experiencing electric sales that are above or tomes and interest expense, portially offset by higher electric below the levels e eflected in rotes. As o result oflower than revenues. For the rate year ended November 30,1991, adjudicated electric safes, the Company recorded non-cosh the Company corned $10.1 million, net of tax effects, in income whichisincluded in "Other Regulatory Amortirations" excess of its allowed rate of return, which was opplied as o of $78.5 million and $0.4 mEon in 1992 and 1991, reduction to the RMC.

respectively.

1 0

[

i l

Kilowort Hour Sales Summary of electric kilowatt hour (kWh)

Role increases The Company received gas rote increases sales for the years 1992,1991 and 1990 were os follows:

ef 7.1% effective December 1,1992, and 4.1% effective i

December 1,1991. These rate increases provided $17 million U" **" "I in additional revenues in 1992 when compared to 1991. A 1992 1991 7990 gas increose of 1.3% in.fonvory 1990 provided $2 million in EeU[nEoI 6,788 7,023 7,022 odditional revenues for 1991 when compared to 1990.

Commerciol!!ndustrial 8,652 8,791 8,832 Sales Volumes The increase in 1992 revenues due to soles System Sales 15,440 15,814 15,854 volumes was primarily due to customer additions and Power Pool Sales 227 598 532 conversions resulting from the Company's gas expansion i

Total Sales 15,667 16,412 16,386 program, oided by a colder heating season in 1992. The Company ndded opproximately 10,000 new gas space The decrease in residential and commercial / industrial soles heating customers to its system for the third consecutive year.

in 1992 was largely due to the cooler weather experienced Summary of gas decatherm (dth) sales for the years 1992, during the summer months. Residential soles, which 1991 and 1990 were os follows:

comprised 44% of system soles, were down by 3.3% when gn,hovsonds of d+)

compared with 1991, while commercial / industrial sales,

,pp,

,pp, gpg which accounted for 53% of system sales, declined by 1.7%.

Power pool soles f!vctuate with relative costs and power pool Space Heating 48,751 41,323 41,081 system ovoilobilities.

Non-Space Hecting 7,541 7,366 7,800 Total Firm 56'292 48,689 48,881 The overage number of electnc customers served in 1992 Interruptible 5'090 4,538 6,347 and 1991 was approximately 1,009,000 and 1,005,000.

respectively. The 4,000 customer increase in 1992 is Total System 61,382 53,227 55,228 similar to the increase experienced in 1991 when compared to 1990.

Summ ry i ver ge use per cust mer i r the years 1992, 1991 and 1990 was as follows:

Summary of overage use per customer for the years 1992, 1991, and 1990 was as follows:

"#D "" d 1992 1991 1990 Un n%enustomer)

S oce Heating 188 165 171 1992 1991 1990 Non-Space Heating 42 40 41 f'esidential 7,518 7,812 7,044 Interruptible 9,568 9,614 15,480 Commercio!/ industrial 80,346 81,797 82,304 System 140 123 129

~' System 15,297 15,731 15,832 fuel Cost Pecoveries Recoveries of fuel erpenses in 1992 Fuel Cost Recoveries Total electric fuel cost recoveries for revenues increased by $9 million compared with 1991, 1992 were down $13 miinon compared with 1991, primarily primorily due to higher sales volumes. In 1991, fuel recovery as a result of lower sales volumes, partially offset by on revenues had decreased by $5 million, primarily due to increose in the overage cost of fuel. In 1991, fuel cost lower soles volumes.

recoveries decreased by $6 million compared with 1990, principolly due to o lower overoge cost of fuel.

Fuel and Purchased Power Expenses for fuel and purchased power for electric operations and for gas Gas in 1992, gas revenues increased by $76 million, or delivered to customers decreo",a by $27 million in 1992 21.7%, when compared to 1991. Revenues in 1991 compared with 1991, and decreased by $18 million in 1991 decreased by $10 million, or 2.8% when compared to 1990.

compared with 1990. Seenmory of fuel and purchased power The changes in the level of revenues when compared to the expenses for the years 1992,1991, and 1990 were os prior year resulted from the following f actors:

follows:

On rhoasands of doibrs)

Ori m&m of dulbrs)

• V2!'91

'911'90 1992 1991 1990 Rote increases

$ 17 2

Electric Fuel

$ 279 $ 381 $ 441 l

Sales Volumes 50 (7)

Purchased Power 281 213 170 Fuel Cost Recovenes 9

(5)

Gas 182 175 176 i

l Total

$ 76

$ (10)

Total

$ 742 $ 769 $ 787 i

i O

N The Company has substantially reduced its dependence on for the years 1992,1991 and 1990, the Company recorded foreign oil for electric generation, substituting gas and non-cosh charges to income of opproximately $101 millic.n, purchased power whenever economical. Summary of electric reflecting the continuing amortization of the BFC, which is fuel and purchased power mix for the years 1992,1991 and efforded rate base treatment under the RMA. For o further 1990 were os follows:

discussion of the BFC and 1989 Settlement, see Notes 1 and 2 of Notes to Financial Statements.

[Percenf of system energy requaements) 1992 1991 1990 Lleguidity Oil 37 %

50%

56 %

Cash and Revolving Credit At December 31,1992, Gas 19 18 20 the Company's cash and cash equivalents omounted to l

Purchased Power 38 25 20 o proximately $309 million, comport.d to $298 million at l

Nuclear Fuel 6

7 4

December 31,1991.

Total 100 %

100 %

100 %

in addition, the Company hos opproximately $251 million available under its revolving line of credit through October 1, Operations and Molntenance Expenses Total 1993, provided by its 1989 Revolving Credit Agreement operations and maintenance expenses, excluding fuel and (1989 RCA). At December 31,1992, no omounts were purchased power, for 1992,1991 and 1990 were $498 outstanding under the 1989 RCA. For o further discussion of million, $523 million and $476 million, respectively. The $25 the 1989 RCA, see Note 7 of Notes to Financial Statements.

million, or 4.8%, decreose in 1992 was primarily due to lower electric operations expenses which resulted from the Financing Programs During 1992, the Company issued Company's oggressive expense reduction ond cost

$211 million oggregate principal amount of G&R Bon 's, containment progroms. The Company also instituted and hos opproximately $1.3 billion oggregate principal amoe.1 of pursued more oggressive collection proctices os evidenced debentures and $420 million of preferred stock. The net l

by a lower provision for doubtful accounts in 1992. Portiolly proceeds from the sole of these securities were used to offsetting these decreoses were certain higher expenses, eliminate all bank debt, redeem higher-cost debt and i

including expenses related to the Company's shore in the preferred stock and to pay any related redemption costs.

Nine Mile Puint Nuclear Power Station, Unit 2 (NMP2) and The detoils respecting the Company's $2.3 billion of i

employee related benefits.

refinoncing octivities in 1992 were os Iollows:

The $47 million, or 9.9%, increase in 1991 was primarily secuntes usued secuntres Redeemed ottributoble to increases in employee woges and benefits, S 56 malion GER Bonds

$ 53 million G&R Bonds electnc production and gas distribution costs, and provision 7.85% Series Due 1999 9.75% Series Due 1999 for doubtful occounts.

$ 75 mil! ion G&R Bond:.

$ 70 million G&R Bonds i

8.50% Series Due 2006 9.625% Series Due 2006 I

Other items in 1992, federalincome taxes were

$ 80 millic:n G&R Bonds S 75 malion GER Bonds I

opproximately $161 million, compared with $182 million L90% % DM008 920% Seies DM008 1

m 1991. In 1990, these taxes amounted to $183 million,

$397 million Debentures

$319 million Debentures excluding the effect of the accounting change for unbilled 7.30% Series Due 1999 10.875% Series Due 1999 i

gas revenues.

$420 million Debentures

$346 million Debentures Interest expenses for 1992,1991 and 1990 were $512 8.90% Series Due 2019 11.375% Series Due 2019 j

million, $524 million and 5508 million, respectively. The

$ 25millionFirstMortgageBonds i

decrease in 1992 was the result of lower interest rates, 9.125% Series Due 2000 primority achieved through refinancings.

$451 million Debentures

$446 million under the 1989 9% Series Due 2002 Term toon Agreement i

in 1992, the Company recorded non-cosh charges to

$363 million Preferred Stock

$320 million Preferred Stock income of opproximately $23 million which represents 7.95% Series AA 10.60% Series Y the increase in the present value of the Class Settlement

$ 57 million Preferred Stock

$ 55 mill;on Preferred Stock liability. These charges amounted to $25 million and 7.66% Series CC 9.80% Series S i

$23 million for 1991 and 1990, respectively. For

$400 malion tor-exempt

$400 malion tax-exempt securities further discussion of the Class Settlement see Note 4 securities, 7.15%,30-year variable weekly rate of Notes to Financial Statements.

hxed annual rate for the years 1992,1991 and 1990, the Company recorded in addition to the above refinancings, the Company utilced non-cosh credits to income of $73 million, $269 million and

$200 million of tax-exempt securities in 1992. The net S313 million, respectively, reflecting the RMC ond related proceeds from the sole of these tax-exempt securities were carrying charges. For o further discussion of the RMC and used to reimburse the Company's treasury for previously RMA, see Notes 2 and 3 of Notes to Financial Statements.

incurred capital expenditures.

O

in addition to the conversion of $400 million of tax-exempt

$7.3 billion. This increase in capitalization primorily reflects securities in June 1992, the Company converted $100 mimon on increase in long-term debt associoted with the Company's of tox-exempt securities in January 1993 from o varioble financing octivities in 1991 and on increase in common weekly interest rate to a 30. year fixed annual rote of 6.90%.

shoreowners' equity comprising 1991 net income of $306 In January 1993, the Company issued $36 million principal million reduced by common and preferred stock dividends amount of Debentures,7.30% Series Due 20N, the net of $245 million.

proceeds of which will be used in February 1993 to redeem, At December 31,1992 and 1991, the components of the of the opplicable redemption price, $35 mi% ion principal Company's capitolization ratios were os follows:

omount of First toortgage Bonds,8.20% 5eries R Due 1999.

E In februory 1993, the Company sold $142 million principc4 amount of Debentures,7.50% Series Due 2007, the net Long. Term Debt 64.7 %

63.9 %

proceeds of which wil! be used in Idarch 1993 to redeem, et Preferred Stock 8.8 8.8 the opplicable redemption prices, the following series of G&R Common Shoreowners' Equity _

26.5 27.3 Bonds: $50 million,6%% Series Due 2006 ond $85 million, Total 100.0 % 100.0 %

8%% Series Due 2007.

Capital Requirements and Capitol Provided The Company hos been able to utilize $100 million of tax-exempt securities in each of the years 1989 through 1992. In Capitol requirements and capital provided for 1992 and 1991 were os follows:

1990, the Company was able to utihze on additional $100 mi!! ion of tor-exempt securities (1991 Series A Electric Facilities Revenue Bonds) oliocated for its benefit.

During the period January 1,1993 to December 31,1995, CapitalRequirements the Company has estimated that it will be required to seek Construction external financing of oppreximately $1.4 billion, principolly Electric

$ 137 $ 127 Gas 104 90 to refund maturing debt and secondarily to meet its operating Common 27 18 ond capital requirements. In addition, the Company intends to continue to access the capital markets to refund higher-cost Total Construction 268 235 bt and preferred stock, when market conditions permit.

Refundings and Dividends ie Company currently has debt and equity securities regis.

Long-term debt 1,344 1,129

ered with the Securities and Exchange Commission on shelf Preferred stock 389 71 reoistrotion statements. The sole of $615 million cf these secur.

Preferred stock dividends 70 66 Common stock dividends 191 173 ities will be used to refund the following securities motoring in 1993: $40 mill;on of First IAortgage Bonds,4.40% Series /A Redemption costs 159 68 Due April 1,1993, $375 milton of Debentures,113/8%

Total Refundings and Dividends 2,153 1,507 Series Due April 1,1993 ond $175 million of Debentures, Shoreham post settlement costs 228 158 11.70% Series Due November 15,1993. The Company may Total Capitol Requirements

$ 2,649 $ 1,900 o!so seli on additiono! $146 million of previously registered securities, which will be used, when market conditions permit, Capital Provided to refund higher-cost debt or preferred stock.

(Increase)in cash (11) $ (195)

For o further descussion on the Company's capital stock and L ng-term debt 1,660 1,532 Preferred stock 411 63 long. term debt, see Notes 6 and 7 of Notes to Financial h" "'I"9' Si5 (7)

(20)

Statements.

Other financing activities 6

9"""

Capitallrotion l

from operations 590 520 The Company's copito!ization (defined os the tctol of long-term Total Capital Provided

$ 2,649 $ 1,900 debt, preferred stock and common shoreowners' equity) of ro, L,,6,,,ntorme,o,y,,, rs, seemen, or cmA nys.

December 31,1992, was approximately $8.2 billion, os For 1993, total capital requirements (excluding common compared to $7.8 billion at December 31,1991. This increase stock dividends) are estimated at $1.2 billion, of which in c pit liz ti n f ppr xim tely $420 mil, on pnncipally construction requirements are estimated to be $320 million, n

reflects on increase in long-term debt and preferred stock mandatory redemptions are $590 million, preferred stock associated with the Company's financing activities m 1992 sinking fund requirements are $8 million, preferred stock l

and on increase in common shoreowners equity compnsmg dividends are $57 million, and Shoreham post settlement l

1992 net income of opproximately $302 million reduced by costs are estimated of opproximately $189 million. The common and preferred stock dividends of $254 million.

Company intends to satisfy these capitol requirements At December 31,1991, capitolization increased by opproxi-through external financing, as discussed above, and internal l

motely $492 million from the December 31,1990, balonce of cash generation from operations.

l l

q h

t f

I Other Motters acceptobly low levels of sulfur. However, the Company i

l erpects that it will incur costs to comply with odditional

[

Electric Competition, Conservation and Supply The continuous emission monitoring (CEM) requirements and for

{

Company is experiencing comp?tition from cogenerators future nitrogen oxide reduction requirements that may be

[

i and other independent power producers located within the imposed under federof or stote regulations. The Company Compony's service territory. These facilities supply electric estimates that the cost of insto!!ing CEM ond nitr ogen oxide l

energy to existing or new industriol and commercial control equipment, which the Company will seek to recover customers and excess electricity is sold to the Company through rates, will be opproximately $15 million and $100

^

pursuant to the purchase requirements of the Public Utility million, respectively.

Regulatory Policy Act of 1978 (PURPA). The Company has contracts with owners of these f acilities which will provide for Accounting Pronouncements The Company will

[

o total of opproximately 340 megawatts (MW) of capacity odopt the provisions of Statement of Financial Accounting I

by 1994, which includes the New York Power Authority's Standards (SFAS) No.106, Employers' Accounting for i

136 MW Holtsville facility. The Company has also entered Postretirement Benefits Other Thon Pensions, during the first f

into controcts for opproximately 450 MW of power from quarter of 1993. SFAS No.106 requires the Company to various projects on on energy-only basis.

recognize the expected cost of providing postretirement

[

benefits when employee services are rendered rather than The Company has. implemented conservation and lood on a pay-as-you-go method. The Company will record on monogement programs to meet Long Island s energy needs occumulated postretirement benefit obligation and I

in the future. In 1992, the Company met its torgeted corresponding regulatory osset of opproximately $376 reductions in its revised 1992 Electric ConservoSon and Load million which represents the transition obligation at Monagement Plon, which colled for a 235 MW reduction en December 31,1992. Additionally, as a result of adopting coincident peak demand by December 31,1992, and SFAS No.106, the Company's onnual postretirement benefit i

onnvolized energy savings of 454 gigawatt hours, at a ex ense willincrease by opproximately $44 million above l

budgeted cost of opproximately $45.3 million. The Company the amount previously recorded under the pay-os you-go l

onhcipates that the Conservation and Load Monogement d

method. This additional $44 million of non-cosh post-Plan well conhnue in future years to gain further reductions in retirement benefit expense will also be accounted for os

[

system peak and energy usoge.

g g g pg i

The Company's current electric lood forecasts indicate that, permit recovery of these regulatory assets through rates.

4 with continued implementation of its aggressive conser.

For a further discussion of SFAS No.106, including the j

votion and lood monogement progroms and with electricity recoverability of these regulatory assets, see Note 8 of provided by independent power producers and cogenerotors, Notes to Financial Stotements.

l 2

the Company's existing generating facilities, the Company's The Company will odopt SFAS No.109, Accounting for portion of nuclear energy generated at NMP2 and contracts income Taxes, during the first quarter of 1993. SFAS No.109 I

for purchased power ore odequete to meet the energy prohibits net of tax occounting and reporting and requires i

demands on tong Island beyond the end of the century.

recognition of a deferred tax liability for the tax benefits which re w mug is cust mq n{the equity component

{

Gas Competition in 1987, the Federo! Energy Regulatory

^ "9 Y sset r G bihty mil be recognized j

Commission (FERC) issued on order allowing gas pipeline Hng i sqch items.f it is probable that the future increase j

i componies and producers access to certcin of the Company's r decre 5e 'n i "e5 Poyable thereon shall be recovered customers for the purpose of supplying competing gas mm r wtme cust mm thmugh future rates.The j

service. As of December 31,1992, opproximately 104 of the Company estimates that had it adopted SFAS No.109 at i

Company,s former lorge gas customers were purchasing gas December 31,1992, the Company would have recorded on l

directly from gas pipeline companies and prodoters and occumulated deferred tax liabihty and o corresponding orranging for its nansportchon through the Company s gas regulatory asset of opproximately $1.2 billion. The impact of moins. The Company receives a fee for this tronsportation SFAS No.109 on the Statement of income is not expected to r

service which accounted for opproximately $6.7 milhon, or be material. For a further discussion of SFAS No.109, see 1.6%, of total gas revenues for 1992.

i Note 1 of Notes to financial Statements.

Cleon Air Act in late 1990, significant omendments to the Selected Financial Doto a

federal Cleon Air Act were adopted. A number of electric utihties anticipate substantiol increases in operating costs Additional Ononcial information for the lost five years is and capitol expenditures as a result of the omendments.

provided in Tobles 1 through 11 of Selected Financial Doto.

The Company does not expect toincur any costs to satisfy Information with regard to the Company's business segments these omendments with respect 1o the reduction of su! fur for the lost three yeors ;s provided in Note 11 of Notes to

~

dioxide emissions, since the Company ofready uses fuel with Financial Statements.

i G

i

I Financial Statomonts l

Statement of Income pn thousands of dollars except per share amourits) f or year ended December 3) 1992 1991 1990 R: venues Electric

$ 2,194,632 $ 2,196,568 $ 2,095,660 i

Gas 427,707 351,161 361,242 Total Revenues 2,621,839 2,547,729 2,456,902 I

Expenses l

Operations - fuel and purchased power 741,784 768,702 786,999 Operotions - other 372,209 375,267 340,518 Maintenance 125,736 147,492 135,291 Depreciation and amortization 119,137 118,955 110,884 l

l Bose financial component omortization 100,971 100,971 100,971 Regulatory liability component omortization (88,573)

(88,573)

(88.,573)

Other regulatory amortizations (22,072) 8,666 14,427 Rote moderation component (30,444)

(228,572).

(297,214)

Oper ating taxes 388,988 388,380 370,317 Federclincome tax - current 530 515 3,638 i

Federolincome tax - deferred and other 172,468 168,937 177,014

-[

l Totol Expenses 1,880,734 1,760,740 1,654,272 j

l Cperating income 741,105 786,989 802,630_

Cther income end (Deductions) i Allowance for other funds used during construction 4,725 2,202 2,940 Rote moderation component carrying charges 42,837 40,456 15,683 i

Other income and deductions, net 28,832 33,783 27,218 i

l Closs Settlement (22,541)

(25,467)

(22,574) l Federal income tax (chorge) - deferred and cther 12,036 (12,201)

(2,629)

Total Other income and (Deductions) 65,889 38,773 20,638 inc:me Before Interest Chorges and Cumulative Effect of Accounting Chonge 806,994 825,762 823,268 Intsrest Chorges and (Credits)

Interest on long-term debt 450,621 472,974 467,700 Other inter est 61,785 50,842 40,559 l

Allowonce for bortowed funds used during construction (7,386)

(3,592)

(4,628)

Total Interest Chorges and (Credits) 505,020 520,224 503,631 Inceme Before Cumulative Effect of Accourting Change 301,974 305,538 319,637 Cumulative Effect of Accounting Change for Unbilled Cos Revenues (not of applicable taxes of $6,017) 11,680 Nst income 301,974 305,538 331,317' Preferred stock dividend requirements 63,954 66,394 68,161 Earnings for Common Stocic

$ 238,020 S 239,144 $ 263,156 Average Common Shores Outstonding (000) 111,439 111,348 111,290 Errnings per Common Shore Before cumulative effect of accounting change 2.14 $

2.15 $

2.26 i

Cernulative effect of accounting change

.10 Errnings per Common Shore 2.14 $

2.15 $

2.36 Cividends Declared per Common Shore 1.72 $

1.60 $

1.25 See Notes to financialStafements.

l.

O 1

l i

Belanco Shoot i

Assets on rhovsands of dollars) l At Decernber 31 1992 199I Utility Plant Electric

$ 3,429,803 S 3,323,008' I

Gas 760,635 666,904 Common 172,703 157,495 Construction work in progress 161,663 157,511 Nuclear fuelin process and in reactor 19,216 29,818 l

4,544,020 4,334,736.

Less-Accumulated depreciation

_ad omortiration 1,382,872 1,332,003 Total Net Utility Plant 3,161,148 3,002,733 Regulatory Asset Base finoncial component (less occumulated omortization of $353,398 and $252,427) 3,685,432 3,786,403 j

Nonutility Property and Other Investments 20,730 9,788 Current Assets Cash and cash equivalents 309,485 298,098 Special deposits 23,683 23,207 i

Customer accounts receivoble (less allowance for doubtful accounts of $24,375 ond $26,935) 208,049 210,525 Other accounts receivcble 6,937 6,515 Accrued unbilled revenues 143,172 136,565 i

Materials and supplies at overage cost 86,482 86,863 Fuel oil of overoge cost 51,702 44,002 Gas in storoge at overage cost 47,002 43,388 Prepayments and other current assets 40,402 34,854

}

TotalCurrent Assets 916,914 884,017 Deferred Chorges Rote moderotion component 651,657 602,053 Shoreham post settlement costs 586,045 378,386 Unomortized cost of issuing securities 380,267 227,713 Shorehom nuclear fuel 77,629 79,760 Accumulated deferred income taxes 511,898 439,235 Other 256,904 133,213 Total Deferred Chorges 2,464,400 1,860,360 Total Assets

$ 10,248,624

$ 9,543,301 See Notes to imoncial 5+atements.

I i

O

Cypitollzotion and Liabilities (In thousands of dollars]

At Deternber 31 1992 1991 Crpitollzotion Long-term debt

$ 4,755,733

$ 5,001,016 Unamortized premium and (discount) on debt

'(14,731)

(14,850) 4,741,002 4,986,166 Preferred stock - redemption required 557,900 524,912 Preferred stock - no redemption required 154,276 154,371 Total Preferred Stock 712,176 679,283 Common stock 558,002 556,825 Premium on capitol stock 998,089 993,509 l

Capitof Stock expense (39,304)

(40,216)

Retained earnings 667,988 620,373 l

Total Common Shoreowners' Equity 2,184,775 2,130,491 i

Totof Copitolization 7,637,953 7,795,940 Current Liabilities Current moturities of long-term debt 590,000 10,000 Current redemption requirements of preferred stock 8,200 10,616 i

Accounts payable and occrued expenses 286,102 223,589 Accrued taxes (including federalincome taxes of $27,100 ond $27,693) 67,525 60,174 f

Accrued interest 131,179 85,565 Dividends payable 53,966 60,287

[

Class Settlement 30,000 20,000 Customer deoosits 24,815 22,664 i

Total Current Liabilities 1,191,787 492,895 f

Deferred Credits l

1989 Settlement credits 164,294 173,507 Class Settlement 167,066 173,564 Accumulated deferred income taxes 970,373 816,053 i

Other 110,341 84,035 l

Total Deferred Credits 1,412,074 1,247,159 f

R serves for Cloims, Demoges, t'

Pensions and Benefits 6,810 7,307 C mmitments and Contingencies Tetal Capitoliration and Llobilities

$ 10,248,624 S 9,543,301 See Notes to Fmancual Statements.

f

Sheroownors' Equity (In thousands of dollars)

Statement of Retoined Earnings 1992 1991 1990 Bolonce at January 1 620,373 $

560,405 $

436,690 Net income for the year 301,974 305,538 331,317 922,347 865,943 768,007 Deductions Cash div:dends declared on preferred stock 62,387 67,261 68,218 Cash dividends declared on common stock 191,693 178,169 139,128 Capjital stock expense 279 140 256 Bolonce at December 31 667,988 $

620,373 $

560,405 Preferred Stock (in thousands of dollars)

At December 31 1992 '

1991 1990 Call Price Per Shore December 31,1992 Finel Por Volue $100 per Shore, Cumulative Shores authorized 7,000,000 7,000,000 7,000,000 Shores issued and outstanding 2,353,757 2,438,993 2,528,400 5.00% Series B

$101.00

$101.00 $

10,000 $

10,000 $

10,000 4.25% Series D 102.00 102.00 7,000 7,000 7,000 4.35% Series E 102.00 102.00 20,000 20,000 20,000 4.35% Series F 102.00 102.00 5,000 5,000 5,000 51/8% Series H 102.00 102.00 20,000 20,000 20,000 5 3/4% Series I Convertible 100.00 100.00 2,276 2,371 2,674 8.12% Series J 101.00 101.00 25,000 25,000 25,000 8.30% Series K 103.'29 103.29 30,000 30,000 30,000 7.40% Series L*

103.22 100.00 20,300 21,350 22,400 8.40% Series M*

103.36 100.00 23,800 25,200 26,600 8.50% Series R*

101.00 100.00 15,000 22,500 26,250 9.80% Series S*

55,478 57,916 7.66% Series CC*

100.00 57,000 Total Por Value $100 235,376 $

243,899 $

252,840 Por Value $25 per Shore, Cumulative Shores authorized 30,000,000 30,000,000 30,000,000 Shores issued and outstanding 19,400,000 17,840,000 17,720,000 l

$2.47 Series O*

$ 25.25

$ 25.25 $

22,000 $

26,000 $

28,000

$2.43 Series P 27.75 27.75 35,000 35,000 35,000 S3.31 Series T*

60,000

$2.65 Series Y*

320,000 320,000

$2.35 Series Z*

27.35 25.00 65,000 65,000 7.95% Series AA*

25.00 363,000 Total Por Value $25 485,000 $

446,000 $

443,000 Less - Sinking fund requirements 8,200 $

10,616 $

13,616 Total Preferred Stock 712,176 $

679,283 $

682,224 Common Stock tin thousor:ds of dottors)

At December 31 1992 1991 1990 Por Value $5 per Shore j

Shores authorized 150,000,000 150,000,000 150,000,000 i

Shores issued and outstanding 111,600,376 111,365,056 111,324,081 Increase in shores outstanding 235,320 40,975 74,613

^

increase in $5 por value 1,177 $

205 $

373 increase in premium on capitol stock 4,493 $

614 $

924 Decrease in capitol stock expense 912 $

2,460 $

240

• Redemptio~ required, see Note 6.

"NotcollablectDe vmber31,1992 Tbe aggrepote fair volve of redeemable preferred stod at December 31,1992 omounted to $581.984 compared to its carrying amount of $566,100.

See Notes o FinancialStaternents.

n O

i

Statomont of Cash Flows (In thousands of dollars) for year ended Dereinber 31

)ppy t99; 19p0 Operating Activities Net income

$ 301,974

$ 305,538

$ 331,317 Adjustments to reconcile net income to not cash provided by operating activities Cumulative effect of occounting change for unbilled gas revenues (11,680)

Depreciation and amortization 119,137 118,955 110,884 Fuel moderation component 34,025 3,804 Provision for doubtful accounts 16,329 35,431 30,097 Base financioi component amortization 100,971 100,971 100,971 Regulatory liability component omortization (88,573)

.(88,573)

(88,573)

Other regulatory amortizations (22,072) 8,666 14,427 Rote moderation component (30,444)

(228,572)

(297,214)

Rote moderation component carrying charges (42,837)

(40,456)

(15,683)

Class Settlement 22,541 25,467 22,574 Amortization of cost ofissuing and redeeming securities 41,204 27,456 23,648 Federalincome taxes - deferred and other 160,432 181,138 179,643 Allowance for other funds used during construction (4,725)

(2,202)

(2,940)

Other 699 38,068 15,234 Changes in operating ossets and liobilities Accounts receivable (14,275)

(26,045)

(22,463)

Accrued unbilled revenues (6,607) 2,352 30,748 Materio!s and supplies, fuel oil and gas in storage (10,933) 28,217 (48,040)

Prepoyments and other current assets (5,548)

(1,035) 23,752 Accounts poyable and occrued expenses 62,513 34,560 2,345 Class Settlement (20,129)

Accrued taxes 7,351 3,926 (42,187)

Other (17,073)

(37,459)

(19,477)

Net Cosh Provided by Operoting Activities 590,064 520,428 321,058 investing Activities Construction and nuclear fuel expenditures (268,179)

(235,349)

(229,525)

Shoreham post settlement costs (227,658)

(158,432)

(152,675)

Other (1,484)

(3,923) 81 Net Cash Used in investing Activities (497,321)

(397,704)

(382,119)

Fironcing Activities Proceeds from issvonce of long-term ceot 1,659,928 1,532,247 112,319 Redemption of long-term debt (1,344,283)

(1,129,000)

(82,000)

Proceeds from sole of preferred stock 411,373 63,130 Redemption of preferred stock (389,428)

(70,638)

(13,659)

Preferred stock dividends paid (69,923)

(65,838)

(68,046)

Common stock dividends paid (190,477)

(172,584)

(125,192)

Cost of issuing and redeeming securities (166,066)

(88,586)

(1,327)

Other 7,520 3,707 1,598 Net Cosh (Used in) Provided by Financing Activities (81,356) 72,438 (176,307)

Net increase (Decrease) in Cosh and Cash Equivalents 11,387

. $ 195,162

$ (237,368)

Cash and cash equivalents at beginning of year

$ 298,098

$ 102,936

$ 340,304 I

Net increase (decrease) in cash and cash equivalents 11,387 195,162 (237,368)

Cosh and Cosh Equivalents of End of Year

$ 309,485

$ 298,098

$ 102,936 -

Interest poid, before reduction for the allowance for borrowed funds used during construction

$ 424,842

$ 477,240

$ 479,278 Federalincome taxes paid 2,100 1,650 900 Federalincome taxes refunded 1,566 642 23,588 See Notes to FinantiolStatements,

l i

Notos to Financial Statomonts Nrte 1. Summary of Significant Accounting Policies Financial Resource Asset GAAP outhorizes recognition l

of the existence of a regulatory asset when it is probable that 1

Regulation The Company's accounting policies conform o regulator wili permit full recovery of a previously incurred to generolly accepted accounting principles (GAAP) as they cost. Pursuant to the 1989 Settlement, the Company apply to o regulated enterprise. Its occounting records are recorded a regulatory asset known as the Financial Resource maintained in occordance with the Uniform Systems of Asset (FRA), to provide the Company with sufficient cash Accounts prescribed by the Public Service Commission of the flows to assure its financiof recovery. The FRA hos two State of New York (PSC) and the Federal Energ> Regulatory components, the Base Financial Component (BFC) and the Commission (FERC).

Rote Moderation Component (RMC). The Pote Moderation Agreement (RMA), one of the constituent documents of the Utility Plant Additions to and replacements of utility plant 1989 Settlement, provides for the full recovery of the FRA.

are capitalized of original cost, which includes materiol, For a further discussion of the 1989 Settlement and the FRA, labor, overhead and on o!!owance for the cost of funds used see Note 2.

during construction. The cost of renewals and betterments relating to units of property is added to utility plant. The Cash and Cosh Equivalents Cash equivalents are highly cost of property replaced, retired or otherwise disposed ofis liquid investments with maturities of three months or less l

deducted from utility plant and, generally, together with when purchased. The carrying amount opproximates fair dismantling costs less any solvage, is charged to occumulated value because of the short maturity of these investments.

depreciation. The cost of repairs and minor renewols is charged to maintenance expense. Moss properties (such as Unbilled Revenues The Company occrues electric poles, wire and meters) are occounted for on on overage revenues for services rendered to customers but not billed unit cost bosis by year of installation.

of month-end.

Allowance for Funds Used During Construction Effective January 1,1990, the Company odopted the full The Uniform Systems of Accounts defines the allowance for ccm I method for unbilled gas revenues. Previously, funds used during construction (AFC) as the net cost of unbilled gas revenues were recognized only for customers 1

borrowed funds for construction purposes and o reasonable billed on a bi-monthly cycle basis for the month in which they rote of return upon the utility's equity when so used. AFC is were n rm fly n t billed. This change better matches j

nd expenses and provides consistency with the reWnues i

not on item of current cash income. AFC is computed monthly using a rote permitted by FERC on that portion of construc-Company s revenue recognition method for electnc tion work in progress which is not included in the Company's revenues. The cumulative effect of this change at Jonvary 1, w s $11.7 milli n, net f t x effects, r S.10 per shore i

rete base. The overage onnvol AFC rate, without giving effect to compounding, was 9.98%,10.74% ond 11.03% for nd had been included m net income for the year ended the years 1992,1991 and 1990, respectively.

December 31,1990. The effect of this change on income before the cumulative effect of occounting change and on i

Drpreciation The provisions for depreciation esult from

• ' "9 5 ** n si ck for the year ended December 31, the applice; tion of straight-line rates to the original cost, by groups, oi deprecinble properties in service. The rates are determined by oge life studies performed annually on Fuel Cost Adjustments The Company's electric and gas deprecioble properties. Depreciation for electric propert.

toriffs include fuel cost odiustment (FCA) clauses which i

ies rovide for the difference between octual fuel costs and the was equivalent to approximately 3.2%,3.3% and 3.2% of fuelc sts 11 wed in the Company,s base tariff rates (base respective overage deprecioble plant costs for the years 1992,1991 and 1990. Depreciation for gas properties was fuel c sts). The Company defers these odiustments, net of tax cts,1 future peri ds in which they will be billed or e

equivalent to approximately 2.4%,2.9% and 2.8% of respective overoge deprecioble plant costs for the years credited to customers, except for base electric fuel costs,n i

f ctu i electric fuel c sts, which are currently excess 1992,1991 and 1990' credited to the RMC os incurred. The Company collects the higher of actual electric fuel costs or base electric fuel costs, pursuant to the RMA.

0

Effective December 1,1991, the electric rate order discussed in Note 10.The Company defers the benefit of 60% of in Note 3 outhorized the odoption of a partial poss-through pre-1982 gas and pre-1983 electric and 100% of all ether fuel cost incentive plan which includes a mechanism that investment tax credits, with respect to regulated properties, compares, on o monthly basis, the Company's actuoi cost to when realized on its tax returns.

produce electric energy ogainst a forgeted fuel value. The For ratemoking purposes, certain occumulated deferred mcentive measures the Company 5 obility to purchose fuel at federal income taxes are deducted from rate base and the lowest possible cost, to purchase energy economicot!y amortized or otherwise opplied as o reduction (increase)in from other power suppliers and to operate its generating federalincome tax expense in future years. Accumulated plants of optimum efficiency. The shoreowners are allocated deferred investment tax credits are amortized rotably over 40% of the impact between octual fuel costs and targeted the lives of the related properties.

fuel values up to o maximum benefit or penalty of 20 basis points of the allowed return on common equity. The The tax effects of other differences between income for shareowners' portion of these impacts are being deferred financial statement purposes and for federof ir.come tax on a monthly basis. The occumulated net deferrol will be purposes are occounted for os current odiustments in federal recovered or returned, through the FCA, over o twelve-income tax provisions.

month period in the following rate year. For a further The Financial Accounting Standards Board (FASB) Statement discussion of the partial poss-through fuel cost ncentive, of Financial Accounting Standards (SFAS) No.109, see Note 3.

Accounting for income Taxes requires, among other matters, Foir Volues of Financial Instruments The fair values recognition of the amount of current and deferred taxes for the Company's long-term debt and redeemoble preferred Payable or refundable at the date of the financial statements result of all events that have been recognized in the s

stock are based on quoted market prices, where available.

The fair volves for all other long-term debt and redeemable fin nci i st tements and odiustment of deferred income taxes preferred stock are estimated using a discounted cash flow for on enacted change in tax lows. For regulated enterprises, onolyses which is based upon the Company's current SFAS No.109 prohibits net of tax occounting and reporting incremental borrowing rate for similar types of securities.

nd requires recognition of a deferred tax liability for the tax benefits which are flowed through to its customers and the Crpitallrotion-Premiums, Discounts and Expenses equity component of AFC. A regulatory asset or liability will Premiums or discounts and expenses related to the issuance be recognized relating to such items if it is probable that the of long-term debt are amortized over the life of ench issue.

future increase or decrease in taxes payable thereon shall Unomortized premiums or discounts and expenses related to be recovered from or returned to customers through future issues of long-term debt that are refinanced are amortized rates. The Company estimates that had it odopted SFAS and recovered through rates over the shorter life of the No.109 at December 31,1992, the Company would have redeemed or newissues. Capitol stock expense related to recorded on occumulated deferred tax liability and a that portion of preferred stock that is required to be corresponding regulatory asset o opproximately $1.2 r

redeemed is written-off as on odiustment to retained billion. The Compony will odopt SFAS No.109 during the earnings upon redemption unless the preferred stock is first quarter of 1993 and does not expect a materialimpact redeemed below por value. In that cose, any resulting goin, on the Statement of income.

net of the related capitol stock expense, is recorded as additional premium on capitol stock. Capitol stock expense Reserves for Claims, Demoges, Pensions and redemption costs related to certoin issues of preferred and Benefits Losses crising from claims against the stock that have been refinanced as well as the cost of Company are partially self-insured. Extraordinary storm issuance of the preferred stock issued are recorded as

- losses are partially self-insured up to $5 million until March 1, deferred charges. These amounts are being amortized and 1993, at which time the Company will bear a greater portion recovered through rates over the shorter life of the of these costs. Amounts provided are credited to the reserves l

redeemed or new issues, based upon experience, risk of loss, octuarial estimates and/or specific orders of the PSC.

i Federal income Taxes The Company provides deferred federal income taxes with respect to certain differences Reclassifications Certain prior year amounts have been between net income before income taxes and taxable income reclassified in the financial statements to be consistent with in certain instances when opproved by the PSC, os disdosed the current year's presentation.

O

N:te 2. The 1989 Settlement energy conservation and load mone y ment program costs, costs to provide added efed.i. system reliability On February 28,1989, the Company and the State of New and inflotion.

resolv;oy its Governor) entered into the 1989 Settlement York (

The RMC balance, which wo 3652 million and $602 million ing certain issues relating to the Company and at December 31,1992 and 1991, respectively, has increased providing, among other matters, for the transfer of the os the difference between revenues resulting from the Shoreham Nuclear Power Station (Shoreham) and its implementation of the rate moderation plan provided for in subsequent decommissioning. On February 29,1992, the the RMA and revenue requirements under conventional Company transferred ownership of Shorehom to the Long rotemokina together with a carrying charge equal to the Island Power Authority (LIPA), on ogency of the State of

~

allowed rcte of return on rate base, has been deferred. The New York. Pursuant to the 1989 Settlement, LIPA is RMC balonce will subsequently decrease and is expected to responsible for the decommesponing of Shoreham and has be fully amortized by November 30,1999, as deferred estimated that the decommissioning, in which Company revenue requirements are recovered.

employees are porticipating, will be completed in 1994.

The PSC opproved the Long Island Lighting Company The 1989 Settlement recites the. tention of the parties that in Rotemaking and Performance Plan (LRPP), discussed in the Company shall be returned to investment grade finonaol Note 3, effective for each of the three rate years in the condition and that the Company and the State of New York eriod beginning December 1,1991. Although the LRPP onticipate that the PSC shali ensure that the future impacts on provides for slightly lower annual electric rate increases than rates are to be minimized to the maximum extent procticable, originally onticipated in the 1989 Settlement, the Company it is the Company s position that these obgectives will continue believes that it will still fully recover the RMC over the ten-to be oieved, in port, through the continued receipt of year period principally as a result of changes in the original odequate and t,mely rate relief.

i ossumptions. The revenues assumed by the LRPP ore Upon the effectiveness of the 1989 Settlement, the Company odequate to provide the Company with recovery of its simultaneously recorded on its Bolonce Sheet the retirement revenue requirements under conventional rotemoking and of its investment of opproximately $4.2 billion in Shoreham recovery of the RMC bolonce over the remainder of the and Bokum Resources Corporation (Bokum) and the ten-year period. However, octual revenues may differ from establishment of the FRA.

those assumed for this period. The original ossumptions underlying the RMA included projections of future revenues, The BFC, o component of the FRA, as initially established, operating expenses and required rotes of return. Since then, represents the present value of the future net-after.tox cash the Company has experienced interest rates, non-Shorehom flows which the RMA provided the Company for its financial property taxes and fuel expenses that are lower than those recovery. The BFC was granted rate base treatment under originally anticipated. As o result, amounts deferred in the i

the terms of the RMA and is included in the Company's RMC have been less than expected. In oddition, os a result of revenue requirements through on amortization included in the Company's improved credit rotings and on overall rates over forty years on a straight-line basis beginning decline in the cost of money in the financial marketplace, the July 1,1989. At December 31,1992 and 1991, the PSC provided the Company in the LRPP with a lower rote of unomortized bolome of the BFC was opproximately $3.7 return on common equity than that initially provided for in billion and $3.8 bimon, respectively.

the RMA. This lower rote of return, which will be in effect for the three years associated with the LRPP, results in a lower The RMC, o component of the FRA, reflects the difference RMC balance than had been anticipated in the 1989 between the Company's revenue requirements under Settlement.

conventional rotemaking and the revenues resulting from the implementation of the rate moderotion plon provided for in Under the 1989 Settlement, cericin tax benefits attributoble the RMA. The RMC, which has provided the Company with a to the Shoreham obandonment are to be shared between i

substantial amount of non-cosh earnings over the lost several rotepayers and shoreewners. A regulatory liability of years, is based upon forecosted dato filed in connection with approximately $794 million was recorded in June 1989 to the RMA. The RMA was designed to provide rote increases preserve on amount equivalent to the rotepayer tax benefits sufficient to recover ths. RMC within a ten-year period. The attributable to the Shoreham abandonment. This amount is RMC is currently odiusted, on a monthly basis, for the being omortized over o ten-year period on a straight-line Company's shore of certain Nine Mile Point Nuclear Power basis from the effective dote of the 1989 Settlement. The tax Station, Unit 2 (NMP2) operations and maintenance benefit orising from the abandonment loss deduction has expenses, fuel credits resulting from the Company's electric been offset against the corresponding regulatory liability in fuel cost odjustment clouse discussed in Note 1 and state the Company's Bolonce Sheet. This tax benefit could not gross receipts tax odiustments related to the FRA. Prior to have been fully recognized under GAAP were it not for the December 1,1991, the RMC was odiusted to reflect octual f act that its recovery is ossured under the 1989 Settlement property taxes, cost of osbestos removol, interest expense, through the regulatory liobility offset.

i O

Shorehom post settlement costs (decommissioning, payments Revenue reconciliation is provided 'hrough a mechonism that in lieu of property taxes and other costs os incurred) are reduces the impact of experiencing electric sales that are being capitalized and amortized and recovered through obove or below the LRPP forecast by providing a fixed rotes over a forty-year period on a straight-line remaining annual net margin level (defined as sales revenues, net of hfe basis.

fuel and gross receipts taxes) that the Company will receive over the three rote years under the LRPP. The differences Upon the effectiveness of the 1989 Settlement, Shore, om between the octual electric net revenues and the annual n

nuclear fuel was reclassified to deferred charges and is be.ing net margin level are deferred on a monthly basis during amortized and recovered through rotes over o forty-year gg period on a stroight-line remaining life basis.

The expense attrition and reconciliation component permits The 1989 Settlement credits on the Bolonce Sheet of the Company to make adjustments for certain expenses approximately $164 million, net of amortization, reflect on recognizing that certain cost increases are unavoidable due odiustment of the book write-off to the negotiated 1989 to inflation and changes in the business. The LRPP includes Settlement omount. A portion of this amount is being the annual reconciliation of certain expenses for woge rates, amortized over o ten-year period. The remaining portion is property taxes, interest charges and demand side not currently being recognized for rotemoking purposes management (DSM) costs, the deferrol and omortization under the 1989 Settlement.

of certain costs for enhanced reliability and operations and maintenance expenses, and the opplication of on inflation Note 3. Rote Matters index to other expenses for the rote years beginning December l,1992 and 1993.

Eloctric Pursuant to the 1989 Settlement, discussed.in Note 2, the Company received electric rote increases The deferred botonces resulting from the net margin, 1

contemptoted by the RMA for each of the three rate years property taxes, interest expense and wage rotes will be in the period ended November 30,1991. The RMA netted at the end of each rate year. The LRPP established a contemplates that the Company will opply to the PSC for band whereby the first $15 million of the total net deferrals torgeted annual rate increases of 4.5% to 5.0% in each year will be used to increase or decrease the RMC bolonce. The for on eight-year period beginning December 1,1991. In LRPP provides for the disposition of the foto! net deferrois in response to the Company's rote filing, the PSC approved the excess of the $15 million band. The total net deferrois in LRPP in November 1991, which provides that the Company excess of $15 million wi!I be refunded to or recovered from receive, for each of the three rote years in the period the rotepayers in the following twelve-month period beginning December 1,1991, onnual electric rate increases beginning in the second quarter of each year. For the rate of 4.15%,4.1% and 4.0%, respectively, with on allowed year ended November 30,1992, the total net deferrois in return on common equity from electric operations of 11.6%

excess of $15 million, to be recovered from the ratepayers, for each of the three rate years. After giving effect to the amounted to opproximately $29.5 million.

reductions required by the Class Settlement discussed in Note 4, the Company's annual electric rate increases are Under the performance incentive component of the LRPP, opproximately 4.15%, 3.9% ond 3.9%, with on allowed the Cornpony is oflowed to earn for each rote year up to return on common equity from electric operations of 60 odditional bas,is points, or forfeit up to 38 basis points, 10.92%,10.72% and 10.58%, for the rate years beginning I the allowed return on common equity as a result of its December 1,1991,1992 and 1993, respectively.

Performance within certain incentive and/or penolfy programs. These progroms consist of a customer service The LRPP was designed to be consistent with the RMA's long-performance plan, o DSM program, o time-of-use term goals including: (o) the recovery of the BFC; (b) the program and a portial poss-through fuel cost incentive recovery of the RMC in opproximately ten years; (c) the plan, discussed in Note 1. The incentives and/or penotties Company's return to investment grade financial condition; related to the customer service performance plan and and (d) the Company's receipt of odequate and timely rate the time-of-use program are determined on a monthly relief. One principal objective of the LRPP is to reassign risk basis during the rate year. The total amounts deferred so that the Company assumes the responsibility for risks of the end of each rate year will be refunded to or within the controf of management, whereas risks largely recovered from the ratepoyers through the FCA in the i

beyond the control of management would be assumed by the following twelve-month period beginning in the second rotepayers. The LRPP reflects on update of the long-ronge quarter of each year. The incentives earned from the forecast of the Company's revenue requirements, which was DSM program are collected in rates, on a monthly basis, the basis of the RMA's initial three rate increases. The LRPP through the FCA. For the rote year ended November 30, contains three major components-revenue reconciliation, 1992, the Company earned a total of opproximately 23 expense attrition and reconciliation, and performance basis points, or $4.3 million, net of tax effects, based upon incentives.

its performance within these progroms.

0

)

1 For the rate year ended November 30,1992, the Company Note 4.The Class Settlement earned $16.2 million, net of tax effects, in excess of its allowed rate of return on common equity which, in The Class Settlement, which become effective on June 28, accordance with the LRPP, was shared equally between 1989, resolved o civil lawsuit ogoinst the Company brought ratepayers (by o reduction to the RMC) and shoreowners.

under the federal Rocketeer influenced and Corrupt These excess earnings were generoted os a result of a Organizations Act (RICO Act). The lawsuit which the Class reduction in operating expenses and the effect of a decrease Settlement resolved had alleged that the Company mode in capitol expenditures included in rate base. Prior to inadequate disclosures before the PSC concerning the December 1,1991, the RMA provided that earned returns construction and completion of nudear generating facilities.

on common equity in excess of targeted allowed rates of The Class Settlement provides the Company's ratepoyers return, os odbsted, were to be opplied to reduce the RMC with reductions, oggregating $390 million, that are to be or mitigate rates, as determined by the PSC, et the end of reflected as odiustments to their monthly electric bills over o each rate year. For the rate year ended November 30,1991, ten. year period beginning June 1,1990. The reductions the Company earned $10.1 million, net of tax effects, in required for the first three years have ciready been reflected excess of its allowed rote of return, which was applied in rates. The reductions in each subsequent twelve-month as a reduction to the RMC. The Company did not earn in period are os follows:

excess of its allowed rote of return for the rate year ended June 1993

$30 million November 30,1990.

June 1994

$30 million To assist in recovering the RMC within o ten-year period June 1995

$40 mi!Iion under the rates provided by the LRPP, the Company, in June 1996

$50 million occordance with the LRPP, hos credited the RMC with several June 1997

$60 million deferred rotepayer benefits. In December 1992, the June 1998

$60 million Company applied a total of approximately $22.5 million of June 1999

$60 million various deferred rotepayer benefits to the RMC including the Upon its effectiveness, the Company recorded its liabil;ty for rotepayers portion of the excess earnings for the rate year the Class Settlement on a present value basis at $170 million ended November 30,1992. In December 1991, the nd s.imult ne usly rec rded a charge to income (net of tax Company applied approximately $57.6 million of previously effects f $57 million) of approximately $113 million. Eoch deferred credits and related carrying charges for omounts m nth the Company records the changes in the present value collected in excess of octual fuel costs and other f such liability that result from the passage of time and from miscellaneous deferred credits os a reduction to the RMC.

monthly reductions. Because the reductions of the liobility are gre ter n the later years, the current present value Gcs in November 1992, the PSC approved a gas rate c Ic 6 ns resu nm sein t t bility despite the increase of 7.1%, or $35.7 million annually, which become reductions m the total amount due. Beginning sometime in 5

effective on December 1,1992. The gas rote decision provides for on 11.0% allowed return on common equity 3, Se amoqnt o% total remaining Class Settlement yw.

gin t decrease os the monthly reductions of for the rate year beginning December 1,1992.

the liability exceed the incremental increases in the present On December 31,1992, the Company filed on application value. The Company expects the Class Settlement liability will with the PSC seeking gas rote relief for the three rate years in be fully satisfied by May 31,2000.

the period beginning December 1,1993. The Company hos As a result of the Class Settlement, the Company's electric requested a gas rate increase of 6.7%, or $37.7 million in rate increases on overage will be opproximately.2% to.3%

odditional revenues to become effective for the first rote per ye r I wer then they would otherwise have been dun.ng year under this filing. The Company's filing also includes o the balonce of the Class Settlement period. The amounts proposed methodology for determining rate increases, rec rded on the Statement of income for 1992,1991 and not to exceed approximately $30 million annually, for the ppr xim tely $23 million, $25 million and $23 subsequent second and third rote years. This filing reflects n, resPectively, represent the increase in present value m

the Company's latest projections of capitol expenditures, of the Class Settlement liability.

operations and maintenance expenses and the cont.inued i

exponsion of its gos business.

i l

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Nste 5. Nine Mile Point Nuclear Power Station, of a qualified fund under opplicable provisions of the federal Unit 2 income tax tow. This IRS ruling allows the Company's contributions to the decommissioning trust to be deductible The Company hos on 18% undivided interest in NMP2 which for income tax purposes for the tax year in which they is operated by Niogoro Mohawk Power Corporation ore mode.

(NMPC) near Oswego, New York. Ownership of NMP2 is shared by five cotenants: the Company (18%), NMPC Note 6. Copitol Stock (41%), New York State Electric & Gas Corporation (18%),

Rochester Ges and Electric Corporation (14%) and Centrol Preferred Stock Redemption of certain series of Hudson Gas & Electric Corporation (9%). At December 31, preferred stock is effected through the operation of various 1992, the Company's net utility plant investment in NMP2 sinking fund provisions. The oggregate por value of was S776 million, net of occumulated depreciation of $97 preferred stock required to be redeemed in each of the years million, which is included in the Company's rate base. Output 1993 through 1996 is $8.2 million and in 1997 is $4.5 million.

of NMP2, which had on operating copobility of 1,080 Dividends on preferred stock are paid in preference to l

megawatts in 1992, is shared in the some proportions os the dividends on common stock or any other stock ranking junior l

l cotenants' respective ownership interests. NMPC hos to preferred stock.

I determined that the operating capability of NMP2, effective January 1,1993, is 1,047 megawatts. The operating Preference Stock None of the authorized 7,500,000 l

expenses of NMP2 are otso allocated to the cotenants in the shores of nonporticipating preference stock, por value $1 per i

some proportions os their respective ownership interests. The shore, which ranks junior to preferred stock, are outstanding.

j Company's shore of these expenses is included in the oppropriate operating expenses on the Statement of Income.

Common Stock Of the 150,000,000 shores of authorized The Company is required to provide its respective shore of common stock at December 31,1992,1,834,289 shores i

financing for any capitol odditions to NMP2. Nuclear fuel were reserved for sole through the Company's Employee costs ossociated with NMP2 ore being amortized on the basis Stock Purchase Plon,6,620,755 shores were committed to of the quantity of heat produced for the generation of the Automatic Dividend Reinvestment Plan (ADRP) and electricity.

132,694 shores were reserved for conversion of the Series I Convertible Preferred Stock at a rate of $17.15 per shore. In NMPC hos contracted with the United States Department June 1992, the Company reinstated the ADRP which had of Energy for the disposal of nudeor fuel The Company q

84. Common and reimburses NMPC for its 18% shore of the cost under the en wsp s

e 7

preferred stock dividend limitohons,in the mortgage securing

[

contract at a rate of $1.00 per megawatt hour of net genero.

the Company's First Mortgoge Bonds are not matenot. There tion less a factor to occount for transmission line losses.

are no dividend limitations contained in the Company,s other Based upon a study performed by NMPC, the Company's debt instruments.

shore of the decommissioning costs for NMP2 is estimated to be $37 million (in 1989 dollars) ossuming that decom-Note 7. Long-Term Debt missioning will commence in 2027 or $237 million (in 2027 dollars). The Company's shore of estimated decommissioning Each of the Company's outstonding mortgages is o tien on costs are being provided for in electric rates and are being substantially all of the Company's properties.

chorged to operations as depreciation expense. The amount of occumulated decommissioning costs collected from the First Mortgoge All of the bonds issued under the First Company's rotepayers through December 31,1992 was Mortgage, including those issued offer. lune 1,1975 and

}

$5.4 million. Amounts collected by the Company for the pledged with the Trustee of the G&R Morigoge (G&R decommissioning of the contaminated portion of the NMP2 Trustee) os additional security for General and Refunding plant, which approximate 84% of total decommissioning Bonds (G&R Bonds), are secured by the lien of the First s

costs, are held in on independent decommissioning trust Mortgage. First Mortgage Bonds pledged with the G&R fund. This fund complies with regulationr issued by the Trustee do not represent outstanding indebtedness of the Nuclear Regulatory Commission (N RC) governing the Company. Amounts of such pledged bonds outstanding were funding of nuclear plant decommissioning costs. The

$1.03 billion and $957 million at December 31,1992 and Company's funding plan for its shore of decommissioning 1991, respectively. The annual First Mortgage depreciation costs will provide reasonable assurance that, at the time fund and sinking fund requirements for 1992, due not later of termination of operation, odequate funds for the than June 30,1993, are estimated at $194 million and $18 decommissioning of the Company's shore of the million, respectively. The Company expects to meet these i

contaminated portion of NMP2 plant will be available.

requirements with property odditions and retired First l'

The Internal Revenue Service (IRS) has ruled that the Mortgoge Bonds.

Company's decommissioning trust meets the requirements G

G&R Mortgoge The lien of the G&R Mortgage is one-year periods upon the acceptance by the lending banks subordinate to the lien of the First Mortgage. The annual of the Company's request delivered to the lending banks G&R Mortgage sinking fund requirement for 1992, prior to April 1 in each year.

due not loter than June 30,1993, is estimated at $27 million.

The Company expects to satisfy this requirement with retired Debentures On January 19,1993, the Company issued G&R Bonds.

$36 million principal amount of Debentures,7.30% Series Due 2000. The net proceeds from the issuance of these Third Mortgagel1989 Term Loon Agreement in debentures will be used in February 1993 to redeem, at the November 1992, the Company used the net proceeds from opplicable redemption price, $35 million principol amount of the issuance of $451 million principal amount of debentures First Mortgage Bonds,8.20% Series R Due 1999.

to repoy the then outstanding 1989 Term Loon Agreement which had been secured by the Third Mortgage. The Third.

Authority Financing Notes Authority Financing Notes Mortgage hos been dischorged as a result of the repayment are issued by the Company to the New York State Energy of the 1989 Term Loon Agreement.

Research and Development Authority (NYSERDA) to secure certain tax-exempt Pollution Control Revenue Bonds, Electric F:urth Mortgoge in December 1992, the Company Focilities Revenue Bonds (EFRBs) and industrial Development satisfied the Fourth Mortgoge which had secured $85 million Revenue Bonds issued by NYSERDA. Certain of these bonds of the Company's obligations under the letters of credit are subject to periodic tender at which time their interest then supporting the 1985 Pollution Control Revenue Bonds rates are subject to redetermination.

ns u dee of credi s ssed below nde he ad ng fnJune fro a vari I e k y ntere t ro oofxed Authority Financing Notes.

annual rate of 7.15% and $100 million of EFRBs that were IC89 Revolving Credit Agreement The Company has c nyerted n J nu ry 1993 from o variable weeklyinterest r tei fixed annual rate of 6.90%. Letters of credit on estimated $251 million available to it through October 1' 1993, under its $300 million 1989 Revolving Credit Agree.

Supporting these EFRBs, by their terms, were termmated ment (1989 RCA). This line of credit is secured by a first lien UPon the conversion to o fixed interest rate.

upon the Company's accounts receivable and fuel oil The 1985 PCRBs are supported by letters of credit pursuont inventories.

to which the letter of credit bank has agreed to pay the The Company has, with the opproval of the NRC, dedicated frinciP I, interest and premium on the tendered 1985 PCRBs,

• 9@'9 '*' UP o CPproximately $163 milhon m the t

$49 million of the 1989 RCA sufficient to cover estimated, not i

yet incurred, costs attributoble to the decommissioning of event of default.The obligation of the Company to reimburse the letter of credit bank is unsecured. These letters of credit Shorehom. As of December 31,1992, LIPA was projecting, based on current information, that the Shoreham decommis-expire n March 16,1996, of which time the Company is sioning costs would total $160 million. The Company has requ red i btom e,ither on extension of the letters of credit provided LIPA with funds oggregating opproximately r substitute credit bockup. If neither con be obto ned, the

$111 million for decommissioning costs incurred to date 1985 PCRBs must be redeemed unless the Company and for decommissioning costs expected to be incurred Purchases the 1985 PCRBs in lieu of redemption and during the first quarter of 1993. Actual decommissioning subsequently remarkets them. Pnor to December 16,1992, costs may differ from LIPA's current estimate. The amount theletters of credit supporting the 1985 PCRBs were partially of credit ovailable to the Company under the 1989 RCA

. cured by the Fourth Mortgage m the amount of $85 will increase os decommissioning costs are funded by the Company.

N M

Th% ed At December 31, "

amounts were outstanding under and fair values of the Company's long. term debt consisted of the 1989 RCA. r

~ ny has the option, when amounts the following at December 31,1992:

cre outstanding,..

nmit to one of three interest rates

~

including: (a) the Adjusted Certificate of Deposit Rote which is U" * "' "* * #

• o rate based on the certificote of deposit rates of certain of fair Carrying the lending banks, (b) the Base Rote which is generally a rote based on Citibank, N.A.'s prime rote and (c) the Eurodollar First Mortgage Bonds

$ 397,971 $ 400,000 Rote which is a rate based on the London interbank Offering General and Refunding Bonds 1,891,842 1,801,000 Rote (LIBOR). The Compony has agreed to pay a fee of one Debentures 2,523,721 2,428,058 quarter of one percent per annum on the unused portion.

Authority Financing Notes 729,610

_716,675 The termination date of the 1989 RCA may be extended for Toto! Long. Term Debt

$5,543,144 $ 5,345,733 l

l O

(in thousands of dollars)

Long-Term Debt et December 31 Matunty Interest Rote Series 1992 1991 First Mortgage Bonds (excludes Pledged sands)

April l,1993 4.40 %

M 40,000 40,000 June 1,1994 45/8%

N 25,000 25,000 June 1,1995 4.55 %

O 25,000 25,000' March 1,1996 51/4%

P 40,000 40,000 April 1,1997 51/2%

O 35,000 35,000 l

September 1,1999 8.20%

R 35,000 35,000 Septembe-1, 2000 91/8%

S 25,000 April 1,2001 71/4%

U 40,000 40,000.

December 1,2001 71/2%

V 50,000 50,000 i

September 1,2002 75/8%

W FA,000 -

50,000 l

December 1,2003 81/8%

X 60,000 60,000 Total First Mortgage Bonds 400,000 425,000 f

Ocneral and Refunding Bonds May 1,1996 83/4%

415,000 415,000 February 15,1997 83/4%

250,000 250,000 March 1,1999 9.75 %

63,000 May 15,1999 7.85 %

56,000 May 15,2006 8.50 %

75,000 June 1,2006 95/8%

70,000 December 1,2006 85/8%

50,000 50,000

'i May 1,2007 85/8%

85,000 85,000 April 1,2008 9.20%

75,000 July 15,2008 7.90%

B0,000 May 1,2021 93/4%

415,000 415,000 July 1,2024 95/8%

375,000 375,000 Total General and Refunding Bonds 1,801,000 1,798,000 f

Third Mortgagel1989 Term Loan Agreement 446,341 i

D bentures April 1,1993 11 3/8 %

375,000 375,000 November 15,1993 11.70 %

175,000 175,000 June 15,1994 10,25 %

400,000 400,000 l

November 15,1994 11.75 %

175,000 175,000 June 15,1999 10.875 %

30,545 350,000 July 15,1999 7.30 %

397,000 t

June 15,2019 11.375 %

4,513 350,000 July 15,2019 8.90 %

420,000 November 1,2022 9%

451,000 Total Debentures 2,428,058 1,825,000 i

i Authority Financing Notes l

Pollution Control Revenue Bonds l

December 1,2006 7.5%

1976 A 28,375 28,375 l

December 1,2009 7.8%

1979B 19,100 19,100 October 1,2012 81I4%*

1982 17,200 17,200 March l,2016 4%"

1985 A,B 150,000 150,000 Electric Facilities Revenue Bonds September 1,2019 7.15 %

1989 A,B 100,000 100,000

?

June 1,2020 7.15%

1990A 100,000 100,000 December 1,2020 7.15 %

1991 A 100,000-100,000 February 1,2022 7.15 %

1992 A,B 100,000

[

August 1,2022 3.95%'"

1992 C 50,000 August 1,2022 4%"

• 1992D 50,000 industrial Development Revenue Bonds December 1,2006 7.5%

1976 A,B 2,000 2,000 Total Authority Financing Notes 716,675 516,675 Total Long-Term Debt 5,345,733 5,011,016 Less - Current motorities 590,000-10,000 l

Total Long-Term Debt less Current Maturities

$4,755,733

$5,001,016

{

' Tendered every three years. next tender October 1994.

' Tendered annuony on March 1.

[

Converted to a fixed annualrote of 6.90% from o variable weekly rate on January 21,1993.

_Q i

Long-term debt due in the neut five years is $590,000 (l993), S600,000 (1994), $25,000 (l 995), S455,000 (1996) and $286,000 (1997).'

f f

Note 8. Retirement Benefit Plans Periodic pension cost for 1992,1991 and 1990 for the Primary Plan included the following components:

Pansion P!.ns The Company maintains a primary U" *""d' W

defined benefit pension p!an (Primary Plan) which covers IM I#

I" substantioil o!! employees, o supplemental plan y

(Supplementol Plon) which covers officers and certain key Service cost-benefits executives and a retirement plan which covers the Board earned during the period $ 13,661 $ 14,323 $ 12,720 of Directors (Directors' Plan).

Interest cost on projected benefit obligation and Primary Plan The Company's funding policy is to contribute service cost 39,574 33,698 32,264 annually to the Primary Plan a minimum amount consistent Actual return on pion ossets (47,156) (63,875) (23,121) with the requirements of the Employee Retirement income Net amortization and deferrol 12,849 33,569 (5,449)

Security Act of 1974 (ERISA) plus such additional amounts,if ony, os the Company may determine to be oppropriate from Net periodic pens. ion cost

$ 18,928 $ 17,715 $ 16,414

'i** I

'I**

• Assumptions used in accounting for the Primary Plan were:

For service before January 1,1992, pension benefits are determined based on the greater of an occrued benefit os lo92 1997 1990 of December 31,1991, or opplying a moving five-year Discount rote 7.75 %

7.75 % 7.25 %

overage to o certain percentage per year of service. For Rote of future compensation service offer January 1,1992, pension benefits are increases 5.5%

5.5%

6.0%

established by crediting the employee with on omount long-term rote of return on determined using the base sofory for each year the employee ossets 7.5%

7.0%

7.0%

is a participant in the plan. This change in the pension benefits calculation resulted in on increase of opproximately The Primary Plan ossets at fair value primarily include cash,

$70 million in the octuaric ' present value of projected benefit cosh equivalents, group onnuity contracts, bonds and listed obligation. Employees are vested in the pension plan offer equity securities.

five years of service with the Company.

SupplementoIPlan The Supplemental Plon, the cost of The Primary Plan's funded status and amounts recognized on which is borne by the Company's shareowners, provides the Bolonce Sheet of December 31,1992 and 1991 were os supplemental death and retirement benefits for officers foIIC)*M and other key executives without contribution from such employees. The Supplemental Plan is a non-qualified plon pn thousands of do!1 ors) under the Internal Revenue Code. Death benefits are 1992 1991 currently provided by insurance. The provision for retirement Actuonal present value of benefit benefits, which is unfunded, totoled opproximately $685,000, 1

bligation

$675,000 ond $561,000 and was recognized as on expense Vested benefits S 453,201 $ 375,326 in 1992,1991 and 1990, respectively.

Nonvested benefits 4,326 5,315 Accumulated benefit obligotion

$ 457,527 $ 380,641 Grect rs' Plan The Directors' Plon, odopted in February 1990, provides benefits to directors who are not officers of the Company. Direc' ors who have served in that capacity for Plan ossets et fair value

$ 556,399 $ 519,816 more than five years qualify os participonts under the plan.

Actuonal present volve of The Directors' Plan is a non-qualified plan under the internal projected benefit obljgotion __ _ 536,818 _ 446,718 Revenue Code. The provision for retirement benefits, which Woiected benefit obligation is unfunded, totaled opproximately $133,000, $101,000 less than plan assets 19,581 73,098 and $99,000 and was recognized as on expense in 1992, Unrecognized January 1, 1991 and 1990, respectively.

j net obligations 98,147 33,113 Unrecognized net gain (128,218) (114,389)

Net occrued pension cost

$ (10,490) $ (8,178)

O

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Postretirement Benefits Other Then Pensions in condition and results of operations. The Company believes it i

addition to providin0 Pension benefits, the Company provides will be permitted to recover these costs through rates. The certain medical and life insurance benefits for retired employ.

Company must adopt SFAS No.112 by January 1,1994, i

ees. Substantially oil of the Company's employees may and does not expect to do so prior to that dote.

l become eligible for these benefits if they reach retirement oge i

ofter working for the Company for o minimum of five years.

Note 9. Commitments and Contingencies i

These and similar benefits for active employees are provided i

by the Company or by insurance companies whose premiums Litigation On February 11,1988, the Company began o cre based on the benefits paid during the year. The cost of lawsuit in Suffolk County Supreme Court ogoinst Suffolk providing these benefits on a pay-as-you-go method was County, seeking the recovery of approximately $54 million

$38,044,000, $37,312,000 and $29,410,000 for 1992, in domoges for Suffolk County's breach of a controct to 1991 and 1990, respectively, and were recognized as on prepare on offsite emergency response plan for Shoreham expense os benefits and premiums were paid. The cost of (long Island Lighting Company v. County of Suffolk). in providing these benefits for opproximately 2,200 retirees addition, the complaint olleges that, because of the delays is not separable from the cost of providing benefits for that have resulted, the Company hos been domoged in on opproximately 6,200 octive employees for the years 1990 odditional amount of $706 million. On October 30,1992, I

through 1992.

the court granted in part and denied in part Suffolk County's In December 1990, the FASBissued SFAS No.106, cwnterci m. Two proposed counterclaims were allowed Employers' Accounting for Postretirement Benefits Other

• • • "9 PProximately $16 milhon m domoges os well os Than Pensions which requires the Company to recognize the

$700 milhon n olleged punitive domoges. The outcome of expected cost of providing postretirement benefits when employee services are rendered rather than on a pay-as-b''""Y "d'E i

n the financial con it. ion of the Company. The Company hos you-go method, orgued that there is no basis for punitive domoges and The Company will adopt the provisions of SFAS No.106 intends to vigorously prosecute its claim ogainst Suffolk during the first quarter of 1993 and record on occumulated County and to defend against these counterclaims.

postretirement benefit obligation and a corresponding regulo-tory asset of opproximately $376 million. This regulatory Commitments The Company hos entered into substantial osset will be amortized and recovered in rates over o twenty-commitments for fossil fuel, gas supply, purchased power year period. Additionolly, os o result of odopting SFAS No.

and transmission facilities. The costs associated with these i

106, the Company's annual postretirement benefit expense commitments are normally recovered from rotepayers i

l willincrease approximately $44 million obove the amount through provisions in the Company's rate schedules.

previously recorded under the pay-os-you-go method.

Nuclear Plant insurance The Compony has property In 1992, the PSC stoff issued a proposed generic occounting d m geinsur nce nd third-porty bodily, injury and property order which proposes that the effects of implementing SFAS nsur nce r as shom in NMP2 and for i

No.106 be phased into rates. The PSC proposes that the Shorehem. The premiums for this coverage are not maten,al.

difference between the postretirement benefit expense The pohaes for this coverage provide for retroactwe recorded for accounting purposes in accordance with SFAS ssessments under certoin circumstances. Max,imum premium No.106 and the postretirement benefit expense reflected in retr ctive premium ssessments c uld be os much as

{

rates will be deferred and occumulated as a regulatory asset.

pProximately $4.7 million. For property demoge at each The ongoing annual postretirement benefit expense will be "d * ' 9 * "* *'*9 ** "

9"E**

• I"I*""

f phased into and fully reflected in rates within o five-year

" '"** 9 *

'*h

• l period with the occumulated postretirement obligotion being with a portial exemption from these requirements for recovered in rates over a twenty-year period.

Shorehom.

in November 1992, the FASB issued SFAS No.112, Under certain circumstances, the Company may be ossessed l

Employer's Accounting for Postemployment Benefits. SFAS odditional amounts in the event of a nudeor incident. Under I

l No.112 establishes occounting stondords for employers wh ogreements established pursuont to the Price Anderson Act, provide benefits to former or inoctive employees offer the Company could be assessed up to opproximately $74

[

employment but before retirement. SFAS No.112 requires million per nudear incident in any one year at any nuclear employers to recognize the c.bligation to provide unit, but not in excess of opproximately $12 million in postemployment benefits if the following conditions are met:

payments per year for each incident. The Price Anderson Act the obligation is attributable to employees services ofready also limits liability for third-party bodily injury and third-party rendered, employee nghts to those benefits are occumulated roperty domoge crising out of a nuclear occurrence at each or vested, p;iyment is probable and the amount of the benefit unit to $7.4 billion.

is reasonably estimated. The Company hos not yet evoluoted the effect of implementing SFAS No.112 on its financial ve p

g e y

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Nrte 10. Federollncome Taxes The amount of investment tax credit (lTC) carryforward for financial statement purposes offer 1992 is opproximately On April 17,1989, the Company received a private letter

$206 million. The Revenue Agents have proposed ITC ruling from the IRS which stated that the Company would be adjustments which, if sustoined, would reduce the Company's entitled, for federalincome tax purposes, to on abandon.

carryforward by opproximately $96 million. These credits ment loss deduction in connection with Shoreham, upon expire by the year 2002. In occordance with the Tax Reform effectiveness of the 1989 Settlement. The Company claimed Act of 1986 (TRA 86), ITC o!!owable os credits to tax returr:s on abandonment loss deduction on its 1989 federal income for years offer 1987 must be reduced by 35% The amount of tax return of opproximately $1.8 billion. The Company's net the reduction will not be allowed as a credit for any other operating loss carryforward is estimated to be opproximately toxoble yeor.

$2.3 billion at December 31,1992.

The Company hos not provided deferred taxes on opproxi-On January 8,1990 ond October 10,1992, the Company motely $500 million of various other deductions and received Revenue Agents' Reports disallowing certain depreciation method differences for property placed in deductions claimed by the Company on its tax returns for the service prior to 1981 which, in conformity with the audit cycle years 1984-1987 and 1988-1989, respectively.

rotemoking practices of the PSC, have been flowed through.

The Revenue Agents' Reports reflects proposed adjustments These various other flow-through tax deductions, which were to the Company's federat income tax returns for 1984 deductible currently for tax purposes but capitalized for through 1909 which, if sustained, would give rise to tax occounting and rotemoking purposes, include certain taxes, deficiencies totaling opproximately $220 million. The o portion of AFC, pensions and certain other employee Company is protesting some of the odiustments and seeks on benefits. See Note I with respect to o change in the method odministrative ond, if necessory, o judicial review of the of occounting for income taxes which the Company will conclusions reoched in the Revenue Agents' Reports.The adopt during the first quarter of 1993.

Company connot predict either the timing or the manner in which this matter will be resolved. If, however, the ultimate disposition of any or oil motters raised in the Revenue Agents' Reports are adverse to the Company, the Company expects that any deficiencies that may orise will be substantially offset by the net operating loss carrybacks associated with the Shoreham obandonment loss deduction and thus any impact would not have o material effect on the Company's financial condition or cash flows.

1 1

I O

I The federal income tax omounts included in the Statement of income differ from the amounts which result from opplying the statutory federalincome tax rate to net income before income taxes. The table below sets forth the reasons for such differences.

(In thousands of dollars).

1992 1991 t990

% of

% of

% of Amount n

Amount n Amount ' nc Fedsrolincome tax, per Statement of Income Current 530-S 515 3,638 Deferred and other (see Note 1) 1989 Settlement Shoreham property 3,806 10,677 3,239 Bokum Resources Corporation 20,400 Rote moderation component 10,351 ~

77,715 101,053 i

Other 1989 Settlement items (5,499)

(13,638).

(13,577) l Shoreham post settlement costs 60,125 50,375 61,475 l

Contractor litigation settlement (18,758)

Class Settlement (1,190)

(2,038)

(534)

Interest capitalized (2,100)

(2,562)

(3,220)

Mortgage recording tax (222) 4,653 (589)

Accelerated tax depreciation 35,951 30,447 33,342 Call premiums 35,441 18,496 (3,111)

Fuel cost odiustments 8,747

. (3,289) 4,879 Capitolized overheads 180 2,287 Retired debt costs 2,645 9,185 Rotemoking and performance plan 17,680 (371)

Lien date property taxes (6,161)

Other items, net 858 (334)

(5,601) l Total Deferred and Other 160,432 181,138 179,643 Tct:1 federalincome tax expense '

160,962 181,653 183,281 income before cumulative effect of occounting change 301,974 305,538 319,637 income Before Cumulative Effect of Accounting Change and income Taxes

$ 462,936

$ 487,191

$ 502,918 Statutory federalincome tax

$ 157,398 34.0 %

$ 165,645 34.0 %

$ 170,992 34.0 %

Additions (reductions)in federal income tax resulting from:

1989 Settlement Shoreham property 4,003 0.9 4,003 0.8 4,035 0.8 Allowance for funds used during construction (4,118) (0.9)

(1,310) (0.3)

(2,573) (0.5)

Lien date property taxes

-277 0.1 (8,757) (1.8)-

Tax credits (6,586) (1.4)

(2,980) (0.6) 1,537 0.3 Excess of book depreciation over tax depreciation 12,193 2.6 13,108 2.7 11,987 2.4 Interest capitalized 2,947 0.6 4,232 0.9 6,031 1.2 Other items, net (4,875) (1.0)

(1,322) (0.3) 29 0.0 Tot:1 Federolincome Tox Expense

$ 160,962 34.8%.

$ 181,653 37.3 %

$ 183,281 36.4 %

O

i N:te 11. Segments of Business The Company is o public utility operating company engaged in the generation, distribution ond sole of electric energy and the purchase, distribution and sole of natural gas to residential and commercial customers in Nossou and Suffolk Counties and the Rockaway Peninsulo in Queens County, all on Long Island, New York. Identifiable ossets by segment include net utility plant, financial resource osset, materials and supplies (excluding common), occrued unbilled revenues, gas in storage, fuel and deferred charges (excluding common). Assets utilized for overoll Company operations consist of other property and investments, cash, temporary cash investments, special deposits, accounts receivable, prepoyments and other current assets, unomortized debt expense and other deferred charges.

(in thovsonds of dollars)

For year ended December 31 1992 1991 1990 Operating revenues Electric

$ 2,194,632

$ 2,196,568

$ 2,095,660 Gas 427,207-351,161 361,242 Total

$ 2,621,839

$ 2,547,729

$ 2,456,902 i

Cperating expenses (entivdes federatincome fores)

Electric

$ 1,354,959

$ 1,252,993

$ 1,151,105 Gas 352,777 338,295 322,515 Total

$ 1,707,736

$ 1,591,288

$ 1,473,620 Cperating income (before federalincome taxes)

Electric 839,673

$ 943,575

$ 944,555 Gas 74,430 12,866 38,727 Total 914,103 956,441 983,282 i

AFC (12,111)

(5,794)

(7,568)

Other income and deductions (49,128)

(48,772)

(20,327)

Interest charges 512,406 523,816 508,259 Federal income taxes-operating 172,998 169,452 180,652 Federalincome taxes-non operating (12,036) 12,201 2,629

]

Income before cumulative effect of accounting change 301,974 305,538 319,637 Cumulative effect of accounting change I

(net of applicable taxes) 11,680 Net income 301,974

$ 305,538

$ 331,317 l

D:preciation and amortization l

Electric 104,034

$ 104,172 98,022 Gas

-15,103 14,783 12,862 Total 119,137

$.118,955

$ 110,884 Construction and nuclear fuel expenditures

• Electric 163,609

$ 144,356

$ 151,425 Gas 109,295 93,195 81,040 Tctal 272,904

$ 237,551

$ 232,465

• Includes non-e ash allowante for other funds used danng construct <on and escludes Shoreham post settlement costs.

(In thovsonds of dollars)

Yr December 31 1992 1991 1990 Identifiable ossets Electric

$ 8,351,370

$ 7,986,887

$ 7,643,963 Gas 767.444 621,570 540,355 Total 9,118,814 8,608,457 8,184,318 Assets utilized for overoll Company operations 1,129,810 934,844 658,366 Total Assets

$ 10,248,624

$ 9,543,301

$ 8,842,684 0

m-m

l N:ta 12. Quarterly Financial Information (UnaudMd)

(In thouwnds of dollars enept earnings per common share) 1992 1991 Cperating revenuos For the quarter ended March 31

$ 697,761 =

$ 657,921 June 30 580,498-543,250 September 30 747,729 773,706 December 31 595,851 572,852 Operating income For the quarter ended March 31

$ 179,741

$ 207,830 June 30 166,954 166,830 September 30 256,800 268,041 December 31 137,610 144,288 N:t income For the quarter ended March 31

$ 66,706

$ 86,404 June 30 59,285 50,089 September 30 141,388 144,449 December 31 34,595 24,596 Enrnings for common stock For the quarter ended March 31

$ 50,553

$ 69,567 June 30 41,040 33,013 September 30 126,295 128,175 December 31 20,132 8,389 E:rnings per common shore i

For the quarter ended March 31

.45

.62 l

June 30

.37

.30 l

September 30 1.14 1.15 December 31

.18

.08 l

Roport of Ernst & Young, independent Auditors To the Shoreowners and Board of Directors of Long Island Lighting Company I

We have audited the occompanying balonce sheet of Long Island Lighting Company os of December 31,1992 and 1991 and the related statements of income, shoreowners' equity and cash flows for each of the three years in the period ended December 31,1992. These financial statements are the responsibility of the Company's management. Our responsibility is to express on opinion on these financial statements based on our audits.

We conducted our audits in occordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonoble assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also include ossessing the occounting principles used and significant estimates mode by monogement, os well os evoluotiog the overall financial statement presente tion.

We believe that our audits provide o reasonable basis for our opinion.

In our opinion, the financial statements referred to above pres: fairly, in all materiol respects, the finoncial position of Long Island Lighting Company at December 31,1 N ond 1991, and the results of its operations and its cash flows for each of the three years in the period ended December 31,1992 in conformity with generally occepted occounting principles.

Y Melville, New York February 5,1993 l

t

I I

Solectod Financial Dato 1992 1991 1990 1989 1988 Summary of Operations Isee Notes to r,nonnat stammen o roue 1 Totoi revenues (000)

$ 2,621,839 $ 2,547,729

$ 2,456,902

$ 2,347,614

$ 2,137,834 Tofof operating income (loss) (000)

Before federalincome taxes

$ 914,103 $ 956,441

$ 983,282 (93,997) $ 701,049 After leder al income tores

$ 741,105 $ 786,989

$ 802,630

$ 620,423

$ 500,938 income (loss) before cumulative effect of accounting changes (000)

$ 301,974

$ 305,538

$ 319,637 (95,803) $ 298,490 l

Cumulative effect of occounting change for l

unbilled gas revenues (net of tones)(000) 11,680 Cumulative effect of accountim change for disallowed costs (net of taxes) (000)

$(1,345,110)

Earnings (loss) for common stock (000)

$ 238,020 $ 239,144

$ 263,156

$ (175,035) $(1,121,128)

Average common shores outstanding (000) 111,439 111,348 111,290 111,215 111,177 Earnings (loss) per common shore Before cumulative effect of occounting changes S

2.14 2.15 2.26 (1.57) $

2.02 Cumulative effect of occounting_ changes

.10 112.10)

Earninas (loss) per common shore 2.14 2.15 2.36 (1.57) $

(10.08)

Pro forma earnings - with accounting changes for unbilled ges revenues and disallowed project costs applied retroottively Earnings (loss) f or common stock (000)

$ 251,476

$ (173,251) $ 223,712 Earninas (loss) ner common shore 2.26 (1.56) $

2.01 Common stock dividends declared per shore l.72 $

1.60 1.25

.50 Common stock dividends paid per shore 1.71 1.55 1.125

.25 Book value per common shore of year end 19.58 $

19.13 18.57 17.45 19.61 Common shareewners et year end 86,111 90,435 82.903 85,142 93.267 Ratio of earnings to fixed charges 1.90 1.93 1.98 1.95 Rotio of earnings to combined fixed charges and preferred stock dividends 1.59 1.60 1.64 1.58 Rot;o of cornings to fixed charges I

(excluding AFC and RMC) 1.73 1.40 1.36 1.60 Rotro of earnings to combined fixed charges and preferred stock d;vidends (excluding AFC and RMC) 1.46 1.17 1.12 1.30

• Ihe Company had no earnungs to cover faed c harges (in thousands of dollars)

Cperations and Molntenance Expense Details Toue2 Totol poyroll and employee benefits

$ 413,817 $ 398,000

$ 357,689

$ 329,694

$ 314,341 Less -- Cho_rged to construction and other 124,076 123,838 97,650 117,761 129,990 Payroil and employee benefits charged to operations 289,741 274,162 260,039 211,933 184,351 F uels - electric operations 282,138 354,859 444,458 461,576 410,174 Fuels - gas operations 182,201 175,046 175,877 188,139 172,431 Purchased power costs 280,914 197,154 168,749 128,368 88,465 fuel _ cost adjustments deferred (3,469) 41,643

{2,085)

(5,631}

3,359 Total Fuel and Purchased Power 741,784 768,702 786,999 772,452 674,429 All other 208,204 248,597 215,770 215,373 173,545 Total Operotions and Maintenance Expense

$ 139,729 $ 1,291,461

$ 1,262,808

$ 1,199,758

$ 1,032,325 1

Employees at December 31 6,502 6,605 6,630 6,239 6,281 l

O

(In thousands of dollars) 1992 1991 1990 1989 1988 Electric Operating income Table 3 R; venues Residential

$ 1,045,799 $ 1,047,490 $ 997,868 $ 915,644 $ 835,584 Commercial and industrial 1,076,302 1,070,098 1,017,387 981,740 883,267 Other system revenues 49,395 47,838 46,673 42,232 40,518 Total system revenues 2,171,496 2,165,426 2,061,928 1,939,616 1,759,369 Sales to other utilities 9,997 23,040 24,140 42,880 24,152 Other revenues 13,139 8,102 9,592 792 3,412 Total Revenues 2,194,632 2,196,568 2,095,660 1,983,288 1,786,933 Expenses Operotions - fuel and purchased power 559,583 593,656 611,122 584,313 501,998 Operations - other 294,909 296,798 271,608 237,931 195,283 Maintenance 105,341 127,446 118,545 115,502 96,599 Depreciation and amortization 104,034 104,172 98,022 91,759 82,811 Base financial component amortization 100,971 100,971 100,971 50,485 Regulatory liobility component amortization (88,573)

(88,573)

(88,573)

(44,286)

Other regulatory amortizations (21,984) 8,666 14,427 1,248 Rote moderation component (30,444)

(228,572)

(297,214)

(131,167)

Regulatory liability component 793,592 Jamesport omortization 104,160 Operating taxes 331,122 338,429 322,197 312,456 262,644 Federolincome iox - current 530 515 3,138 14,612 18,394 Federof income tax - deferred and other 158,908 173,259 169,274 (738,500) 166,557 Total Expenses 1,514,397 1,426,767 1,323,517 1,392,105 1,324,286 El:ctric Operating Income

$ 680,235 $ 769,801 $ 772,143 $ 591,183 $ 462,647 (In thovsonds of dollars}

Cas Operating income roble 4 Rsvenues Residential-space heating

$ 243,950 $ 190,976 $ 198,734 $ 209,192 $ 201,312

- other 33,035 29,383 30,854 31,692 31,803 Non residentiol-space heating 90,363 70,938 68,441 72,351 68,114

- other 29,094 25,515 26,501 28,674 28,078 Totol firm revenues 396,442 316,812 324,530 341,909 329,307 Interruptible revenues 19,658 21,686 30,515 19,226 18,821 Totol system revenues 416,100 338,498 355,045 361,135 348,128 Other revenues 11,107 12,663 6,197 3,191 2,773 Total Revenues 427,207 351,161 361,242 364,326 350,901 Expenses Operations - fuel 182,201 175,046 175,877 188,139 172,431 Operations - other 77,300 78,469 68,910 59,587 53,415 Maintenance 20,395 20,046 16,746 14,286 12,599 Depreciation and amortization 15,103 14,783 12,862 11,671 10,785 Regulatory omortizations (88)

Operating taxes 57,866 49,951 48,120 51,935 48,220 Federalincome tox - current 500 Federalincome tax - deferred and other 13,560 (4,322) 7,740 9,468 15,160 Totol Expenses 366,337 333,973 330,755 335,086 312,610 Ces Operating income 60,870 $

17,188 $

30,487 $

29,240 $

38,291 l

)

i G

- 1 1992 1997 1990 1989 1988 Electric Soles and Customers rose 5 Sales - millions of kWh L

Residential 6,788 7,022 7,022 7,063 6,979 l

Commercial and industrio!

8,181 8,322 8,359 8,636 8,566 Other 471 469 472 470 483 System sales 15,440 15,813 15,853 16,169 16,028 Sales to other utilities 227 598 532 633 445 l

Total Sales 15,667 16,411 16,385 16.802 16,473 f

Customers - monthly overage Residential 902,885 898,974 895,294 890,406 882,962 Commercial and industrial 101,838 101,740 101,.i62 100,481 98,450 Other 4,593 4,540 4,504 4,452 4,436 Customers - total monthly overage 1,009,316 1,005,254 1.001,360 995,339 985,848 Customers - total at year end 1,009,028 1,005,363 1,001,441 996,488 989,097 i

Residential kWh per customer 7,518 7,812 7,844 7,932 7,905 Revenue per kWh 15.41c 14.92c 14.21c 12.96c 11.97c l

Commercial and Industrial kWh per customer 80,346 81,797 82,304 85,943 87,005 Revenue per kWh 13.16c 12.86c 12.17c 11.37c 10.31 c System kWh per customer 15,297 15,731 15,832 16,245 16,258 l

Revenue per kWh 14.06c 13.69c 13.01 c 12.00c 10.97e i

Gas Sales and Customers roue 6 l

Sales - thousands of dth i

Residential-space heating 35,089 29,687 29,810 32,024 31,276

- other 3,203 3,195 3,448 3,491 3,589 Non-residential-space heating 13,662 11,636 11,271 11,548 11,054

- other 4,338 4,171 4,352 4,539 4,580 Total firm sales 56,292 48,689 48,881 51,602 50,499 Interruptible sales 5,090 4,538 6,347 5,300 5,078 TotoI 5 ales 61,382 53,227 55,228 56,902 55,577 l

Customers - monthly overage

)

Residential-space heating 227,834 220,562 211,400 204,982 198,949

- other 169,189 171,581 176,000 179,415 181,926 Non. residential-space heating 31,666 30,453 29,072 27,733 25,979

- other 10,777 11,003 11,310 11,517 11,725 Total firm customers 439,466 433,599 427,782 423,647 418,579 Interruptible customers 531 472 410 359 325 Customers - total monthly overoge 439,997 434,071 428,192 424,006 418,904 j

Customers - total of year end 442,117 436,853 430,571 426,060 - 421,429

)

Residential dth per customer 96.4 83.9 85.8 92.4 91.5 Revenue per dth

$ 7.23

$ 6.70

$ 6.90

$ 6.78

$ 6.69 Non-residential i

dth per customer 424.1 381.3 386.9 409.9 414.6 Revenue per dth

$ 6.64

$ 6.10

$ 6.08

$ 6.28

$ 6.15

]

System i

dth per customer 139.5 122.6 128.9 134.2 132.7 Revenue per dth

$ 6.78

$ 6.36

$ 6.43

$ 6.35

$ 6.26 i

o t

,,a v

n.,---

t I

1992 1991 1990 1989 1968 Electric Operations hele 7 Energy - millions cf kWh Net generation 10,592 13,570 13,981 15,220 15,228 Power purchased - net 6,211 3,638 2,989 2,087 1,940 Totol system requirements 16,803 17,208 16,970 17,307 17,168 Company use and unoccounted for (1,363)

(1,395)

(1,117)

(1,138)

(1,128)

[

System sales 15,440 15,813 15,853 16,169 16,040 Sales to other utilities 227 598 532 633 433 Total Energy Available 15,667 16,411 16,385 16,802 16,473 Peak Demond - mW l

Station coinciuent demand 2,975 3,085 3,260 3,178 3,347 Power purchased - net 636 819 426 510 475 System Peak Demand 3,611 3,904 3,686 3,688 3,822 System Copobility - mW LILCO stations 4,091 4,078 4,077 4,066 3,834 l

Nine Mile Point 2 (LtLCO's 18% share) 188 194 194 194 194 Firm purchases - net 170 244 300 400 482 Toto! Copability 4,449 4,516 4,571 4,660 4,510 Fuel Consumed for Electric Operations Oil-thousands of borrels 10,656 15,314 16,401 20,480 19,927 i

Gas - thousands of dth 34,475 32,924 36,477 26,490 29,126 Nuclear - thousands of mW days 124 154 108 105 87 l

Totol-billions of Btu 102,126 129,937 139,874 154,669 153,828 i

Do!!ars per million Btu 2.62 2.61 S

3.07 2.86 2.53 i

Cents per kWh of net generation 2.76c 2.73c 3.24c 3.06c 2.67c Heat rote - Btu per net kWh 10,558 10,484 10,564 10,704 10,545 Fu";I Mix (Percentage of system reamrements) l Oil 37 %

50%

$6%

67 %

68 %

Gas 19 18 20 13 15 i

Purchased Power 38 25 20 16 13 l

Nuclear Fuel 6

7 4

4 4

i Total 100 %

100 %

100 %

(",'%

100 %

l Ces Operoflons roues En:rgy-thousands of dth l

Natural gas 64,911 55,579 55,407 60,359 58,743 Manufactured gas and change in storoge 48 60 (15) 53 (18)

['

Total Natural and Manufactured Gas 64,959 55,639 55,392 60,412 58,725 Total system requirements 64,959 55,639 55,392 60,412 58,725 Company use and unoccounted for (3,577)

(2,412)

(164)

(3,510)

(3,148)

Total Energy Available 61,382 53,227 55,228 56,902 55,577 Maximum Day Sendout-dth 448,726 435,050 406,177 462,610 431,940

[

System Copobility - dth per doy Natural gas 561,584 507,344 507,344 461,788 411,596 i

LNG manufactured or LP gas 120,700 128,200 128,200 145,600 145,600 Total Copability 682,284 635,544 635,544 607,388 557,196 Calendor Degree Days (66-year overage 5,028) 5,066 4,378 4,139 5,169 5,162 r

i

(in thousands of dollars)

]

1992 1991 1990 1989 1988 l

Construction Expenditures

• Toble 9 Electric Production 46,217 $

32,541 36,400 $

59,880- $ 419,028 l

Transmission 15,535 12,452 23,418 9,022 13,379 Distribution 74,951 74,770 82,975 66,679 64,653 l

Generof (,ncludes nuclear fuel) 5,049 9,880 (1,765) -

3,615 17,227 j

Electric Total 141,752 129,643 141,028 139,196 514,287 Gas Total 104,028 89,950 78,766 49,847 37,518 Common Total 27,124 17,958 12,671 11,007 9,352 Total Construction Expenditures 272,904 $ 237,551_ $ 232,465 $ 200,050 $ 561,157 l

• Includes non. cash ottowance for other funds used dunny constructoon and excludes Shoreham post seniement costs.

l Solonce Sheet table 10 Assets Utility plant

$ 4,544,020 $ 4,334,736 $ 4,150,822_ $ 3,939,410 $ 8,017,047 Less - Accumulated depreciation j

ond omortization 1,382,872 1,332,003 1,262,743 1,158,253 1,071,923 Total Net Utility Plant 3,161,148 3,002,733 2,888,079 2,781,157 6,945,124 Regulatory asset 3,685,432 3,786,403 3,887,373 3,988,344 Nonutility property and other investments 20,730 9,788 6,381 6,050 69,271 _

l Current essets 916,914 884,017 726,060 982,032 571,934 l

Deferred charges

.i Rote moderation component 651,657 602,053 411,443 102,971 l

Shoreham post settlement costs 586,045 378,386 225,818 75,044

-l Unomortized cost of issuing securities 380,267 227,713 132,875 150,610 52,689

-l Shoreham nuclear fuel 77,629 79,760 92,069 97,925 Accumulated deferred income taxes 511,898 439,235 359,768-262,298 525,029 I

Other 256,904 133,213 112,818 73,607 162,290 Total Deferred Chorges 2,464,400 1,860,360 1,334,791 762,455 740,008

)

Total Assets

$ 10,248,624

$ 9,543,301

$ 8,842,684 $ 8,520,038 $ 8,326,337 Copitolization and Llobilities Capitalization Long-term debt S 4,755,733

$.5,001,016

$ 4,556,016 $ 4,560,016 $ 3,449,821 Unomortized premium and (discount) on debt (14,731)

(14,850)

(23,125)

(28,587)

(25,011)

Preferred stock - redemption required 557,900 524,912 527,550 541,187 513,924 Preferred stock - no redemption required 154,276 154,371 154,674 155,592 221,050 Treasury stock, of cost (58,430)

Retained earnings restricted for preferred stock dividend requirements 341,008 Common stock and premium 1,556,091 1,550,334 1,549,505 1,547,971 1,557,293 Capital stock expense (39,304)

(40,216)

-(42,676)

(42,916)

(56,151)-

Retained earnings 667,988 620,373 560,405 436,690

- 679,579 Total Capitalization 7,637,953 7,795,940 7,282,349 7,169,953 6,623,083 Current Liabilities 1,191,787-492,895 449,830 470,885 583,017 Deferred Credits 1989 Settlement credits 164,294 173,507 182,720 191,933 Class Settlement 167,066 173,564 167,569_.

164,040 Accumulated deferred income taxes 970,373 816,053 634,704 430,933 963,975 Other 110,341 84,035 117,172 81,443 144,015 Total Deferred Credits 1,412,074 1,247,159 1,102,165 868,349 1,107,990 Reserves for Claims, Domoges, Pensions and Benefits 6,810 7,307 8,340 10,851 12,247 Total Capitalization ond Liabilities

$ 10,248,624

$ 9,543,301

$ 8,842,684 $ 8,520,038 $ 8,326,337 O

1992 1991 1990 1989 1988 Crpitalization Ratios

• Tone il l

Long-term debt 65 %

64 %

62 %

63 %

53 %

l Preferred stock 9

9 10 10 1.5 l

Common equity 26 27 28 27 32 Total Capitalization 100 %

100 %

100 %

100 %

100%

• Incluaes carrent ma+vrses of long terrn de bt and current redempt.on reqw emen's of preferred stock r

l Comrnon and Preferred Stock Prices Tone 12 l

The common stock of the Company is troded on the New York Stock Exchange and the Pacific Stock Exchange. The Preferred l

Stock $100 por value, Series B, E, I, J, K and CC and the Preferred Stock $25 por value, Series O, P, Z ond AA of the Company I

are, and Series 5, I and Y were traded on the New York Stock Exchange. The table below indicates the high and low prices on the New York Stock Exchange listing of composite transactions for the years 1992 and 1991.

1992 1991 Quorter Quarter First Second Third Fourth First Second Third Fourth Common Stock High 24%

24 %

25%

25%

23%

23%

24 %

25 Low 22%

22%

23%

23%

19 21 %

22%

23%

Pref;rred Stock Series B 5.00 %

High 61 66 70 67 53 %

54 56 %

58 Low 56%

57 65 62 48 51 %

53 52 Series E 4.35 %

High 52 %

59 %

62 60 47 46%

49 52 Low 49 49 %

55 54 43 %

44 %

45 47 %

Series 1 5%%

High 138 146 %

136 131 136 141 %

low 133 143%

125 131 134 139 Series J 8.12 %

High 96%

96% 100 % 101 85 %

86 91 94 Low 92 92 %

94 %

96 78 82 %

83 88%

Series K 8.30 %

High 98%

98 102 101 85 88 91 97 Low 94 %

94 96%

97%

78 83 %

85 91 Series O $2.47 High 28 28 29%

27 %

25 %

26%

27 27 %

Low 26%

26 26 25 %

24%

24 %

25 26 Series P

$2A3 High 27%

28%

29%

28%

25 %

27 %

27%

28 Low 26%

27%

27%

27%

24 %

24%

25%

26%

Series S 9.80 %

High 105 % 105 99% 101 102 % 105 tow 102 102 %

96% 100 101 102 Series T

$3.31 High 27 %

27 %

Low 26 26%

Series Y

$2.65 High 29 28%

27 27%

28 28 %

Low 27%

27%

25 25%

26%

26%

Series Z

$2.35 High 28 %

28 29 29 25 %

26%

28%

tow 27 26 %

27 27%

25 4 24%

26 Series AA 7.95 %

High 26 %

27 Low 25%

25 %

Series CC 7.66 %

High 102 103 Low 100% 100 The Frelened Stock S100 par volve, Sernes D 4.25% traded m the over-the<ounter morLet and no prne dato is avadaUe lhe Preferred Stock S100 par volve Serres F, H L M and R ore held privately.

• Nc' trades reported dormg this pernod.

i O

i Corporoto laformation Exocutive Offices Annvol Moeting 175 East Old Country Road The AnnvolMeetir g of Shoreowners will be held on i

l Hicksville, New York 11801 Tuesday, April 20, 993 at 3:00 p.m. In connection with l

l this meeting, proxie, will be solicited by the Company.

Common Stock Listed l

New York Stock Exchange Form 10-K Annual Report Pocific Stock Exchange The Company will furnish, without charge, o copy of the Company's Annual Report, Form 10-K, as filed with Ticker Symbol: LIL the Securities and Exchange Commission, upon written request to: Investor Relations, Long Island Lighting Transfer Agent and Registrar Company,175 East Old Country Pood, Hicksville,

[

Common Stock and Preferred Stock New York 11801.

The Bank of New York Shoreholder Services Department lith Floor 101 Porclay Street New York, NY 10286-1258 l

1-800-524-4458 l

t Shoreowners' Agent for Automatic j

Dividend Reinvestment Plan j

The Bank of NewYork t

Dividend Reinvestment Deportrr.ent lith Floor l

101 Barclay Street New York, NY 10286-1258 1-800-524-4458 l

O i

r,,

Diroctors William J. Catacosinos Anthony F. Earley, Jr.

Richard L. Schmolensee l

Chairman of the Board and President and Director Chief ExecutiveOfficer Chief Operating Officer Center for Energy and Long Island Lighting Company Long Island Lighting Company Environmental Policy Research j

UY A. J:mes Bornes Winfield E. Fromm Deon Retired Vice President George J. Sideris School of Public ond Eaton Corporation Retired Senior Vice President Finance j

Environmental Affairs Electrical Engineering Long Island Lighting Company l

Indiono University Bosil A. Paterson John H.Tolmoge G3crge Bugliarello Partner Portner President Meyer, Suozzi, English H.R. Tolmoge & Son Polytechnic University

& Klein, PC Agriculture Ranso L. Caporall Phyllis S. Vineyard Chairman of the Board Eben W. Pyne Director and Chief Executive Officer Corporate Director Long Island Community Grummon Corporation and Consultont Foundation W.R. Groce and Company P +tsr O. Crisp Retired Senior Vice President President Citibank, N.A.

Venrock, Inc.

Venture CopitalInvestments Of ficers William J. Catacosinos Adam M. Madsen Walter F. Wilm, Jr.

Chairman of the Board and Vice President Vice President Chief Executive Officer Corporate Planning Edward J. Youngling Anthony F. Earley, Jr.

Arthur C. Marquardt Vice President President and Vice President Customer Relations Chief Operating Officer Gas Operations James T. Flynn Brian R. McCaffrey Robert J. Grey Executive Vice President Vice President General Counsel

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Edward C. Dietz Senior Vice President Joseph W. McDonnell Kathleen A.Marion Electric Business Unit Vice President Corporate Secretary and

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William N. Dimoulos Robert B. Steger Controller Vice President Vice President Herbert M. Leimon Information Systems Fossil Proouct. ion Assistont General Counsel

' 9Y William E. Steiger, Jr.

and Assistont Corporate Rsb;rt X. Kelleher Vice President Secretory Vice President Engineering and Construction Christion G. Wilding JLhn D. Leonard, Jr.

Vice President Vice President Conservation and Corporate Services and Lood Monogement i

Nuclear Operations

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