ML17059A308

Long Island Lighting Co Annual Rept for 1993

ML17059A308
Person / Time
Site:	Nine Mile Point
Issue date:	12/31/1993
From:	LONG ISLAND LIGHTING CO.
To:
Shared Package
ML17059A306	List: ML17059A305 ML17059A307 ML17059A308 ML18041A027 ML20070R318 ML20070R326
References
NUDOCS 9405200165
Download: ML17059A308 (52)

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To Our Shareowners p ~p ~ was a year in which LILCO's finan-M~cial health continued to improve.

Earnings for the year were $240 million or $2.15 per common share, and we increased our quarterly common

~tock dividend by 2.3 percent to 44.5 cents per share, fective October 1, 1993.

During the

year, we made significant strides toward fulfillingour vision of the future, a future chal-lenged by the competing demands to lower costs and improve service. The company began to set in motion its blueprint for success with an emphasis on perfor-mance and service. We have worked hard to lower costs by improving efficiency and taking advantage ofchanging market conditions and new opportunities.

These efforts have resulted in a major accomp-lishment the company's latest rate plan, filed on December 31, 1993. The plan proposes to freeze base electric rates for the next two years, holding base rates at current levels through November, 1996.

LILCO has taken this action now to help revitalize the Long Island economy and to help better position the company to deal with the trend toward competition. We elieve we can accomplish this significant task while ntinuing to return the company to financial health under the plan set out in the Shoreham settlement agreement.

The following factors have allowed us to propose this rate freeze:

Lower operating and capital costs.

We are contain-ing costs with tight budget control over expense and capital items. By operating more efficiently, we have been able to streamline our work force five percent through attrition over the last two years and plan to reduce it another five percent by the end of 1995. We have reduced overtime, implemented a managed health care program, and improved the reliabilityofour power plants. These, and other, cost-containment programs, combined with a low inflation rate, have allowed the company to save

$130 million in the last four years.

Lower interest rates.

Over the last few years, LILCO has taken fulladvantage oflower interest rates available to the company with a comprehensive refinancing pro-gram. Since 1989, the company has refinanced more than

$4 billion of high cost debt, saving LILCO and its customers approximately $88 million annually.

Lower fuel and power costs.

A drop in oil prices, the conversion ofpower plants from oil-fired to natural gas fuel and the availability of excess low-cost power from offLong Island have helped to hold down the cost of electricity. Today, only 33 percent of the energy provided to LILCO customers is generated by burning oil. Natural gas and purchased power play a much greater role in providing electricity to customers.

Lower property taxes.

LILCO remains the largest taxpayer on Long Island. State, county and local taxes paid by the company in 1993 exceeded

$595 million.

Nevertheless, LILCO's property tax payments are less than they were anticipated to be under the Shoreha~

settlement because taxes have not escalated at t~

projected rate, and the courts have determined that some utility property had been overassessed.

Reduced conservation costs.

With additional power plants and another interconnection to import power from upstate, LILCOnow has ample electricity to meet energy requirements for the next decade. While continuing to view conservation as a solution to ease energy demand and as a key element in economic development, the company can scale back expensive incentive programs that pay customers to conserve.

We are mindful of our high electric rates, and we are taking this step to freeze base electric rates to send a clear signal to our customers and the financial community that we can control rates and help improve the long-term economic future of the company and the community.

We want to become energy "partners" with our customers by providing the expertise they need to succeed here on Long Island. With special energy packages and information services, LILCO is helping customers nd potential customers relocate, expand, and improve eir operations on Long Island.

We will be intro-ducing value-added services such as individual account managers for LILCO's largest customers and "one-stop-shopping" to expedite all customer inquiries as part of our program to provide unparalleled service to our customers.

We believe these measures, combined with our base rate freeze, favorably position the company for long-term success. The rating agencies have become increasingly concerned about changes in the utility industry and have imposed stricter standards on utilities. In December, following a review of the utility industry in general, Standard

&, Poor's rating agency downgraded the securities of many utilities, including those of LILCO.

While Duffand Phelps lowered its ratings on LILCO's preferred stock and debentures, it reaffirmed its ratings on the company's'irst mortgage and general and refunding bonds. LILCO's ratings by Moody's and Fitch have remained the same.

LILCO's proposed rate plan calls for the company to aggressively control costs and gradually improve its debt-to-equity ratio.

We believe these actions will stabilize our current securities ratings and eventually result in higher ratings.

On behalf of the company's Board of Directors and officers, I would like to thank you, our shareowner, for your past and continuing interest in LILCO.

Sincerely, William J. Catacosinos Chairman, President and Chief Executive Officer

Lynda Thompson is helping LILCOsave time and money. She's one ofthe company's meter readers now using ITRON, the most advanced hand-held data recording device in thc industry. This state-of-thc-art cquipmcnt operates faster and morc accurately than previous models.

r LILCO invests in research and development to improve production, delivery and conservation of electricity and natural gas. It's an important part of reducing expenses.

For every dollar invested in R&D, LILCO expects a

$3 return in more cost efficient operations.

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enhanced these returns through the Long Island Energ~

1 Research and Development Initiative. The initiative unites Long Island academic and business organizations, tapping into the vast local supply of innovative technology and talent. Such partnerships have yielded improved training techniques, new gas leak detection devices, and an additive to help detect lost coolant in commercial refrigeration.

These projects improve efficiency and cut costs good news for customers and shareowners.

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~ Keeping tabs on world events that might affect oil prices is one ofthe ways Fuels Supply Manager Jimmy Huic plans LILCO's oil purchases.

Searching for the lowest possible prices, Huie and his team carefully monitor supplies, negotiate competitive contracts, and intain constant contact with oil dealers and brokers on the lookout for low-cost oil available on thc spot market.

st year their efforts saved LILCOand its customers morc than $4.I million.

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On a daily, and sometimes hourly basis, LILCOelectric system operators act as "power" brokers, determining the most economic mix offuels and generating units to supply electric service to customers at the lowest possible cost.

Many times, this action includes purchasing power from other utilities instead of producing it in our own plants.

Last year, such purchases saved the company more than

$100 million. ~ The fuel oil LILCO uses to generate electricity cost $180 million in 1993. That's one of the reasons why LILCO carefully designs its oil purchasing practices to get the lowest cost possible.

With a greater supply ofgas entering Long Island through the Iroquois pipeline, LILCOhas been able to increase its use ofthis clean- ~

burning, economical fuel. Control Operator Randy Scott monitors fuel levels at the company's Northport Power Station Unit 4 recently converted to dual-fuel burning capability. The conversion enables LILCOto react to market changes and respond by burning eit oil or gas, whichever is more economical. Thc company expects to save millions ofdollars annually from the conversion.

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A recent order by the Federal Energy Regulatory Commission has changed the way utilities buy, transport, and sell natural gas. Known as FERC Order No. 636, this new ruling deregulates the sale of natural gas and makes gas procurement the responsibility ofutilities. The chan eliminates the "middle man," which should help low purchased gas costs and allow LILCO to take advantage ofnew business opportunities.

t As a result we have sold gas outside our service area in markets from Mississippi to Connecticut. In another new venture, LILCOwillact as fuel manager for a cogeneration facilityat the Brooklyn Navy Yard. Under this contract, the company willbroker a portion of its gas transportation capacity.

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~ Meet Call Section Manager Mary Martin. She's an important part ofLILCO's new Customer Assistance Center. Working with the center's more than 240 customer representatives, Mary is helping to improve the quality ofLILCO's24-hour-away call handling capability t

rough better training and supervisory support. Also at the center arc technical experts in conservation, electric, gas, and consumer services to provide immediate tesponsc to a wide range ofcustomer inquiries.

LILCO is committed to providing unparalleled service to its customers. It is the guiding principle for every area of the company's operations from customer relations to electric and gas service. t In fulfillingthis commitment, LILCO employees have been faced with the challenge of responding faster and more accurately to requests for service, information, and assistance while employing cost-containment strategies.

With improved set-ups like LILCO's new Customer Assistance Center, employees are finding innovative ways to provide better service by consolidating and streamlining resources.

LILCOresponds to more than 800000 gas and electric service requests annually. To respond faster and morc accurately to these requests,

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the company developed a mobile communications system called the Computer-Assisted Radio Dispatch System, or CARDS.

This new technology enables field workers like Gas Customer Service Specialist Jim Buttacavoli to work morc efficiently with bett deployment ofrepair crews and provide automatic feedback on the status ofa job. The new system also allows customers to schedule routine repair work at their convenience another example ofhow LILCOis putting new technology to work for thc pcoplc we serve.

0 From the company's reorganization to its new call-handling capabilities, technological innovation is providing the backbone to support LILCO's service initiatives. In review-ing every area of company operations, employees are searching for ways to apply new technologies to improv~

the efficiency, speed, and responsiveness of customs service.

t Applications such as the use of military technology to improve power plant operations and marine research to protect heating equipment exemplify how greater efficiency can be combined with improved service just one of the ways LILCO continues to lower costs for customers.

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~ On his own time, LILCOlineman Phil Batishko invented a tool to help in an expensive repair job reconstructing 82 ofthe company's transmission towers. The tool, a hydraulicjack mounted on an adjustable pole, supports heavy wire and relieves pressure on support arms while

'pairs are completed. Phil's innovative device helped make the work easier and faster, saving time and money during the 3'h month project.

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j To find out how to do a job better, just ask someone who does it. That's LILCO's philosophy to turn employee ideas into action and savings for the company and its customers. With programs like the Employee Suggestion

System, Q-Teams, and Service First, LILCO gives all employees a voice in how to improve efficiency and service. Their suggestions have saved the company and its customers millions ofdollars. s>> LILCO's most valuable.

asset will always be its dedicated and experienced employees.

By listening carefully to their ideas, the company can provide better services at lower cost.

Financial Review Overview Nearly five years have passed since the effective date ofthe 1989 Settlement, discussed in Note 2 ofNotes to Financial Statements, which resolved the controversy surrounding the Shoreham Nuclear Power Station (Shoreham). Over this period oftime, the Company has focused on managing costs and improving operating efficiencies. This, coupled with six electric rate increases, lower than anticipated fuel and financing costs and significantly lower production expenses has helped to improve thc Company's financial health. This also enabled the Company to file with thc Public Service Commission ofthe State ofNcw York (PSC) on December 31, 1993 an electric rate plan requesting that base rates be frozen for a two-year period beginning December 1, 1994.

The Company's electric rate plan to freeze base rates is designed to moderate the rate increases that were originally contemplated in the 1989 Settlement. The two-year base rate freeze willhelp better position the Company to respond to the current environment in the utilityindustry and to assist in Long Island's economic recovery.

Other significant events during 1993 included:

~ Approval, by the PSC, ofthe third annual electric rate increase of4.0% effective December 1, 1993, under the three-year electric rate plan authorized in 1991.

~ For the first time since the 1989 Settlement became cffcctive, revenues provided under the Rate Moderation Agreement exceeded revenues that would have been provided under conventional ratcmaking, resulting in the decline ofthe Rate Moderation Component balance and an improvement in the Company's cash flowposition.

~ An increase in the Company's common stock quarterly dividend from 43 A cents pcr share to 44 A cents per share, rcprcscnting the fourth consecutive year of dividend increases.

Earnings for common stock in 1993 were $2.15 per common share compared to $2. 14 per common share in 1992.

~ The approval by thc PSC ofa three-year gas rate plan providing annual rate increases of4.7%, 3.8% and 2.8%,

for the rate years beginning Dcccmber 1, 1993, 1994, and 1995, respectively. This follows an increase in gas rates of 7.1% that was effective December 1, 1992.

~ The addition ofover 9,000 new gas space heating customers, resulting from the Company's gas expansion program.

~ The refinancing ofa significant amount ofthe Company's higher-cost securities as a result ofvery favorable long-term interest rates.

Refinancing ofapproximately $983 millionofhigher-cost securities significantly lowered the Company's cost ofdebt and preferred stock. These 1993 rcfinancings willresult in more than $ 18 millionin annual cash savings through lower interest expense and preferred stock dividends.

Since the 1989 Settlement became effective, the Company's aggressive refinancing program has resulted in annual cash savings ofapproximately $88 million.

Liquidityand Capital Resources Cash and Revolving Credit AtDecember 31; 1993, the Company's cash and cash equivalents amounted to approximately $249 million, compared to $309 millionat December 31, 1992. In addition, the Company has approximately $276 millionavailable through October 1, 1994, provided by its 1989 Revolving Credit Agreement (1989 RCA).

At December 31, 1993, no amounts were outstanding under the 1989 RCA. For a further discussion ofthe 1989 RCA, see Note 7 ofNotes to Financial Statements.

Capital Requirements and Capital Provided During 1993, the Company continued its aggressive refinancing ofhigher-cost debt and preferred stock, taking advantage of declining interest rates. In 1993, the Company redeemed $568 millionofhigher-cost securities through the issuance ofapprox-imately $382 millionofdebentures and $204 millionofpreferred stock. The Company also issued $420 millionofdebentures to redeem $415 millionofmaturing debt.

In addition to these refinancings, the Company issued $200 millionofdebentures and $ 100 millionoftax-exempt securities and used the proceeds to reimburse the Company's treasury for previously incurred capital expenditures. In November 1993, the Company satisfied the maturity of$ 175 millionof debentures with cash on hand.

For a further discussion on the Company's capital stock and long-term debt, see Notes 6 and 7 ofNotes to Financial Statements.

16

First Mortgage Bonds General and Refunding Bonds Debentures

$ 25

$ 25

$ 40 415 575

$ 600

$ 25

$ 455 The Company is planning, subject to market conditions, to fund a portion ofthese mandatory redemptions with the issuance of common equity in order to improve its debt-to-equity ratio.

Capital requirements and capital provided for 1993 and 1992 werc as follows:

(in millions ofdollars) 1993 1992 Capital Requirements Construction Electric Gas Common otal Construction 136 137 125 104 41 27 302 268 Refundings and Dividends Long-term debt Preferred stock Preferred stock dividends Common stock dividends Redemption costs 960 1,344 206 389 57 70 196 191 15 159 Total Rcfundings and Dividends 1,434 2,153 Shorcham post settlement costs 207 228 Total Capital Requirements

$ 1,943

$2,649 Capital Provided Decrease (increase) in cash Long-term debt Preferred stock Financing costs Other financing activities Internal cash generation from operations 61 1,090 202 (2) 10 (11) 1,660 411 (7) 6 590 Total Capital Provided

$ 1,943

$ 2,649 For ftttthcr information, see the Statement ofCash Flows.

~ ie Company expects that itwillseek external financing of approximately $ 1.1 billionsolely for the purpose ofrefunding maturing debt in the years 1994, 1995 and 1996 as follows:

(In millions ofdollars) 1994 1995 1996 For 1994 total capital requirements (excluding common stock dividends) are estimated at $ 1.1 billion,ofwhich mandatory redemptions are $600 million, construction requirements are

$327 million, preferred stock sinking fund requirements are $5 million, preferred stock dividends are $53 millionand Shoreham post settlement costs are $ 158 million.

During 1994, the Company expects to access the capital markets only for funds required to satisfy maturing securities or to refund outstanding securities to reduce financing costs. Itis anticipated that the internal funds generated from operations willbe sufficient to satisfy all other capital requirements, including both common and preferred stock dividends.

Long-term debt Preferred stock Common shareowners'quity 1993 1992 65.0%

64.7%

8.5 8.8 26.5 26.5 100.0%

100.0%

The Company's debt-to-equity ratio reflects two substantial charges to common shareowners'quity made in 1988 and 1989. In 1988, the Company was required to write4own net assets ofapproximately $ 1.3 billion, net oftax effects, relating to its investments in Shoreham and Nine MilePoint Nuclear Power Station, Unit2 (NMP2). In 1989, the Company incurred a loss for common stock ofapproximately $ 175 million, reflecting the effects ofthe 1989 Settlement and the Class Settlement, discussed in Notes 2 and 4 ofNotes to Financial Statements. The Company is committed to improving its debt-to~uity ratio through growth in retained earnings, debt reduction through improved cash flows, and the issuance of common equity.

Capitalization The Company's capitalization, including current maturities of long-term debt and current redemption requirements of preferred stock, at December 31, 1993, was approximately

$8.4 billion, as compared to $8.2 billionat December 31, 1992.

This increase in capitalization ofapproximately $ 185 million principally reflects an increase in long-term debt and preferred stock associated with the Company's financing activities in 1993 and an increase in common shareowners'quity comprising 1993 net income ofapproximately $296 million reduced by common and preferred stock dividends of approximately $253 million.

At December 31, 1993 and 1992, the components ofthe Company's capitalization ratios were as follows:

Rate Matters Electric In conjunction with the 1989 Settlement, the PSC authorized the recognition ofa regulatory asset known as the Financial Resource Asset (FRA). The FRA consists oftwo components, the Base Financial Component (BFC) and the Rate Moderation

Component (RMC). The Rate Moderation Agreement (RMA),

one ofthe constituent documents ofthe 1989 Scttlemcnt, pro-vides for the fullrecovery ofthe FRA. The RMA, by its terms, specifies that the FRA was created to provide the Company adequate financial indicia for the period 1989 through 1999 and to restore the Company's debt securities to investment grade levels as determined by independent rating agencies.

The BFC, as initiallyestablished, represents the present value ofthe future net-after-tax cash flows which the RMAprovided the Company for its financial recovery. The BFC was granted rate base treatment under the terms ofthe RMAand is included in the Company's revenue requirements through an amortiza-tion included in rates over forty years on a straight-line basis that began July 1, 1989.

The RMC reflects the difference between the Company's revenue requirements under conventional ratemaking and the revenues resulting from the implementation ofthe rate moderation plan provided for in the RMA. This revenue difference, together with a carrying charge equal to the allowed rate ofreturn on rate base, has been deferred. The RMC has provided the Company with a substantial amount ofnon-cash earnings since the effective date ofthe 1989 Settlement through December 31, 1992, because thc revenues provided under the RMAwere less than the revenues required under conventional ratemaking. During 1993, however, as revenues provided under the RMAbegan to exceed the revenues that would have been provided under conventional ratcmaking the RMC balance began to decline.

Pursuant to the 1989 Settlement, the Company has received six electric rate increases consistent with the objectives ofthe RMA. In response to the Company's rate filingin December 1990, the PSC approved the Long Island Lighting Company Ratemaking and Performance Plan (LRPP) in November 1991, which provided for annual electric rate increases of4.15%,

4.1% and 4.0% effective December 1, 1991, 1992 and 1993, respectively. Effective December 1, 1993, the Company began receiving the third ofthese three annual electric rate increases.

The LRPP provides for an allowed return on common equity from electric operations of 11.6% foreach ofthe three rate years.

The LRPP was designed to be consistent with the RMA's long term goals. One principal objective ofthe LRPP is to reassign risk so that the Company assumes the responsibility for risks within the control ofmanagement, whereas risks largely beyond the control ofmanagement would be assumed by the ratepayers.

One ofthe major components ofthe LRPP provides for a revenue reconciliation mechanism that mitigates the impact on earnings ofexperiencing electric sales that are above or below the LRPP forecast by providing a fixed annual net margin level (defined as sales revenues, net offuel and gross receipts taxes) that the Company willreceive for each ofthe three rate y'ears under the LRPP. Another component ofthe LRPP allows the Company to earn for each rate year up to 60 additional basis points, or forfeitup to 38 basis points, ofthe allowed return on common equity as a result ofits performance withincertain incentive and/or penalty programs. These programs consist ofa customer service performance plan, a demand side management program, a time-of-use program, a partial pass through fuel cost incentive plan and effective December 1, 1993, an electric transmission and distribution reliabilityplan. For the rate years ended November 30, 1993 and 1992, the Company earned approximately $9.2 millionand

$4.3 million, net oftax effects, respectively, based upon its performance withinthese programs. The LRPP contains a mechanism whereby earnings in excess ofthe allowed rate of return on common equity (11.6%), excluding the impacts ofth~

various incentive and/or penalty programs, are shared equally ~

between ratepayers and shareowners. For the rate years ended November 30, 1993 and 1992, the Company earned approxi-mately $8.9 millionand $21.4 million, net oftax effects, respectively, in excess ofits allowed rate ofreturn on common equity which was shared equally between ratepayers and shareowners.

In Did:mbcr 1993, the Company filed a three-year electric rate plan with the PSC for the period beginning December 1, 1994 that minimizes future electric rate increases while retaining consistency with the RMA's objective ofcontinuing the restoration ofthe Company's financial health. The filing provides for zero percentage base rate increases in years one and two ofthe plan and a rate increase of4.3% in the third year. Although base electric rates would be frozen during the first two years ofthe plan, annual rate increases ofapproxi-mately 1% to 2% are expected to result in these years from the operation ofthe Company's fuel cost adjustment (FCA) clause.

The FCA captures, among other amounts, any increases in the cost offuel above the level recovered in base rates and, under a continuation ofthe rate mechanisms provided by the LRPP, any amounts to'be recovered or refunded to ratepayers in excess of

$ 15 millionwhich result from the reconciliation ofrevenue, certain expenses and earned performance incentive components.

The electric rate plan requests an allowed rate ofreturn on equity of 11.0%. The Company's rate filingreflects four underlying objectives: (i) to limitthe balance ofthe RMC

ing the three-year period to no more than its 1992 peak alance of$652 million; (ii)to recover thc RMC within no more than thirteen years of its 1989 inception; (iii)to minimize the final three rate increases that willfollowthe two-year rate freeze period; and (iv) to continue the Company's gradual return to financial health. The Company's'electric rate plan is subject to approval by the PSC.

The Company's current electric rate plan provides forlower annual electric rate increases than originally anticipated under the 1989 Settlement. However, as a result ofchanges in certain assumptions upon which the RMAwas based, their impact on the RMC, and the Company's plans to reduce demand side management (DSM), operations, maintenance and capital ex-penditures, the Company has determined that the overall objectives ofthe RMAcan be met under the multi-year plan described above. As a result oflower than originally anticipated inflation rates, interest costs, property taxes, fuel costs and the return on common equity allowed by the PSC, the RMC, which originally had been anticipated to peak at $ 1.2 billionin 1994, has already peaked at $652 millionin 1992. With thc exception ofan increase in the 1995-1996 period, which is not now projected to cause the RMC to increase above its $652 million peak, the RMC is expected to decline until it is fullyamortized.

Under this electric rate plan, the recovery Ofthe RMC would be tended, ifnecessary, for an additional period ofnot morc an three years beyond the approximate ten-year period envisioned in the RMA. The actual length ofthe RMC extension willdepend on the extent to which the assumptions underlying the rate plan materialize. The Company's current projections indicate that the RMC willbe recovered in eleven years.

For a further discussion ofthe 1989 Settlement and Rate Matters, see Notes 2 and 3 ofNotes to Financial Statements.

Gas In December 1993, the PSC approved a three-year gas rate settlement between the Company and the staff ofthe PSC. The gas rate settlement provides that the Company receive, for the rate years beginning December 1, 1993, 1994 and 1995, annual gas rate increases of4.7%, 3.S% and 2.S%, respectively. In the determination ofthe revenue requirements for the firstyear ofthe gas rate settlemcnt an allowed rate ofreturn on equity of 10.1% was used. The gas rate decision also provides for earnings in excess ofa 10.6% return on equity in any ofthe three rate years covered by the settlement be shared equally between the Company's firmgas customers and its share-owners. The allowed rate ofreturn for the rate year that began December 1, 1992 was 11.0 %.

Electric Competition Non-UtilityGenerators (NUGs)

The development ofthe NUG industry has been encouraged by federal and state legislation. There are two ways that NUGs may negatively impact the Company: first, NUGs may locate on a customer's site, providing part or all ofthat customer' electric energy requirements. The Company estimates that in 1993 sales lost to such on-site NUGs totalled 234 gigawatt-hours (Gwh) in sales or approximately $20 millionin revenues, nct offuel. This represents only 1.0% ofthe Company's 1993 net revenues. Second, in accordance with the Public Utility Regulatory Policy Actof 1978 (PURPA), the Company is required to purchase all the power offered by NUGs that are Qualified Facilities (QF). QFs have the choice ofpricing these sales at either (i) PSC published estimates ofthe Company's long run avoided costs (LRAC)or (ii) the Company's tariff rates. Additionally, until repeal in 1992, New York State law set a minimum price ofsix cents per kilowatt-hour (Kwh) for certain categories ofQFs, considerably above the Company's avoided cost. The six-cent minimum now only applies to contracts entered into before June 1992.

The Company believes that the repeal ofthe six-cent law, coupled with the PSC's updates which resulted in lower LRAC estimates, has significantly reduced the economic advantage to entrepreneurs seeking to compete with the Company.

As ofDecember 31, 1993, 39 QFs were on line and selling approximately 200 megawatts (MW)ofpower to the Company.

The Company estimates that in 1993, thc purchases federal and state law required itto make from QFs cost the Company

$47 millionmore than itwould have cost to generate this power itself.

With the exception ofapproximately 40 MWofpower to be produced at the Stony Brook campus ofthe State University of New York beginning in early 1995, the Company does not expect any new major NUGs to be built on Long Island in the foreseeable future.

Retail Competition For over a decade, the Company has voluntarily provided wheeling ofNew YorkPower Authority (NYPA)power for economic development. As a result, NYPA power has displaced approximately 400 Gwh ofenergy sales. The net revenue loss associated with this amount ofsales is approxi-mately $27 millionor 1.3% ofthe Company's 1993 net revenues. The potential loss ofadditional load is limited by conditions in the Company's current transmission agreements with NYPA.

Competition for customer loads also comes from other electric utilities (including those in Connecticut, New York, and New Jersey) which seek to entice commercial and industrial customers to relocate within their service territories by offering reduced rates and other incentives.

19

In order to retain existing and attract new commercial and industrial customers, the Company offers an Economic Development Rate which provides rate abatement to new or existing customers that qualify under the program approved by the PSC.

Neither federal nor New YorkState law mandates retail wheeling. The Staffofthe PSC has recently recommended that the PSC examine the issues attending retail wheeling.

Conservation and Supply The Company's 1993 Electric Conservation and Load Management Plan called for a cumulative 194 MWreduction in coincident peak demand by December 31, 1993 and a cumulative annualized energy savings of578 Gwh, at a cost of$33.5 million. The Company has met these targets. These reductions were achieved through several different programs including customer education/information, rebate, audit and direct installation which targeted a number ofenergy efficient technologies.

In the fourth quarter of 1993, a modified DSM Plan was filed with the PSC to support the objectives ofthe Company's December 31, 1993 electric rate plan filing.Under this modified plan a greater emphasis willbe placed on the educational aspect ofthe Company's conservation efforts in lieu ofthe conventional reliance on rebates. This willhelp to shift the responsibility for adopting and implementing energy efficient practices away from the utilityand to the customer.

The Company's current electric load forecasts indicate that, with continued implementation ofits conservation and load management programs and with the availability ofelectricity provided by QFs located within the Company's service territory, the Company's existing generating facilitics, its portion ofnuclear energy generated at NMP2 and power purchased from other electric systems are adequate to meet the energy demands on Long Island beyond the end ofthe century.

Investment Rating The Company's securities are rated by Moody's Investors Service, Inc. (Moody's), Standard and Poor's Corporation (S&P), Fitch Investors Service, Inc. (Fitch) and Duffand Phelps (D&P).

During the period 1989 through 1992, the rating agencies significantly upgraded their ratings ofthe Company's securities. In 1993, both Moody's and Fitch reaffirmed their assigned ratings on the Company's securities. S&P however, lowered its ratings on the Company's First Mortgage Bonds and G&RBonds one level to minimum investment grade and lowered its ratings on the Company's Debentures and Preferred Stock to one level below minimum investment grade. D&P lowered its ratings on the Company's debentures and preferred stock one level.

S&P's actions reflect its concerns regarding the utilityindustry's challenges relating to intensified competitive pressures, sluggish demand expectations, slow earnings growth prospects, high common dividend payouts, environmental cost pressures and nuclear operating and decommissioning costs.

Clean AirAct In late 1990, significant amendments to the federal Clean Air Act were adopted. As a result, the Company expects that it willhave to expend $4.3 millionin 1994 to meet continuous emission monitoring requirements and $3.5 millionin 1994 and

$2.0 millionin 1995 to meet Phase I nitrogen oxide (NOx) reduction requirements. In addition, subject to regulations that have not yet been issued, the Company estimates that it may be required to expend as much as $ 125 millionby May 1999 to meet Phase IINOx reduction requirements and approximately

$50 millionby 2000 to meet requirements for the control of hazardous air pollutants from power plants. The Company believes that all such costs would be recoverable in rates.

20

ults ofOperations Earnings Summary results ofearnings for the years 1993, 1992 and 199,1 were as follows:

(In millions ofdollars and shares except earnings per share)

Rate Increases Sales Volumes Fuel Cost Recoveries Total (ln millionsofdollars)

'93/<92

'92/'91 75 72 60 (61) 22 (13)

$ 157 (2)

Net Income Preferred Stock Dividend R

uirements 1993 1992 1991 296 302 305 56 64 66 For all periods, net income, earnings for common stock and earnings per common share include a non-cash allowance for funds used during construction (AFC) and the effects of the RMC.

Overall earnings remained stable in 1993 while the Company's improved cash flowcontinued, consistent with the 1989 ettlement. The earnings in the electric business were lower in 993 when compared to 1992 due primarily to the expensing of previously deferred storm costs, lower interest rates associated with the short-term investments and regulatory adjustments.

The lower level ofearnings in the electric business was offset by a significant increase in the gas business earnings. The Company saw continued expansion in the gas business in 1993.

Revenues Total revenues in 1993, including revenues from recovery of fuel costs, were $2.9 billion, representing an increase of$259 millionor 9.9% over 1992 revenues.'Total revenues for the Company's electric and gas operations for the years 1993, 1992 and 1991 were as follows:

Earnings for Common Stock 240 238 239 Average Shares Outstanding 112.1 111.4 111.3 Earnings per Common Share

$ 2.15

$ 2.14

$ 2.15 AFC &RMC (Deducted)

Included in Net Income (25) 60 183 AFC&RMC-%ofNetIncome-(8)%

20%

60%

Residential Commercial/Industrial Other 7,118 6,788 7,023 8,257 8,181 8,322 449 471 469 Rate Increases The Company received electric rate increases of4.0% effective December 1, 1993 and 4.1% effective December 1, 1992.

These rate increases provided $75 millionin additional revenues for 1993 when compare'd to 1992. A 4.15% rate increase effective December 1, 1991 provided $72 millionin additional revenues for 1992 when compared to 1991.

Sales Volumes The increase in revenue from sales volumes was primarily attributable to warmer weather experienced in the summer of 1993 when compared to the same period in 1992. The decrease in revenues from sales volumes for 1992 when compared to 1991 is also attributable to weather. The Company's current electric rate structure, discussed above under the heading "Rate Matters," provides for a revenue reconciliation mechanism which mitigates the impact on earnings ofexperiencing electric sales that are above or below the levels reflected in rates. As a result oflower than adjudicated electric sales, the Company recorded non-cash income, which is included in "Other Regulatory Amortizations" of$43.5 million, $78.5 millionand

$0.4 millionin 1993, 1992 and 1991, respectively. For a further discussion on the recoverability ofthese amounts see the discussion under the heading "Rate Matters."

Summary ofelectric kilowatt hour (Kwh) sales for the years 1993, 1992 and 1991 were as follows:

(in millions ofKwh) 1993 1992 1991 Electric Gas (In millionsofdollars) 1993 1992 1991

$ 2,352

$ 2,195

$ 2,197 529 427 351 System Sales Power Pool Sales Total Sales 15,824 15,440 15,814 304 227 598 16,128 15,667 16,412 Total Revenues

$ 2,881

$ 2,622

$ 2,548 E<lectric Revenues In 1993, electric revenues increased $ 157 millionwhen compared to 1992. Revenues in 1992 had decreased $2 million compared with 1991. The changes in the level ofrevenues hen compared to the prior year resulted from the following factors:

The increase in residential and commercial/industrial sales in 1993 was largely due to the warmer weather experienced during the summer months. Residential sales, representing 45% ofsystem sales, were up by 4.9% when compared with 1992, while commercial/industrial sales, which accounted for 52% ofsystem sales, increased by 0.9%. Power pool sales fluctuate with relative costs and power pool system availabilities.

The average number ofelectric customers served in 1993 and 1992 was approximately 1,013,000 and 1,009,000, respectively.

The customer increase in 1993 is similar to the increase experienced in 1992 when compared to 1991.

Summary ofgas d era rh arm (drh) sales for Ihe years 1993, 39~

and 1991 were as follows:

gn thousands ofdth) 1993 1992 1991 Fuel Cost Recoveries Total electric fuel cost recoveries for 1993 were up $22 million compared with 1992, primarily as a result ofhigher sales volumes, partially offset by a decrease in the average cost of fuel. In 1992, fuel cost recoveries decreased by $ 13 million compared with 1991, principally due to lower sales volumes, partially offset by an increase in the average cost offuel.

Gas Revenues Space Heating Non-S ace Heating Total Firm Interruptible Total S stem Off< stem Sales Total Sales 51,557 48,751 41,323 7,626 7,541 7,366 59,183 56,292 48,689 5,920 5,090 4,538 65,103 61,382 53,227 2,894 67,997 61,382 53,227 Rate Increases Sales Volumes Fuel Cost Recoveries Total

$ 35 17 34 50 33 9

$ 102

$ 76 Rate Increases The Company received a gas rate increase of4.7%, effective December 31, 1993, but was permitted by the PSC to recognize additional revenues of$4.6'million in 1993, as ifthe rate increase had been effective on December 1, 1993. The Company had also received rate increases of7.1%, effective December 1, 1992, and 4.1%, effective December 1, 1991.

The effects ofthese rate increases was to increase revenues by

$35 millionin 1993 when compared with 1992, and by $ 17 millionin 1992 when compared with 1991.

Sales Volumes The increase in 1993 revenues due to sales volumes was primarily due to customer additions and conversions resulting from the Company's gas expansion program. The Company added over 9,000 new gas space heating customers to its system in 1993. In 1992, the Company added approximately 10,000 new gas space heating customers.

In 1993, gas revenues increased by $ 102 million,or 23.8%,

when compared to 1992. Revenues in 1992 increased by $76 million, or 21.7%, when compared to 1991. The changes in the level ofrevenues when compared to the prior year resulted from the followingfactors:

(ln millionsofdollars) f931392

'92/'91 Fuel Cost Recoveries Recoveries ofgas fuel expenses in 1993 revenues increased by

$33 millioncompared with 1992, primarily due to higher sales volumes. In 1992, fuel recovery revenues had increased by

$9 million, primarily due to higher average gas prices.

Fuels for Electric Operations Oil Gas Nuclear'urchased Power Total Gas Fuels Total 180 190 301 93 79 66 13 11 13 293 280 214 579 560 '94 249 182 175 828 742 769 The Company has significantly reduced the amount ofoilitwould otherwise have used to generate electricity by burning gas, pur-chasing power and utilizingnuclear generation from NMP2.

Summary ofelectric fuel and purchased power mix for the years 1993, 1992 and 1991 were as follows:

(Percent ofsystem energy requirements) 1993 1992 1991 Fuels and Purchased Power Expenses for fuels and purchased power increased by $86 millionin 1993 compared with 1992, and decreased by $27 millionin 1992 compared with 1991.

Summary offuel and purchased power expenses for the years 1993, 1992 and 1991 were as follows:

gn millionsofdollars) 1993 1992 1991 Oil Gas Nuclear Purchased Power Total 33%

37%

50%

19 19 18 7

6 7

41 38 25 100%

100%

100 o

22

~Operations and Maintenance Expenses Total operations and maintenance expenses, excluding fuel and purchased power, for 1993, 1992 and 1991 were $522 million,

$498 millionand $523 million, respectively. The $24 million, or 4.8%, increase in 1993 when compared to 1992 was primarily due to the recognition ofpreviously deferred storm costs, the recording ofhigher accruals for uncollectible accounts and higher transmission and distribution costs for both the electric and gas businesses.

The $25 million, or 4.8%,

decrease in 1992 compared to 1991 was primarily attributable to lower electric operations expenses.

Interest Expense Interest expense for 1993, 1992 and 1991 was $534 million,

$513 millionand $524 million, respectively. The increase in 1993 when compared to 1992 was attributable to higher debt levels and the conversion in June 1992 of$400 millionoftax-exempt securities from a weekly variable interest rate to a higher 30-year fixed rate. Also contributing to the increase, was the issuance in November 1992 of30-year fixed rate debentures, the proceeds ofwhich were used to eliminate variable rate bank debt. The conversion ofthe tax-exempt securities and refinancing ofbank debt was done in order to take advantage ofhistorically low interest rates. Partially offsetting this increase in interest expense were the effects of the Company's aggressive refinancing ofhigher-cost debt in 1993. The decrease in 1992 when compared to 1991 is due to significantly lower interest rates on the Company's outstanding debt, primarily resulting from the Company's aggressive refinancing efforts in the latter part of 1991 and during 1992.

Rate Moderation Component In 1993, the Company recorded non~h charges to income of approximately $49 millionreflecting the amortization ofthe RMC offset by related carrying charges. In 1992 and 1991, the Company recorded noncash credits to income ofapproxi-inately $73 millionand $269 million, respectively, representing the accretion of the RMC and related carrying charges. For a discussion ofthe RMC and RMA, see Notes 2 and 3 ofNotes to Financial Statements.

Base Financial Component For each ofthe years 1993, 1992 and 1991, the Company recorded non~h charges to income ofapproximately $ 101 million, reflecting the continuing amortization ofthe BFC, whiclt is afforded rate base treatment under the RMA. For a further discussion ofthe BFC and 1989 Settlement, see Notes 1

and 2 ofNotes to Financial Statements.

Accounting Pronouncements Effective January 1, 1993 the Company adopted the provisions ofStatement ofFinancial Accounting Standards (SFAS) No. 106, Employers'ccounting for Postretirement Benefits Other Than Pensions. SFAS No. 106 requires the Company to recognize the expected cost ofproviding postretirement benefits when employee services are rendered rather than on a pay-as-you-go method. The Company recorded an accumulated postretirement benefit obligation and corresponding regulatory asset of approximately $376 millionwhich represents the transition obligation at January 1, 1993. As a result ofadopting SFAS No. 106, the Company's annual postretirement benefit cost for 1993 increased by approximately $28 millionabove the amount that would have been recorded under the pay-as-you-go method.

This additional noncash postretirement benefit cost has been accounted for as a regulatory asset. The PSC has permitted recovery ofthese regulatory assets through rates. The adoption ofSFAS No. 106 had no impact on net income for the year ended December 31, 1993. For a further discussion ofSFAS No. 106, see Note 8 ofNotes to Financial Statements.

Effective January 1, 1993 the Company adopted SFAS No.

109, Accounting for Income Taxes. As permitted under SFAS No. 109, the Company has elected not to restate the financial statements ofprior years. The adoption ofSFAS No. 109 is in compliance with the PSC's Statement ofInterim Policy on Accounting and Ratemaking issued in January 1993. This statement asserts that the adoption and ongoing implementation ofSFAS No. 109 on an interim basis willbe done in such a manner that all its provisions shall be complied with on a revenue neutral basis. As ofJanuary 1, 1993, the cumulative adjustment to the deferred tax liabilityand the corresponding regulatory asset is approximately $ 1.6 billion. The $800 million increase from the amount reported in interim financial statements results from the Company's further analysis ofdeferred taxes to recognize SFAS No. 109 requirements to present tax assets and liabilities gross. SFAS No. 109 requires, among other matters, recognition ofthe amount ofcurrent and deferred taxes payable or refundable at the date ofthe financial statements as a result of all events that have been recognized in the financial statements

'nd adjustment ofdeferred income taxes for an enacted change in tax laws. For regulated enterprises, SFAS No. 109 prohibits net oftax accounting and reporting and requires recognition of a deferred tax liabilityfor the tax benefits which are flowed through to its customers. A regulatory asset or liabilitywillbe recognized relating to such items ifit is probable that the future increase or decrease in taxes payable thereon shall be recovered from or returned to customers through future rates. For a further discussion ofSFAS No. 109, see Notes 1 and 10 of Notes to Financial Statements.

Selected Financial Data Additional information respecting revenues, expenses, electric and gas operating income and operations data and balance sheet information for the last five years is provided in Tables 1

through 9 ofSelected Financial Data. Information with regard to the Company's business segments for the last three years is provided in Note 11 ofNotes to Financial Statements.

23

Financial Statements Balance Sheet Assets AtDcccmbcr 31 UtilityPlant Electric Gas Common Construction work in progress Nuclear fuel in process and in reactor Less Accumulated depreciation and amortization Total Net UtilityPlant Regulatory Assets Base financial component (less accumulated amortization of$454,369 and $353,398)

Rate moderation component Shoreham post settlement costs Shoreham nuclear fuel Postretirement benefits other than pensions Regulatory tax asset Other Total Regulatory Assets NonutilityProperty and Other Investments Current Assets Cash and cash equivalents Special deposits Customer accounts receivable fess allowance for doubtful accounts of$23,889 and $24,375)

Other accounts receivable Accrued unbilled revenues Materials and supplies at average cost Fuel oil at average cost Gas in storage at average cost Prepayments and other current assets Total Current Assets Deferred Charges Unamortized cost ofissuing securities Accumulated deferred income taxes Other Total Deferred Charges Total Assets Sce Notes to Financial Statements.

1993 3,544,569 860,899 201,418 176,504 16,533 4,799,923 1,452,366 3,347,557 3,584,461 609,827 777,103 75,497 402,921 1,848,998 311,832 7,610,639 23,029 248,532 23,439 249,074 12,199 170,042 68,882 35,857 75,182 41,652 924,859 350,239 1,157,009 42,705 1,549,953

$ 13,456,037 gn thousands ofdollars 3,429,803 760,635 172,703 161,663 19,216 4,544,020 1,382,872 3,161,148 3,685,432 651,657 586,045 77,629 220,380 5,221,143 20,730 309,485 23,683 208,049 6,937 143,172 86,482 51,702 47,002 40,402 916,914 380,267 1,027,733 36,524 1,444,524

$ 10,764,459

apitalization and Liabilities At December 31 Capitalization Long-term debt Unamortized premium and (discount) on debt Preferred stock redemption required Preferred stock no redemption required Total Preferred Stock Common stock Premium on capital stock Capital stock expense Retained earnings Total Common Shareowners'quity Total Capitalization Regulatory Liabilities Regulatory liabilitycomponent 1989 Settlement credits Regulatory tax liability Other Total Regulatory Liabilities Current Liabilities urrent maturities oflong-term debt urrent redemption requirements ofpreferred stock Accounts payable and accrued expenses Accrued taxes (including federal income tax of$28,424 and $27, 100)

Accrued interest Dividends payable Class Settlement Customer deposits Total Current Liabilities Deferred Credits Class Settlement Accumulated deferred income taxes Other Total Deferred Credits Reserves for Claims and Damages Pensions and Other Postretirement Benefits Commitments and Contingencies Total Capitalization and Liabilities See Notes to Financial Statements.

1993 4,887,733 (17,393) 4,870,340 649,150 64,038 713,188 561,662 1,010,283 (50,427) 711,432 2,232,950 7,816,478 436,476 155,081 177,669 138,612 907,838 600,000 4,800 277,519 52,656 142,409 54,542 30,000 27,046 1,188,972 164,942 2,932,029 12,622 3,109,593 8,714 424,442

$ 13,456,037 (ln thousands ofdollars) 4,755,733 (14,731) 4,741,002 557,900 154,276 712, 176 558,002 998,089 (39,304) 667,988 2,184,775 7,637,953 515,835 164,294 100,470 780,599 590,000 8,200 275,612 67,525 131,179 53,966 30,000 24,815 1,181,297 167,066 970,373 9,871 1,147,310 2,687 14,613

$ 10,764,459

Statement of Income

'or year ended December 31 (ln thousands ofdollars except per share amount~

1993 1992 199~/

Revenues Electric Gas Total Revenues Expenses Operations fuel and purchased power Operations other Maintenance Depreciation and amortization Base financial component amortization Regulatory liabilitycomponent amortization

'989 Settlement credits amortization Other regulatory amortizations Rate moderation component Operating taxes Federal income tax current Federal income tax deferred and other Total Expenses Operating Income Other Income and (Deductions)

Allowance for other funds used during construction Rate moderation component carrying charges Other income and deductions, net Class Settlement Federal income tax (charge) deferred and other Total Other Income and (Deductions)

Income Before Interest Charges Interest Charges and (Credits)

Interest on long-term debt Other interest Allowance for borrowed funds used during construction Total Interest Charges and (Credits)

Net Income Preferred stock dividend requirements Earnings for Common Stock Average Common Shares Outstanding (000)

Earnings pcr Common Share Dividends Declared per Common Share See Notes to Financial Statements.

$ 2,352,109 528,886 2,880,995 827,591 387,808 133,852 122,471 100,971 (79,359)

(9,214)

(18,044) 88,667 385,847 6,324 1789530 2,125,444 755,551 2,473 40,004 38,997 (23,178) 12,578 70,874 826,425 466,538 67)534 (4,210) 529,862 296,563 56,108 240,455 112,057 2.15 1.76

$ 2,194,632 427,207 2,621,839 741,784 372,209 125,736 119,137 100,971 (79,359)

(9,214)

(22,072)

(30,444) 388,988 530 172,468 1,880,734 741,105 4,725 42,837 29,273 (22,541) 12,036 66,330 807,435 450,621 62,226 (7,386) 505,461 301,974 63,954 238,020 111,439 2.14 1.72

$ 2,196,568 351,161 2,547,729 768,702 375,267 147,492 118,955 100,971 (79,359)

(9,214) 10,375 (228,572) 388,380 515 168,937 1,762,449 785,280 2,202 40,456 35,492~

(25,467)~

(12,201) 40,482 825,762 472,974 50,842 (3,592) 520,224 305,538 66,394 239,144 111,348 2.15 1.60 26

"tatement of Cash Flows (ln thousands ofdollars) r year ended December 31 Operating Activities Net Income Adjustments to reconcile net income to net cash provided by operating activities Fuel moderation component Provision fordoubtful accounts Depreciation and amortization Base financial component amortization Regulatory liabilitycomponent amortization 1989 Settlement credits amortization Other regulatory amortizations Rate moderation component Rate moderation component carrying charges Class Settlement Amortization ofcost ofissuing and redeeming securities Federal income tax deferred and other Allowance for other funds used during construction Other Changes in operating assets and liabilities Accounts receivable Accrued unbilled revenues Materials and supplies, fuel oil and gas in storage Prepayments and other current assets A'ccounts payable and accrued expenses ccrued taxes Other Net Cash Provided by Operating Activities Investing Activities Construction and nuclear fuel expenditures Shoreham post settlement costs Other Net Cash Used in Investing Activities Financing Activities Proceeds from issuance oflong-term debt Redemption oflong-term debt

~

Proceeds from sale ofpreferred stock Redemption ofpreferred stock Preferred stock dividends paid Common stock dividends paid Cost ofissuing and redeeming securities Other Net Cash (Used in) Provided by Financing Activities Net (Decrease) Increase in Cash and Cash Equivalents Cash and cash equivalents at beginning ofyear Net (decrease) increase in cash and cash equivalents Cash and Cash Equivalents at End ofYear 1993 296,563 18,555 122,471 100,971 (79,359)

(9,214)

(18,044) 88,667 (40,004) 23,178 52,063 165,952 (2,473)

(2,197)

(65,898)

(26)870) 5,265 (1,250)

(8,800)

(14,869)

(22,694) 582,013 (302,220)

(207,114)

(934)

(510,268) 1,089,770 (960,000) 201,709 (205,600)

(56,727)

(195,794)

(17,036) 10,980 (132,698)

(60,953) 309,485 (60,953) 248,532 1992 301,974 16,329 119,137 100,971 (79,359)

(9,214)

(22,072)

(30,444)

(42,837) 22,541 41,204 160,432 (4,725) 699 (14,275)

(6,607)

(10,933)

(5,548) 62,513 7,351 (17,073) 590,064 (268,179)

(227,658)

(1,484)

(497,321) 1,659,928 (1,344,283) 411,373 (389,428)

(69,923)

(190,477)

(166,066) 7,520 (81,356) 11,387 298,098 11,387 309,485 1991 305,538 34,025 35,431 118,955 100,971 (79,359)

(9,214) 10,375 (228,572)

(40,456) 25,467 27,456 181,138 (2,202) 38,068 (26,045) 2,352 28,217 (1,035) 34,560 3,926 (39,168) 520,428 (235,349)

(158,432)

(3,923)

(397,704) 1,532,247 (1, 129,000) 63,130 (70,638)

(65,838)

(172,584)

(88,586) 3,707 72,438 195,162 102,936 195,162 298,098 terest paid, before reduction for the allowance for borrowed funds used during construction Federal income tax paid Federal income tax refunded See Notes to Financial Statements.

469,978 6,000 1,000 424,842 2,100 1,566 477,240 1,650 642 27

Statement of Capitalization Shares Outstanding (tn thousands ofdolla At December 31 1993 1992 1993 199 Common Shareowners'quity Common stock, $5.00 par value Premium on capital stock Capital stock expense Retained earnings 112,332,490 111,600,376 561,662 1,010,283 (50,427) 711,432 558,002 998,089 (39,304) 667,988 Total Common Shareowners'quity 2,232,950 2,184,775 Preferred Stock Redemption Required Par value $ 100 per share 7.40% Series L 8.40% Series M 8.50% Series R 7.66% Series CC Less Sinking fund r uirement Par value $25 per share

$2.47 Series 0

$2.35 Series Z 7.95% Series AA

$ 1.67 Series GG

$ 1.95 Series NN 7.05% Series QQ 6.875% Series UU Less Sinking fund requirement Total Preferred Stock Redem tion Re uired Prcferrcd Stock No Redemption Required Par value $100 per share 5.00%'Series B 4.25% Series D 4.35% Series E 4.35% Series F 5'/s% Series H SsA% Series IConvertible 8.12% Series J 8.30% Series K Par value $25 per share

$2.43 Series P Total Preferred Stock No Redem tion R uired Total Preferred Stock 192,500 112,500 570,000 14,520,000 880,000 1,554,000 3,464,000 2,240,000 100,000 70,000 200,000 50,000 200,000 20,375 203,000 238,000 150,000 570,000 880,000 2,600,000 14,520,000 100,000 70,000 200,000 50,000 200,000 22,757 250,000 300,000 1,400,000 19,250

'1,250 57,000 4,800 82,700 363,000 22,000 38,850 86,600 56,000 566,450 649,150 10,000 7,000 20,000 5,000 20,000 2,038 64,038 64,038 713,188 20,300 23,800 15,000 57,000 6,200 109,900 22,000 65,000 363,000 2,000 448,000 557,900 10,000 7,000 20,000 5,000 20,000 2,276 25,000 30,000 119,276 35,000 154,276 712,176 Long-Term Debt Maturity Interest Rate.

Series First Mortgage Bonds (excludes Pledged Bonds)

April 1, 1993 June 1, 1994 June 1, 1995 March 1, 1996 April 1, 1997 September 1, 1999 April 1, 2001 December 1, 2001 September 1, 2002 December 1, 2003 Total First Mortgage Bonds 4.40%

4 5/8%

4.55%

5 1/4%

5 1/2%

8.20%

7 1/4%

7 1/2%

7 5/8%

8 1/8%

M N

0 p

Q R

U V

W X

25,000 25,000 40,000 35,000 125,000 40,000 25,000 25,000 40,000 35,000 40,000 50,000 50,000 60,000

(in thousands ofdollars)

December 31 Maturity InterestRate Series 1993 1992 General and Refunding Bonds May I, 1996 February 15, 1997 May 15, 1999 May 15, 2006 December I, 2006 May I, 2007 July 15, 2008 May I, 2021 July I, 2024 Total General,and Refunding Bonds Debentures April I, 1993 November 15, 1993 June 15, 1994 November 15, 1994 June 15, 1999 July 15, 1999 January IS, 2000 July 15, 2001 March 15, 2003 March I, 2004 June I, 2005 March I, 2007 June 15, 2019 July 15, 2019 November I, 2022 March 15, 2023 Total Debentures Authorityk'inancing Notes Pollution Control Revenue Bonds December I, 2006 December I, 2009 October I, 2012 March 1, 2016 Electric Facilities Revenue Bonds

, September 1,2019 June I, 2020 December I, 2020 February I, 2022 August 1, 2022 November I, 2023 November I, 2023 Industrial Development Revenue Bonds December I, 2006 Total Authorit Financing Notes "Unamortized Premium and (Discount) on Debt otal Long-Term Debt ss Current maturitics 8 3/4%

8 3/4%

7.85%

8.50%

8 5/8%

8 5/8%

7.90%

9 3/4%

9 5/8%

11 3/8%

11.70%

10.25%

11.75%

10.875%

7.30%

7.30%

6.25%

7.05%

7.00%

7.125%

7.50%

11.375%

8.90%

9.00%

8.20%

7.5%

7.8%

8 I/4%

2.5%

7.15%

7.15%

7.15%

7.15%

6.9%

2.95%

2.85%

7.5%

1976A 1979B 1982 1985 A,B 1989 A,B 1990A 1991A 1992 A,B 1992 C,D 1993 A 1993 B 1976A,B 415,000 250,000 56,000 75,000

.80,000 415,000 375,000 1,666,000 400,000 175,000 30,545 397,000 36,000 145,000 150,000 59,000 200,000 142,000 4,513 420,000 451,000 270,000 2,880,058 28,375 19,100 17,200 150,000 100,000 100,000 100,000 1OO,OOO 100,000 50,000 50,000 2,000 816,675 (17,393) 5,470,340 600,000 415,000 250,000 56,000 75,000 50,000 85,000 80,000 415,000 375,000 1,801,000 375,000 175,000 400,000 175,000 30,545 397,000 4,513 420,000 4S1,000 2,428,058 28,375 19,100 17,200 1S0,000 100,000 100,000 100,000 100,000 100,000 2,000 716,675 (14,731) 5,331,002 590,000 Total Lon -Term Debt Less Current Maturities Total Ca italization Sec Notes to Financial Statcmcnts.

4,870,340 4,741,002 29

$7,816,478

$7,637,953

Statement of Retained Earnings Balance at January 1

Net income for the year 1993 667,988 296,563 964,551 922,347 865,943 (ln thousands ofdollar 1992 199 620,373 560,405 301,974 305,538 Deductions Cash dividends declared on preferred stock Cash dividends declared on common stock Capital stock expense 55,861 197,236 22 62,387 191,693 279 67,261 178,169 140 Balance at December 31 See Notes to Financial Statements.

711,432 667,988 620,373 Notes to Financial Statements Note 1. Summary ofSignificant Accounting Policies Regulation The Company's accounting policies conform to generally accepted accounting principles (GAAP) as they apply to a regulated enterprise. Its accounting records are maintained in accordance with the Uniform Systems ofAccounts prescribed by the Public Service Commission ofthe State ofNew York (PSC) and the Federal Energy Regulatory Commission (FERC).

UtilityPlant Additions to and replacements ofutilityplant are capitalized at original cost, which includes material, labor, overhead and an allowance for the cost offunds used during construction. The cost ofrenewals and betterments relating to units ofproperty is added to utilityplant. The cost ofproperty replaced, retired or otherwise disposed ofis deducted from utilityplant and, generally, together with dismantling costs less any salvage, is charged to accumulated depreciation. The cost ofrepairs and minor renewals is charged to maintenance expense. Mass properties (such as poles, wire and meters) are accounted for on an average unit cost basis by year ofinstallation.

Allowance for Funds Used During Construction The Uniform Systems ofAccounts defines the allowance for funds used during construction (AFC) as the net cost of borrowed funds for construction purposes and a reasonable rate ofreturn upon the utility's equity when so used. AFC is not an item ofcurrent cash income. AFC is computed monthly using a rate permitted by FERC on a portion ofconstruction work in progress. The average annual AFC rate, without giving effect to compounding, was 9.73%, 9.98% and 10.74% for the years 1993, 1992 and 1991, respectively.

Depreciation The provisions for depreciation result from the application of straight-line rates to the original cost, by groups, ofdepreciable properties in service. The rates are determined by age-life studies performed annually on depreciable properties. Depreciation for electric properties was equivalent to approximately 3.0%, 3.2%

and 3.3% ofrespective average depreciable plant costs for the years 1993, 1992 and 1991. Depreciation for gas properties was equivalent to approximately 2.0%, 2.6% and 2.9% of respective average depreciable plant costs for the years 1993, 1992 and 1991.

Financial Resource Asset GAAP authorizes recognition ofthe existence ofa regulatory asset when it is probable that a regulator willpermit full recovery ofa previously incurred cost. Pursuant to the 1989 Settlement and in accordance with GAAP, the Company recorded a regulatory asset known as the Financial Resource Asset (FRA). The FRA is designed to provide the Company with sufficient cash flows to assure its financial recovery. The FRA has two components, the Base Financial Component (BFC) and the Rate Moderation Component (RMC). The Rate Moderation Agreement (RMA),one ofthe constituent docu-ments ofthe 1989 Settlement, provides for the fullrecovery of the FRA. For a further discussion ofthe 1989 Settlement and the FRA, see Note 2.

Cash and Cash Equivalents Cash equivalents are highly liquid investments with maturities ofthree months or less when purchased. The carrying amount approximates fair value because ofthe short maturity ofthese

'nvestments.

Fair Values ofFinancial Instruments The fair values for the Company's long-term debt and redeem-able preferred stock are based on quoted market prices, where available. The fair values forall other long-term debt and redeemable preferred stock are estimated using a discounted cash flowanalyses which is based upon the Company's current incremental borrowing rate forsimilar types ofsecurities.

30

apitalization-Premiums, Discounts and Expenses

~

~

Premiums or discounts and expenses related to the issuance oflong-term debt are amortized over the lifeofeach issue.

Unamortized premiums or discounts and expenses related to issues oflong-term debt that are refinanced are amortized and recovered through rates over the shorter lifeofeither the redeemed or new issues. Capital stock expense and redemption costs related to certain issues ofpreferred stock that have been refinanced as well as the cost of issuance ofthe preferred stock issued are recorded as deferred charges. These amounts are being amortized and recovered through rates over the shorter lifeofthe redeemed or ncw issues.

Revenues The Company accrues electric and gas revenues for services rendered to customers but not billed at monthwnd.

Fuel Cost Adjustments The Company's electric and gas tariffs include fuel cost adjustment (FCA) clauses which provide for the disposition of the difference between actual fuel costs and the fuel costs allowed in the Company's base tariffrates (base fuel costs). The Company defers these differences to future periods in which they willbe billed or credited to customers, except for base electric fuel costs in excess ofactual electric fuel costs, which are currently credited to the RMC as incurred.

Federal Income Taxes Effective January 1, 1993, the Company adopted the Financial Accounting Standards Board (FASB) Statement ofFinancial Accounting Standards (SFAS) No. 109, Accounting for Income Taxes. As permitted under SFAS No. 109, the Company has elected not to restate the financial statements ofprior years. The adoption ofSFAS No. 109 is in compliance with the PSC's Statement ofInterim Policy on Accounting and Ratemaking issued January 15, 1993. This statement asserts that the adoption and ongoing implementation ofSFAS No. 109 on an interim basis willbe done in such a manner that all its provisions shall be complied with on a revenue neutral basis. As of January 1, 1993, the cumulative adjustment to the deferred tax liabilityand the corresponding regulatory asset is approxi-mately $ 1.6 billion. The $800 million increase from the amount reported in interim financial statements results from the Company's further analysis ofdeferred taxes to recognize SFAS No. 109 requirements to present tax assets and liabilities gross. SFAS No. 109 requires, among other matters, recogni-tion ofthe amount ofcurrent and deferred taxes payable or refundable at the date ofthe financial statements as a result of all events that have been recognized in the financial statements and adjustment ofdeferred income taxes for an enacted change in tax laws. For regulated enterprises, SFAS No. 109 prohibits net oftax accounting and reporting and requires recognition of a deferred tax liabilityfor the tax benefits which are fiowed through to its customers. A regulatory asset or liabilitywillbe recognized relating to such items ifit is probable that the future increase or decrease in taxes payable thereon shall be recovered from or returned to customers through future rates.

The tax effects of'other differences between income for financial statement purposes and for federal income tax purposes are accounted for as current adjustments in federal income tax provisions.

Prior to the adoption ofSFAS No. 109 the Company provided deferred federal income taxes with respect to certain items of income and expense that were reported in different years in the financial statements and the tax return.

The Company defers the benefit of60% ofpre-1982 gas and pre-1983 electric and 100% ofall other investment tax credits, with respect to regulated properties, when realized on its tax returns. Accumulated deferred investment tax credits are amortized ratably over the lives ofthe related properties.

For ratemaking purposes, the Company provides deferred federal income taxes with respect to certain differences between net income before income taxes and taxable income in certain instances when approved by the PSC, as disclosed in Note 10.

Also certain accumulated deferred federal income taxes are deducted from rate base and amortized or otherwise applied as a reduction (increase) in federal income tax expense in.

future years.

Reserves for Claims and Damages Losses arising from claims against the Company, including worker's compensation claims, property damage, extraordinary storm costs and general liabilityclaims, are partially self-insured. Extraordinary, storm losses incurred by the Company are partially insured by certain commercial insurarice carriers.

These insurance carriers provide partial insurance coverage for individual storm losses between $5 millionand $50 million.

Storm losses which are outside ofthe above-mentioned range are self-insured by the Company. Reserves for these losses are based on, among other things, experience, risk ofloss and the ratemaking practices ofthe PSC.

Reclassifications To conform with an order ofthe FERC, dated March 31, 1993, the Company reclassified certain deferred items as regulatory assets and regulatory liabilities on its Balance Sheet. Regulatory assets and liabilities, as defined in this order, are assets and liabilities created through the ratemaking actions ofregulatory agencies.

Certain other prior year amounts have been reclassified in the financial statements to be consistent with the current year' presentation.

Note 2. The 1989 Settlement On February 28, 1989, the Company and the State ofNew York (by its Governor) entered into the 1989 Settlement resolv-ing certain issues relating to the Company and providing, among other matters, for the transfer ofthe Shoreham Nuclear Power Station (Shoreham) and its subsequent decommis-sioning. On February 29, 1992, the Company transferred ownership ofShoreham to the Long Island Power Authority (LIPA),an agency ofthe State ofNew York. Pursuant to the 1989 Settlement, LIPA is responsible for the decommissioning ofShoreham and has estimated that the decommissioning, in which Company employees are participating, willbe completed in 1994. Based on the latest available information, LIPAhas projected that the cost ofdecommissioning Shoreham willtotal approximately $ 164 million. This estimate excludes the costs associated with'the disposal ofShoreham's fuel which is estimated to be $ 122 million. AtDecember 31, 1993, the Company has funded approximately $140 millionand $30 millionofthese costs, respectively. LIPAanticipates that the Nuclear Regulatory Commission (NRC) willterminate its license for Shoreham by the end of 1994.

Upon the effectiveness ofthe 1989 Settlement, in June of 1989, the Company simultaneously recorded on its Balance Sheet the retirement ofits investment ofapproximately $4.2 billion principally in Shoreham and the establishment ofthe FRA, discussed in Note 1.

The BFC, a component ofthe FRA, as initiallyestablished, represents the present value ofthe future net-after-tax cash flows which the RMAprovided the Company for its financial recovery. The BFC was granted rate base treatment under the terms ofthe RMAand is included in the Company's revenue requirements through an amortization included in rates over forty years on a straight-line basis that began July 1, 1989.

At December 31, 1993 and 1992, the unamortized balance of the BFC was approximately $3.6 billionand $3.7 billion, respectively.

The RMC, a component ofthe FRA, reflects the difference between the Company's revenue requirements under conventional ratemaking and the revenues resulting from the implementation ofthe rate moderation plan provided for in the RMA. The RMC is currently adjusted, on a monthly basis, for the Company's share ofcertain Nine MilePoint Nuclear Power Station, Unit 2 (NMP2) operations and maintenance expenses, fuel credits resulting from the Company's electric fuel cost adjustment clause discussed in Note 1 and state gross receipts tax adjustments related to the FRA. The RMC has provided the Company with a substantial amount ofnon~h earnings from the effective date ofthe 1989 Settlement through December 31, 1992.

AtDecember 31, 1993 and 1992, the RMC balance was $610 millionand $652 million, respectively. Prior to December 31, 1992 the RMC had increased as the difference between revenues resulting from the implementation ofthe rate moderation plan provided for in the RMAand revenue requirements under conventional ratemaking, together with a carrying charge equal to the allowed rate ofreturn on rate base, had been deferred. Subsequent to December 31, 1992, the RMC balance has been decreasing as revenues resulting from the implementa-tion ofthe rate moderation plan are greater than revenue requirements under conventional ratemaking. For a further discussion ofthe impact on the amortization ofthe RMC under the Company's current electric rate structure and the Company's proposed electric rate plan for the three-year period beginning December 1, 1994, see Note 3.

Under the 1989 Settlement, certain tax benefits attributable to the Shoreham abandonment are to be shared between rate-payers and shareowners. A regulatory liabilityofapproximately

$794 millionwas recorded in June 1989 to preserve an amount equivalent to the ratepayer tax benefits attributable to the Shoreham abandonment. This amount is being amortized over a ten-year period on a straight-line basis from the effective date ofthe 1989 Settlement. The Company has reclassified the regulatory liabilitycomponent which was previously reported as a reduction ofthe corresponding deferred tax asset arising from the abandonment loss deduction.

Shoreham post settlement costs (decommissioning, payments in lieu ofproperty taxes and other costs as incurred) are being capitalized and amortized and recovered through rates over a forty-year period on a straight-line remaining lifebasis.

I Upon the effectiveness ofthe 1989 Settlement, Shoreham nuclear fuel was reclassified to deferred charges included in the Regulatory Asset section ofthe Balance Sheet and is being amortized and recovered through rates over a forty-year period on a straight-line reniaining life basis.

The 1989 Settlement credits on the Balance Sheet ofapproxi-mately $ 155 million,.net ofamortization, reflect an adjustment ofthe book write-offto the negotiated 1989 Settlement amount.

A portion ofthis amount is being amortized over a ten-year period. The remaining portion is not currently being recognized for ratemaking purposes under the 1989 Settlement.

32

te 3. Rate Matters Electric Pursuant to the 1989 Settlement, discussed in Note 2, the Company received electric rate increases contemplated by the RMAfor each ofthe three rate years in the period ended November 30, 1991. The RMAcontemplates that the Company willapply to the PSC for targeted annual rate increases of4.5% to 5.0% in each year for an eight-year period beginning December 1, 1991. In response to the Company's December 1990 rate filing,the PSC approved the Long Island Lighting Company Ratemaking and Performance Plan (LRPP) in November 1991, which provides that the Company receive, for each ofthe three rate years in the period beginning December 1, 1991, annual electric rate increases of 4.15%, 4.1% and 4.0%, respectively, with an allowed return on common equity from electric operations of 11.6% for each ofthe three rate years. Aftergiving effect to the reductions required by the Class Settlement discussed in Note 4, the Company's annual electric rate increases were approximately 4.15%, 3.9% and 3.9%, with an allowed return on common equity from electric operations of 10.92%, 10.72% and 10.58%, for the rate years beginning December 1, 1991, 1992 and 1993, respectively.

The LRPP was designed to be consistent with the RMA's long-rm goals. One principal objective ofthe LRPP is to reassign sk so that the Company assumes the responsibility for risks within the control ofmanagement, whereas risks largely beyond the control ofmanagement would be assumed by the ratepayers. The LRPP reflects an update ofthe long-range forecast ofthe Company's revenue requirements which was the basis ofthe RMA's initial three rate increases. The LRPP contains three major components revenue reconciliation, expense attrition and reconciliation, and performance incentives.

Revenue reconciliation is provided through a mechanism that reduces the impact ofexperiencing electric sales that are above or below the LRPP forecast by providing a fixed annual net margin level (defined as sales revenues, net offuel and gross receipts taxes) that the Company willreceive over the three rate years under the LRPP. The differences between the actual electric net revenues and the annual net margin level are deferred on a monthly basis during the rate year.

The expense attrition and reconciliation component permits the Company to make adjustments for certain expenses recognizing that certain cost increases are unavoidable due to inflation and changes in the business. The LRPP includes the annual recon-ciliation ofcertain expenses for wage rates, property taxes, interest charges and demand side management (DSM) costs, the eferral and amortization ofcertain costs for enhanced relia-lity, production operations and maintenance expenses, and the pplication ofan inflation index to other expcnscs for the rate years beginning Deccmbcr 1, 1992 and 1993.

Under the performance incentive componerit ofthe LRPP, the Company is allowed to earn for each rate year up to 60 additional basis points, or forfeitup to 38 basis points, ofthe allowed return on common equity as a result ofits performance withincertain incentive and/or penalty programs. These programs consist ofa customer service program, a time-of-use program, a partial pass through fuel cost incentive plan and, effective December 1, 1993, an electric transmission and distribution reliabilityplan. The incentives and/or penalties related to the customer service performance plan, the time-of-use program, the electric transmission'and distribution relia-bilityplan and the partial pass through fuel cost incentive plan are determined on a monthly basis during the rate year and deferred until final approval from the PSC. The incentives earned from the DSM program are collected in rates on a monthly basis through the FCA. Based upon the Company's performance within these programs, the Company earned a total ofapproximately 49 basis points or approximately $9.2 million, net oftax effects, and 23 basis points, or approximately

$4.3 million, net oftax effects, for the rate years ended November 30, 1993 and 1992, respectively.

The deferred balances resulting from the net margin, property taxes, interest expense, wage rates, performance incentives and associated carrying charges, excluding DSM incentives, are netted at the end ofeach rate year. The LRPP established a band whereby the first $ 15 millionofthe total net deferrals are used to increase or decrease the RMC balance. The LRPP provides for the disposition ofthe total net deferrals in excess of the $ 15 millionband. Upon approval by the PSC, the total net deferrals in excess of$ 15 millionare refunded or recovered from the ratepayers through the FCA over a twelve-month period in the followingrate year.

During 1993, the PSC authorized the Company recovery of

$45.2 millionofthe total net deferrals for the rate year ended November 30, 1992. The first$ 15 millionofthe total net deferrals was recorded as an increase to the RMC, with the remaining $30.2 millionbeing recovered from the ratepayers through the FCA through July 31, 1994. For the rate year ended November 30, 1993, the total net deferrals, to be recovered from the ratepayers, subject to PSC review, amounted to approximately $63 millionofwhich $48 millionwillbe recovered through the FCA, over a twelve-month period beginning December 1, 1994.

33

The Company earned $8.9 millionand $21.4 million, net oftax effects, for the rate years ended November 30, 1993 and 1992, respectively, in excess ofits allowed rate ofreturn on common equity of 11.6% which, in accordance with the LRPP, was shared equally between ratepayers (by a reduction to the RMC) and shareowners. Prior to December 1, 1991, the RMA provided that earned returns on common equity in excess of targeted allowed rates ofreturn, were to be applied to reduce the RMC or mitigate rates, as determined by the PSC, at the end ofeach rate year. For the rate year ended November 30, 1991,.the Company earned $ 10.1 million, net oftax effects, in excess ofits allowed rate ofreturn, which was applied as a reduction to the RMC.

To assist in the recovery ofthe RMC balance under the rates provided by the LRPP, the Company, in accordance with the LRPP, has credited the RMC with several deferred ratepayer benefits. In December 1993 and 1992, the Company applied a total ofapproximately $ 10.1 millionand $22.5 millionof various deferred ratepayer benefits to the RMC including the ratepayers portion ofthe excess earnings for the rate years ended November 30, 1993 and 1992, respectively.

In December 1993, the Company filed a three-year electric rate plan with the PSC for the period beginning December 1, 1994 that minimizes future electric rate increases while retaining consistency with the RMA's objective ofcontinuing the restoration ofthe Company's financial health. The electric rate plan provides for zero percentage base rate increases before giving effect to the reductions required by the Class Settlement, discussed in Note 4, in years one and two ofthe plan and a base rate increase of4.3% in the third year prior to giving effect to the reductions required by the Class Settlement. Although base electric rates would be frozen during the first two years ofthe plan, annual rate increases ofapproximately 1% to 2% are expected to result in these years from the operation ofthe Company's FCA. The FCA captures, among other amounts, any increases in the cost offuel above the level recovered in base rates, and under the LRPP, any amounts to be recovered or refunded to ratepayers in excess of$ 15 millionwhich result from the reconciliation ofrevenue, certain expenses and earned performance incentive components, discussed above. The electric rate plan requests an allowed rate ofreturn on equity of 11.0%. The Company's two-year base rate frceze proposal reflects four underlying objectives: (i) to limitthe balance ofthe RMC during the three-year period to no more than its 1992 peak balance of$652 million;(ii)to recover the RMC within no more than thirteen years ofits 1989 inception; (iii)to minimize the final three rate increases that willfollowthe two-year rate freeze period; and (iv) to continue the Company's gradual return to financial health. The Company's electric rate plan is subject to approval by the PSC.

The Company's current electric rate plan provides forlower annual electric rate increases than originally anticipated under the 1989 Settlement. However, as a result ofchanges in certain assumptions upon which the RMAwas based, their impact on the RMC and the Company's plans to reduce DSM, operations and maintenance and capital expenditures, the Company has determined that the overall objectives ofthe RMAcan be met under the multi-year plan described above. As a result of lower than originally anticipated inflation rates, interest costs, property taxes, fuel costs and return on common equity allowed by the PSC, the RMC, which originally had been anticipated to peak at $ 1.2 billionin 1994, has already peaked at $652 million in 1992. With the exception ofan increase in 1995-1996, which is not now projected to cause the RMC to increase above its

$652 millionpeak, the RMC is expected to decline until it is'ully amortized.

Under the electric rate plan, the recovery ofthe RMC would be extended, ifnecessary, for an additional'period ofnot more than three years beyond the approximate tcn-year period envisioned in the RMA. The actual length ofthe RMC extension willdepend on the extent to which the assumptions underlying the rate plan materialize. The Company's current projections indicate that the RMC willbe recovered in eleven years instead often years.

Gas In December 1993, the PSC approved a three-year gas rate settlement between the Company and the Staffofthe PSC. The gas rate settlement provides that the Company receive, for each ofthe rate years beginning December 1, 1993, 1994 and 1995, annual gas rate increases of4.7%, 3.8% and 2.8%, respec-tively. In the determination ofthe revenue requirements for the firstyear ofthe gas rate settlement an allowed rate ofreturn on equity of 10.1% was used. The gas rate decision also provides for earnings in excess ofa 10.6% return on equity in any of the three rate years covered by the settlement be shared equally between the Company's firmgas customers and its share-owners. The allowed rate ofreturn for the rate year that began December 1, 1992 was 11.0%.

34

June 1994 June 1995 June 1996 June 1997 June 1998 June 1999

$30 million

$40 million

$50 million

$60 million

$60 million

$60 million Upon its effectiveness, the Company recorded its liabilityfor the Class Settlement on a present value basis at $ 170 million and simultaneously recorded a charge to income (net oftax effects of$57 million)ofapproximately $ 113 million. Each nonth the Company records the changes in the present value of such liabilitythat result from the passage oftime and from monthly reductions. The Company expects the Class Settlement liabilitywillbe fullysatisfied by May 31, 2000.

As a result ofthe Class Settlement, the Company's electric rate increases on average willbe approximately.2% to.3% per year lower than they would otherwise have been during the Class Settlement period.

ote 4. The Class Settlement The Class Settlement, which became effective on June 28, 1989, resolved a civillawsuit against the Company brought under the federal Racketeer Influenced and Corrupt Organizations Act (RICO Act). The lawsuit which the Class Settlement resolved, had alleged that the Company made inadequate disclosures before the PSC concerning the construction and completion of nuclear generating facilities. The Class Settlement provides the Company's ratepayers with reductions, a'ggregating $390 million,that are to be reflected as adjustments to their monthly electric billsover a ten-year period which began on June 1, 1990.

The reductions in each ofthe remaining twelve-month periods are as follows:

Note 5. Nine MilePoint Nuclear Power Station, Unit2 The Company has an 18% undivided interest in NMP2 which is operated by Niagara Mohawk Power Corporation (NMPC) near Oswego, New York. Ownership ofNMP2 is shared by five cotenants: the Company (18%), NMPC (41%), New York State Electric &Gas Corporation (18%), Rochester Gas and Electric Corporation (14%) and Central Hudson Gas &Electric Corporation (9%). AtDecember 31, 1993, the Company's net utilityplant investment in NMP2 was $759 million, net of accumulated depreciation of$ 119 million, which is included in the Company's rate base. Output ofNMP2 is shared in the same proportions as the cotenants'espective ownership interests. The operating expenses ofNMP2 are also allocated to the cotenants in the same proportions as their respective ownership interests. The Company's share ofthese expenses is included in the appropriate operating expenses on the Statement ofIncome. The Company is required to provide its respective share offinancing for any capital additions to NMP2. Nuclear fuel costs associated withNMP2 are being amortized on the basis ofthe quantity ofheat produced for the generation of electricity.

NMPC has contracted with the United States Department of Energy for the disposal ofnuclear fuel. The Company reimburses NMPC for its 18% share ofthe cost under the contract at a rate of$ 1.00 per megawatt hour ofnet generation less a factor to account for transmission line losses'.

Based upon a study performed by NMPC which reflects a change in the NRC minimum decommissioning funding requirement effective 1993, the Company's share ofthe decommissioning costs for NMP2 is estimated to be $80 million (in 1993 dollars) assuming that decommissioning willcommence in 2027 (which willbe $234 millionin 2027 dollars). The Company's share ofestimated decommissioning costs are being provided for in electric rates and are being charged to operations as depreciation expense. The amount ofaccumulated decom-missioning costs collected from the Company's ratepayers through December 31, 1993 was $7.1 million. Amounts collected by the Company for the decommissioning ofthe contaminated portion ofthe NMP2 plant, which approximate 92% oftotal decommissioning costs, are held in an independent decommissioning trust fund. This fund complies with regula-tions issued by the NRC governing the funding ofnuclear plant decommissioning costs. The Company's funding plan for its share ofdecommissioning costs willprovide reasonable assurance that, at the time oftermination ofoperation, adequate funds for the decommissioning ofthe Company's share ofthe contaminated portion ofNMP2 plant willbe available.

35

Note 6. Capital Stock Preferred Stock The Company has 7,000,000 authorized shares, cumulative preferred stock, par value $ 100 and 30,000,000 authorized shares, cumulative preferred stock, par value $25. Dividends on preferred stock are paid in preference to dividends on common stock or any other stock ranking junior to preferred stock.

Preferred Stock Subject to Mandatory Redemption The aggregate fair value ofredeemable preferred stock with mandatory redemptions at December 31, 1993 and 1992 amounted to $658,795,000 and $581,984,000, respectively, compared to their carrying amounts of$653,950,000 and

$566,100,000, respectively.

AtDecember 31, 1993, the Company had the option to redeem all outstanding preferred stock Series L, $100 par value, and Series R, $ 100 par value, at their optional redemption prices of

$ 102.99 per share and $ 100.50 per share, respectively. No other preferred stock series subject to mandatory redemptions were redeemable at December 31, 1993.'he Company is required to redeem the followingseries of preferred stock through the operation ofvarious sinking fund provisions: (i) on each July 31, 10,500 shares ofthe Series L at a price of$ 100 per share; (ii)on each December 15, 37,500 shares ofthe Series R at a price of$ 100 per share; (iii)on each March 1, commencing March 1, 1999, 77,700 shares of the Series NN at a price of$25 per share; and (iv) on each October 15, commencing October 15, 1999, 112,000 shares ofthe Series UU at a price of$25 per share.'In addition, the Company willhave the noncumulative option to double the number ofshares to be redeemed pursuant to the sinking fund in any year for the preferred stock series mentioned above. The aggregate par value ofpreferred stock required to be redeemed by use ofsinking funds in each ofthe years 1994 through 1996 is $4.8 millionand in 1997 and 1998 is $ 1.1 million.

The Company is also required to redeem certain series ofpre-ferred stock which are not subject to sinking fund requirements.

The scheduled mandatory redemption for these series are as follows: (i) Series CC on August 1, 2002; (ii)Series AAon June 1, 2000; (iii)Series GG on March 1, 1999; and (iv) Series QQ on May 1, 2001.

During 1992, the Company issued $363 millionPreferred Stock, 7.95% Series AAand $57 millionPreferred Stock, 7.66%

Series CC, the proceeds ofwhich were used to redeem $320 millionPreferred Stock, $2.65 Series Yand $55 million Preferred Stock, 9.80% Series S, respectively, at their optional redemption prices.

Preferred Stock Not Subject to Mandatory Redemption The Company has the option to redeem certain series ofits preferred stock. For the series subject to optional redemption at December 31, 1993, the call prices were as follows:

5.00% Series B

$101.00 4.25% Series D

$102.00 4.35% Series E

$ 102.00 4.35% Series F

$ 102.00 5 1/8% Series H

$ 102.00 5 3/4% Series IConvertible

$ 100.00 Preference Stock None ofthe authorized 7,500,000 shares ofnonparticipating preference stock, par value $ 1 per share, which ranks junior to preferred stock, are outstanding.

Common Stock Ofthe 150,000,000 shares ofauthorized common stock at December 31, 1993, 1,789,842 shares were reserved for sale through the Company's Employee Stock Purchase Plan, 5,946,929 shares were committed to the Automatic Dividend Reinvestment Plan (ADRP) and 118,812 shares were reserved for conversion ofthe Series I Convertible Preferred Stock at a rate of$ 17.15 per share. In June 1992, the Company reinstated the ADRP which had been suspended since February 1984.

Common and preferred stock dividend limitations in the mortgage securing the Company's First Mortgage Bonds are not material. There are no dividend limitations contained in the Company's other debt instruments.

Note 7. Long-Term Debt Each ofthe Company's outstanding mortgages is a lien on substantially all ofthe Company's properties.

First Mortgage Allofthe bonds issued under the First Mortgage, including those issued after June 1, 1975 and pledged with the Trustee of the G&R Mortgage (G&RTrustee) as additional security for General &Refunding Bonds (G&R Bonds), are secured by the lien ofthe First Mortgage. First Mortgage Bonds pledged with the G&RTrustee do not represent outstanding indebtedness of the Company. Amounts ofsuch pledged bonds outstanding were $ 1.03 billionat December 31, 1993 and 1992. The annual First Mortgage depreciation fund and sinking fund require-ments for 1993, due not later than June 30, 1994, are estimated at $216 millionand $ 18 million, respectively. The Company expects to meet these requirements with property additions and retired First Mortgage Bonds.

36

~ '8rR Mortgage The lien ofthe G&R Mortgage is subordinate to the lien ofthe First Mortgage. The annual G&RMortgage sinking fund requirement for 1993, due not later than June 30, 1994, is estimated at $24 million. The Company expects to satisfy this requirement with retired G&RBonds.

1989 Revolving Credit Agreement The Company has an estimated $276 millionavailable to it through October 1, 1994, under its $300 million 1989 Revolving Credit Agreement (1989 RCA). This line ofcredit is secured by a first lien upon the Company's accounts receivable and fuel oil inventories.

The Company is currently, with the approval ofthe NRC, dedicating $24 millionofthe 1989 RCA to cover estimated, not yet incurred, costs attributable to the decommissioning of Shoreham, discussed in Note 2. The amount ofcredit available to the Company under the 1989 RCA willincrease as decom-

, missioning costs are funded by the Company.

AtDecember 31, 1993, no amounts were outstanding under the 1989 RCA. The Company has the option, when amounts are outstanding, to commit to one ofthree interest rates including:

(i) the Adjusted Certificate ofDeposit Rate which is a rate based on the certificate ofdeposit rates ofcertain ofthe lending banks, ii)the Base Rate which is generally a rate based on Citibank, N.A.'s prime rate and (iii)the Eurodollar Rate which is a rate based on the London Interbank Offering Rate (LIBOR). The Company has agreed to pay a fee ofone quarter ofone percent per annum on the unused portion. The termination date ofthe 1989 RCA may be extended for one-year periods upon the acceptance by the lending banks ofthe Company's request delivered to the lending banks prior to April 1 in each year.

AuthorityFinancing Notes Authority Financing Notes are issued by the Company to the New York State Energy Research and Development Authority (NYSERDA) to secure certain tax-exempt Pollution Control Revenue Bonds (PCRBs), Electric Facilities Revenue Bonds (HFRBs) and Industrial Development Revenue Bonds issued by NYSERDA. Certain ofthese bonds are subject to periodic tender at which time their interest rates are subject to redctermination.

The 1993 EFRBs and the 1985 PCRBs are supported by letters ofcredit pursuant to which the letter ofcredit banks have agreed to pay the principal, interest and premium ifapplicable, in the aggregate, up to approximately $272 millionin the event ofdefault. The obligation ofthe Company to reimburse the letter ofcredit banks is unsecured. These letters ofcredit expire November 17, 1996 for the 1993 EFRBs and on March 16, 1996 for the 1985 PCRBs, at which time the Company is required to obtain either an extension ofthe letters ofcredit or substitute credit backup. Ifneither can be obtained, the 1993 EFRBs and PCRBs 8'/4%

2.5%

1982 17,200 Tendered every three years, next tender October 1994.

1985 A,B

$ 150,000 Tendered annually on March 1.

EFRBs 2.95%

1993 A

$ 50,000 Tendered weekly.

2.85%

1993 B

$ 50,000 Tendered annually on November 1.

Fair Values ofLong-Term Debt The carrying amounts and fair values ofthe Company's long-term debt consisted ofthe followingat December 31:

(ln thousands ofdollars) 1993 Fair Value Carrying Amount First Mortgage Bonds General and Refunding Bonds

'ebentures Authorit Financing Notes 124,719 125,000 1,806,728 1,666,000 2,944,499 2,880,058 851,800

'16,675 Total Long-Term Debt

$ 5,727,746

$ 5,4S7,733 Fair Value Carrying Amount First Mortgage Bonds 397,971 400,000 General and Refunding Bonds 1,891,842 1,801,000 Debentures 2,523,721 2,428,058 Authorit Financing Notes 729,610 716,675 Total Lon -Term Debt

$ 5,543,144

$ 5,345,733 MaturitySchedule Total long-term debt maturing in the next five years is $600 million(1994), $25 million(1995), $455 million(1996), $286 million(1997) and $ 1 million(1998).

the 1985 PCRBs must be redeemed unless the Company purchases them in lieu ofredemption and subsequently remarkets them.

Tender requirements ofAuthority Financing Notes at December 31, 1993 are as follows:

(ln thousands ofdollars)

Interest Rate Series Princi al 37

Actuarial present value ofbenefit obligation Vested benefits Nonvested benefits

$ 512,692

$ 453,201 5,920 4,326 Accumulated benefit obligation

$ 518,612

$ 457,527 Plan assets at fair value Actuarial present value of ro'ected benefit obligation Projected benefit obligation less than plan assets Unrecognized January 1, net obligations Unrecognized net ain

$ 598,600

$ 556,399 597,128 536,818 1,472 19,581 91,397 98,147 (97,029)

(128,218)

Note 8. Retirement Benefit Plans Pension Plans The Company maintains a primary defined benefit pension plan (Primary Plan) which covers substantially all employees, a supplemental plan (Supplemental Plan) which covers officers and certain key executives and a retirement plan which covers the Board ofDirectors (Directors'lan).

Primary Plan The Company's funding policy is to contribute annually to the Primary Plan a minimum amount consistent with the require-ments ofthe Employee Retirement Income Security Actof 1974 (ERISA) plus such additional amounts, ifany, as the Company may determine to be appropriate from time to time.

Effective January 1, 1992, the Plan was amended to update the benefit calculation, whereby for service before January 1, 1992, pension benefits are determined based on the greater of the accrued benefit as ofDecember 31, 1991, or by applying a moving five-year average ofPlan compensation, not to exceed the January 1, 1992 salary, to a certain percentage, determined by years ofservice at December 31, 1991. For service after January 1, 1992, pension benefits are equal to 2% ofPlan compensation through age 49 and 2 I/2% thereafter.

Employees are vested in the pension plan after five years ofservice with the Company.

The Primary Plan's funded status reflects changes in assump-tions used in accounting due to changes in market conditions.

The 1993 projected benefit obligation increased by approxi-mately $31 milliondue to changes in the discount rate used, partially offset by a lower rate offuture compensation increases.

The Primary Plan's funded status and amounts recognized on the Balance Sheet at December 31, 1993 and 1992 were as follows:

(ht thousands ofdollars) 1993 Service cost benefits earned during the period

$ 14,481

$ 13,661

$ 14,323 Interest cost on projected benefit obligation and service cost 41,865 39,574 33,698 Actual return on plan assets (54,010)

(47,156)

(63,875)

Net amortization and deferral 10,025 12,849 33,569 Net riodic nsion cost

$ 12,361

$ 18,928

$ 17,715 Assumptions used in accounting for the Primary Plan were:

Discount rate Rate offuture compensation increases Long-term rate ofrctur'n on assets 1993 1992 1991 7.25%

7.75%

7.75%

5.0%

5.5%

5.5%

7.5%

7.5%

7.0%

The Primary Plan assets at fair value primarily include cash, cash equivalents, group annuity contracts,,bonds and listed equity securities.

In 1993, the PSC issued an order which addressed the accounting and ratemaking treatment ofpension costs in accordance with SFAS No. 87, Employers'ccounting For Pensions. Under the PSC order, the Company is required to recognize any deferred net gains or losses over a ten-year period rather than using the corridor approach method. The Company believes that by adopting this method ofaccounting for financial reporting purposes, a better matching ofrevenues and the Companay's pension cost willresult from the imple-mentation ofthe PSC order. For the year ended December 31, 1993, this change in the annual pension cost calculation reduced pension expense by approximately $4.6 million. The Company deferred a like amount ofrevenues to reflect the difference between pension expense in rates and pension expense under the PSC's order. In addition, the PSC authorized the Company to defer the difference between the pension rate allowance and annual pension contributions deposited into the pension fund.

The Company is required to accrue, to the benefit ofthe ratepayer, a carrying charge on any such deferred balance.

Periodic pension cost for 1993, 1992 and 1991 for the Primary Plan included the followingcomponents:

gn thousands ofdollars) 1993 1992 1991 Net accrued nsion cost

$ (4,160)

$ (10,490) 38

pplemental Plan he Supplemental Plan, the cost ofwhich is borne by the Company's shareowners, provides supplemental death and retirement benefits for officers and other key executives without contribution from such employees. The Supplemental Plan is a non-qualified plan under the Internal Revenue Code. Death benefits are currently provided by insurance. The provision for retirement benefits, which is unfunded, totaled approximately

$2,800,000, $685,000 and $675,000 which was recognized as

'n expense in 1993, 1992 and 1991, respectively.

Directors'lan The Directors'lan, adopted in February 1990, provides benefits to directors who are not officers ofthe Company.

Directors who have served in that capacity for more than five years qualify as participants under the plan. The Directors'lan is a non-qualified plan under the Internal Revenue Code. The provision for retirement benefits, which is unfunded, totaled approximately $ 150,000, $ 133,000 and $ 101,000 which was recognized as expense in 1993, 1992 and 1991, respectively.

Postretirement Benefits Other Than Pensions In addition to providing pension benefits, the Company provides certain medical and lifeinsurance benefits forretired employees.

Substantially all ofthe Company's employees may become igible for these benefits ifthey reach retirement age after rking for the Company for a minimum offive years. These and similar benefits for active employees are provided by the Company or by insurance companies whose premiums are based on the benefits paid during the year. Effective January 1, 1993, the Company adopted the provisions ofSFAS No. 106, Employers'ccounting for Postretirement Benefits Other Than Pensions, which requires the Company to recognize the expected cost ofproviding postretirement benefits when employee services are rendered rather than on a pay-'as-'ou-go method.

Effective January 1, 1993, the Company recorded an accumu-lated postretirement benefit obligation and a corresponding regulatory asset ofapproximately $376 million. Additionally, as a result ofadopting SFAS No. 106, the Company's annual postretirement benefit cost for 1993 increased by approximately

$28 millionabove the ainount that would have been recorded under the pay-as-you-go method.

In 1993, the PSC issued a final order which required that the effects ofimplementing SFAS No. 106 be phased into rates.

The order required the Company to defer as a regulatory asset the difference between postretirement benefit expense recorded for accounting purposes in accordance with SFAS No. 106 and the postretirement benefit expense reflected in rates. The ongoing annual postretirement benefit expense willbe phased to and fullyreflected in rates withina five-year period with e accumulated postretirement obligation being recovered in rates over a twenty-year period.

Retirees Fully eligible plan participants Otheractive lan artici ants Accumulated postretirement benefits obligation Unrecognized net gain Unrecognized transition obligation

$ 152,800

$ 140,900 63,800 78,500 137,200 156,200 353,800 375,600 49,237 (375,600)

Accrued stretirement benefit cost

$ 403,037 Periodic postretirement benefit cost for the years 1993 and 1992 were as follows:

1993 Service cost-benefits earned during the period Interest cost on projected benefits obligation and service cost 12,980 29,531 Periodic postretirement cost 42,511 13,400 Assumptions used in accounting for postretirement benefits were as follows:

Discount rate Rate offuture compensation increases 1993 1992 7.25%

7.75%

5.0%

5.5%

The assumed health care cost trend rates used in measuring the accumulated postrctirement benefit obligation at December 31, 1993 and 1992 were 9.5% and 15.0%, respectively, gradually declining to 6.0% in 2001 and thereafter. A one-percentage point increase in the health care cost trend rate would increase the accumulated postretirement benefit obligation as of December 31, 1993 and 1992 by approximately $46 million and $58 million, respectively, and the sum ofthe service and interest costs in 1993 by $8 million.

Postemployment Benefits In November 1992, the FASB issued SFAS No. 112, Employers'ccounting for Postemployment Benefits, which establishes accounting standards for employers who provide benefits to former or inactive employees after employment but before retirement. The Company willbe required to comply with the new rules beginning in 1994. The effect ofadopting the new rules willnot be material to the Company's financial position or results ofoperations. The Company believes itwill, be permitted to recover these costs through rates.

Accumulated postretirement benefits obligation at December 31 were as follows:

gn thousands ofdollars) 1993 1992 39

Note 9. Commitments and Contingencies Commitments The Company has entered into substantial commitments for fossil fuel, gas supply, purchased power and transmission facilities. The costs associated with these commitments are normally recovered from ratepayers through provisions in the Company's rate schedules.

The Company expects that itwillhave to expend $4.3 millionin 1994 to meet continuous emission monitoring requirements and

$3.5 millionin 1994 and $2.0 millionin'1995 to meet Phase I nitrogen oxide (NOx) reduction requirements. In addition, subject to details that are expected to appear in regulations that have not yet been issued, the Company estimates that it may be required to expend as much as $ 125 millionby May 1999 to meet Phase H NOx reduction requirements and approximately

$50 millionby 2000 to meet requirements for the control of hazardous air pollutants from power plants. The Company believes that such cost would be recoverable in rates.

Contingencies Litigation On February 11, 1988, the Company began a lawsuit in Suffolk County Supreme Court against Suffolk County, seeking the recovery ofapproximately $54 millionin damages for Suffolk County's breach ofa contract to prepare an offsite emergency response plan for Shoreham (Long Island Lighting Company v.

County ofSuffolk). In addition, the complaint alleges that, because ofthe delays that have resulted, the Company has been damaged in an additional amount of$706 million. On October 30, 1992, the court granted in part and denied in part Suffolk County's motion to amend its answer to assert additional defenses and counterclaims. Two proposed counterclaims were allowed seeking approximately $ 16 millionin damages as well as $700 millionin alleged punitive damages. The outcome of these counterclaims, ifadverse, could have a material effect on the financial condition ofthe Company. The Company has argued that there is no basis forpunitive damages and intends to vigorously prosecute its claim against Suffolk County and to defend against these counterclaims.

Environmental The Company is subject to environmental laws and regulations ofthe United States Environmental Protection Agency (EPA) and other regulatory agencies. The Company is monitoring its activities and to date, has not identified any material environ-mental contingencies. The Company believes that costs related to such contingencies, ifany, would be recoverable in rates.

Nuclear Plant Insurance The Company has property damage insurance and third-party bodily injury and property liabilityinsurance for its 18% share in NMP2 and for Shoreham. The premiums for this coverage Note 10. Federal Income Taxes As ofDecember 31, 1993, the significant components ofthe Company's deferred tax assets and liabilities calculated under the provisions ofSFAS No. 109 were as follows:

'eferred Tax Assets Net operating loss carryforwards Litigation settlements Shoreham property Accelerated depreciation Excess credits Unutilized investment tax credits Tax credit carryfoiwards Other Total Deferred Tax Assets Deferred Tax Liabilities 1989 Settlement Accelerated depreciation Call premiums Rate case deferrals Other Total Deferred Tax Liabilities Net Deferred Tax Liabilit gn thousands ofdollars)

707, 87,050 38,535 20,612 35,362 67,215 138,035 62,800 1,'157,009 2,180,413 597,827 63,735 43,957 46,097 2,932,029

$ 1,775,020 The Company's net operating loss (NOL)carryforward for federal income tax purposes is estimated to be approximately

$2 billionat December 31, 1993. The NOLwillexpire in the years 2003 through 2007. The amount ofinvestment tax credit (ITC) carryforward is approximately $219 million.The ITC credits expire by the year 2002. In accordance with the Tax Reform Actof 1986 (TRA 86), ITC allowable as credits to tax returns for years after 1987 must be reduced by 35%. The amount ofthe reduction willnot be allowed as a credit for any are not material. The policies for this coverage provide for retroactive premium assessments under certain circumstances.

Maximum retroactive premium assessments could be as much as approximately $4.7 million. For property damage at each nuclear generating site, the NRC requires a minimum of$ 1.06 billionofcoverage. The NRC has provided the Company with a partial exemption from these requirements for Shoreham.

Under certain circumstances, the Company may be assessed additional amounts in the event ofa nuclear incident. Under agreements established pursuant to the Price Anderson Act, the Company could be assessed up to approximately $79.3 million per nuclear incident in any one year at any nuclear unit, but not in excess ofapproximately $ 10 millionin payments pet; year for each incident. The Price Anderson Act also limits liabilityfor third-party bodily injury and third-party property damage arising out ofa nuclear occurrence at each unit to $9.4 billion.

er taxable year. For financial reporting purposes, a valua-ion allowance was not required to offset the deferred tax assets related to these carryforwards.

On January 8, 1990 and October 10, 1992, the Company received Revenue Agents'eports disallowing certain deductions claimed by the Company on its tax returns for the audit cycle years 1984-1987 and 1988-1989, respectively. The Revenue Agents'eports reflects proposed adjustments to the Company's federal income tax returns for 1984 through 1989 which, ifsustained, would give rise to tax deficiencies totaling approximately $220 million. The Revenue Agents have proposed ITC adjustments which, ifsustained, would reduce the Company's carryforward by approximately $96 million.

The Company is protesting some ofthe adjustments and seeks an administrative and, ifnecessary, a judicial review ofthe conclusions reached in the Revenue Agents'eports. The Company cannot predict either the timing or the manner in which these matters willbe resolved. Ifhowever, the ultimate disposition ofany or all matters raised in the Revenue Agents'eports are adverse to the Company, the Company expects that any deficiencies that may arise willbe substantially offset by the net operating loss carrybacks associated with the 1989 Shoreham abandonment loss deduction of$ 1.8 billionand thus any impact would not have a material effect on the Company's, financial condition or cash flows.

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

Federal Income Tax, per Statement ofIncome Current Deferred and other (see Note 1) 1989 Settlement Shoreham property Bokum Resources Corporation Rate moderation component Other 1989 Settlement items Net operating loss carryforward Shoreham post settlement costs Contractor litigation settlement Accelerated tax depreciation Call premiums Ratcmaking and performance plan Other items Total Deferred and Other Total Federal Income Tax Expense Net Income Net Income Before Federal Income Tax 1993

%of Pre-tax Amount Income 6,324 4,753 (30,511) 11,396 78,708 62,993 (503) 32101 (5,460) 14,369 (1,894) 165,952 172,276 296,563

$ 468,839 1992

%of Pre-tax

. Amount Income 530 3,806 10,351 8,622 (14,121) 60,125 35,951 35,441 17,680 2,577 160,432 160,962 301,974

$ 462,936 (In thousands ofdollars) 1991

%of Pre-tax Amount Income 515 10,677 20,400 77,715 872 (14,510) 50,375 (18,758) 30,447 18,496 (371) 5,795 181,138 181,653 305,538

$ 487,191 Statutory Federal Income Tax Additions (reductions) in federal income tax 1989 Settlement Shoreham property Allowance for funds used during construction Tax credits Excess ofbook depreciation over tax depreciation Interest capitalized Other items Total Federal Income Tax Expense 4,256 0.9 (2,304)

(6,871)

(0.5)

(1.5) 4,003 (4,118)

(6,586) 0.9 4,003

,0.8 (0.9)

(1,310)

(0.3)

(1.4)

(2,980)

(0.6) 12,437 3,443 (2,779) 2.7 0.7 (0.6) 12,193 2,947 (4,875) 2.6 13,108 2.7 0.6 4,232 0.9 (1.0)

(1,045)

(0.2)

$ 172,276 36'7%

$ 160,962 34.8%

$ 181,653 37.3%

$ 164~094 35.0%

$ 157,398 34.0%

$ 165,645 34.0%

Note 11. Segments of Business The Company is a public utilityengaged in the generation, distribution and sale ofelectric energy and the purchase, distribution and sale ofnatural gas to residential, commercial and industrial customers in Nassau and Suffolk Counties and the Rockaway Peninsula in Queens County, all on Long Island, New York. Identifiable assets by segment include net utilityplant, regulatory assets, materials and supplies (excluding common), accrued unbilled revenues, gas in storage, fuel and deferred charges (excluding common). Assets utilized for overall Company operations consist ofother property and investments, cash and cash equivalents, special deposits, accounts receivable, prepayments and other current assets, unamortized debt expense and other deferred charges.

For year ended December 31 Operating revenues Electric Gas 1993 2,352,109 528,886 2,194,632 427,207 (in thousands ofdollars) 1991 2,196,568 351,161 Total Operating expenses (excludes federal income tax)

Electric Gas Total 2,880,995 2,621,839 2,547,729 1,513,452 1,354,959 1,254,702 427,138 352,777 338,295 1,940,590 1,707,736 1,592,997 Operating income (before federal income tax)

Electric Gas Total AFC Other income and deductions Interest charges Federal income taxoperating Federal income taxnonoperating 838,657 101,748 940,405 (6,683)

(55,823) 534,072 184,854 (12,578) 839,673 74,430 914,103 (12,111)

(49,569) 512,847 172,998 (12,036) 941,866 12,866 954,732 (5,7 (50,48 523,816 169,452 12,201 Net income 296,563 301,974 305,538 Depreciation and amortization Electric Gas 106,149 16,322 104,034 15,103 104,172 14,783 Total 122,471 119,137 118,955 Construction and nuclear fuel expenditures*

Electric Gas 170,941 133,752 163,609 109,295 144,356 93,195 Total 304,693 272,904 237,551

~Includes non~h allowance forother funds used during construction and excludes Shoreham post settlement costs.

(in thousands ofdollars)

AtDecember 31 1993 1991 Identifiable assets Electric Gas

$ 11~253j674 8 867 205'8 582 081 1,080,906 767,444 621,570 Total Assets utilized for overall Company operations 12,334,580 1,121,457 9,634,649 1,129,810 9,203,651 934,844 Total Assets

$ 13456037

$ 10764459

$ 10,138,49 42

te 12. Quarterly Financial Information (Unaudited) gn thousands of'dollars except earnings pcr common share)

Operating revenues For the quarter ended March 31 June 30 September 30 December 31 Operating income For the quarter ended March 31 June 30 September 30 December 31 Net income For the quarter ended March 31 June 30 September 30 December 31 1993

$ 760,451 604,871 849,700

'665,973

$ 192,391 167,599 263,984 131,577 67,861 56,806 144,549 27,347 1992

$ 697,761 580,498 747,729 595,851

$ 179,741 166,954 256,800 137,610 66,706 59,285 141,388 34,595 Earnings for common stock For the quarter ended March 31 53,286 50,553 June 30, 42,451 41,040 September 30 131,022 126,295 December 31 13,696 20,132 Earnings per common share

~

~ For the quarter ended March 31 June 30 September 30 December 31

48

.38 1.17

.12

.45

.37 1.14'18 In the fourth quarter of 1993, the Company recorded income ofapproximately $6.5 million, net oftax effects, or $.06 pcr common share related to the settlement ofcertain litigation. In addition, during the fourth quarter of 1993, the Company recorded a charge to earnings ofapproximately $7.3 million, nct oftax effects, or $.07 per common share principally related to previously deferred storm costs aud the reconciliation ofcertain ratcmaking mechanisms recorded in connection with the conclusion ofthe Company's rate year.

Report of Ernst 8c Young, Independent Auditors To the Shareowners and Board ofDirectors ofLong Island Lighting Company We have audited the accompanying balance sheet ofLong Island Lighting Company and the related statement ofcapitalization as of December 31, 1993 and 1992 and the related statements ofincome, retained earnings and cash flows for each ofthe three years in the period ended December 31, 1993. These financial statements are the responsibility ofthe Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

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

An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position ofLong Island Lighting Company at December 31, 1993 and 1992, and the results ofits operations and its cash flows for each ofthe three years in the period ended December 31, 1993, in conformity with generally accepted accounting principles.

discussed in Notes 8 and 10 to the financial statements, effective January 1, 1993, the Company changed its methods faccounting for postretirement benefits other than pensions and income taxes.

Melville, New York February 4, 1994 43

Selected Financial Data Balance Sheet 1993 1991 (in thousands ofdoll~

t990 198~

Table 1

Assets Net utilityplant Regulatory assets Other assets Total Assets Capitalization and Liabilities Capitalization Long-term debt Preferred stock redemption required Preferred stock no redemption required Common shareowners'quity Total Capitalization Liabilities Total Capitalization and Liabilities 3,347,557 3,161,148 3,002,733 2,888,079 7,610,639 5,221,143 4,951,086 4,723,357 2,497,841 2,382,168 2,184,676 1,905,802

$ 13,456,037

$ 10,764,459

$ 10,138,495 9,517,238 4)870,340 4,741,002 4,986,166 4,532,891 649,150 557,900 524,912 527,550 64,038 154,276 154,371 154,674 2,232,950 2,184,775 2,130,491 2,067,234 7,816,478 7,637,953 7,795,940 7,282,349 5,639,559 3,126,506 2,342,555 2,234,889

$ 13,456,037

$ 10,764,459

$ 10;138,495 9,517,238 2,781,157 4,335,845 2,156,949 9,273,951 4,531,429 541,187 155,592 1,941,745 7,169,953 2,103,998 9,273,951 Summary ofOperations (tn thousands ofdollars except per share amounts)

Table 2 Total revenues Total operating income (loss)

Income (loss) before cumulative effect ofaccounting change Cumulative effect ofaccounting change for unbilled gas revenues (net oftax)

Earnings (loss) for common stock Average common shares outstanding (000)

Earnings (loss) per common share Before cumulative effect ofaccounting change Cumulative effect ofaccounting change Earnings (loss) per common share Common stock dividends declared per share Common stock dividends paid per share Book value pcr common share at year end Common shareowners at year end

,240,455 112,057 11,680 238,020 239,144 263,156 111,439 111,348 111,290 2.15 2.14 2.15 2.26

.10 2.15 2.14 2.15 2.36 1.76 1.72 1.60 1.25 1.75 1.71 1.55 1.125 19.88 19.58 19.13 18.57 94,877 86,111 90,435 82,903 2,880,995 2,621,839 2,547,729 2,456,902 755,551 741,105 785,280 802,630 296,563 301,974 305,538 319,637 2,347,614 620,423 (95,80 (175,035) 111,215 (1.57)

(1.57)

.50

.25 17.45 85,142 Operations and Maintenance Expense Details (fn thousands ofdollars)

Table 3 Total payroll and employee benefits Less Charged to construction and other Payroll and employee benefits charged to operations Fuels electric operations Fuels gas operations Purchased power costs Fuel cost adjustments deferred Total Fuel and Purchased Power Allother Total Operations and Maintenance Expense Employees at December 31 44 293,341 289,741 274,162 260,039 287,349 282,138 354,859 444,458 248,559 182,201 175,046 175,877 292,136 280,914 197,154 168,749 (453)

(3,469) 41,643 (2,085) 827,591 741,784 768,702 786,999 228,319 208,204 248,597 215,770 1,349,251 1,239,729 1,291,461 1,262,808 6,337 6,541 6,605 6,630

'410,329 413,817 398,000 357,689 116,988 124,076 123,838 97,650 329,694 117,761 211,933 461,576 188,139 128,368 (5,631 772,452 215,373 1,199,758 6,239

Electric Operating Income 1993 1992 l991 (ln thousands ofdollars) 1989 Table 4 Revenues Residential Commercial and industrial Other system revenues 1,145,891 1,132,487 49,790 1,045,799 1,047,490 997,868 1,076,302 1,070,098 1,017,387 49,395 47,838 46,673 915,644 981,740 42,232 Total system revenues Sales to other utilities Other revenues 2,328,168 12,872 11,069 2,171,496 9,997 13,139 2,165,426 2,061,928 23,040 24,140 8,102 9,592 1,939,616 42,880 792 Total Revenues 2,352,109 2,194,632 2,196,568 2,095,660 1,983,288 Expenses Operations fuel and purchased power Operations other Maintenance Depreciation and amortization Base financial component amortization Regulatory liabilitycomponent amortization 1989 Settlement credits amortization Other'regulatory amortizations Rate moderation component Regulatory liabilitycomponent Jamesport amortization perating taxes eral income tax current ederal income tax deferred and other 579,032 306,116 111,765 106,149 100,971 (79,359)

(9,214)

(17,082) 88,667 326,407 6,324 158,941 559,583 294,909 105,341 104,034 100,971 (79,359)

(9,214)

(21,984)

(30,444) 331,122 530 158,908 593,656 296,798 127,446 104,172 100,971 (79,359)

(9,214) 10,375 (228,572) 338,429 515 173,259 611,122 271,608 118,545 98,022 100,971 (79,359)

(9,214) 14,427 (297,214) 322,197 3,138 169,274 584,313 237,931 115,502 91,759 50,485 (39,679)

(4,607) 1,248 (131,167) 793,592 104,160 312,456 14,612 (738,500)

Total Expenses Electric Operating Income 1,678,717 673,392 680,235 768,092 772,143 1,514,397 1,428,476 1,323,517 1,392,105 591,183 Gas Operating Income (In thousands ofdollars)

Table 5 Revenues Residential space heating other Non-residential space heating other Total firm revenues Interruptible revenues Total system revenues Other revenues Total Revenues Expenses Operations fuel Operations other Maintenance Depreciation and amortization Regulatory amortizations perating taxes ederal income tax current Federal income tax deferred and other Total Expenses Gas Operating Income 310,109 39,515 106,140 33,181 488,945 24,028 512,973 15,913 528,886 248,559 81,692 22,087 16,322 (962) 59,440 19,589 446,727 82,159 243,950 33,035 90,363 29,094 396,442 19,658 416,100 11,107 427,207 182,201 77,300 20,395 15,103 (88) 57,866 13,560 366,337 60,870 190,976 29,383 70,938 25,515 316,812 21,686 338,498 12,663 351,161 175,046 78,469 20,046 14,783 49,951 (4,322) 333,973 17,188 198,734 30,854 68,441 26,501 324,530 30,515 355,045 6,197 361,242 175,877 68,910 16,746 12,862 48,120 500 7,740 330,755 30,487 209,192 31,692 72,351 28,674

'41,909 19,226 361,135 3,191 364,326 188,139 59,587 14,286 11,671 51,935 9,468 335,086 29,240 45

Electric Sales and Customers Sales millions ofkWh Residential Commercial and industrial Other System sales Sales to other utilities Total Sales Customers monthly average Residential Commercial and industrial Other Customers total monthly average Customers total at year end 1993 7,118 8,257 449 15,824 304 16,128 905,997 102,254 4,553 1,012,804 1,011,965 6,788 8,181 471 15,440 227 15,667 902,885 101,838 4,593 1,009,316 1,009,028 199l 7,023 8,322 469 15,814 598 16,412 898,974 101,740 4,540 1,005,254 1,005,363 7,022 8,359 472 15,853 532 16,385 895,294 101,562 4,504 1,001,360 1,001,441 19 Table 6 7,063 8,636 470 16,169 633 16,802 890,406 100,481 4,452 995,339 996,488 Residential kWh per customer Revenue per kWh Commercial and Industrial kWh per customer Revenue per kWh 7,856 7,518 16.10C 15.41C 7,812 14.92C 80,749 13.72C 80,346 81,797 13.16C 12.86C 7,844 14.21C 82,304 12.17C 7,932 12.96C 85,943 11.37C System kWh per customer Revenue per kWh Gas Sales and Customers Sales thousands ofdth Residential space heating other Non-residential space heating other Total firmsales Interruptible sales Offsystem sales Total Sales Customers monthly average Residential space heating other Non-residential space heating other Total firmcustomers Interruptible customers Customers total monthly average Customers total at year end Residential dth per customer Revenue per dth Non-residential dth per customer Revenue per dth System dth per customer Revenue per dth 46 15,631 14.71C 37,191 3,297 14,366 4,329 59,183 5,920 2,894 67,997 233,882 166,974 32,783 10,631 444,270 542 444,812 446,384 101.0 8.64 430.6 7.45 146.4 7,88 15,297 14.06C 35,089 3,203 13,662 4,338 56,292 5,090 61,382 227,834 169,189 31,666 10,777 439,466 531 439,997 442,117 96.4 7.23 424.1 6.64 139.5 6.78 15,731 13.69c 29,687 3,195 11,636 4,171 48,689 4,538 53,227 220,562 171,581 30,453 11,003 433,599 472 434,071 436,853 83.9 6.70 381.3 6.10 122.6 6.36 15,832 13.01C 29,810 3,448 11,271 4,352 48,881 6,347 55,228 211,400 176,000 29,072 11,310 427,782 410 428,192 430,571 85.8 6.90 386.9 6.08 128.9 6.43 16,245 12.

Table 7 32,024 3,491 11,548 4,539 51,602 5,300 56,902 204,982 179,415 27 733 11,517 423,647 359 424,006 426,060 92.4 6.78 409.9 6.28 134.2 6.35

Electric Operations Energy millionsofkWh Net generation Power purchased net Total system requirements Company use and unaccounted for System sales Sales to other'tilities Total Energy Available Peak Demand mW Station coincident demand Power purchased net System Peak Demand System Capability mW LILCOstations Nine MilePoint 2 (LILCO's 18% share)

Firm purchases net Total Capability Fuel Consumed for Electric Operations Oilthousands ofbarrels Gas thousands ofdth clear thousands ofmW days 1 billions ofBtu liars per millionBtu Cents per kWh ofnet generation Heat rate Btu per net kWh Fuel Mix(Percentage ofsystem requirements)

Oil Gas Purchased Power Nuclear Fuel Total 1993 10,514 6,719 17,233 (1,387) 15)846 304 16,150 2,931 1,036 3,967 4,063 188 548 4,799 9,740 36,269 181

~

98,025 2.79 2.97C 10,628 33%

19 41 7

100%

10,592 6,211 16,803 (1,363) 15,440 227 15,667 2,975 636 3,611 4,091 188 432 4,711 10,656 34,475 124 102,126 2.62 2.76C 10,558 37%

19 38 6

100%

1991 13,570 3,638 17,208 (1,395) 15,813 598 16,411 3,085 819 3,904 4;078 194 423 4,695 15,314 32,924 154 129,937 2.61 2.73C 10,484 50%

18 25 7

100%

1990 13,981 2,989 16,970 (1,1 17) 15,853 532 16,385 3,260 426 3,686 4,077 194 408 4,679 16,401 36,477 108 139,874 3.07 3.24C 10,564 56%

20 20 4

100%

t989 Table 8 15,220 2,087 17,307 (1,138) 16,169 633 16,802 3,178 510 3,688 4,066 194 400 4,660 20,480 26,490 105 154,669 2.86 3.06C 10,704 67,%

13 16 4

100%

Gas Operations Energy thousands ofdth Natural gas Manufactured gas and change in storage Total Natural and Manufactured Gas Total system requirements Company use and unaccounted for 69,970 (68) 69,902 69,902 (1,905) 64,911 48 64,959 64,959 (3,577) 55,579 60 55,639 55,639 (2,412) 55,407 (15) 55,392 55,392 (164)

Table 9 60,359 53 60,412 60,412 (3,510)

Total Energy Available Maximum Day Sendout dth System Capability dth per day Natural gas

.NG manufactured or LP gas al Capability Calendar Degree Days (67-year average 5,027) 67,997 485,896 561,584 120,700 682,284 4,899 61,382 448,726 561,584 120,700 682,284 5,066 53,227 435,050 507,344 128,200 635,544 4,378 55,228 56,902 406,177 462,610 4,139 5,169 507,344 461,788 128,200 145,600 635,544 607,388 47

Corporate Information Executive Offices 175 East Old Country Road Hicksville, New York 11801 Common Stock Listed New YorkStock Exchange Pacific Stock Exchange Ticker Symbol: LIL Transfer Agent and Registrar Common Stock and Preferred Stock The Bank ofNew York Shareholder Services Department Church Street Station P.O. Box 11277 New York, NY 10286-1612 1-800-524-4458 Sharcowners'gent for Automatic Dividend Rcinvcstmcnt Plan The Bank ofNew York Dividend Reinvestment Department Church Street Station P.O. Box 11277 New York, NY 10286-1612 1-800-524-4458 Annual Meeting The Annual Meeting ofShareowncrs willbe held on Tuesday, April 12, 1994 at 3:00 p.m. In connection with this meeting, proxies willbe solicited by thc Company.

Form 10-K Annual Rcport The Company willfurnish, without charge, a copy of the Company's Annual Report, Form 10-K, as filed with the Securities and Exchange Commission, upon written request to:

Investor Relations Long Island Lighting Company 175 East Old Country Road Hicksville, New York 11801 Common Stock Prices 24/8 22/8 25~/e 23~/8 First Quarter Second Quarter Third Quarter Fourth Quarter The common stock ofthe Company is traded on the New York Stock Exchange and the Pacific Stock Exchange. Certain of the Company's preferred stock series are traded on the New YorkStock Exchange. The quoted market prices for the Company's common stock for the years 1993 and 1992 were as follows:

1993 1992 High Low High Low 28~/,

24~/8 28'/4 24'/,

29~/8 27 273/4 23i/4 48 LILCOuses rccycled paper to help conserve our natural resources.

I

Directors Officers WilliamJ. Catacosinos Chairman ofthe Board,

" President and Chief Executive Officer Long Island Lighting Company A. James Barnes Dean School ofPublic and Environmental Affairs Indiana University George Bugliarello President Polytechnic University Renso L. Caporali Chairman ofthe Board and Chief Executive Officer Grumman Corporation r O. Crisp President Venrock, Inc.

Venture Capital Investments WinfieldE. Fromm Retired Vice President Eaton Corporation Electrical Engineering VickiL. Fuller Vice President Emerging Markets and High Yield Alliance Capital Management Corporation Katherine D: Ortega Former Treasurer ofthe United States Basil A. Paterson Partner Meyer, Suozzi, English

&Klein, PC Law Richard L. Schmalensee Director Center for Energy and Environmental Policy Research Massachusetts Institute ofTechnology George J. Sideris Retired Senior Vice President Finance Long Island Lighting Company John H. Talrnage Partner H.R. Talmage &Son Agriculture Phyllis S. Vineyard Director Long Island Community Foundation WilliamJ. Catacosinos Chairman ofthe Board, President and Chief Executive Officer James T. Flynn Executive Vice President and Chief Operating Officer Arthur C. Marquardt Senior Vice President Gas Business Unit Anthony Nozzolillo Senior Vice President and Chief Financial Officer WilliamN. Dimoulas Vice President Information Systems and Technology Robert X. Kelleher Vice President Human Resources John D. Leonard, Jr.

Vice President Corporate Services and Nuclear Operations Adam M. Madsen Vice President Corporate Planning Brian R. McCaffrey Vice President Administration WilliamG. Schiffmacher Vice President Electric Operations Robert B. Steger Vice President Fossil Production WilliamE. Steiger, Jr.

Vice President Engineering and Construction Walter F. Wilm, Jr.

Vice President Edward J. Youngling Vice President Customer Relations and Conservation Robert J. Grey General Counsel Theodore A. Babcock Treasurer Kathleen A. Marion Corporate Secretary and Assistant to the Chairman Thomas J. Vallely, III Controller Herbert M. Leiman Assistant General Counsel and Assistant Corporate Secretary Joseph W. McDonnell Vice President External Affairs

Long Island Llghtlng Company, 175 East Old Country Road, Hlcksvlllo, Now York 11801