Annual Report (Form 10-K), fiscal year 1994

ITEM 1. BUSINESS
THE COMPANY:
Long Island Lighting Company (the "Company") was incorporated in 1910 under the Transportation Corporations Law of the State of New York and supplies electric and gas service in Nassau and Suffolk Counties and to the Rockaway Peninsula in Queens County, all on Long Island, New York. The mailing address of the Company is 175 East Old Country Road, Hicksville, New York 11801 and its general telephone number is (516) 755-6650.
TERRITORY:
The Company's service territory covers an area of approximately 1,230 square miles. The population of the service area, according to the Company's 1994 estimate, is about 2.7 million persons, including approximately 98,000 persons who reside in Queens County within the City of New York. The 1994 population estimate reflects a 0.2% increase since the 1990 census.
Approximately 80% of all workers residing in Nassau and Suffolk Counties are employed within the two counties. In 1994, total non-agricultural employment in Nassau and Suffolk Counties increased by approximately 4,500 employees, an employment increase of 0.4%. The area served is predominantly residential, but the Company receives approximately one-half of its electric revenues from commercial and industrial customers. About 89% of total employment is non-manufacturing.
SEGMENTS OF BUSINESS:
The percentages of total revenues and operating income before income taxes derived from electric and gas operations for each of the last three years are shown in the following table:
For additional information respecting the Company's electric and gas financial results and operations, see "Management's Discussion and Analysis of Financial Condition and Results of Operations for the Year Ended December 31, 1994, " "Selected Financial Data" and Notes 2, 3, and 11 of Notes to Financial Statements for the Year Ended December 31, 1994.
EMPLOYEES:
At December 31, 1994, the Company had approximately 5,950 full-time employees, of which approximately 2,450 belong to Local 1049 and approximately 1,400 belong to Local 1381 of the International Brotherhood of Electrical Workers. The Company's contracts with these unions will expire on February 13, 1996.
REGULATION AND ACCOUNTING CONTROLS:
The Company is subject to regulation by the Public Service Commission of the State of New York (the "PSC") with respect to rates, issuance and sale of securities, adequacy and continuance of service, safety and siting of certain facilities, accounting, conservation of energy, management effectiveness and other matters. To ensure that its accounting controls and procedures are consistently maintained, the Company actively monitors these controls and procedures. The Audit Committee of the Company's Board of Directors, as part of its responsibilities, periodically reviews this monitoring program.
New York law requires that all utilities be periodically audited to identify those aspects of their operations, if any, which are in need of improvement. During 1994, the PSC conducted two separate audits of the Company, one involving Executive Compensation and the other involving Management and Accounting Controls. The results of these audits are expected to be issued to the Company in early 1995. The Company plans to implement those recommendations that will improve its operations.
The Company is also subject, in certain of its activities, to the jurisdiction of the United States Department of Energy ("DOE") and the Federal Energy Regulatory Commission ("FERC"). In addition to its accounting jurisdiction, FERC has jurisdiction over the rates the Company may charge for the sale of electric energy for resale in interstate commerce, including the rates the Company charges for electricity sold to municipal electric systems within the Company's territory, and for the transmission, through the Company's system, of electric energy to other utilities or to industrial customers. It is in part in the exercise of this jurisdiction over transmission that FERC is currently considering certain issues relating to competition in the electric industry. For additional information relating to these FERC proceedings see the discussion under the heading "Management's Discussion and Analysis of Financial Condition and Results of Operations for the Year Ended December 31, 1994." FERC also has
some jurisdiction over a portion of the Company's gas supplies and substantial jurisdiction over transportation to the Company of its gas supplies.
Operation of Nine Mile Point Nuclear Power Station, Unit 2 ("Nine Mile Point 2"), a nuclear facility in which the Company has an 18% interest, is subject to regulation by the Nuclear Regulatory Commission ("NRC").
THE NEW YORK STATE TAKEOVER PROPOSAL:
At the request of the then Governor of the State of New York, on October 13, 1994, the chief executives of the New York Power Authority ("NYPA") and the Long Island Power Authority ("LIPA") invited the Company to enter into negotiations with them regarding a proposal to convert the Company into a public power utility. Under the proposal, the two state authorities contemplated a business combination in which holders of the Company's common stock would receive $21.50 in cash for each outstanding share of the Company's common stock. NYPA/LIPA indicated that the completion of this transaction would be subject to, among other things, the availability of tax-exempt financing sufficient to complete the transaction and the verification by NYPA and LIPA that the transaction would result in rate reductions in excess of 10%. The Company's Board of Directors has authorized the Company to enter into discussions with NYPA and LIPA to explore the proposal in greater detail, but no such discussions have been held.
The new governor of the State of New York had empaneled a task force to study the takeover proposal. While the task force did not make its recommendation public, published reports in local newspapers indicate that the task force recommended to reject the proposal.
ELECTRIC OPERATIONS:
General
The Company's system energy requirements are supplied from sources located both on and off Long Island. The Company's generating sources, with an aggregate summer generating capability of approximately 4,388,000 kilowatts ("kW"), include five steam electric generating stations and a number of internal combustion and diesel supplemental generating units, all located on Long Island, the Company's 18% share of Nine Mile Point 2, a nuclear generating station located in upstate New York, and a 136 megawatt ("MW") facility located in Holtsville, Long Island, which is owned and operated by NYPA. This facility was constructed for the benefit and at the request of the Company and commenced operation in 1994. Additional generating facilities owned by others, such as independent power producers and cogenerators located on Long Island and investor-owned and public electric systems located off Long Island, provide the balance of the Company's energy supplies.
The following table indicates the 1994 summer capacity of the Company's major generating facilities, internal combustion units and facilities under its control as reported to the New York Power Pool ("NYPP") in December 1994:
The maximum demand on the Company's system to date was 3,967,000 kW on July 9, 1993, representing 83% of its total available capacity of 4,799,000 kW on that day, which included 548,000 kW of firm capacity purchased from other sources. By agreement with the NYPP, the Company is required to maintain, on a monthly basis, an installed and contracted firm power reserve generating capacity equal to at least 18% of its actual peak load. The Company is currently meeting this NYPP requirement.
System Requirements and Reliability
In 1994, system kilowatt hour ("kWh") energy requirements were 0.4% higher than in 1993. As a result of the implementation of conservation programs and the availability to customers of energy supplies from cogeneration sources discussed below under the heading "Independent Power Producers and Cogenerators," the Company forecasts a 0.9% decrease and 0.4% increase, relative to 1994, in system energy requirements for the years 1995 and 1996, respectively. However, for the period 1995-2004, the Company forecasts an average annual growth rate in system energy requirements of 0.5%. With the availability of electricity provided by the Company's existing generating facilities, by its portion of nuclear energy generated at Nine Mile Point 2 and by power purchased from other electric systems and certain non-Company-owned facilities located within the Company's service territory, the Company believes it has adequate generating sources to meet its energy demands beyond the year 2000.
The Company's system electric requirements for the last three years were provided as follows:
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* Generated on the Company's own system. Oil consumption for the Company's system electric energy
requirements in 1994 was 7.5 million barrels compared to 9.7 million barrels in 1993. Certain units may be fired with oil or with natural gas when it is available on an economic or as-required basis. Gas consumption for the Company's system electric energy requirements in 1994 was 44.3 million dekatherms ("Dth") compared to 36.3 million Dth in 1993.
** Generated at Nine Mile Point 2.
*** Generated at (i) more economical nuclear, coal, oil and hydroelectric units owned by other electric systems and transmitted to the Company over its interconnections; (ii) the NYPA Holtsville facility; and (iii) cogenerators and independent power producers located within the Company's service territory.
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In 1992 and 1993, cogenerators and independent power producers provided 9.4% of the Company's system requirements for each of those years. In 1994, cogenerators and independent power producers provided 9.2% of the Company's system requirements. After the completion of a 40 MW cogeneration facility at the Stony Brook campus of the State University of New York ("Stony Brook") currently expected by mid 1995, independent power producers and cogenerators will provide an estimated 10.4% of the Company's system energy requirements.
The Company does not expect any new major independent power producers or cogenerators to be built on Long Island in the foreseeable future. Among the reasons supporting this conclusion is the Company's belief that the market for additional large electric projects to provide power to the Company's remaining commercial and industrial customers is small. Furthermore, under federal law, the Company is required to buy energy from qualified producers at the Company's avoided costs. Current long-range avoided cost estimates for the Company have significantly reduced the economic advantage to entrepreneurs seeking to compete with the Company and with existing independent power producers. For additional information respecting competitive issues facing the Company, see Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations for the Year Ended December 31, 1994."
Energy Sources
Oil: In recent years, the Company has been able to reduce its oil requirements generally by burning natural gas and by increasing its power purchases. The availability and cost of oil used by the Company are affected by factors beyond its control such as the international oil market, environmental regulations, conservation measures and the availability of alternative fuels. The Company's fuel oil is supplied principally by five suppliers.
For information concerning federal and other regulatory environmental limitations on fuel oil burned by the Company, see "Environment -- Air." For additional information concerning the recovery of electric fuel costs, see Note 1 to Notes to Financial Statements for the Year Ended December 31, 1994.
Gas: In addition to burning oil, several of the Company's generating stations have the capability of burning natural gas. These dual-fired units enable the Company to burn the most cost efficient fuel and to reduce its dependency on oil.
Nuclear: The Company holds an 18% interest in Nine Mile Point 2, a 1,047 MW nuclear generating unit near Oswego, New York. The cotenants of Nine Mile Point 2, in addition to the Company, are Niagara Mohawk Power Corporation ("Niagara Mohawk"), New York State Electric & Gas Corporation ("NYSEG"), Rochester Gas and Electric Corporation ("RG&E") and Central Hudson Gas & Electric Corporation.
For additional information on Nine Mile Point 2 and nuclear plant insurance, see Notes 5 and 10, respectively, of Notes to Financial Statements for the Year Ended December 31, 1994.
Independent Power Producers and Cogenerators: Independent power producers and cogenerators located within the Company's service territory provided approximately 203 MW of capacity to the Company in 1994. Capacity from these sources is expected to remain at approximately 203 MW in 1995. The Company has also contracted to purchase all excess power, currently estimated to total 9.2 MW, from the Stony Brook project on an energy-only basis. The Company had signed contracts for energy-only purchases totaling over 400 MW from several other projects, but these projects were not built prior to December 31, 1994, the expiration date of these contracts. In addition, the Company was ordered by the PSC to enter into a contract with Mayflower Energy Partners, L.P. ("Mayflower") incorporating the PSC's 1989 Long Run Avoided Cost ("LRAC") estimates. The contract, which the Company executed under protest, would have required the Company to purchase, on an energy-only basis, power for 15 years from a 300 MW facility scheduled to begin commercial operation in 1995. The Company commenced a lawsuit against the PSC and the New York courts ultimately annulled the PSC order requiring the Company to execute the contract. The Company then notified Mayflower that it was exercising its right to terminate the agreement as a result of Mayflower's failure to meet the construction commencement milestone date. Subsequently, in October 1994, Mayflower petitioned the PSC for a new contract based on a different LRAC estimate. The Company opposed Mayflower's petition on the grounds that the rates contained in the LRAC estimate requested by Mayflower were not just and reasonable. In February 1995, the PSC denied Mayflower's petition.
Interconnections: Five interconnections allow for the transfer of electricity between the Company and members of the NYPP and the New England Power Pool. Energy from these sources is transmitted pursuant to transmission agreements with Niagara Mohawk, NYPA, Northeast Utilities and Consolidated Edison Company of New York, Inc. ("Con Edison") and displaces energy which would otherwise be generated on the Company's system at a higher cost. The capacity of these interconnections is utilized for (i) the requirements of Con Edison, a co-owner with the Company of three of these interconnections, (ii) the requirements on Long Island of NYPA, the owner of one of these interconnections, (iii) the Company's purchases from NYPA and other utilities and (iv) the transmission of the Company's share of power from Nine Mile Point 2.
Conservation Services: In 1993, the Company filed a Modified Demand Side Management ("DSM") Plan with the PSC to support the objectives of the Company's electric rate case filed in December 1993. Under this modified plan, the Company proposed a substantially lower level of spending than that initially approved for 1994. The PSC did not approve the Company's proposed DSM program, but instead issued a ruling in July 1994 which dictated energy savings targets that were greater than those originally proposed by the Company. Specifically, the targets for the Company's DSM programs amounted to a 161.3 MW reduction in coincident peak demand and an annualized energy savings of 702.6 gigawatthours ("GWh") by December 31, 1994. The Company was successful in its DSM efforts.
In 1995, the Company intends to continue to carefully manage DSM expenditures and more fully transform DSM into a strategic marketing tool which can be used to position the Company for the future. In these efforts, the Company will act to further increase the emphasis on education and information programs and further decrease its emphasis on utility rebate payments. In addition, financing programs and other cost sharing arrangements will be stressed as a means to reduce DSM program costs. Finally, DSM programs will be redesigned to enhance the Company's competitive position through the offering of programs and services to the Company's customers and programs which promote the efficient use of electricity, including energy-efficient load growth.
1989 Settlement and Electric Rates
General: On February 28, 1989, the Company and the State of New York (by its Governor) entered into an agreement (the "1989 Settlement") settling certain issues relating to the Company and providing for, among other matters, the return of the Company to financial health, the transfer of the Shoreham Nuclear Power Station ("Shoreham") to LIPA and Shoreham's subsequent decommissioning.
The Rate Moderation Agreement: The Rate Moderation Agreement ("RMA"), a constituent document of the 1989 Settlement approved by the PSC, created an asset known as the Financial Resource Asset (the "FRA") and provides for its full recovery. The FRA has two components, the Base Financial Component (the "BFC") and the Rate Moderation Component (the "RMC").
The BFC, as initially established, represented the present value of the future net-after-tax cash flows which the RMA provided the Company for its financial recovery. Similar to plant investments, the BFC was granted rate base treatment under the terms of the RMA and is included in the Company's electric rates through amortization over 40 years on a straight-line basis. At December 31, 1994, the BFC amounted to $3.5 billion, net of accumulated amortization.
The RMC reflects the difference between the Company's revenue requirements under conventional ratemaking and the revenues resulting from the implementation of the rate moderation plan provided for in the RMA. Prior to December 31, 1992, the RMC had increased as the difference between revenues resulting from the implementation of the rate moderation plan provided for in the RMA and revenue requirements under conventional ratemaking, together with a carrying charge equal to the allowed rate of return on rate base, was deferred. The RMC had provided the Company with a substantial amount of non-cash earnings since the effective date of the 1989 Settlement through December 31, 1992, because the revenues provided under the RMA were less than the revenues required under conventional ratemaking. At December 31, 1992, the RMC balance was $652 million. Subsequent to December 31, 1992, the RMC balance decreased as revenues resulting from the operation of the rate moderation plan exceeded revenue requirements under conventional ratemaking. At December 31, 1994 and 1993, the RMC balance was $463 million and $610 million, respectively.
Electric Rates: The RMA contemplated, among other objectives, a series of rate increases designed to restore the Company to financial health. Pursuant to the RMA, the Company received electric rate increases of 5.4% effective February 18, 1989 and 5.0% for each of the rate years that began on December 1, 1989 and December 1, 1990. In 1991, the PSC approved annual electric rate increases of 4.15%, 4.1% and 4.0% effective on December 1 of 1991, 1992 and 1993, respectively.
In December 1993, the Company filed a three-year electric rate plan with the PSC for the period beginning December 1, 1994 (the "Electric Rate Plan"). The Electric Rate Plan, which may be approved, modified or rejected by the PSC, requests an allowed rate of return on common equity of 11.0% and provides for zero percent base rate increases in years one and two of the plan and an overall rate increase of 4.3% in the third year. Although base electric rates would be frozen during the first two years of the Electric Rate Plan, annual rate increases of approximately 1% are expected to result in years one and two from the operation of the Company's fuel cost adjustment ("FCA") mechanism. The FCA captures, among other things, amounts to be recovered from or refunded to ratepayers in excess of $15 million which result from the reconciliation of revenue, certain expenses, and earned performance incentive components as prescribed by the Long Island Lighting Company Ratemaking and Performance Plan.
The PSC had been expected to issue a final order on the Company's Electric Rate Plan before November 29, 1994, the date that the statutory suspension period was initially scheduled to terminate. However, in order to accommodate further settlement negotiations in the proceedings, the Company had requested extensions through April 1995, which were granted by the PSC.
In the past, the PSC has taken actions consistent with the recovery from ratepayers of the 1989 Settlement-deferred charges provided by the RMA. The PSC has granted the Company six of the eleven electric rate increases contemplated by the RMA and has also publicly confirmed its commitment to the effectuation of the 1989 Settlement. Although the ultimate outcome of the Electric Rate Plan cannot be predicted, the Company expects that any PSC order will be consistent with the provisions of the RMA respecting the recovery of the FRA and other 1989
Settlement-deferred charges.
For additional information respecting the 1989 Settlement and electric rates, see the discussion under the heading "Management's Discussion and Analysis of Financial Condition and Results of Operation for the Year Ended December 31, 1994" and Notes 1, 2 and 3 of Notes to Financial Statements for the Year Ended December 31, 1994.
Competitive Environment
For a discussion of the competitive issues facing the Company, see "Management's Discussion and Analysis of Financial Condition and Results of Operations For the Year Ended December 31, 1994."
SHOREHAM DECOMMISSIONING:
Pursuant to the 1989 Settlement, the Company transferred Shoreham and the Company's possession-only license for Shoreham to LIPA in February 1992, following a decision by the NRC that approved the transfer. In June 1992, the NRC issued an order authorizing LIPA to decommission Shoreham. During the fourth quarter of 1994, LIPA completed the decommissioning subject to the NRC's completion of a review of radiological measurements and its termination of the possession-only license, which is currently expected by mid-1995.
Under an agreement entered into as part of the 1989 Settlement (the "Amended and Restated Asset Transfer Agreement"), the Company is required to reimburse LIPA for any of its costs associated with the decommissioning of Shoreham. The Site Cooperation and Reimbursement Agreement (the "Site Agreement") entered into by the Company and LIPA describes the payment by the Company of LIPA's and NYPA's expenses attributable to the transfer, ownership, possession, maintenance and decommissioning of Shoreham, including certain taxes and payments-in-lieu-of-taxes ("PILOTS") with respect to the Shoreham site. The Site Agreement also governs, among other things, the conduct of the parties and of NYPA, and their access to facilities and properties at the Shoreham site.
At December 31, 1994, Shoreham post settlement costs totaled approximately $923 million (net of accumulated amortization of approximately $56 million). The $923 million consists of $429 million of property taxes and PILOTS and $494 million of decommissioning costs, fuel disposal costs and all other costs incurred at Shoreham after June 30, 1989, net of Shoreham salvage proceeds of approximately $44 million. The Company currently estimates that, during 1995, an additional $13 million of post settlement costs (other than PILOTS and finance charges) will be incurred. The precise amount of taxes and PILOTS that must be paid is the subject of the litigation described in Item 3, "Legal Proceedings -- Shoreham."
The PSC has determined that all costs associated with Shoreham which are prudently incurred by the Company subsequent to the effectiveness of the 1989 Settlement are decommissioning costs. The RMA provides for recovery of such costs through electric rates over the balance of a 40-year period ending 2029. In addition, pursuant to the RMA, the Company reflects the costs of the nuclear fuel related to Shoreham as a deferred charge to be recovered from ratepayers. The Company is required under the Amended and Restated Asset Transfer Agreement to reimburse LIPA for any of its costs associated with the storage and disposal of Shoreham's fuel, which was completed in 1994, and is allowed to recover these reimbursed amounts from its ratepayers as well.
For additional information respecting the 1989 Settlement, see Notes 1 and 2 of Notes to Financial Statements for the Year Ended December 31, 1994.
GAS OPERATIONS:
General
In 1994, the Company was an active participant in proceedings before FERC in various matters in an effort to reduce interstate pipeline charges, improve operational tariffs and to mitigate any adverse impact from interstate pipeline filings on the Company's customers. In addition, in 1995, the Company will actively participate in the proceedings before the PSC in an attempt to influence the establishment of the new competitive natural gas marketplace within the State of New York.
Gas System Requirements
At year-end 1994, the Company had a total of 449,316 firm gas customers, compared to 445,830 at year-end 1993 and 441,580 at year-end 1992. Of the 1994 year-end total, 277,077 were space heating customers. Total firm sales in 1994 were 58,889,386 Dth, compared to 59,182,674 Dth in 1993. The maximum daily sendout experienced on the Company's gas system in 1994 was 585,227 Dth on January 19, 1994. The forecasted maximum daily sendout for the 1994-95 winter season (November 1 - March 31) is 608,000 Dth, representing 86% of the Company's maximum daily firm operating supply capability of 705,597 Dth for this period. Based on this forecasted amount, the Company should have a peak day surplus of 97,597 Dth of firm supply including peak shaving capability for the 1994-95 winter season. The Company recovers the costs of its gas supply from both its firm and interruptible customers through provisions in the Company's rate schedules.
Continuing its recent efforts to expand its base of customers, the Company is emphasizing residential and commercial gas marketing. In particular, new market segments and new uses for natural gas are being sought, especially as a replacement for diesel fuel. The technology for natural gas as a vehicular fuel is becoming commercially viable. Natural gas can be cost effective if used in high volume for public transportation and public works vehicles. In addition to the Long Island Bus Company (formerly the Metropolitan Suburban Bus Authority), the Company has worked with local municipalities in testing the viability of converting various vehicle types to compressed natural gas as well as in designing and installing refueling stations. Projects currently under consideration could ultimately displace several thousand gallons of diesel fuel per day.
Gas Transportation and Supply
The proceedings before FERC, developing out of its Order No. 636, have resulted in a regulatory "unbundling" of the gas supply, transportation and storage services that for decades had been provided by the nation's natural gas pipelines. As a result of Order No. 636, pipelines, for the most part, no longer act as sales agents to bundle the mix of services from the producers and other interstate pipelines. Local distribution companies ("LDCs") must now make arrangements for gas supplies and gas storage directly with producers, marketers, pipelines and the owners of storage facilities. In addition, each LDC must now also make separate transportation arrangements with each pipeline in the path between the supplier and the LDC's citygate and not merely with the nearest pipeline connecting to the LDC's system. Prior to the effective date of Order No. 636, LDCs had purchased their gas supplies at the citygate from those pipelines serving their territories. The citygate is generally the location where the interstate pipeline meets the local distribution company's system. The Company shares common citygate facilities, known as the New York Facilities, with Con Edison and the Brooklyn Union Gas Company. The Company's principal pipeline suppliers are Transcontinental Gas Pipe Line Corporation ("Transcontinental"), Texas Eastern Transmission Corporation ("Texas Eastern"), CNG Transmission Corporation ("CNG"), Tennessee Gas Pipeline Company ("Tennessee") and the Iroquois Gas Transmission System ("Iroquois"). Through its wholly-owned subsidiary, the Company is a general partner in Iroquois, with an equity share of 1%. The Company, through a wholly-owned subsidiary, had been a 3-1/3% equity partner in the Liberty Pipeline Company ("Liberty"). However, as a result of a re-evaluation of its gas supply needs, in May 1994, the Company notified the other Liberty partners of its withdrawal from the Liberty pipeline partnership.
Gas Transportation: The Company's gas transportation capacity for meeting its 1994-95 winter season requirements is provided from a portfolio of year-round, winter seasonal, storage and cogenerator services summarized below:
Year-Round Pipeline Firm Transportation: The Company has 318,692 Dth per day of year-round pipeline firm transportation capacity provided by four interstate pipeline companies: Transcontinental, Texas Eastern, Tennessee and Iroquois. For the 1994-1995 winter season, options to purchase 60,200 Dth per day of capacity have been granted to off-system markets leaving a total of 258,492 Dth available to meet system peak-day requirements.
Winter Seasonal Pipeline Firm Transportation: The Company has winter seasonal pipeline firm transportation capacity on Transcontinental amounting to 2,726 Dth per day available through March 31, 1995.
Storage: The Company also has long-term firm storage services to meet higher winter demand which provide a total operating supply of approximately 287,839 Dth per day with a total capacity of 23,505,043 Dth for the winter period. Of these totals, 277,589 Dth per day, or a total capacity of 22,268,043 Dth, is provided by gas storage fields at Leidy, Pennsylvania, and 10,250 Dth per day, or a total capacity of 1,237,000 Dth, is provided by a gas storage field in upstate New York operated by Honeoye Storage Corporation ("Honeoye"). The Company currently owns 23- 1/3% of the common stock of Honeoye. In addition, the Company has the right to request 812,500 Dth in the winter period from a cogeneration facility with the obligation to return quantities in kind during the following summer period.
The Company also contracts for storage capacity in a facility in Louisiana near sources of supply and pipeline transportation. Up to 50,687 Dth per day can be withdrawn with a total storage capacity of 4,459,220 Dth available at this facility. While this facility provides the Company with greater security of supply and enhanced operational flexibility in meeting peak-day requirements, the Company has no related firm pipeline transportation agreement for these supplies. Therefore, to access gas from this storage, the Company must curtail the transportation of some of its firm contract supply.
Other Deliveries: The Company has contract rights with NYPA to receive a total of 900,000 Dth during a continuous 100 day period between November 1 and March 31 of each winter season at a daily rate not to exceed 30,840 Dth per day.
Gas Supply: The Company's gas supplies for the 1994-95 winter season are provided from a portfolio of year-round, winter seasonal, storage and peak shaving supplies summarized below.
Year-Round Firm Supply: Of the 213,469 Dth of firm supplies, 83,575 Dth are Canadian and 129,894 Dth are domestic. The Company owns 2.7% of the common stock of Boundary Gas, Inc., ("Boundary"), a corporation formed with 15 other gas utility companies to act as a purchasing agent for the importation of natural gas from Canada. The Company obtains 2,470 Dth per day of its long-term firm Canadian supply from this source. Gas supplies to use 105,223 Dth per day of the remaining year-round pipeline firm transportation capacity are purchased by the Company in both the seasonal and monthly spot markets.
Winter Seasonal Firm Supply: The Company also contracts for firm seasonal supply of 90,223 Dth delivered during the period November 1 - March 31 of each year from a number of winter seasonal suppliers.
Peak Shaving: The Company has its own peak shaving supplies to meet its requirements on excessively cold winter days. They include a liquefied natural gas plant with a storage capacity of approximately 620,000 Dth of gas and vaporization facilities which provide 103,300 Dth per day to the peak-day capability of the Company's system. In addition, the Company has propane facilities that produce 22,400 Dth per day of peak shaving with a storage capacity of approximately 100,000 Dth.
Gas Rates
In December 1993, the PSC approved a three-year gas rate settlement between the Company and the Staff of the PSC. The gas rate settlement provides that the Company receive, for each of the rate years beginning December 1, 1993, 1994 and 1995, annual gas rate increases of 4.7%, 3.8% and 2.8%, respectively. In the determination of the revenue requirements for the gas rate settlement, an allowed rate of return on equity of 10.1% was used. The gas rate decision also provides for earnings in excess of a 10.6% return on equity in any of the three rate years covered by the settlement to be shared equally between the Company's firm gas customers and its shareowners. For additional information respecting gas rates, see Note 3 of Notes to Financial Statements for the Year Ended December 31, 1994.
Other Activities
The unbundling of gas transportation activities and the need for local distribution companies to negotiate directly with producers and other suppliers and with pipelines has provided the Company with new business opportunities. These new opportunities include providing gas to non-traditional markets including LDCs and end-users from Mississippi to Connecticut. In 1994, total activities in this area generated $26 million in revenue. The profit realized from this activity is shared 85%-15% between the Company's firm gas customers and shareowners, respectively.
Recovery of Transition Costs
Transition costs are the costs associated with unbundling the pipelines' merchant services in compliance with Order No. 636. They include pipelines' unrecovered gas costs and the costs that pipelines incur as a result of reforming or terminating their gas supply contracts. In order to recover transition costs, pipelines must demonstrate to FERC that such costs were attributable to FERC Order No. 636 and that they were prudently incurred. While the Company has challenged, on both eligibility and prudence grounds, its suppliers' pipelines' efforts to recover their claimed transition costs, the Company presently estimates that its total transition costs will be approximately $9 million. As of December 31, 1994, the Company has paid approximately $7 million of these transition costs and is currently collecting these costs from its gas customers in rates.
ENVIRONMENT:
General
The Company is subject to federal, state and local laws and regulations dealing with air, water and land quality and other environmental matters. It is not possible to ascertain with certainty if or when the various required governmental approvals for which applications have been made will be issued, whether, except as noted below, additional facilities or modifications of existing or planned facilities will be required or, generally, what effect existing or future controls may have upon Company operations. Except as set forth below and in Item 3 - "Legal Proceedings", no material proceedings have been commenced or, to the knowledge of the Company, are contemplated
by any federal, state or local agency against the Company, nor is the Company a defendant in any material litigation with respect to any matter relating to the protection of the environment.
In 1995 and 1996, in order to comply with environmental regulations, the Company anticipates capital expenditures of approximately $6.0 million and $3.5 million, respectively.
Air
Federal, state and local regulations affecting new and existing electric generating plants govern, among other emissions, sulfur dioxide and nitrogen oxide ("NOx") and, in the future, hazardous air pollutants.
The laws governing the sulfur content, by weight, of the fuel oil being burned by the Company in compliance with the United States Environmental Protection Agency ("EPA") approved Air Quality State Implementation Plan ("SIP") are administered by the New York State Department of Environmental Conservation ("DEC"). The Company does not expect to incur any costs to satisfy the 1990 amendments to the federal Clean Air Act (the "Act") with respect to the reduction of sulfur dioxide emissions, since the Company already uses fuel with acceptable low levels of sulfur.
During 1994, the Company spent approximately $6.4 million in order to comply with the Act. These expenditures were necessary to meet continuous emissions monitoring requirements and Phase I NOx reduction requirements under the Act.
The Company expects that it will have to expend approximately $1 million in 1995 to meet continuous emission monitoring requirements and to meet Phase I NOx reduction requirements. In order to generate 210 tons of NOx reduction credits already under contract for sale to a third party, the Company anticipates spending $2.5 million in 1995 and $1.9 million in 1996 for earlier than required NOx reduction systems. Subject to requirements that are expected to be promulgated in forthcoming regulations, the Company estimates that it may be required to spend an additional $80 million (net of NOx credit sales) by 2003 to meet Phase II and Phase III NOx reduction requirements. In an effort to minimize anticipated NOx reduction requirements, the Company is engaged in a $7 million research and development project along with several co-funding organizations to demonstrate an innovative NOx reduction technology at its E. F. Barrett Power Station. The Company is committed to fund $3.6 million of the project costs. Through 1994, approximately $5 million has been expended by all of the co-funders. It is anticipated that the remaining $2 million will be spent in 1995. In addition, the Company anticipates that it may be required to spend approximately $24 million by 1999 to meet potential requirements for the control of hazardous air pollutants from power plants. The Company believes that all of the above costs will be recoverable in rates.
Electromagnetic fields ("EMF") occur naturally and also are produced wherever there is electricity. These fields exist around power lines and other utility equipment. The Company is in compliance with all applicable regulatory standards and requirements concerning EMF. The Company also monitors scientific developments in the study of EMF, contributes to funding for research efforts and is actively involved in customer and employee outreach programs to inform the community of EMF developments as they occur. Although an extensive body of scientific literature has not shown an unsafe exposure level or a causal relationship between EMF exposure and adverse health effects, concern over the potential for adverse health effects will likely continue without final resolution for some time.
To date, the Company has not been involved in any matter that alleged such a causal relationship. However, four residential property owners have initiated lawsuits against the Company alleging that the existence of EMF has diminished the value of their homes. These actions are in the preliminary stages of discovery and their outcome is uncertain. The Company is currently unable to predict the impact, if any, that EMF-related matters will have on its financial position.
Water
Under the federal Clean Water Act and the New York State Environmental Conservation Law, the Company is required to obtain a State Pollutant Discharge Elimination System permit to make any discharge into the waters of the United States or New York State. The DEC has the jurisdiction to issue those permits and their renewals and has issued permits for the Company's generating units. The permits allow the continued use of the circulating water systems which have been determined to be in compliance with State Water Quality Standards. The permits also allow for the continued use of the chemical treatment systems. The Company expects to upgrade certain underground tanks and piping systems in 1995 in order to comply with federal and local regulations.
Land
The DEC has indicated to New York State utilities that it may require all such utilities to investigate and, where necessary, remediate their former manufactured gas plant sites. The Company is the owner of six pieces of property on which the Company or certain of its predecessor companies produced manufactured gas. Although the exact amount of the Company's clean-up costs cannot yet be determined, based on the findings of investigations at two of these six sites, preliminary estimates indicate that it may cost approximately $35 million to clean up all of these sites over the next five to ten years. Accordingly, the Company has recorded a $35 million liability and has also recorded a $35 million regulatory asset to reflect its belief that the PSC will provide for the future recovery of these costs as it has for other New York State utilities. The Company has notified its former and current insurance carriers that it seeks to recover from them certain of these cleanup costs. However, the Company is unable to predict the amount of insurance recovery, if any, that it may obtain.
The Company has been notified by the EPA that it is one of many potentially responsible parties ("PRPs") that may be liable for the remediation of a licensed disposal site located in Philadelphia, Pennsylvania, and operated by Metal Bank of America. The Company and nine other PRPs, all of which are public utilities, have completed a Remedial Investigation and Feasibility Study which is currently being reviewed by the EPA. The level of remediation required will be determined when the EPA issues its decision, currently expected in May 1995. The Company currently anticipates that the total cost to remediate this site will be between $14 million and $30 million. The Company has recorded a liability of $1.1 million representing its estimated share of the cost to remediate this site. The Company believes that any cost incurred to remediate this site will be recoverable through rates.
The Company has also been named a PRP for disposal sites in both Kansas City, Kansas, and Kansas City, Missouri. The Company is investigating allegations that it had previously stored or made agreements for the disposal of polychlorinated biphenyls ("PCBs") or items containing PCBs at these sites. The Company is currently unable to determine its share of the cost to remediate these sites or the impact, if any, on the Company's financial position. The Company believes that any costs incurred to remediate these sites will be recoverable through rates.
In March 1989, the Company was notified that it was a PRP for a landfill in Port Washington, Long Island. The Company does not believe that it has contributed to the contamination of the site and has declined the EPA's requests to participate in the investigation and remediation activities at the site. The Company has not received further communications regarding this site.
The Company is in the process of entering into an Administrative Order on Consent with the DEC to remediate lead contaminated soils at a former distribution gas holder site in Inwood, New York that contained a gas holder coated with lead paint. Based on the current cleanup objectives, remediation costs are estimated at $2 million and are expected to be incurred from 1995 to 1996.
As a result of a leak in a fluid filled electrical cable in August 1994, the Company is required to remediate certain soil locations in North Hills, Long Island that were impacted by a release of insulating fluid from
the cable. The preliminary estimated cleanup costs, expected to be incurred from 1995 to 1996, range from $0.5 to $3.2 million. The Company has initiated cost recovery actions against third parties it believes are responsible for causing the cable leak, the outcome of which is uncertain.
For information concerning environmental litigation, see Item 3 -- "Legal Proceedings--Environmental."
Nuclear Waste
Under the federal Low Level Radioactive Waste Policy Amendment Act of 1985, New York was required, by January 1, 1993, to have arranged for the disposal of all low level, radioactive waste generated within the state or, in the alternative, contracted for the disposal of waste at an operating facility outside the state. Failure to do so would require New York to forfeit to the generators of waste in the state the rebate of a portion of the surcharges paid by such generators for the disposal of waste at operating facilities outside the state. New York's contract with the State of South Carolina for the disposal of all low level radioactive waste (except mixed wastes) expired in June 1994.
Under the Amended and Restated Asset Transfer Agreement, discussed under the heading "Shoreham Decommissioning," LIPA is responsible for the disposal of waste associated with the decommissioning of Shoreham, although such costs will be paid by the Company and recovered through electric rates. All low level radioactive waste associated with the decommissioning of Shoreham was sent to South Carolina for disposal prior to the expiration of the disposal contract.
All low level radioactive waste generated at the Nine Mile Point 2 site since June 1994 is being temporarily stored at the Nine Mile site. A waste management program has been put in place that will properly handle interim on-site storage of low level radioactive waste for at least ten years, if required. All costs associated with temporary storage and ultimate disposal are expected to be recovered in rates.
In addition, Niagara Mohawk, on behalf of the Nine Mile Point 2 cotenants, has entered into a contract with DOE for the permanent storage of Nine Mile Point 2 spent nuclear fuel. The Company reimburses Niagara Mohawk for its 18% share of the cost under the contract at a rate of $1.00 per megawatt hour of net generation less a factor to account for transmission line losses. The Company is collecting its portion of this fee from the Company's ratepayers. However, progress in developing a permanent DOE repository for such high level radioactive material has been slow and it is unlikely that the DOE's latest projections for opening a facility in 2010 can be met. In the interim, DOE is proposing to begin accepting some spent fuel from the electric utility industry as early as 1998 at a proposed Monitored Retrievable Storage ("MRS") facility. In view of the very limited progress made to date, it is unlikely that this facility will begin operation in 1998. A more probable date for operation of the MRS facility cannot be accurately determined at this time. Currently, all spent nuclear fuel from Nine Mile Point 2 is being stored on site. The present licensed storage capacity for Nine Mile Point 2 is expected to be sufficient to meet its needs so that storage alternatives are not believed to be needed at this time. The Company does not anticipate that the possible unavailability of a DOE facility in 1998 will inhibit the operation of Nine Mile Point 2.
THE COMPANY'S SECURITIES:
General
The Company's securities are rated by Moody's Investors Service, Inc., Standard and Poor's Ratings Group, Fitch Investors Service, Inc. and Duff and Phelps, Inc. For information relating to the ratings of the Company's securities, see the discussion under the heading "Management's Discussion and Analysis of Financial Condition and Results of Operations for the Year Ended December 31, 1994."
The G&R Mortgage
The Company's General and Refunding Indenture dated June 1, 1975 (the "G&R Indenture" or "G&R Mortgage") is a lien upon substantially all of the Company's properties. The lien of the G&R Mortgage is currently subordinate to the lien of the Company's Indenture of Mortgage and Deed of Trust dated September 1, 1951 (the "Indenture of Mortgage" or "First Mortgage"). The G&R Mortgage will become the Company's senior mortgage in 1997, the year in which the last of the currently outstanding non-pledged First Mortgage Bonds mature. Outstanding at December 31, 1994 were approximately $2 billion of General and Refunding Bonds (the "G&R Bonds") and $100 million of First Mortgage Bonds, excluding $1.3 billion of First Mortgage Bonds which are pledged with the G&R Trustee as additional security for the G&R Bonds (the "Pledged Bonds"). Additional information concerning the Company's G&R Mortgage and the First Mortgage is discussed below and in Note 7 of Notes to Financial Statements for the Year Ended December 31, 1994.
Under the G&R Mortgage, the Company may issue G&R Bonds on the basis of either matured or redeemed G&R Bonds and First Mortgage Bonds (other than Pledged Bonds) or on the basis of the Bondable Value of Property Additions ("BVPA"). Generally, when issuing G&R Bonds, the Company must satisfy a mortgage interest coverage requirement (the "G&R Mortgage Interest Coverage"). The G&R Mortgage Interest Coverage requires that the Net Earnings available for interest for any 12 consecutive calendar months within the 15 consecutive calendar months preceding the issuance of the G&R Bonds must be equal to at least two times the stated annual interest payable on outstanding G&R Bonds and Prior Lien Bonds (other than Pledged Bonds), including any new G&R Bonds. Under the G&R Mortgage Interest Coverage, the Company would currently be able to issue approximately $4.1 billion of additional G&R Bonds based upon: (i) earnings for the 12 months ended December 31, 1994 and (ii) an assumed interest rate of 10% for such additional G&R Bonds. A change of 1/8 of 1% in the assumed interest rate of such G&R Bonds would result in a change of approximately $51 million in the amount of such G&R Bonds that the Company could issue. The maximum amount of additional G&R Bonds which the Company is currently able to issue on the basis of either matured or retired G&R Bonds and First Mortgage Bonds (other than Pledged Bonds) and on the basis of the BVPA is approximately $520 million.
The Company believes that, based upon currently scheduled redemptions and maturities, it will have sufficient retired G&R Bonds and First Mortgage Bonds for the foreseeable future to satisfy the requirements of the G&R Sinking Fund or to withdraw with retired G&R Bonds and First Mortgage Bonds any cash that may be deposited to satisfy the Sinking Fund requirements. The Sinking Fund requires the Company to pay $26 million or to certify a like amount of retired G&R Bonds and First Mortgage Bonds on or before June 30, 1995. The Company is planning to satisfy this requirement in 1995 with retired G&R Bonds. In addition, the Company may use Property Additions to satisfy this requirement.
The Maintenance Fund covenant under the G&R Mortgage requires that the aggregate amount of Property Additions added subsequent to December 31, 1974 must be, as of the end of each calendar year subsequent to 1974, at least equal to the cumulative Provision for Depreciation (as defined in the G&R Mortgage) from December 31, 1974. The G&R Mortgage requires cash (or retired G&R Bonds or retired First Mortgage Bonds) to be deposited to satisfy the Maintenance Fund requirement only when such cumulative Provision for Depreciation exceeds such aggregate amount of Property Additions. As of December 31, 1994, the amount of such cumulative Property Additions calculated pursuant to the G&R Mortgage was approximately $9.7 billion, including approximately $5.5 billion of Property Additions attributable to Shoreham. Also, as of December 31, 1994, the amount of the cumulative Provision for Depreciation, similarly calculated, was approximately $1.6 billion. The Company anticipates that the aggregate amount of Property Additions will continue to exceed the cumulative Provision for Depreciation.
The First Mortgage
Under the provisions of the G&R Mortgage, the Company may not issue any additional bonds under the Company's First Mortgage other than Pledged Bonds which are required, concurrently with the issuance of each new series of G&R Bonds, to be deposited with the G&R Trustee. The issuance of any such Pledged Bonds does not create additional indebtedness. The coverage requirements of the First Mortgage and the Company's ability to issue additional Pledged Bonds do not restrict the Company's ability to issue additional G&R Bonds. Of the approximately $1.4 billion of First Mortgage Bonds outstanding at December 31, 1994, $1.3 billion, or 93%, were Pledged Bonds. After satisfying the 1994 Depreciation Fund and Sinking Fund requirements discussed below, the Company expects that it will issue additional Pledged Bonds if it issues additional G&R Bonds prior to the maturity, in 1997, of the last of the outstanding non- pledged First Mortgage Bonds.
The First Mortgage requires the Company to pay the First Mortgage Trustee by June 30 of each year cash equal to 1% of all previously issued First Mortgage Bonds (excluding bonds issued on the basis of retired bonds). Currently, the annual First Mortgage Sinking Fund requirement is approximately $21 million. The Company expects to satisfy this requirement prior to June 30, 1995, with retired First Mortgage Bonds. The annual Sinking Fund requirement is not expected to change, because of restrictions in the G&R Mortgage, until and unless the Company issues additional G&R Bonds. The Company expects to be able to satisfy the Sinking Fund requirement in 1996, the last year in which this requirement must be met, with cash, available Property Additions or retired First Mortgage Bonds which become available through scheduled maturities.
The Depreciation Fund covenant of the First Mortgage requires that the Company pay to the First Mortgage Trustee by June 30 of each year cash (which may be withdrawn up to the amount of Gross Bondable Additions and retired First Mortgage Bonds made the basis for such withdrawal) equal to the greater of (a) the amount actually charged on the Company's books as a utility operating revenue deduction for the preceding calendar year for depreciation, depletion, obsolescence, retirements and amortization of the Company's Utility Plant ("Book Depreciation") or (b) an amount equal to (i) 15% of gross operating revenues (less the cost of electricity and gas purchased for resale) from Utility Plant for such year less (ii) the amount actually expended for maintenance of Utility Plant during such year ("Revenue Depreciation"). Since the oil crisis of the 1970s, Revenue Depreciation in each year has been greater than Book Depreciation for such year. The Revenue Depreciation requirement for 1994 was approximately $239 million. Instead of paying cash to satisfy this Depreciation Fund requirement, the First Mortgage permits the Company to deliver First Mortgage Bonds or certify Property Additions. The Company expects to satisfy the 1994 requirement by June 30, 1995, using a combination of First Mortgage Bonds and Property Additions. The Company presently plans, assuming that its expenditures for capital improvements are approximately $250 million annually and notwithstanding that G&R Bonds may be issued which would require, in turn, the issuance of First Mortgage Bonds to be pledged, that it will have adequate Property Additions and sufficient retired First Mortgage Bonds, including Pledged Bonds, to satisfy the Depreciation Fund requirements in 1996, the last year in which this requirement must be met.
Unsecured Debt
The Company's First Mortgage, its G&R Mortgage and its Restated Certificate of Incorporation do not contain any limitations upon the issuance of unsecured debt. The Company's unsecured debt consists of Debentures and certain tax-exempt securities.
The Company's Debenture Indenture, dated as of November 1, 1986, as supplemented, and its Debenture Indenture, dated as of November 1, 1992, as supplemented, (together, the "Debenture Indentures") each provide for the issuance of an unlimited amount of Debentures to be issued in amounts that may be authorized from time to time in one or more series. The Debentures are unsecured and rank pari passu with all other unsecured indebtedness of the Company subordinate to the obligations secured by the Company's two mortgages. Currently, there are approximately $2.3 billion of Debentures outstanding.
As of December 31, 1994, the Company had outstanding approximately $867 million principal amount of promissory notes, securing $2 million of tax-exempt Industrial Development Revenue Bonds ("IDRBs"), approximately $215 million of tax-exempt Pollution Control Revenue Bonds ("PCRBs") and $650 million of tax-exempt Electric Facility Revenue Bonds ("EFRBs"). Of these amounts, $17 million issued in 1982, $150 million issued in 1985 (the "1985 PCRBs"), $100 million issued in 1993 (the "1993 EFRBs") and $50 million issued in 1994 (the "1994 EFRBs") are subject to periodic tenders by the holders of the tax-exempt bonds. The 1985 PCRBs, 1993 EFRBs and 1994 EFRBs are supported by letters of credit pursuant to which the letter of credit banks have agreed to pay the principal, interest and premium, if applicable, on any tendered 1985 PCRBs, 1993 EFRBs or 1994 EFRBs, in the aggregate, up to approximately $163 million, $109 million, and $54 million respectively, in the event of default. These letters of credit expire on March 16, 1996, November 17, 1996 and October 26, 1997, respectively. The obligations of the Company to reimburse the letter of credit banks supporting the 1985 PCRBs, the 1993 EFRBs and the 1994 EFRBs are unsecured. Each of the IDRBs, the PCRBs and the EFRBs have been issued by the New York State Energy Research and Development Authority ("NYSERDA").
See Note 7 of Notes to Financial Statements for the Year Ended December 31, 1994 for additional information respecting the Company's outstanding debt securities.
Equity Securities
Preferred Stock: The Company's Restated Certificate of Incorporation provides that the Company may not issue additional Preferred Stock unless the net earnings of the Company available for payment of interest on its debt after depreciation and all taxes for any 12 consecutive calendar months within the 15 calendar months preceding the month of issuance are at least 1.50 times the aggregate of the annual interest charges and dividend requirements on the debt and Preferred Stock to be outstanding immediately after the issuance of such Preferred Stock (the "Earnings Ratio"). The Company currently satisfies the Earnings Ratio and could issue up to approximately $250 million of Preferred Stock. When the proceeds from the sale of the Preferred Stock to be issued are used to redeem outstanding Preferred Stock, the requirement to satisfy the Earnings Ratio is not applicable if the dividend requirement and the requirements for redemption in a voluntary liquidation of the Preferred Stock to be issued do not exceed the respective amounts for the Preferred Stock which is to be retired. Additional Preferred Stock may also be issued beyond amounts permitted under the Earnings Ratio with the approval of at least two-thirds of the votes entitled to be cast by the holders of the total number of shares of outstanding Preferred Stock.
Default in the payment of dividends on any shares of Preferred Stock in an amount equivalent to or exceeding four full quarterly dividends for any series of Preferred Stock entitles all holders of shares of Preferred Stock, voting separately as a class and regardless of series, to elect a majority of the Board of Directors of the Company. The remaining Directors are elected by the holders of Common Stock. The right of holders of shares of Preferred Stock to elect a majority of the Board of Directors ceases when and if the Company ceases to be in default in the payment of its Preferred Stock dividends. At that time, the terms of office of the Directors of the Company elected by the holders of Preferred Stock terminate and the resulting vacancies are to be filled by the vote of the remaining Common Stock Directors.
Preference Stock: Issuance of Preference Stock, which is subordinate to the Company's Preferred Stock, but senior to its Common Stock, with respect to declaration and payment of dividends and the right to receive amounts payable on any dissolution, does not require satisfaction of a net earnings test or any other coverage requirement, unless established by the Board of Directors for one or more series of Preference Stock, prior to the issuance of such series. No Preference Stock has been issued by the Company nor does the Company currently plan to issue any Preference Stock.
Common Stock: The Company's Common Stock is listed on the New York and Pacific Stock Exchanges, and is traded under the symbol "LIL". The Board of Directors' current policy is to pay cash dividends on the Common Stock on a quarterly basis. However, before declaring any dividends, the Company's Board of
Directors considers, among other factors, the Company's financial condition, its ability to comply with provisions of the Company's Restated Certificate of Incorporation and the availability of retained earnings, future earnings and cash.
EXECUTIVE OFFICERS OF THE COMPANY:
Current information regarding the Company's Executive Officers, all of whom serve at the will of the Board of Directors, follows:
William J. Catacosinos: Dr. Catacosinos has served as Chairman of the Board of Directors and Chief Executive Officer of the Company since January 1984, and as a Director since December 1978. Dr. Catacosinos also served as President of the Company from March 1984 to January 1987 and from March 1994 to present. Dr. Catacosinos, 65, a resident of Mill Neck, Long Island, earned a bachelor of science degree, a masters degree in business administration and a doctoral degree in economics from New York University. Dr. Catacosinos currently chairs the Executive Committee of the Company's Board of Directors, and is a member of the boards of U.S. Life Corporation, Austin International Communications, Edison Electric Institute, the Long Island Association, the German American Chamber of Commerce, the Business Alliance for a New, New York, and a member of the Advisory Committee of the Huntington Township Chamber Foundation. He is the former chairman and chief executive officer of Applied Digital Data Systems, Inc., Hauppauge, New York, a manufacturer of computer and related products. Previously, Dr. Catacosinos also served as chairman of the board and treasurer of Corometric Systems, Inc. of Wallingford, Connecticut and as Assistant Director at Brookhaven National Laboratory. He was also a member of the boards of Utilities Mutual Insurance Co. from November 1985 through December 1994 and Ketema, Inc. from June 1988 through December 1994. Ketema is a diversified manufacturer of, among other things, electrical and aerospace equipment. In compliance with Section 305(b) of the Federal Power Act, Dr. Catacosinos had authorization from FERC to hold the position of an officer or director of a public utility and at the same time the position of an officer or director of a firm that supplies electrical equipment to such public utility.
Theodore A. Babcock: Mr. Babcock was named Treasurer of the Company on February 4, 1994. As Treasurer, he is responsible for Treasury Operations, Debt Management, Trust Asset Management, Risk Management and Remittance Processing. Mr. Babcock, 40, joined the Company in July 1992 as Assistant Treasurer. He previously spent five years in the AMBASE Corporation as an Assistant Vice President and was promoted in 1988 to Vice President and Treasurer. Prior to AMBASE, Mr. Babcock spent 11 years with the Associated Dry Goods Corporation where he was promoted to Assistant Treasurer and Director of Corporate Treasury Operations in 1984. Mr. Babcock received a bachelor of science degree in accounting from Manhattan College and a masters degree in finance from Iona College.
James T. Flynn: Mr. Flynn was named Chief Operating Officer of the Company on March 1, 1994 and continues in his position of Executive Vice President which he assumed in April 1992. Mr. Flynn joined the Company in October 1986 as Vice President of Fossil Production and later assumed the position of Group Vice President, Engineering and Operations. Before joining the Company, Mr. Flynn, 61, was general manager-Eastern Service Department for General Electric. His career began as a member of General Electric's Technical Marketing Program in 1957. He holds a bachelor of science degree in mechanical engineering from Bucknell University and is a Licensed Professional Engineer in the State of Pennsylvania.
Joseph E. Fontana: Mr. Fontana was named Controller of the Company on October 1, 1994. Mr. Fontana, 37, joined the Company in December 1992 as Director of Accounting Services. He held the position of Assistant Controller from February 1994 through September 1994. Before joining the Company, Mr. Fontana was a Senior Manager at the international accounting firm, Ernst & Young LLP. He holds a bachelor of science degree in accounting from Westchester State College and is a Certified Public Accountant.
Robert X. Kelleher: Vice President of Human Resources since July 1986, Mr. Kelleher, 58, joined the Company in 1959 and has held various managerial positions in the Finance, Accounting, Purchasing, Stores and Employee Relations organizations. He was Industrial Relations Manager from 1975 to 1979, Manager of the Employee Relations Department from 1979 to 1985 and Assistant Vice President of the Employee Relations Department from 1985 to 1986. Mr. Kelleher is a graduate of St. Francis College and the Human Resources Management and Executive Management Programs of Pennsylvania State University. Mr. Kelleher is a member of the American Compensation Association, Personnel Directors Council, Industrial Relations Research Institute, Edison Electric Institute's Labor Relations Committee and is on the advisory council of New York Institute of Technology's Center for Labor Relations.
John D. Leonard, Jr.: Mr. Leonard joined the Company in 1984, initially serving as Vice President of Nuclear Operations. He assumed additional duties as Vice President of Corporate Services from July 1989 through March 1994. Mr. Leonard was named Vice President of Engineering and Construction on April 1, 1994 and continues to be responsible for nuclear issues. Mr. Leonard, 62, was the vice president and assistant chief engineer for design and analysis at the New York Power Authority, from 1980 to 1984. Prior to this position, he served as a resident manager of the Fitzpatrick Nuclear Power Plant for approximately five years. Before accepting a position at the New York Power Authority, Mr. Leonard served as corporate supervisor of operational quality assurance of the Virginia Electric Power Company from 1974 to 1976. In 1974, Mr. Leonard retired with the rank of Commander from the United States Navy, having commanded two nuclear powered submarines in a career that spanned 20 years. He holds a bachelor of science degree from Duke University and a master of science degree from the Naval Post Graduate School. He is a Licensed Professional Engineer in the State of New York.
Adam M. Madsen: Vice President of Corporate Planning since 1984, Mr. Madsen, 58, holds a bachelors degree in electrical engineering from Manhattan College and a master of science degree in nuclear engineering from Long Island University. He has been with the Company since 1961, serving in various engineering positions including Manager of Engineering from 1978 to 1984. Prior to that time, he held the position of Manager of the Planning Department. Since 1978, Mr. Madsen has been the Company's representative to the Planning Committee of the New York Power Pool. He is a member of the Northeast Power Coordinating Council's Joint Coordinating Committee and an alternate to the Council's Executive Committee. He also serves on the Board of Directors of the Empire State Electric Energy Research Company. Mr. Madsen is a Licensed Professional Engineer in the State of New York.
Kathleen A. Marion: Ms. Marion was named Vice President of Corporate Services on April 1, 1994 and continues in her position of Corporate Secretary which she assumed in April 1992. Ms. Marion has served as Assistant to the Chairman since April 1987 and was Assistant Corporate Secretary from April 1990 to 1992. Ms. Marion, 40, has a bachelor of science degree in business and finance from the State University of New York at Old Westbury.
Arthur C. Marquardt: Senior Vice President of Gas Business Unit since March 1992, Mr. Marquardt, 48, joined the Company in January 1991. He held the position of Vice President of Strategic Business Planning from January 1991 through March 1992. He is chairman of the New York Facilities executive committee, director of the Huntington Chamber of Commerce, the Huntington Chamber Foundation, the Long Island Builders Institute and a member of the Family Service League Business Advisory Council. Mr. Marquardt has had extensive and varied business experience at Combustion Engineering Inc., General Electric Company, Quadrex Corporation, and at Pacific Nuclear Systems, Inc. where he was president and chief operating officer. He received a bachelor of science degree in mechanical engineering from Tufts University.
Brian R. McCaffrey: Vice President of Administration since March 1987, Mr. McCaffrey, 49, joined the Company in 1973. Mr. McCaffrey holds a bachelor of science degree in aerospace engineering from the University of Notre Dame. He also received a master of science degree in aerospace engineering from Pennsylvania State University and a master of science degree in nuclear engineering from Polytechnic University. He is a Licensed Professional Engineer in New York. Prior to this assignment as Vice President, Mr. McCaffrey served in many positions in the nuclear organizations of the Company and positions in engineering capacities associated with gas turbine and fossil power station projects. Mr. McCaffrey is a member of the executive board of the Suffolk County Council Boy Scouts of America.
Joseph W. McDonnell: Vice President of External Affairs since July 1992, Dr. McDonnell, 43, joined the Company in 1984. Dr. McDonnell was Assistant to the Chairman from 1984 through 1988 when he was named Vice President of Communications. Prior to joining the Company, Dr. McDonnell was the director of strategic planning and business administration for Applied Digital Data Systems, Inc. and associate director of the University Hospital at the State University of New York at Stony Brook. He holds bachelor of arts and master of arts degrees in philosophy and a master of arts degree in theology from the State University of New York at Stony Brook and a Ph.D in communications from the University of Southern California.
Anthony Nozzolillo: Mr. Nozzolillo was named Senior Vice President of Finance and Chief Financial Officer of the Company on February 4, 1994. His reporting responsibilities include the offices of Controller, Treasurer, Tax & Benefits Planning, Investor Relations and Financial Planning. Prior to this appointment he had been the Company's Treasurer since July 1992. He has been with the Company since 1972 serving in various positions including Manager of Financial Planning and Manager of Systems Planning. Mr. Nozzolillo is a director of Nuclear Mutual Ltd. and was a director of Utilities Mutual Insurance Company through December 1994. Mr. Nozzolillo, 46, holds a bachelor of science degree in electrical engineering from the Polytechnic Institute of Brooklyn and a master of business administration degree from Long Island University C.W. Post Campus.
Richard Reichler: Mr. Reichler was named Deputy General Counsel and Vice President of Tax and Benefit Compliance on December 14, 1994. He held the position of Assistant Vice President for Tax and Benefits Planning from October 1991 through December 1994. Prior to joining the Company, Mr. Reichler, 60, was a partner in the international accounting firm, Ernst & Young LLP for twenty-three years. He holds a bachelor of arts degree from Columbia College and a bachelor of law degree from Columbia University School of Law. Since 1989, he has taught various courses at Baruch College, including state and local taxation, corporate taxation and real estate taxation. He has authored several publications on tax and employee benefits topics and has served as a member of the Executive Committee of the Tax Section of the New York State Bar Association and as an advisor to the United Development Corporation High Technology Advisory Council.
William G. Schiffmacher: Mr. Schiffmacher was named Vice President of Customer Relations on April 1, 1994. He held the position of Vice President of Electric Operations from July 1990 through March 1994. Mr. Schiffmacher, 51, joined the Company in 1965 after receiving a bachelor of electrical engineering degree from Manhattan College. Mr. Schiffmacher also holds a master of science degree in management engineering from Long Island University. He has held a variety of positions in the Company, including Manager of Electric System Operation, Manager of Electrical Engineering and Vice President of Engineering and Construction.
Robert B. Steger: Mr. Steger was named Vice President of Electric Operations on April 1, 1994. He held the position of Vice President of Fossil Production from February 1990 through March 1994. Mr. Steger, 58, joined the Company in 1963 and has since held progressive operating and engineering positions including Manager of Electric Production-Fossil from 1985 through 1989. He holds a bachelor of mechanical engineering degree from Pratt Institute and is a Licensed Professional Engineer in the State of New York.
William E. Steiger, Jr.: Mr. Steiger was named Vice President of Fossil Production on April 1, 1994. He held the position of Vice President of Engineering and Construction from July 1990 through March 1994. Mr. Steiger, 51, has been with the Company since 1968. During his career with the Company, Mr. Steiger has served, among other positions, as Lead Nuclear Engineer for Shoreham, Chief Operations Engineer for Shoreham, Plant Manager for Shoreham as well as Assistant Vice President of Nuclear Operations. He received a bachelor of science degree in marine engineering from the United States Merchant Marine Academy and a master of science degree in nuclear engineering from Long Island University.
Edward J. Youngling: Mr. Youngling was named Senior Vice President of the Electric Business Unit on April 1, 1994. He held the position of Vice President of Customer Relations and Conservation from March 1993 through March 1994. He joined the Company in 1968 as an Assistant Engineer in the Electric Production Department and has held various positions in the offices of fossil production, engineering and nuclear operations including service as Department Manager of Nuclear Engineering. In 1988, Mr. Youngling was named Vice President of Conservation and Load Management. In 1990, Mr. Youngling became Vice President of Customer Relations. The Office of Customer Relations and the Office of Conservation were merged in March 1994. Mr. Youngling, 50, holds a bachelor of science degree in mechanical engineering from Lehigh University.
CAPITAL REQUIREMENTS, LIQUIDITY AND CAPITAL PROVIDED:
Information as to Capital Requirements, Liquidity and Capital Provided appears in Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations for the Year Ended December 31, 1994."
ITEM 2.



ITEM 2. PROPERTIES
The location and general character of the principal properties of the Company are described in Item 1, "Business" under the headings "Electric Operations" and "Gas Operations."
ITEM 3.

ITEM 3. LEGAL PROCEEDINGS
Shoreham
Pursuant to the Long Island Power Authority Act ("LIPA Act"), LIPA is required to make PILOTS to the municipalities that impose real property taxes on Shoreham. Pursuant to the 1989 Settlement, the Company agreed to fund LIPA's PILOTS obligation. The timing and duration of PILOTS under the LIPA Act are the subject of litigation entitled LIPA, et al. v. Shoreham-Wading River Central School District, et al, brought in Nassau County Supreme Court by LIPA against, among others, Suffolk County, the Town of Brookhaven and the Shoreham-Wading River Central School District. The Company was permitted to intervene in the lawsuit. On January 10, 1994, the Appellate Division, Second Department, affirmed a lower court's March 29, 1993 decision holding, in major part, that the Company is not obligated for any real property taxes that accrued after February 28, 1992, attributable to property that it conveyed to LIPA, that PILOTS commenced on March 1, 1992, that PILOTS are subject to refunds and that the LIPA Act does not provide for the termination of PILOTS. Generally, these holdings are favorable to the Company. On July 7, 1994, the Court of Appeals denied a motion by all parties in which they sought leave to appeal the Appellate Division decision on the basis that such decision is not a final determination of this matter and therefore is not reviewable by the Court of Appeals. The proper amount of PILOTS is to be determined in pending litigation described in the next paragraph.
The costs of Shoreham included real property taxes imposed by the Town of Brookhaven on Shoreham and capitalized by the Company during construction. The Company has sought judicial review in Suffolk County Supreme Court (Long Island Lighting Company v. The Assessor of the Town of Brookhaven, et al.) of the assessments upon which those taxes were based for the years 1976 through 1992 (excluding 1979). The court has
consolidated the review of the tax years at issue into two phases: 1976 through 1983, excluding 1979 (Phase 1); and 1984 through 1992 (Phase 2). On October 26, 1992, the court ruled that Shoreham had been overvalued for property tax purposes for Phase 1. Although the court did not award a refund because of a need to make further factual findings, the Company estimates that it is entitled to a refund of approximately $34 million plus interest. Regarding Phase 1, the Appellate Division, Second Department, affirmed the Supreme Court's ruling and denied leave to appeal to the Court of Appeals. The respondents have sought leave before the Court of Appeals to appeal to that court. The Company has opposed this motion but has sought the Court of Appeal's permission to appeal in the event that respondents' motion is granted. In the Phase 2 proceeding, which is currently in progress, the Company is seeking to recover over $500 million, excluding interest, in property taxes paid on Shoreham during this period. The amount of the Company's recovery, if any, in the Phase 2 proceeding and the timing of all refunds cannot yet be determined. The Company has indicated to the PSC that all refunds, less litigation costs, will be used to reduce future electric costs. LIPA has been permitted to intervene for limited purposes in this pending litigation.
Environmental
On February 18, 1994, a lawsuit was filed in the United States District Court for the Eastern District of New York by the Town of Oyster Bay (the "Town"), against the Company and 19 other PRPs. The Town is seeking indemnification for remediation and investigation costs that have been or will be incurred for a federal Superfund site in Syosset, New York, which served as a Town-owned and operated landfill between 1954 and 1975. In a Record of Decision issued in September 1990, the EPA set forth a remedial design plan, the cost of which was estimated at $27 million and is reflected in the Town's lawsuit. In an Administrative Consent Decree entered into between the EPA and the Town in December 1990, the Town agreed to undertake remediation at the site. The Company has agreed to participate in a joint PRP defense effort with several other defendants. Liability, if imposed, would be joint and several. While the outcome of this matter is not certain, based upon the Company's past experience in similar matters and the number and financial condition of the corporate defendants named in the litigation, the Company does not believe that this proceeding will have a material adverse effect on its financial condition.
Human Resources
Pending before federal and state courts, the Federal Equal Employment Opportunity Commission and the New York State Division of Human Rights are charges by individuals alleging that the Company discriminated against them on various grounds.
The Civil Rights Bureau of the New York Attorney General's office has subpoenaed the Company for the production of documents to aid in its investigation as to whether the Company has engaged in discriminatory employment practices based upon age. No charges have been filed by the Attorney General.
The Company has estimated that any costs to the Company resulting from these matters will not have a material adverse effect on its financial condition.
Other Matters
On January 13, 1993, the New York State Department of Law ("DOL") informed the Company that the DOL's Antitrust Bureau opened an investigation into its Full Service Pilot Program and Contractor Advisory Council, two programs designed to increase the Company's residential natural gas sales. The DOL stated that the implementation of the Full Service Pilot Program and the practices of the Contractor Advisory Council may have anticompetitive effects in the gas-fired heating equipment installation and conversion business and that a preliminary investigation has raised questions of possible violations of the New York General Business Law and the Sherman Act. The DOL has not taken any further action in this matter. If required, the Company expects that it can demonstrate that the programs identified by the DOL for investigation are very limited in scope and do not involve
any violations. The outcome of the investigation by the DOL, if adverse, is not expected to have a material effect on the financial condition of the Company.
ITEM 4.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
PART II
ITEM 5.

ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
At March 1, 1995, the Company had 118,704,301 registered holders of record of Common Stock.
The Common Stock of the 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 York Stock Exchange.
Information respecting the high and low sales prices and the dividends declared on the Company's Common Stock during the past two years is set forth in the table below.
Item 6:

Item 6: Selected Financial Data
*Includes current maturities of long-term debt and current redemption requirements of preferred stock.
*Includes non-cash allowance for other funds used during construction and excludes Shoreham post settlement costs.
ITEM 7:

ITEM 7: MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
This discussion and analysis addresses matters of significance with regard to the Company and its financial condition, liquidity, capital requirements and results of operations for the last three years.
OVERVIEW
In 1994, the Company reached a milestone by generating sufficient cash from operations to meet all of its operating and construction requirements in addition to satisfying a portion of its maturing debt obligations with cash on hand. The positive cash flow resulted, in part, from the collection of deferred revenues associated with the Rate Moderation Component (RMC) and the Long Island Lighting Company Ratemaking and Performance Plan, and the Company's continued efforts to maximize operating efficiencies while reducing operating costs.
Since 1989, the Company has received six electric rate increases and has experienced lower than anticipated fuel costs, financing costs and production expenses, all of which have helped to improve cash flow, which in turn, has improved the Company's financial health. This improved financial health has enabled the Company to file with the Public Service Commission of the State of New York (PSC) on December 31, 1993, a three year electric rate plan (Electric Rate Plan) requesting that base electric rates be frozen through November 30, 1996, and that overall electric rates increase 4.3% beginning December 1, 1996. The Electric Rate Plan, as designed, will help to better position the Company to meet existing and anticipated competitive challenges in addition to assisting the economic recovery of Long Island.
Three Administrative Law Judges (ALJs) issued a recommended decision to the PSC with respect to the Company's Electric Rate Plan. The ALJs agreed with the Company's proposal to freeze base electric rates for the first year, and implied that base rates could remain frozen for the second year as well. The ALJs encouraged the Company and other intervening parties in the proceeding to negotiate a settlement regarding the third year of the Company's Electric Rate Plan. The Company, the PSC and other parties to this proceeding continue to negotiate toward a three year rate settlement. The Company believes that a three year rate settlement is in the best interest of shareowners and ratepayers.
Other significant achievements during 1994 included:
- The Company maintained the same level of earnings per common share in 1994 as in 1993, despite a lower allowed return on common equity for the gas business and the issuance of 6.1
million shares of common stock during 1994;
- The public offering of 5.1 million shares of the Company's common stock, for the first time in nearly ten years, raised approximately $100 million. This offering, combined with the satisfaction of a portion of maturing debt with cash on hand, has resulted in a reduction of the Company's debt ratio to 62.5% at December 31, 1994 from 65.0% at December 31, 1993;
- The continuation of the Company's quarterly common stock dividend rate at 44 1/2 cents per share;
- The reduction of the Company's average coupon rate on its outstanding long-term debt to 7.9% as a result of the Company's refinancing activities. The refinancing of a significant amount of the Company's long-term debt and preferred stock, over the past several years, has resulted in annual cash savings of approximately $100 million;
- The reduction of the RMC balance from $610 million at December 31, 1993 to $463 million at December 31, 1994. This reduction resulted, in part, from current year revenues under the Rate Moderation Agreement exceeding revenues that were required in 1994 under conventional ratemaking;
- The completion, pending final regulatory approval, of the decommissioning of the Shoreham Nuclear Power Station, including the removal and transportation of Shoreham's fuel to another utility;
- The receipt of a gas rate increase effective December 1, 1994, which is the second of three gas rate increases under a three-year settlement between the Company and the PSC which provides for annual rate increases of 4.7%, 3.8% and 2.8% for the rate years beginning December 1, 1993, 1994 and 1995, respectively;
- The addition of over 8,500 new gas space heating customers, resulting from the continuation of the Company's gas expansion program;
- The establishment of a record maximum day gas sendout of 585,227 dekatherms on January 19, 1994.
In addition, in 1994, the Company received an invitation at the request of the former Governor of New York State (State), from the chief executives of the New York Power Authority and the Long Island Power Authority, for the Company to enter into negotiations with them in a proposal to convert the Company into a public power utility. The new Governor of the State empaneled
a task force to study the "takeover" proposal. While the task force did not make its recommendation public, published reports in local newspapers indicate that the task force recommended to reject the proposal.
LIQUIDITY
At December 31, 1994, the Company's cash and cash equivalents amounted to approximately $185 million, compared to $249 million at December 31, 1993. The decrease in cash and cash equivalents reflects the Company's strategy of applying available cash balances toward the satisfaction of maturing debt.
The Company has available for its use a $300 million revolving line of credit through October 1, 1995, provided by its 1989 Revolving Credit Agreement (1989 RCA). At December 31, 1994, no amounts were outstanding under the 1989 RCA. This line of credit is secured by a first lien upon the Company's accounts receivable and fuel oil inventories. The 1989 RCA may be extended for one year periods upon the acceptance by the lending banks of a request by the Company. The Company's request must be delivered to the lending banks prior to April 1 of each year. In 1995, the Company intends to request such an extension. For a further discussion of the 1989 RCA, see Note 7 of Notes to Financial Statements.
CAPITALIZATION
The Company's capitalization, including current maturities of long-term debt and current redemption requirements of preferred stock, at December 31, 1994, was approximately $8.3 billion, compared to $8.4 billion at December 31, 1993. At December 31, 1994 and 1993, the Company's capitalization ratios were as follows:
The Company is committed to reducing its debt ratio. To achieve this goal, the Company intends to continue reducing debt with cash generated from operations and intends to issue common or preferred stock if market conditions prove favorable. With this commitment in mind, the Company issued 5.1 million shares of common stock in 1994, marking the first time in approximately ten years that the Company issued common equity, other than through its Automatic Dividend Reinvestment Plan, its Employee Stock Purchase Plan or through the conversion of Series I Preferred Stock.
In 1994, the Company applied the net proceeds from the sale of the 5.1 million shares of common stock and the issuance of $285 million of General and Refunding Bonds (G&R Bonds) toward the repayment, at maturity, of $400 million of debentures and the redemption of $30 million and $5 million of debentures that had
been scheduled to mature in 1999 and 2019, respectively. Cash from operations provided the balance of funds needed to retire/redeem this debt and to retire $25 million of First Mortgage Bonds, which matured in June 1994. In addition, in November 1994 the Company used cash on hand to satisfy the payment of $175 million of maturing debentures.
The Company's need to access the financial markets to provide additional capital or to refinance its maturing debt has diminished compared to prior years. The Company intends to use cash generated from operations to satisfy the payment of $25 million of First Mortgage Bonds maturing on June 1, 1995. With respect to the repayment of $455 million and $286 million of debt maturing in 1996 and 1997, respectively, the Company intends to use cash generated from operations to the maximum extent practicable. The balance of funds necessary to satisfy maturing debt obligations in 1996 and 1997 will be obtained through the issuance of either debt or equity securities, or some combination thereof.
Despite improving financial indicia, the Company's securities, which are rated by Standard and Poor's Corporation (S&P), Moody's Investors Service (Moody's), Fitch Investors Service, L.P. (Fitch) and Duff and Phelps, Inc. (D&P), have been downgraded by certain rating agencies over the past eighteen months. In June 1994, Moody's lowered the credit ratings of the Company reflecting Moody's expectations that the Company's high tariff rates will intensify business risk in an increasingly competitive environment. Recently, S&P placed its ratings on the Company's securities on "Credit Watch with negative implications," Fitch changed its credit trends to "declining" and Moody's placed the Company's credit ratings under review for a possible downgrade reflecting their respective concerns about the regulatory environment in New York State.
At December 31, 1994, the ratings for each of the Company's principal securities were as follows:
Bold face indicates securities that meet or exceed minimum investment grade.
The Company's Authority Financing Notes (Notes), some of which are secured by letters of credit, are rated by certain of the rating agencies. The ratings on the Notes secured by letters of credit reflect the ratings of the institutions issuing the letters of credit, and not that of the Company.
CAPITAL REQUIREMENTS AND CAPITAL PROVIDED
Capital requirements and capital provided for 1994 and 1993 were as follows:
For further information, see the Statement of Cash Flows.
Given the Company's current electric load forecast and the availability of electricity provided by the Company's generating facilities and by purchases of power from others, the Company forecasts that it will not need any new generating facilities until beyond the year 2000. As a result, the Company does not forecast any need for external financing for the construction of generating facilities during this period. With respect to financing other capital additions to plant, the Company estimates that cash generated from operations will be sufficient to meet any such requirements in 1995.
For 1995, total capital requirements (excluding common stock dividends) are estimated at $431 million, of which maturing debt is $25 million, additions to plant are $277 million, preferred stock dividends are $53 million, preferred stock sinking funds are $5 million and Shoreham post settlement costs are $71 million, including $58 million for payments in lieu of taxes.
RATE MATTERS
Electric
In conjunction with the 1989 Settlement, the PSC agreed to the recognition of a regulatory asset known as the Financial Resource Asset (FRA). The FRA consists of two components, the Base Financial Component (BFC) and the RMC, discussed in Note 1 of Notes to Financial Statements. The Rate Moderation Agreement (RMA), one of the constituent documents of the 1989 Settlement, provides for the full recovery of the FRA.
The BFC was granted rate base treatment under the terms of the RMA and 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. The RMC had provided the Company with a substantial amount of non-cash earnings since the effective date of the 1989 Settlement through December 31, 1992, as the revenues provided under the RMA were less than the revenues required under conventional ratemaking. During 1993, however, as revenues provided under the RMA began to exceed the revenues that would have been provided under conventional ratemaking, the RMC balance began to decline.
Pursuant to the 1989 Settlement, the Company has received six electric rate increases as contemplated by the RMA. In November 1991, the PSC approved the Long Island Lighting Company Ratemaking and Performance Plan (LRPP) which provided annual electric rate increases of 4.15%, 4.1% and 4.0% effective December 1, 1991, 1992 and 1993, respectively. The LRPP provided for an allowed return on common equity from electric operations of 11.6% for each of the three rate years.
The LRPP was designed to be consistent with the RMA's long-term goals. One principal objective of the LRPP is to reassign risk so that the Company assumes the responsibility for risks within the control of management, whereas risks largely beyond the control of management would be assumed by the ratepayers.
One of the major components of the LRPP provides for a revenue reconciliation mechanism that eliminates the impact on earnings of experiencing electric sales that are above or below the LRPP forecast by providing a fixed annual net margin level (defined as sales revenues, net of fuel and gross receipts taxes) that the Company receives under the LRPP.
The LRPP allows the Company to earn for each rate year up to 60 additional basis points, or forfeit up to 38 basis points, of the allowed return on common equity as a result of the Company's performance within certain incentive and/or penalty programs. These programs consist of a customer service performance plan, a demand side management (DSM) program, a time-of-use program, a partial pass through fuel cost incentive plan, and effective December 1, 1993, an electric transmission and distribution reliability plan. Based upon the Company's performance within these programs, the Company earned a total of 50 and 49 basis points, or approximately $9.2 million, net of tax effects, for each of the rate years ended November 30, 1994, and 1993. For the rate year ended November 30, 1992, the Company earned approximately $4.3 million, net of tax effects, for its performance in these programs.
The LRPP contains a mechanism whereby earnings in excess of the allowed return on common equity of 11.6%, excluding the impacts of the various incentive and/or penalty programs, are shared equally between ratepayers and shareowners. The Company earned $8.9 million and $21.4 million, net of tax effects, for the rate years ended November 30, 1993 and 1992, respectively, in excess of its allowed return on common equity which was shared equally between ratepayers (by a reduction to the RMC) and shareowners. For the rate year ended November 30, 1994, the Company did not earn in excess of its allowed return on common equity.
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 of the restoration of the Company's financial health. The Electric Rate Plan requests an allowed return on common equity of 11.0%, and provides for base rates to be frozen in years one and two and an overall rate increase of 4.3% in the third year. Although base electric rates would be frozen during the first two years of the Electric Rate Plan, annual rate increases of approximately 1% are expected to result from the operation of the Company's fuel cost adjustment (FCA) clause. The FCA captures, among other things, amounts to be recovered from or refunded to ratepayers in excess of $15 million, which result from the reconciliation of revenues, certain expenses and earned performance incentive components, under the LRPP, discussed in Note 3 of Notes to Financial Statements.
The Company's Electric Rate Plan reflects four underlying objectives: (i) to limit the balance of the RMC during the three year period to no more than its 1992 peak balance of $652 million; (ii) to recover the RMC within the time frame established in the 1989 Settlement; (iii) to minimize, beginning in the third year of the Electric Rate Plan, the final three rate increases contemplated in the 1989 Settlement that follow the two
year rate freeze period; and (iv) to continue the Company's gradual return to financial health.
The Electric Rate Plan provides for, with some modifications, the continuation of the LRPP revenue and expense reconciliations and performance incentives. The Electric Rate Plan includes the annual reconciliation of certain expenses for property taxes, interest costs, DSM costs and the deferral and amortization of certain costs for enhanced reliability. The Company would be allowed to earn for each of the three rate years under the Electric Rate Plan up to 50 additional basis points, excluding incentives under the DSM program, or forfeit up to 47 basis points of the allowed return on common equity of 11.0% as a result of the Company's performance within certain performance programs. These programs consist of a customer service program, a partial pass through fuel cost incentive plan, a DSM program and an electric transmission and distribution reliability plan.
The Company's Electric Rate Plan provides for lower annual electric rate increases than originally anticipated under the 1989 Settlement. However, as a result of changes in certain assumptions upon which the RMA was 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 of the RMA can be met under the Electric Rate Plan. As a result of lower than originally anticipated inflation, 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 billion in 1994, peaked at $652 million in 1992. With the exception of a projected increase in 1995 and 1996, which is not now anticipated to cause the RMC to increase above its $652 million peak, the RMC is expected to decline until it is fully amortized.
Under the Electric Rate Plan, the recovery of the RMC would be extended, if necessary, for an additional period of not more than three years beyond the approximate ten year period envisioned in the RMA. The actual length of the RMC extension will depend upon the extent to which the assumptions underlying the Electric Rate Plan materialize. The Company's current projections indicate that the RMC will be recovered in eleven years.
The Staff of the PSC (Staff) and other intervening parties filed testimony in response to the Company's Electric Rate Plan. Staff concurs with the Company's proposal for an 11.0% return on common equity in each of the three years, and has reaffirmed its commitment to the principals of the RMA, including the full recovery of the RMC within the time frame established by the RMA. However, Staff has recommended an overall zero percent rate increase for the first two years, contrasted with the Company's proposal for a base rate freeze with FCA adjustments of approximately 1% in years one and two, as described above. Staff
did not make a recommendation for the level of rate relief in the third year.
In September 1994, three ALJs of the PSC issued a recommended decision to the PSC with respect to the Company's Electric Rate Plan. The ALJs agreed with the Company's proposed 11.0% return on common equity and its proposal to freeze base electric rates for the first rate year. While no explicit recommendation was made concerning the second year, the recommended decision implied that base rates could remain frozen for the second rate year as well.
With respect to the third rate year beginning December 1, 1996, the ALJs determined that it was not appropriate for them to issue a recommendation since, in their opinion, the Company's revenue requirements for the third rate year could not be precisely determined at this time. Alternatively, the ALJs encouraged the Company and other parties in the proceeding to negotiate a settlement concerning any rate increase for the third rate year.
The PSC had been expected to issue a final order on the Company's Electric Rate Plan before November 29, 1994, the date that the statutory suspension period was scheduled to terminate. However, in order to accommodate further settlement negotiations in the proceeding, the Company has requested extensions through April 1995, which were granted by the PSC. The Company's offers to extend the suspension period were conditioned upon the continuation of the current LRPP rate mechanisms. Although the ultimate outcome of the Electric Rate Plan cannot be predicted, the Company expects that any PSC order will be consistent with the provisions of the RMA respecting the recovery of the FRA and other 1989 Settlement deferred charges.
Gas
In December 1993, the PSC approved a three year gas rate settlement, between the Company and the Staff of the PSC. The gas rate settlement provides that the Company receive, for each of the rate years beginning December 1, 1993, 1994 and 1995, annual gas rate increases of 4.7%, 3.8% and 2.8%, respectively. In the determination of the revenue requirements for the gas rate settlement, an allowed return on common equity of 10.1% was used. The gas rate decision provides that earnings in excess of a 10.6% return on common equity in any of the three rate years covered by the settlement be shared equally between the Company's firm gas customers and its shareowners. For the rate year ended November 30, 1994, the Company earned $9.2 million, net of tax effects, in excess of the 10.6% return on common equity. The firm gas customers' portion of these excess earnings amounting to $4.6 million, net of tax effects, has been deferred until its final disposition is determined by the PSC.
ENVIRONMENT
During 1994, the Company spent approximately $6.4 million in order to comply with the 1990 amendments to the Federal Clean Air Act (Act). These expenditures were necessary to meet continuous emissions monitoring requirements and Phase I nitrogen oxide (Nox) reduction requirements under the Act.
The Company expects that it will have to expend approximately $1 million in 1995 to meet continuous emission monitoring requirements and to meet Phase I Nox reduction requirements. In order to generate 210 tons of NOx reduction credits already under contract for sale to a third party, the Company anticipates spending $2.5 million in 1995 and $1.9 million in 1996 for earlier than required Nox reduction systems. Subject to requirements that are expected to be promulgated in forthcoming regulations, the Company estimates that it may be required to spend an additional $80 million (net of Nox credit sales) by 2003 to meet Phase II and Phase III NOx reduction requirements. In an effort to minimize costs associated with anticipated NOx reduction requirements, the Company is engaged in a $7 million research and development project along with several co-funding organizations to demonstrate an innovative NOx reduction technology at its E.F. Barrett Power Station. The Company is committed to fund $3.6 million of the project costs. Through 1994, approximately $5 million has been expended by all of the co-funders. It is anticipated that the remaining $2 million will be spent in 1995. In addition, the Company estimates that it may be required to spend approximately $24 million by 1999 to meet potential requirements for the control of hazardous air pollutants from power plants. The Company believes that all of the above mentioned costs will be recoverable through rates.
The New York State Department of Environmental Conservation has indicated to New York State utilities that it may require all such utilities to investigate and, where necessary, remediate their former manufactured gas plant (MGP) sites. The Company is the owner of six pieces of property on which the Company or certain of its predecessor companies produced manufactured gas. Although the exact amount of the Company's clean-up costs cannot yet be determined, based on the findings of investigations at two of these six sites, preliminary estimates indicate that it will cost approximately $35 million to clean-up all of these sites over the next five to ten years. Accordingly, the Company has recorded a $35 million liability and a corresponding regulatory asset to reflect its belief that the PSC will provide for the future recovery of these costs through rates as it has for other New York State utilities. The Company has notified its former and current insurance carriers that it seeks to recover from them certain of these clean-up costs. However, the Company is unable to predict the amount of insurance recovery, if any, that it may obtain.
The Company has been notified by the Environmental Protection Agency (EPA) that it is one of many potentially responsible parties (PRPs) that may be liable for the remediation of three contaminated licensed treatment, storage and disposal sites. At one site, located in Philadelphia, Pennsylvania, and operated by Metal Bank of America, the Company and nine other PRPs, all of which are public utilities, have completed a Remedial Investigation and Feasibility Study which is currently being reviewed by the EPA. The level of remediation required will be determined when the EPA issues its decision, currently expected in May 1995. The Company currently anticipates that the total cost to remediate this site will be between $14 million and $30 million. The Company has recorded a liability of $1.1 million representing its estimated share of the cost to remediate this site. The Company believes that any cost incurred to remediate this site will be recoverable through rates.
With respect to the other two sites, which are located in Kansas City, Kansas and Kansas City, Missouri, the Company is investigating allegations that it had previously stored or made agreements for the disposal of polychlorinated biphenyls (PCBs) or items containing PCBs at these sites. The Company is currently unable to determine its share of the cost to remediate these sites or the impact, if any, on the Company's financial position. The Company believes that any cost incurred to remediate these sites will be recoverable through rates.
NYPA AND LIPA PROPOSAL
At the request of the then Governor of the State of New York, on October 13, 1994 the chief executives of the New York Power Authority (NYPA) and the Long Island Power Authority (LIPA) invited the Company to enter into negotiations with them regarding a proposal to convert the Company into a public power utility. Under the proposal, the two state authorities contemplated a business combination in which holders of the Company's common stock would receive $21.50 in cash for each outstanding share of the Company's common stock. NYPA and LIPA indicated that the completion of this transaction would be subject to, among other things, the availability of tax-exempt financing sufficient to complete the transaction and the verification by NYPA and LIPA that the transaction would result in rate reductions in excess of 10%. The Company's Board of Directors has authorized the Company to enter into discussions with NYPA and LIPA to explore the proposal in greater detail, but no such discussions have been held.
The new Governor of the State of New York had empaneled a task force to study the takeover proposal. While the task force did not make its recommendation public, published reports in local newspapers indicate that the task force recommended to reject the proposal.
COMPETITIVE ENVIRONMENT
Significant changes are taking place in the business and regulatory environment in which electric utilities operate. In response, the Company, like utilities across the nation, is actively involved with federal and State agencies in evaluating what type of competition would best serve both customers and investors. The Company has also undertaken a review of its current operations, seeking to shape those operations to best meet the challenges of a competitive environment. As federal legislators and regulators continue pursuing a policy of evaluating competition in the electric utility industry, state regulators are addressing the many complex and politically sensitive issues which will affect the cost and reliability of service to customers in their jurisdictions. The focus on electric competition has also prompted municipalities, school districts and certain other customers to seek permission to buy energy elsewhere.
The Electric Industry - Federal Regulatory Issues
As a result of Congress' passage of the Public Utility Regulatory Policies Act of 1978 (PURPA) and the National Energy Policy Act of 1992 (NEPA), the once monopolistic electric utility industry now faces competition.
PURPA's goal was to reduce the United States' dependence on foreign oil, encourage energy conservation and promote diversification of fuel supply. Accordingly, PURPA provided for the development of a new class of electric generators which rely on either cogeneration technology or alternate fuels. The utilities are obligated under PURPA to purchase the electric output of certain of these new generators, which are known as qualified facilities (QFs).
NEPA sought to increase economic efficiency in the creation and distribution of power by relaxing restrictions on the entry of new competitors to the wholesale electric power market (i.e., sales to an entity for resale to the ultimate consumer). NEPA does so by creating exempt wholesale generators that can sell power in wholesale markets without the regulatory constraints placed on generators such as the Company. NEPA also expanded the Federal Energy Regulatory Commission (FERC)'s authority to grant access to utility transmission systems to all parties who seek wholesale wheeling for wholesale competition. Significant issues associated with the removal of wholesale transmission system access restrictions have yet to be resolved and the potential impact on the Company's financial position cannot yet be determined.
FERC is in the process of setting policy which will largely
determine how wholesale competition will be implemented. FERC has recently declared that utilities must provide wholesale wheeling to others that is comparable to the service utilities provide themselves. The policy will be tested and further defined in individual proceedings. In addition, FERC has issued policy statements concerning regional transmission groups, transmission information requirements and "good faith" requests for service and transmission pricing. FERC is also initiating proceedings to address issues relating to stranded assets and power pooling. Utilities, including the Company, and other interested parties are actively involved in these proceedings.
Major issues are arising as the industry and government contemplate the move toward a more market-driven environment. These issues include: the impact of competition on customers who are unable to or who have chosen not to avail themselves of competition options; the ability of utility investors to continue to receive a return of and a reasonable return on their investments; the effect on service quality and reliability; comparability of service; the parameters of regulatory jurisdiction; the relative efficiency of competitors; the effects of mergers and the recoverability of transition costs and of assets that may become impaired.
The Electric Industry - New York State Regulatory Issues
The PSC has instituted a number of cases which will determine the boundaries within which power providers can compete in New York.
In 1994, the PSC completed the first phase of a competitive opportunities proceeding, issuing guidelines that allow New York utilities, at their option, to negotiate discounted rates with customers who otherwise would purchase electricity elsewhere. Any net revenue lost through these negotiations will be shared between ratepayers and shareowners, with percentages to be determined in rate cases. With respect to the Company, the Commission has ruled that the Company's shareowners must bear 30% of any "discount" negotiated by the Company in order to retain customers. While this percentage is comparable to that required of other utilities, the Company believes the percentage should be significantly lower due to the Company's unique financial structure and, therefore, has appealed the PSC's decision.
The PSC has recently begun a second phase of this proceeding in which it will develop principles to guide the transition to a more competitive environment, explore how to improve the wholesale electric market and determine the role regulation will play. The issues to be reviewed include: wholesale competition with or without a spin-off of generation assets; retail competition; planning and reliability; customer impacts; financial and legal considerations; and affordability of electric
service to all customers. The PSC will also address the critical issue of whether utilities will be required to write- off assets in order to offer more competitive prices.
In addition, the State Energy Planning Board has released the 1994 State Energy Plan (SEP) which calls for the development of a fully competitive wholesale generation market within five years. While continuing to caution that full retail competition may not be in the best interests of the State, the SEP threatens that retail competition should be considered sooner "in the absence of utility cooperation" in the development of a fully competitive wholesale market.
The Company's Service Territory
The changing utility regulatory environment has affected the Company in a number of ways. For example, PURPA's encouragement of the non-utility generator (NUG) industry has negatively impacted the Company. The Company estimates that in 1994, sales lost to NUGs totaled 237 gigawatt-hours (Gwh) representing a loss in revenues net of fuel (net revenues) of approximately $24 million, or approximately 1.1% of the Company's 1994 net revenues. Additionally, as mentioned above, the Company is required to purchase all the power offered by QFs. As of December 31, 1994, QFs were selling approximately 203 megawatts (MW) of power to the Company. The Company estimates that, in 1994, purchases from QFs required by federal and State law cost the Company $53 million more than it would have cost had the Company generated this power. The Company has also contracted, beginning in early 1995, to purchase all excess power from the 40 MW Stony Brook project located at the State University of New York at Stony Brook, New York.
QFs have the choice of pricing sales to the Company at either (i) the PSC's published estimates of the Company's long run avoided costs (LRAC) or (ii) the Company's tariff rates, which are modified from time to time, reflecting the Company's actual avoided costs. Additionally, until repealed in 1992, New York State law set a minimum price of six cents per kilowatt-hour (kWh) for utility purchases of power from certain categories of QFs, 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 of the six cent law, coupled with recent PSC updates which resulted in lower LRAC estimates, has significantly reduced the economic benefits to QFs seeking to sell power to the Company.
After the anticipated loss of the Stony Brook load, estimated to be approximately 190 Gwhs annually, or a net revenue loss of
approximately $13 million, the Company expects that electric load losses due to NUGs will stabilize. The Company believes that a number of factors, including customer load characteristics such as a lack of a significant industrial base and related large thermal load, will mitigate load loss and thereby make cogeneration economically unattractive.
The Company has also experienced a revenue loss as a result of its policy of voluntarily providing wheeling of NYPA power for economic development. The Company estimates that NYPA power has displaced approximately 400 Gwh of annual energy sales. The net revenue loss associated with this amount of sales is approximately $28 million or 1.4% of the Company's 1994 net revenues. Currently, the potential loss of additional load is limited by conditions in the Company's transmission agreements with NYPA.
Aside from NUGs, a number of customer groups are seeking to hasten consideration and implementation of full retail competition. For example, an energy consultant has petitioned the PSC, seeking alternate sources of power for Long Island school districts. The County of Nassau has also petitioned the PSC to authorize retail wheeling for all classes of electric customers in the county. In addition, several towns on Long Island are investigating municipalization. Municipalization, in which customers form a government-sponsored electric supply company, is one form of competition likely to increase as a result of NEPA. The Town of Southampton and several other towns in the Company's service territory are considering the formation of a municipally owned and operated electric authority to replace the services currently provided by the Company. Suffolk County has also approached FERC to determine whether it can qualify as a municipal power authority in order to purchase cheaper electricity from non-Company sources. The Company's geographic location and the limited electrical interconnections to Long Island serve to limit the accessibility of its transmission grid to potential competitors from off the system.
The matters discussed above involve substantial social, economic, legal, environmental and financial issues. The Company is opposed to any proposal that merely shifts costs from one group of ratepayers to another, that fails to enhance the provision of least-cost, efficiently-generated electricity or that fails to provide the Company's shareowners with an adequate return on and recovery of their investment. The Company is unable to predict what action, if any, the PSC or FERC may take regarding any of these matters, or the impact on the Company's financial condition if some or all of these matters are approved or implemented by the appropriate regulatory authority.
CONSERVATION SERVICES
In 1993, the Company filed a modified DSM plan with the PSC to support the objectives of the Company's Electric Rate Plan filed in December 1993. Under this modified plan, the Company proposed a substantially lower level of spending than that initially approved for 1994. The PSC did not approve the Company's proposed plan, but instead issued a ruling in July 1994, which dictated energy savings targets that were greater than those originally proposed by the Company. Specifically, the targets for the Company's DSM programs amounted to a 161.3 MW reduction in coincident peak demand and an annualized energy savings of 702.6 Gwh by December 31, 1994. The Company was successful in its DSM efforts.
In 1995, the Company intends to continue to carefully manage DSM expenditures and more fully transform DSM to a strategic marketing tool which can be used to position the Company for the future. In these efforts, the Company will act to further increase the emphasis on education and information programs and further decrease its emphasis on utility rebate payments. In addition, financing programs and other cost sharing arrangements will be stressed as a means to reduce DSM program costs. Finally, DSM programs will be redesigned to enhance the Company's competitive position through the offering of programs and services to the Company's customers which promote the efficient use of electricity, including energy-efficient load growth.
RESULTS OF OPERATIONS
EARNINGS
Summary results of earnings for the years 1994, 1993 and 1992 were as follows:
The Company achieved the same level of earnings per common share in 1994 as in 1993 despite an increase in the average number of common shares outstanding. This was primarily the result of the Company's cost containment program and the impact on earnings of positive cash flow from operations, which allowed the Company to use cash balances to satisfy maturing debt.
The electric business achieved a higher level of earnings in 1994 as compared to 1993, offset by a decrease in the gas business earnings. The decrease in gas business earnings in 1994 was the result of several factors including: (i) a lower allowed return on common equity; (ii) a write-off in 1994, of previously deferred storm costs and (iii) a provision in the Company's gas rate structure which became effective December 1, 1993, which requires earnings in excess of a 10.6% return on common equity be shared equally between the Company's firm gas customers and its shareowners.
The earnings in the electric business were lower in 1993 when compared to 1992 due primarily to the expensing of previously deferred storm costs, lower interest rates associated with short-term investments and certain regulatory adjustments recorded in accordance with the Company's electric rate structure. The lower level of earnings in the electric business was offset by a significant increase in earnings in the gas business, resulting from the continuation of the Company's gas expansion program. REVENUES
Total revenues, including revenues from recovery of fuel costs, were $3.1 billion, $2.9 billion and $2.6 billion for the years 1994, 1993 and 1992, respectively.
Electric Revenues
Revenues from the Company's electric operations for the years 1994, 1993 and 1992 were $2.5 billion, $2.4 billion and $2.2 billion, respectively.
In November 1991, the PSC approved the LRPP, which provided the Company with annual electric rate increases of 4.15%, 4.1% and 4.0% for the rate years beginning December 1, 1991, 1992 and 1993, respectively. These rate increases provided $69 million of additional revenues in 1994 as compared to 1993, and $75 million of additional revenues in 1993 as compared to 1992.
The LRPP contains several regulatory mechanisms that impact the level of revenues, but have no impact on earnings. The Company's current electric rate structure provides for a revenue reconciliation, which eliminates the impact on earnings of experiencing sales that are above or below the levels reflected in rates. As a result of lower than adjudicated electric sales, the Company recorded non-cash income, which is included in "Other Regulatory Amortization," of $50.9 million, $43.5 million and $78.5 million in 1994, 1993 and 1992, respectively.
Under the LRPP, base fuel costs collected in rates in excess of actual fuel costs are applied as a reduction to the RMC. The Company applied $83.9 million, $37.5 million and $22.9 million of amounts collected in excess of actual fuel costs as a reduction to the RMC for the rate years ended November 30, 1994, 1993 and 1992, respectively.
Under the LRPP, deferred balances associated with the reconciliation of revenue, expenses and performance incentives in excess of $15 million per annum are returned to or recovered from the ratepayers through the FCA. During the period August 1993 through July 1994, the Company collected, through the FCA, approximately $2.7 million per month for an aggregate of $30.2 million related to the deferred balances for the rate year ended November 30, 1992. Since August 1994, the PSC has allowed the Company to continue the collection of a like amount through the FCA which will continue through the end of the suspension period. These additional revenues, amounting to approximately $13.4 million through December 1994, were recorded as a reduction to the RMC. The Company is awaiting PSC approval for the recovery of $48.1 million and $63.6 million for the 1993 and 1994 rate year deferrals. For a further discussion of the LRPP regulatory mechanisms, see Note 3 of Notes to Financial Statements. Total electric sales volumes in millions of kWh were 16,382 in 1994, 16,128 in 1993 and 15,667 in 1992. The increase in sales in 1994 and 1993 was primarily the result of warmer than normal weather experienced in the summer months. The increases in sales were partially offset by sales lost to non-utility generators and power displaced by NYPA, discussed above under the heading "Competitive Environment." In 1994 and 1993, the composition of system sales was 45% residential and 52% commercial/industrial. In 1992, the composition was 44% residential and 53% commercial/industrial.
Gas Revenues
Revenues from the Company's gas operations for the years 1994, 1993 and 1992 were $586 million, $529 million and $427 million, respectively.
In December 1993, the PSC approved a three year gas rate settlement between the Company and the Staff of the PSC. The gas rate settlement provides the Company with annual gas rate increases of 4.7%, 3.8% and 2.8% for the rate years beginning December 1, 1993, 1994 and 1995, respectively. The Company had also received an annual gas rate increase of 7.1% effective December 1, 1992. These rate increases provided $25 million in additional revenues for 1994 as compared to 1993, and $35 million in additional revenues for 1993 as compared to 1992.
Total gas firm sales volumes in thousands of dekatherms (Mdth) were 58,889 in 1994, 59,183 in 1993 and 56,292 in 1992. In 1994, firm sales volumes decreased when compared to 1993 primarily due to warmer weather experienced during the 1994 heating season as compared to 1993, partially offset by the addition of approximately 8,500 new gas space heating customers resulting from the continuation of the Company's gas expansion program. The number of monthly average space heating customers was 273,633, 266,665 and 259,500 for the years 1994, 1993 and 1992, respectively. The Company has a weather normalization clause which mitigates the impact on revenues of experiencing weather that is warmer or colder than the "normal" value used for projecting sales. In 1993, firm sales volumes increased as a result of colder weather experienced during the 1993 heating season as compared to 1992 combined with additional gas space heating customers resulting from the Company's gas expansion program.
The Company began selling gas off-system in 1993. Off-system gas sales revenues were $26 million and $8 million on volumes of 7,232 Mdth and 2,894 Mdth, for the years ended December 31, 1994 and 1993, respectively. Any profits realized from off-system sales are allocated 85% to ratepayers and 15% to shareowners.
Recoveries of gas fuel expenses increased revenues by $33 million and $26 million in 1994 and 1993, respectively. In 1994, the increase in the recoveries of gas fuel expenses was primarily due to increased billed sales volumes and higher average gas prices, when compared to 1993. In 1993, the increase was primarily due to higher average gas prices, when compared to 1992.
OPERATING EXPENSES
Fuel and Purchased Power
Summary of fuel and purchased power expenses for the years 1994, 1993 and 1992 were as follows:
Despite an increase in electric sales volumes during 1994 and rising fuel oil prices, fuel for electric operations decreased primarily as a result of the Company's efforts to reduce its dependency on oil as the primary fuel for electric generation. The Company, over the past several years, has refitted several generating facilities to enable them to burn either oil or natural gas, depending upon the relative cost of each commodity at any given time.
In addition to the increased use of natural gas, the Company has reduced oil consumption by using energy generated at Nine Mile Point Nuclear Power Station, Unit 2 (NMP2) and by purchasing power from other systems, cogenerators and independent power producers. The total barrels of oil consumed for electric operations was 7.5 million, 9.7 million and 10.7 million, for the years 1994, 1993 and 1992, respectively.
Cogenerators and independent power producers provided approximately 9% of the Company's system requirements in 1994, 1993 and 1992. The increase in purchased power expenses in 1994 is primarily attributable to purchases from the 136 MW facility in Holtsville, New York, owned by NYPA, constructed for the benefit of the Company. Summary of electric fuel and purchased power mix for the years 1994, 1993 and 1992 were as follows:
Gas fuel expenses for gas operations increased by $30 million and $67 million in 1994 and 1993, respectively. The increase in 1994 is primarily attributable to the additional fuel costs associated with the Company's off-system gas sales, while the increase for 1993 was primarily due to significantly higher gas prices and increased volumes, as a result of colder than normal weather during the heating season.
Operations and Maintenance Expenses
Operations and maintenance (O&M) expenses, excluding fuel and purchased power, were $541 million, $522 million and $498 million, for the years 1994, 1993 and 1992, respectively. The increase in O&M for 1994 was primarily due to the recognition of previously deferred storm costs associated with gas operations, an increase in costs associated with the Company's gas expansion program, the recognition of certain costs which exceeded the Company's insurance recoveries, an increase in employee benefit costs and the effects of inflation. These higher O&M expenses were partially offset by the continuation of the Company's cost containment program. The increase in 1993 was principally due to the recognition of previously deferred storm costs associated with electric operations, the recording of higher accruals for uncollectible accounts and higher transmission and distribution costs for both the electric and gas businesses.
Rate Moderation Component and Related Carrying Charges
In 1994 and 1993, the Company recorded non-cash charges to income of approximately $198 million and $89 million, respectively, representing the amortization of the RMC. In 1992, the Company recorded non-cash income of approximately $30 million, representing the accretion of the RMC. The Company accrues a carrying charge on the unamortized balance of the RMC which amounted to $32 million, $40 million and $43 million for the years 1994, 1993 and 1992, respectively. For further discussion on the RMC, see Notes 1, 2 and 3 of Notes to Financial Statements. Other Regulatory Amortization
In 1994, other regulatory amortization was a non-cash charge to income of $4.3 million, compared to a non-cash credit to income of $18.0 million in 1993. The change reflects an increase in the amortization of LRPP deferrals, higher amortization of Shoreham post settlement costs, and a non-cash charge to income reflecting the operation of the interest deferral mechanism, as defined in the Company's electric rate structure. These items were partially offset by higher deferred net margin revenues, discussed above under "Revenues."
In 1993, other regulatory amortization was lower than 1992 as a result of lower net margin revenues and the amortization of the 1992 rate year LRPP deferrals which began in August 1993. Partially offsetting these items was the recognition of additional non-cash credits to income resulting from the operation of the interest deferral mechanism. For a discussion on the Company's rate mechanisms, see Note 3 of Notes to Financial Statements.
Operating Taxes
Operating taxes were $407 million, $386 million and $389 million, for the years 1994, 1993 and 1992, respectively. The increase in operating taxes of approximately $21 million in 1994 when compared to 1993 is primarily attributable to higher gross receipts taxes, resulting from increased revenues, higher property taxes, additional payroll taxes and higher dividend taxes.
INTEREST EXPENSE
The reduction in interest expense in 1994 when compared to 1993 is primarily attributable to lower outstanding debt levels. The Company's strategy is to apply available cash balances toward the satisfaction of debt whenever practicable. During 1994, the Company used approximately $200 million of cash on hand and the proceeds from the issuance of 5.1 million shares of common stock to help lower debt by approximately $300 million. The lower interest expense also reflects the satisfaction of $175 million of maturing debt in November 1993, with cash on hand.
The increase in 1993 when compared to 1992 was attributable to higher debt levels and the conversion in June 1992 of $400 million of tax-exempt securities from a weekly variable interest rate to a higher thirty year fixed rate. Also contributing to the increase, was the issuance in November 1992 of thirty year fixed rate debentures, the proceeds of which were used to eliminate variable rate bank debt. The conversion of the tax-exempt securities and refinancing of bank debt was done in order to take advantage of historically low long-term interest rates. Partially offsetting this increase in interest expense were savings realized from the effects of the Company's aggressive refinancing of higher-cost debt in 1993. ACCOUNTING PRONOUNCEMENTS
Effective January 1, 1993, the Company adopted the provisions of Statement of Financial Accounting Standards (SFAS) No. 106, Employers' Accounting for Postretirement Benefits Other Than Pensions. Under a PSC order issued in response to SFAS No. 106, the Company defers as a regulatory asset the difference between postretirement benefits expense recorded for accounting purposes in accordance with SFAS No. 106 and postretirement expenses reflected in rates. The PSC order also requires that the ongoing annual postretirement benefit expense be phased into and fully recovered in rates within a five year period, with the accumulated postretirement benefit obligation being recovered in rates over a twenty year period. The adoption of SFAS No. 106 had no impact on net income for the years ended December 31, 1994 and 1993. For a further discussion of SFAS No. 106, see Notes 1 and 8 of Notes to Financial Statements.
Effective January 1, 1993, the Company adopted SFAS No. 109, Accounting for Income Taxes. SFAS No. 109 requires utilities to establish deferred tax assets and liabilities for, among other things, transactions that were not recognized under Accounting Principles Board Opinion No. 11, Accounting for Income Taxes. SFAS No. 109 provides that regulatory assets and liabilities may be established for these specific SFAS No. 109 created deferred tax assets and liabilities providing that the regulator provides for the future recovery or return of these amounts through rates. As a result of a PSC order issued in January 1993, providing for the recovery or return of such amounts, the Company has recorded regulatory tax assets and liabilities to offset the effect of accumulated deferred tax liabilities and assets created as a result of adopting SFAS No. 109. The adoption of SFAS No. 109 had no impact on net income for the years ended December 31, 1994 and 1993. For a further discussion of SFAS No. 109, see Notes 1 and 9 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 11 of Item 6, Selected Financial Data. Information with regard to the Company's business segments for the last three years is provided in Note 11 of Notes to Financial Statements.
ITEM 8.


ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Financial Statements
See Notes to Financial Statements.
See Notes to Financial Statements.
Page
See Notes to Financial Statements.
See Notes to Financial Statements.
See Notes to Financial Statements.
See Notes to Financial Statements.
See Notes to Financial Statements.
NOTES TO FINANCIAL STATEMENTS
NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
REGULATION
The Company's accounting policies conform to generally accepted accounting principles as they apply to a regulated enterprise. Its accounting records are maintained in accordance with the Uniform Systems of Accounts prescribed by the Public Service Commission of the State of New York (PSC) and the Federal Energy Regulatory Commission (FERC).
REGULATORY ASSETS AND LIABILITIES
General
The Company's Balance Sheet reflects the rate actions of its regulators through the creation of regulatory assets and liabilities. Regulatory assets are generally created whenever it is probable that the regulators will permit the recovery through rates of a previously incurred cost that would otherwise be charged to expense. Regulatory liabilities are generally created whenever it is probable that the regulators will require a return through rates of revenues or gains that would otherwise be recorded to income.
Base Financial Component and Rate Moderation Component
Pursuant to the 1989 Settlement, 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 BFC represents the present value of the future net-after-tax cash flows which the Rate Moderation Agreement (RMA), one of the constituent documents of the 1989 Settlement, provided the Company for its financial recovery. The BFC was granted rate base treatment under the terms of the RMA and is included in the Company's revenue requirements through an amortization included in rates over forty years on a straight-line basis which 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 of the rate moderation plan provided for in the RMA. For a further discussion of the 1989 Settlement and FRA, see Note 2.
Shoreham Post Settlement Costs
The balance consists of Shoreham Nuclear Power Station (Shoreham) decommissioning costs, fuel disposal costs, payments in lieu of taxes, carrying charges and other costs. These costs are being capitalized and amortized and recovered through rates over a forty year period on a straight-line remaining life basis which began July 1, 1989.
Shoreham Nuclear Fuel
The balance principally reflects the unamortized portion of Shoreham nuclear fuel which was reclassified from Nuclear Fuel in Process and in Reactor at the time of the 1989 Settlement. This amount is being amortized, and recovered through rates over a forty year period on a straight-line remaining life basis which began July 1, 1989.
Postretirement Benefits Other Than Pensions
Under a PSC order issued in response to the Financial Accounting Standards Board (FASB) Statement of Financial Accounting Standards (SFAS) No. 106, Employers' Accounting for Postretirement Benefits Other Than Pensions, the Company defers as a regulatory asset the difference between postretirement benefit expense recorded for accounting purposes in accordance with SFAS No. 106 and postretirement benefit expense reflected in rates. Pursuant to the PSC order, the ongoing annual postretirement benefit expense must be phased into and fully recovered in rates within a five year period, with the accumulated postretirement obligation being recovered in rates over a twenty year period. For a further discussion of SFAS No. 106, see Note 8.
Regulatory Tax Asset/Liability
SFAS No. 109, Accounting for Income Taxes, requires utilities to establish deferred tax assets and liabilities for, among other things, transactions that did not give rise to deferred tax assets and liabilities under Accounting Principles Board (APB) Opinion No. 11, Accounting for Income Taxes. SFAS No. 109 provides that regulatory assets and liabilities may be established for these specific SFAS No. 109 created deferred tax assets and liabilities providing that the regulator provides for the future recovery or return of these amounts through rates. As a result of a PSC order issued in January 1993, providing for the recovery or return of such amounts, the Company has recorded regulatory tax assets and liabilities to offset the effect of accumulated deferred tax liabilities and assets created as a result of adopting SFAS No. 109.
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.
Regulatory Liability Component
Pursuant to the 1989 Settlement, certain tax benefits attributable to the Shoreham abandonment are to be shared between ratepayers and shareowners. A regulatory liability of approximately $794 million was 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 which began July 1, 1989.
1989 Settlement Credits
The balance represents the unamortized portion of an adjustment of the book write-off to the negotiated 1989 Settlement amount. A portion of this amount is being amortized over a ten year period which began on July 1, 1989. The remaining portion is not currently being recognized for ratemaking purposes.
UTILITY PLANT
Additions to and replacements of utility plant are capitalized at original cost, which includes material, labor, indirect costs associated with an addition or replacement and an allowance for the cost of funds used during construction. The cost of renewals and betterments relating to units of property is added to utility plant. The cost of property replaced, retired or otherwise disposed of is deducted from utility plant and, generally, together with dismantling costs less any salvage, is charged to accumulated depreciation. The cost of repairs 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 of installation.
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION
The Uniform Systems of Accounts defines the allowance for funds used during construction (AFC) as the net cost of borrowed funds for construction purposes and a reasonable rate of return upon the utility's equity when so used. AFC is not an item of current cash income. AFC is computed monthly using a rate permitted by FERC on a portion of construction work in progress. The average annual AFC rate, without giving effect to compounding, was 9.18%, 9.73% and 9.98% for the years 1994, 1993 and 1992, respectively.
DEPRECIATION
The provisions for depreciation result from the application of straight-line rates to the original cost, by groups, of depreciable 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%, 3.0% and 3.2% of respective average depreciable plant costs for the years 1994, 1993 and 1992. Depreciation for gas properties was equivalent to approximately 2.0%, 2.0% and 2.6% of respective average depreciable plant costs for the years 1994, 1993 and 1992.
CASH AND CASH EQUIVALENTS
Cash equivalents are highly liquid investments with maturities of three months or less when purchased. The carrying amount approximates fair value because of the short maturity of these investments.
FAIR VALUES OF FINANCIAL INSTRUMENTS
The fair values for the Company's long-term debt and redeemable preferred stock are based on quoted market prices, where available. The fair values for all other long-term debt and redeemable preferred stock are estimated using discounted cash flow analyses which are based upon the Company's current incremental borrowing rate for similar types of securities. CAPITALIZATION - PREMIUMS, DISCOUNTS AND EXPENSES
Premiums or discounts and expenses related to the issuance of long-term debt are amortized over the life of each issue. Unamortized premiums or discounts and expenses related to issues of long-term debt that are refinanced are amortized and recovered through rates over the shorter life of either the redeemed issue or the new issue. Capital stock expense and redemption costs related to certain issues of preferred stock that have been refinanced as well as the cost of issuance of the preferred stock issued are recorded as deferred charges. These amounts are being amortized and recovered through rates over the shorter life of the redeemed issue or the new issue.
REVENUES
The Company accrues electric and gas revenues for services rendered to customers but not billed at month-end. The Company's electric rate structure, discussed in Note 3, provides for a revenue reconciliation mechanism which eliminates the impact on earnings of experiencing electric sales that are above or below the levels reflected in rates. The Company's gas structure provides for a weather normalization clause, which reduces the impact on revenues of experiencing weather which is warmer or colder than the "normal" value used for projecting sales.
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 tariff rates (base fuel costs). The Company defers these differences to future periods in which they will be billed or credited to customers, except for base electric fuel costs in excess of actual electric fuel costs, which are currently credited to the RMC as incurred.
FEDERAL INCOME TAX
Effective January 1, 1993, the Company adopted SFAS No. 109. As permitted under SFAS No. 109, the Company elected not to restate the financial statements of prior years.
The Company provided deferred federal income taxes with respect to certain items of income and expense that are reported in different years for financial statement purposes and for federal income tax purposes.
The Company defers the benefit of 60% of pre-1982 gas and pre-1983 electric and 100% of all 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 of the related properties.
For ratemaking purposes, the Company provides deferred federal income taxes with respect to certain differences between income before income taxes and taxable income in certain instances when approved by the PSC, as disclosed in Note 9. 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 workers' compensation claims, property damage, extraordinary storm costs and general liability claims, are partially self-insured. Reserves for these claims and damages are based on, among other things, experience, risk of loss and the ratemaking practices of the PSC. Extraordinary storm losses incurred by the Company are partially insured by certain commercial insurance carriers. These insurance carriers provide partial insurance coverage for individual storm losses to the Company's transmission and distribution system between $5 million and $50 million. Storm losses which are outside of the above-mentioned range are self-insured by the Company. The Company is currently assessing its storm insurance requirements, as current policies expire March 1, 1995.
RECLASSIFICATIONS
Certain prior year amounts have been reclassified in the financial statements to be consistent with the current year's presentation. NOTE 2. THE 1989 SETTLEMENT
On February 28, 1989, the Company and the State of New York entered into the 1989 Settlement resolving certain issues relating to the Company and providing, among other matters, for the financial recovery of the Company and for the transfer of Shoreham and its subsequent decommissioning. Upon the effectiveness of the 1989 Settlement, in June 1989, the Company simultaneously recorded on its Balance Sheet the retirement of its investment of approximately $4.2 billion principally in Shoreham and the establishment of the FRA.
The BFC, a component of the FRA, as initially established, represents the present value of the future net-after-tax cash flows which the RMA provided the Company for its financial recovery. The BFC was granted rate base treatment under the terms of the RMA and 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, 1994 and 1993, the unamortized balance of the BFC was approximately $3.5 billion and $3.6 billion, respectively.
The RMC, a component of the FRA, reflects the difference between the Company's revenue requirements under conventional ratemaking and the revenues resulting from the implementation of the rate moderation plan provided for in the RMA. Prior to December 31, 1992, the RMC had increased as the difference between revenues resulting from the implementation of the rate moderation plan provided for in the RMA and revenue requirements under conventional ratemaking, together with a carrying charge equal to the allowed rate of return on rate base, was deferred. The RMC had provided the Company with a substantial amount of non-cash earnings from the effective date of the 1989 Settlement through December 31, 1992. Subsequent to December 31, 1992, the RMC balance had been decreasing as revenues resulting from the operation of the rate moderation plan exceeded revenue requirements under conventional ratemaking. The RMC is currently adjusted, on a monthly basis, for the Company's share of certain Nine Mile Point 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 gross receipts tax adjustments related to the FRA. At December 31, 1994 and 1993, the RMC balance was $463 million and $610 million, respectively. For a further discussion of the impact on the amortization of the RMC under the Long Island Lighting Company Ratemaking and Performance Plan (LRPP) and the Company's Electric Rate Plan for the three year period beginning December 1, 1994, see Note 3.
On February 29, 1992, the Company transferred ownership of Shoreham to the Long Island Power Authority (LIPA), an agency of the State of New York. Pursuant to the 1989 Settlement, the Company has funded the decommissioning of Shoreham. Based on the latest available information, LIPA has reported that the cost of decommissioning Shoreham, which is essentially complete, totaled approximately $181 million, excluding the costs associated with the disposal of Shoreham's fuel which was also completed in 1994 and cost approximately $112 million. LIPA anticipates that the Nuclear Regulatory Commission (NRC) will terminate its license for Shoreham during 1995. NOTE 3. RATE MATTERS
ELECTRIC
Long Island Lighting Company Ratemaking and Performance Plan
Pursuant to the 1989 Settlement, discussed in Note 2, the Company received electric rate increases as contemplated by the RMA for each of the three rate years in the period ended November 30, 1991. The RMA contemplates that the Company will apply to the PSC for targeted annual rate increases of 4.5% to 5.0% in each year for an eight year period beginning December 1, 1991. In November 1991, the PSC approved the LRPP which provided annual electric rate increases of 4.15%, 4.1% and 4.0%, respectively, for each of the three rate years in the period beginning December 1, 1991, with an allowed return on common equity from electric operations of 11.6% for each of the three rate years. After giving 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 term goals. One principal objective of the LRPP was to reassign risk so that the Company assumes the responsibility for risks within the control of management, whereas risks largely beyond the control of management would be assumed by the ratepayers. The LRPP reflects an update of the long range forecast of the Company's revenue requirements which was the basis of the 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 eliminates the impact of experiencing electric sales that are above or below the LRPP forecast by providing a fixed annual net margin level (defined as sales revenues, net of fuel and gross receipts taxes) that the Company will receive 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 reconciliation of certain expenses for wage rates, property taxes, interest costs and demand side management (DSM) costs. The LRPP also provides for the deferral and amortization of certain costs for enhanced reliability and production operations and maintenance expenses and the application of an inflation index to other expenses for the rate years beginning December 1, 1992 and 1993.
Under the performance incentive component of the LRPP, the Company is allowed to earn for each rate year up to 60 additional basis points, or forfeit up to 38 basis points, of the allowed return on common equity as a result of its performance within certain incentive and/or penalty programs. These programs consist of a customer service program, a time of-use program, a partial pass through fuel cost incentive plan, a DSM program and, effective December 1, 1993, an electric transmission and distribution reliability plan. These incentives and/or penalties, except for incentives earned under the DSM program, 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 of 50 and 49 basis points or approximately $9.2 million, net of tax effects, for each of the rate years ended November 30, 1994 and 1993. For the rate year ended November 30, 1992 the Company earned a total of 23 basis points or approximately $4.3 million, net of tax effects.
The deferred balances resulting from the net margin, property taxes, interest costs, wage rates, performance incentives and associated carrying charges, excluding DSM incentives, are netted at the end of each rate year. The LRPP established a band whereby the first $15 million of the total net deferrals are used to increase or decrease the RMC balance. The LRPP provides for the disposition of the total net deferrals in excess of the $15 million band. Upon approval by the PSC, the total net deferrals in excess of $15 million are refunded to or recovered from the ratepayers through the FCA over a twelve month period.
The Company recorded deferred balances of approximately $45.2 million, $63.1 million and $78.6 million of the total net deferrals for the rate years ended November 30, 1992, 1993 and 1994, respectively. The first $15 million of the total net deferrals has been recorded for the rate years ended November 30, 1992 and 1993 and upon approval by the PSC of the Company's reconciliation filing will be recorded for the rate year ended November 30, 1994 as an increase to the RMC with the remaining net deferrals of $30.2 million, $48.1 million and $63.6 million, respectively, recovered from the ratepayers through the FCA. As of July 31, 1994, the Company has fully collected the November 30, 1992 net deferrals through the FCA and is awaiting PSC approval for the collection of the 1993 and 1994 rate year net deferrals through the FCA. Effective August 1994, the PSC has allowed the Company to continue the collection of a like amount of the total net deferrals related to the rate year ended November 30, 1992 through the FCA. These additional revenues amounting to approximately $13.4 million through December 1994 were recorded as a reduction to the RMC. The Company expects to collect the 1993 rate year net deferrals of $48.1 million by November 30, 1995 and the 1994 rate year net deferrals of $63.6 million over the twelve month period ending November 30, 1996.
The LRPP contains a mechanism whereby earnings in excess of the allowed return on common equity of 11.6%, excluding the impacts of the various incentive and/or penalty programs, are shared equally between ratepayers and shareowners. The Company earned $8.9 million and $21.4 million, net of tax effects, for the rate years ended November 30, 1993 and 1992, respectively, in excess of its allowed return on common equity. The amount in excess of the allowed return on common equity was shared equally between ratepayers (by a reduction to the RMC) and shareowners for the rate years ended November 30, 1993, and 1992. For the rate year ended November 30, 1994, the Company did not earn in excess of its allowed return on common equity.
To assist in the recovery of the 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 1994, the Company applied a total of approximately $5.1 million of net deferred ratepayer benefits to the RMC including DSM revenues overcollected in the 1994 rate year. In December 1993 and 1992, the Company reduced the RMC by approximately $10.1 million and $22.5 million representing various deferred ratepayer benefits including the ratepayers portion of the excess earnings for the rate years ended November 30, 1993 and 1992, respectively.
Electric Rate Plan
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 of the restoration of the Company's financial health. The Electric Rate Plan requests an allowed return on common equity of 11.0% and provides for base rates to be frozen in years one and two and an overall rate increase of 4.3% in the third year. Although base electric rates would be frozen during the first two years of the Electric Rate Plan, annual rate increases of approximately 1% are expected to result from the operation of the Company's FCA. The FCA captures, among other things, amounts to be recovered from or refunded to ratepayers in excess of $15 million which result from the reconciliation of revenues, certain expenses and earned performance incentive components, discussed above.
The Company's Electric Rate Plan reflects four underlying objectives: (i) to limit the balance of RMC during the three year period to no more than its 1992 peak balance of $652 million; (ii) to recover the RMC within the time frame established in the 1989 Settlement; (iii) to minimize, beginning in the third year of the Electric Rate Plan, the final three rate increases contemplated in the 1989 Settlement that follow the two year rate freeze period; and (iv) to continue the Company's gradual return to financial health.
The Electric Rate Plan provides for, with some modifications, the continuation of the LRPP revenue and expense reconciliations and performance incentives. The Electric Rate Plan includes the annual reconciliation of certain expenses for property taxes, interest costs, DSM costs and the deferral and amortization of certain costs for enhanced reliability. The Company would be allowed to earn for the three rate years under the Electric Rate Plan up to 50 additional basis points, excluding incentives under the DSM program, or forfeit up to 47 basis points of the allowed return on common equity of 11.0% as a result of the Company's performance within certain performance programs. These programs consist of a customer service program, a partial pass through fuel cost incentive plan, a DSM program and an electric transmission and distribution reliability plan.
The Company's Electric Rate Plan provides for lower annual electric rate increases than originally anticipated under the 1989 Settlement. However, as a result of changes in certain assumptions upon which the RMA was 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 of the RMA can be met under the Electric Rate Plan. 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 billion in 1994, peaked at $652 million in 1992. With the exception of a projected increase in 1995 and 1996, which is not now anticipated to cause the RMC to increase above its $652 million peak, the RMC is expected to decline until it is fully amortized. Under the Electric Rate Plan, the recovery of the RMC would be extended, if necessary, for an additional period of not more than three years beyond the approximate ten year period envisioned in the RMA. The actual length of the RMC extension will depend on the extent to which the assumptions underlying the Electric Rate Plan materialize. The Company's current projections indicate that the RMC will be recovered in eleven years.
The staff of the PSC (Staff) and other intervening parties filed testimony in response to the Company's Electric Rate Plan. Staff concurs with the Company's proposal for an 11.0% return on common equity in each of the three years and has reaffirmed its commitment to the principles of the RMA, including the full recovery of the RMC within the time frame established by the RMA. However, Staff has recommended an overall zero percent rate increase for the first two years, contrasted with the Company's proposal for a base rate freeze with FCA adjustments of approximately 1% in years one and two, as described above. Staff did not make a recommendation for the level of rate relief in the third year.
In September 1994, three Administrative Law Judges (ALJs) of the PSC issued a recommended decision to the PSC with respect to the Company's Electric Rate Plan. The ALJs agreed with the Company's proposed 11.0% return on common equity and its proposal to freeze base electric rates for the first rate year. While no explicit recommendation was made concerning the second year, the recommended decision implies that base rates could remain frozen for the second rate year as well.
With respect to the third rate year beginning December 1, 1996, the ALJs determined that it was not appropriate for them to issue a recommendation since, in their opinion, the Company's revenue requirements for the third rate year cannot be precisely determined at this time. Alternatively, the ALJs encouraged the Company and other parties in this proceeding to negotiate a settlement concerning any rate increase for the third rate year.
The PSC had been expected to issue a final order on the Company's rate proposal before November 29, 1994, the date that the statutory suspension period was scheduled to terminate. However, in order to accommodate further settlement negotiations in the proceeding, the Company has requested extensions through April 1995, which were granted by the PSC. The Company's offers to extend the suspension period were conditioned upon the continuation of the current LRPP rate mechanisms. Although the ultimate outcome of the Electric Rate Plan cannot be predicted, the Company expects that any PSC order will be consistent with the provisions of the RMA respecting the recovery of the FRA and other 1989 Settlement deferred charges.
GAS
In December 1993, the PSC approved a three year gas rate settlement between the Company and the Staff of the PSC. The gas rate settlement provides that the Company receive, for each of the rate years beginning December 1, 1993, 1994 and 1995, annual gas rate increases of 4.7%, 3.8% and 2.8%, respectively. In the determination of the revenue requirements for the gas rate settlement an allowed return on common equity of 10.1% was used. The gas rate decision also provides that earnings in excess of a 10.6% return on common equity in any of the three rate years covered by the settlement be shared equally between the Company's firm gas customers and its shareowners. For the rate year ended November 30, 1994, the Company earned $9.2 million, net of tax effects, in excess of the 10.6% return on common equity. The firm gas customers' portion of these excess earnings amounting to $4.6 million, net of tax effects, has been deferred until its final disposition is determined by the PSC. NOTE 4. THE CLASS SETTLEMENT
The Class Settlement, which became effective on June 28, 1989, resolved a civil lawsuit against the Company brought under the federal Racketeer Influenced and Corrupt Organizations 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 electric ratepayers with reductions, aggregating $390 million, that are being reflected as adjustments to their monthly electric bills over a ten year period which began on June 1, 1990.
The reductions which begin in each of the remaining twelve month periods are as follows:
Upon its effectiveness, the Company recorded its liability for the Class Settlement on a present value basis at $170 million and simultaneously recorded a charge to income (net of tax effects of $57 million) of approximately $113 million. Each month the Company records the changes in the present value of its liability that results from the passage of time and from monthly reductions. The Company expects the Class Settlement liability will be fully satisfied by May 31, 2000.
In accordance with the Class Settlement, the Company, in 1990, established a $10 million fund to reimburse former electric ratepayers entitled to refunds under the Class Settlement. At December 31, 1994, approximately $4.5 million remains undistributed in the fund. Pursuant to the terms of the Class Settlement, the undistributed portion of the net fund balance will be used to reduce ratepayers' bills upon the Company's receipt of the funds from the trustee. NOTE 5. NINE MILE POINT NUCLEAR POWER STATION, UNIT 2
The Company has an 18% undivided interest in NMP2 which is operated by Niagara Mohawk Power Corporation (NMPC) near Oswego, New York. Ownership of NMP2 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%). At December 31, 1994, the Company's utility plant investment in NMP2 was $749 million, net of accumulated depreciation of $140 million, which is included in the Company's rate base. Output of NMP2 is shared in the same proportions as the cotenants' respective ownership interests. The operating expenses of NMP2 are also allocated to the cotenants in the same proportions as their respective ownership interests. The Company's share of these expenses is included in the appropriate operating expenses on its Statement of Income. The Company is required to provide its respective share of financing for any capital additions to NMP2. Nuclear fuel costs associated with NMP2 are being amortized on the basis of the quantity of heat produced for the generation of electricity.
NMPC has contracted with the United States Department of Energy for the disposal of nuclear fuel. The Company reimburses NMPC for its 18% share of the cost under the contract at a rate of $1.00 per megawatt hour of net generation less a factor to account for transmission line losses.
The Company's share of the decommissioning costs for NMP2 is estimated to be $82 million and $234 million, in 1994 dollars and 2027 dollars, respectively, based upon a 1989 study performed by NMPC which was updated in 1993 to reflect a change in the NRC minimum decommissioning funding requirement. NMPC has informed the Company that decommissioning costs for NMP2 will increase primarily as a result of the inclusion of nuclear fuel storage charges and costs for continuing care. NMPC will be performing an updated decommissioning study for NMP2 in 1995. The Company will update its estimate for decommissioning costs upon the NRC's approval of the 1995 study. NMPC expects to commence decommissioning in 2027, shortly after cessation of operations, using a method which removes or decontaminates NMP2 components promptly. The Company's share of estimated decommissioning costs are being provided for in electric rates and are being charged to operations as depreciation expense over the expected service life of NMP2. The amount of decommissioning costs recorded as depreciation expense in 1994 was $1.6 million. The accumulated decommissioning costs collected in rates through December 31, 1994 amounted to $8.7 million. The Company has established an independent decommissioning trust fund for the decommissioning of the contaminated portion of the NMP2 plant, which is approximately 92% of total decommissioning costs. As of December 31, 1994, the Company has accumulated $8.3 million in this external trust fund. Net earnings on this fund are recorded as an increase to accumulated depreciation. This fund complies with regulations issued by the NRC governing the funding of nuclear plant decommissioning costs. NOTE 6. CAPITAL STOCK
COMMON STOCK
During 1994, the Company issued 6.1 million shares of common stock, including the public offering in June of 5.1 million shares at $20 per share. The Company has 150,000,000 shares of authorized common stock, of which 118,416,606 were issued and outstanding at December 31, 1994. The Company has reserved 1,747,570 shares for sale through its Employee Stock Purchase Plan, 5,009,762 shares were committed to the Automatic Dividend Reinvestment Plan and 114,126 shares were reserved for conversion of the Series I Convertible Preferred Stock at a rate of $17.15 per share. 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.
PREFERRED STOCK
The Company has 7,000,000 authorized shares, cumulative preferred stock, par value $100 per share and 30,000,000 authorized shares, cumulative preferred stock, par value $25 per share. 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 of redeemable preferred stock with mandatory redemptions at December 31, 1994 and 1993 amounted to approximately $564 million and $659 million, respectively, compared to their carrying amounts of $649 million and $654 million, respectively.
The Company is required to redeem each year certain series of preferred stock through the operation of sinking fund provisions as follows:
In addition, the Company will have the non-cumulative option to double the number of shares to be redeemed pursuant to the sinking fund provisions in any year for the preferred stock series R, NN and UU. The aggregate par value of preferred stock required to be redeemed through sinking funds in 1995 and 1996 is $4.8 million, in 1997 and 1998 is $1.1 million and in 1999 is $5.8 million.
The Company is also required to redeem all shares of certain series of preferred stock which are not subject to sinking fund requirements. The scheduled mandatory redemption for these series are as follows: (i) Series GG on March 1, 1999; (ii) Series AA on June 1, 2000; (iii) Series QQ on May 1, 2001; and (iv) Series CC on August 1, 2002. PREFERRED STOCK NOT SUBJECT TO MANDATORY REDEMPTION
The Company has the option to redeem certain series of its preferred stock. For the series subject to optional redemption at December 31, 1994, the call prices were as follows:
PREFERENCE STOCK
At December 31, 1994, none of the authorized 7,500,000 shares of nonparticipating preference stock, par value $1 per share, which ranks junior to preferred stock, were outstanding. NOTE 7. LONG-TERM DEBT
Each of the Company's outstanding mortgages is a lien on substantially all of the Company's properties.
FIRST MORTGAGE
All of the bonds issued under the First Mortgage, including those issued after June 1, 1975 and pledged with the Trustee of the General and Refunding Mortgage (G&R Trustee) as additional security for General & Refunding Bonds (G&R Bonds), are secured by the lien of the First Mortgage. First Mortgage Bonds pledged with the G&R Trustee do not represent outstanding indebtedness of the Company. Amounts of such pledged bonds outstanding were $1.3 billion and $1.0 billion at December 31, 1994 and 1993, respectively. The annual First Mortgage depreciation fund and sinking fund requirements for 1994, due not later than June 30, 1995, are estimated at $239 million and $21 million, respectively. The Company expects to meet these requirements with property additions and retired First Mortgage Bonds.
G&R MORTGAGE
The lien of the G&R Mortgage is subordinate to the lien of the First Mortgage. The annual G&R Mortgage sinking fund requirement for 1994, due not later than June 30, 1995, is estimated at $26 million. The Company expects to satisfy this requirement with retired G&R Bonds.
1989 REVOLVING CREDIT AGREEMENT
The Company has available through October 1, 1995, $300 million under its 1989 Revolving Credit Agreement (1989 RCA). This line of credit is secured by a first lien upon the Company's accounts receivable and fuel oil inventories.
At December 31, 1994, no amounts were outstanding under the 1989 RCA. The Company has the option, when amounts are outstanding, to commit to one of three interest rates including: (i) the Adjusted Certificate of Deposit Rate which is a rate based on the certificate of deposit rates of certain of the 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 of one quarter of one percent per annum on the unused portion. The 1989 RCA may be extended for one year periods upon the acceptance by the lending banks of a request by the Company which must be delivered to the lending banks prior to April 1 of each year. It is the Company's intent to request an extension prior to April 1, 1995. AUTHORITY FINANCING 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 Industrial Development Revenue Bonds, Pollution Control Revenue Bonds (PCRBs) and Electric Facilities Revenue Bonds (EFRBs) issued by NYSERDA. Certain of these bonds are subject to periodic tender at which time their interest rates may be subject to redetermination. Tender requirements of Authority Financing Notes at December 31, 1994 were as follows:
The 1994 and 1993 EFRBs and the 1985 PCRBs are supported by letters of credit pursuant to which the letter of credit banks have agreed to pay the principal, interest and premium, if applicable, in the aggregate, up to approximately $326 million in the event of default. The obligation of the Company to reimburse the letter of credit banks is unsecured. These letters of credit expire on October 26, 1997 for the 1994 EFRBs, November 17, 1996 for the 1993 EFRBs, and March 16, 1996 for the 1985 PCRBs, at each of which times the Company is required to obtain either an extension of the letters of credit or substitute credit backup. If neither can be obtained, the 1993 EFRBs, the 1994 EFRBs and the 1985 PCRBs must be redeemed unless the Company purchases them in lieu of redemption and subsequently remarkets them.
FAIR VALUES OF LONG-TERM DEBT
The carrying amounts and fair values of the Company's long-term debt at December 31 were as follows:
For a further discussion on the fair value of the securities listed above, see Note 1.
MATURITY SCHEDULE
Total long-term debt maturing in each of the next five years is $25 million (1995), $455 million (1996), $286 million (1997), $101 million (1998) and $454 million (1999).
NOTE 8. RETIREMENT BENEFIT PLANS
PENSION PLANS
The Company maintains a defined benefit pension plan which covers substantially all employees (Primary Plan), a supplemental plan which covers officers and certain key executives (Supplemental Plan) and a retirement plan which covers the Board of Directors (Directors' Plan). The Company also maintains 401(k) plans for its union and non-union employees. The Company does not contribute to these plans.
Primary Plan
The Company's funding policy is to contribute annually to the Primary Plan a minimum amount consistent with the requirements of the Employee Retirement Income Security Act of 1974 (ERISA) plus such additional amounts, if any, as the Company may determine to be appropriate from time to time.
For service before January 1, 1992, pension benefits are determined based on the greater of the accrued benefit as of December 31, 1991, or by applying a moving five year average of Plan compensation, not to exceed the January 1, 1992 salary, to certain percentages as defined in the Primary Plan, determined by years of service at December 31, 1991. For service after January 1, 1992, pension benefits are equal to 2% per year of Plan compensation through age 49 and 2 1/2% thereafter. Employees are vested in the Primary Plan after five years of service with the Company.
The Primary Plan's funded status and amounts recognized on the Balance Sheet at December 31, 1994 and 1993 were as follows:
Periodic pension cost for 1994, 1993 and 1992 for the Primary Plan included the following components:
The Primary Plan assets at fair value 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 of pension costs in accordance with SFAS No. 87, Employers' Accounting 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. This change in the annual pension cost calculation reduced pension expense by $4.6 million in the year of adoption, 1993. The Company believes that this method of accounting for financial reporting purposes, results in a better matching of revenues and the Company's pension cost. The Company defers differences between pension rate allowance and pension expense under the PSC's order. In addition, the PSC requires the Company to measure the difference between the pension rate allowance and the annual pension contributions contributed into the pension fund.
Supplemental Plan
The Supplemental Plan, the cost of which 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 plan benefits, which is unfunded, totaled approximately $2.3 million, $2.8 million and $.7 million which was recognized as expense in 1994, 1993 and 1992, respectively.
Directors' Plan
The Directors' Plan provides benefits to directors who are not officers of the Company. Directors who have served in that capacity for more than five years qualify as participants under the plan. The Directors' Plan is a non-qualified plan under the Internal Revenue Code. The provision for retirement benefits, which is unfunded, totaled approximately $148,000, $150,000, and $133,000 which was recognized as expense in 1994, 1993 and 1992, respectively. POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
In addition to providing pension benefits, the Company provides certain medical and life insurance benefits for retired employees. Substantially all of the Company's employees may become eligible for these benefits if they reach retirement age after working for the Company for a minimum of five 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 of SFAS No. 106, Employers' Accounting for Postretirement Benefits Other Than Pensions, which requires the Company to recognize the expected cost of providing postretirement benefits when employee services are rendered rather than when paid. As a result, the Company, in 1993, recorded an accumulated postretirement benefit obligation and a corresponding regulatory asset of approximately $376 million. Additionally, as a result of adopting SFAS No. 106, the Company's postretirement benefit cost for 1993 increased by approximately $28 million above the amount that would have been recorded under the pay-as-you-go method.
In 1993, the PSC issued an order which required that the effects of implementing SFAS No. 106 be phased into rates. The order requires 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 will be phased into and fully reflected in rates within a five year period with the accumulated postretirement obligation being recovered in rates over a twenty year period. In addition, the Company is required to recognize any deferred net gains or losses over a ten year period.
In 1994, the Company established Voluntary Employee's Beneficiary Association (VEBA) trusts for union and non-union employees for the funding of incremental costs collected in rates for postretirement benefits. In December 1994, the Company contributed $2.2 million for the incremental postretirement benefit cost collected in gas rates. In 1995, the Company will begin funding the incremental postretirement benefit cost for the electric business as these amounts are reflected in rates. Accumulated postretirement benefit obligation other than pensions at December 31 were as follows:
Periodic postretirement benefit cost other than pensions for the years 1994, 1993 and 1992 were as follows:
Assumptions used to determine the postretirement benefit obligation were as follows:
The assumed health care cost trend rates used in measuring the accumulated postretirement benefit obligation at December 31, 1994 and 1993 were 9.0% and 9.5%, 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, 1994 and 1993 by approximately $44 million and $46 million, respectively, and the sum of the service and interest costs in 1994 and 1993 by $6 and $8 million, respectively. NOTE 9. FEDERAL INCOME TAX
At December 31, the significant components of the Company's deferred tax assets and liabilities calculated under the provisions of SFAS No. 109 were as follows:
Federal income tax expense in accordance with APB No. 11, for the year 1992 was as follows:
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 income before income tax. The table below sets forth the reasons for such differences.
The Company's net operating loss (NOL) carryforwards for federal income tax purposes is estimated to be approximately $1.6 billion at December 31, 1994. The NOL will expire in the years 2004 through 2007. The amount of investment tax credit (ITC) carryforwards, net of the 35% reduction required by the Tax Reform Act of 1986, are approximately $142 million. The ITC carryforwards expire by the year 2005. For financial reporting purposes, a valuation 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' Reports 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' Reports reflect proposed adjustments to the Company's federal income tax returns for 1984 through 1989 which, if sustained, would give rise to tax deficiencies totaling approximately $220 million. The Revenue Agents have proposed ITC adjustments which, if sustained, would reduce the Company's ITC carryforwards by approximately $96 million. The Company is protesting some of the adjustments and is seeking an administrative and, if necessary, a judicial review of the conclusions reached in the Revenue Agents' Reports. The Company cannot predict either the timing or the manner in which these matters will be resolved. If however, the ultimate disposition of any or all matters raised in the Revenue Agents' Reports are adverse to the Company, the Company expects that any deficiencies that may arise will be substantially offset by the net operating loss carrybacks associated with the 1989 Shoreham abandonment loss deduction of $1.8 billion and thus any impact would not have a material effect on the Company's financial condition or cash flows. NOTE 10. COMMITMENTS AND CONTINGENCIES
COMMITMENTS
The Company has entered into substantial commitments for gas supply, purchased power and transmission facilities. The costs associated with these commitments are recovered from ratepayers through provisions in the Company's rate schedules.
The Company expects that it will have to expend approximately $1 million in 1995 to meet continuous emission monitoring requirements and to meet Phase I nitrogen oxide (NOx) reduction requirements. Subject to requirements that are expected to be promulgated in forthcoming regulations, the Company estimates that it may be required to expend approximately $80 million (net of NOx credit sales) by 2003 to meet Phase II and Phase III NOx reduction requirements and approximately $24 million by 1999 to meet potential requirements for the control of hazardous air pollutants from power plants. The Company believes that all of the above costs will be recoverable through rates.
CONTINGENCIES
Environmental Matters
The Company is subject to federal, State and local laws and regulations dealing with air and water quality and other environmental matters. The Company continually monitors its activities in order to determine the impact of such activities on the environment and to ensure compliance with various environmental laws. Except as set forth below, no material proceedings have been commenced or, to the knowledge of the Company, are contemplated against the Company with respect to any matter relating to the protection of the environment.
The New York State Department of Environmental Conservation has indicated to New York State utilities that it may require all such utilities to investigate and, where necessary, remediate their former manufactured gas plant (MGP) sites. The Company is the owner of six pieces of property on which the Company or certain of its predecessor companies produced manufactured gas. Although the exact amount of the Company's clean-up costs cannot yet be determined, based on the findings of investigations at two of these six sites, preliminary estimates indicate that it will cost approximately $35 million to clean up all of these sites over the next five to ten years. Accordingly, the Company has recorded a $35 million liability and has also recorded a $35 million regulatory asset to reflect its belief that the PSC will provide for the future recovery of these costs through rates as it has for other New York State utilities. The Company has notified its former and current insurance carriers that it seeks to recover from them certain of these clean-up costs. However, the Company is unable to predict the amount of insurance recovery, if any, that it may obtain. The Company has been notified by the Environmental Protection Agency (EPA) that it is one of many potentially responsible parties (PRPs) that may be liable for the remediation of three contaminated licensed treatment, storage and disposal sites. At one site, located in Philadelphia, Pennsylvania, and operated by Metal Bank of America, the Company and nine other PRPs, all of which are public utilities, have completed a Remedial Investigation and Feasibility Study which is currently being reviewed by the EPA. The level of remediation required will be determined when the EPA issues its decision, currently expected in May 1995. The Company currently anticipates that the total cost to remediate this site will be between $14 million and $30 million. The Company has recorded a liability of $1.1 million representing its estimated share of the cost to remediate this site. The Company believes that any cost incurred to remediate this site will be recoverable through rates.
With respect to the other two sites, located in Kansas City, Kansas and Kansas City, Missouri, the Company is investigating allegations that it had previously stored or made agreements for disposal of polychlorinated biphenyls (PCBs) or items containing PCBs at these sites. The Company is currently unable to determine its share of the cost to remediate these two sites or the impact, if any, on the Company's financial position. The Company believes that any cost incurred to remediate these sites will be recoverable through rates.
As a result of its daily business activity, the Company is involved in various legal and administrative proceedings, including other environmental proceedings. The Company believes the resolution of these proceedings will not have a material adverse effect on the Company's financial position or results of operations.
NUCLEAR PLANT INSURANCE
The NRC requires the owners of nuclear facilities to maintain certain types of insurance. For property damage at each nuclear generating site, the NRC requires a minimum of $1.06 billion of coverage. The NRC has provided the Company with a partial exemption from these requirements for Shoreham. With respect to third party liability and property damage, the NRC requires nuclear plant owners to carry $200 million in primary coverage. Pursuant to these requirements, the Company carries property insurance and third party bodily injury and property liability insurance for its 18% share in NMP2 and for Shoreham. The annual premiums for this coverage are not material.
The policies also include retroactive premiums under certain circumstances. For the property damage policies, the retroactive premium assessments, on a per occurrence basis, could be as much as $4.6 million. Once Shoreham is declared a non-nuclear site by the NRC this retroactive premium assessment may decrease significantly. For the third party liability and property damage insurance, the retroactive premium is related to the NRC's requirement that nuclear facility owners, in addition to carrying $200 million in primary coverage, also participate in a Secondary Financial Protection Fund (Fund). Under the Price Anderson Act, that assessment related to the Fund could be up to $79.3 million per nuclear incident in any one year at any nuclear unit, but not in excess of $10 million in payments per year for each incident. The Price Anderson Act also limits liability for third-party bodily injury and third-party property damage arising out of a nuclear occurrence at each unit to $8.9 billion.
In 1994, the NRC granted the Company permission to withdraw from the Fund because Shoreham had been defueled. The withdrawal was effective November 18, 1994. The withdrawal relieves the Company from any retroactive premium assessment relating to any nuclear incident as of November 18, 1994 or later. The Company remains liable for retroactive assessments for any nuclear incident occurring prior to November 18, 1994 during the time the Company participated in the Fund because of its Shoreham ownership. The likelihood that the Company's retroactive premium responsibility would be triggered, however, is remote since it is highly unlikely that a nuclear unit had a nuclear incident prior to November 18, 1994, did not report the incident, and that incident is significant enough to exceed the primary coverage of $200 million, thus triggering the retroactive premium provisions. As a co-owner of NMP2, the Company remains liable for 18% of any retroactive premium assessment levied against the NMP2 owners. NOTE 11. SEGMENTS OF BUSINESS
The Company is engaged in the electric and natural gas utility businesses. The Company serves 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 utility plant, regulatory assets, materials and supplies, accrued unbilled revenues, gas in storage, fuel and deferred charges. Assets utilized for overall Company operations consist primarily of cash and cash equivalents, accounts receivable and unamortized cost of issuing securities.
*Includes non-cash allowance for other funds used during construction and excludes Shoreham post settlement costs.
NOTE 12. QUARTERLY FINANCIAL INFORMATION (Unaudited)
In the fourth quarter of 1993, the Company recorded income of approximately $6.5 million, net of tax effects, or $.06 per common share related to the settlement of certain litigation. In addition, in the fourth quarter of 1993, the Company recorded a charge to earnings of approximately $7.3 million, net of tax effects or $.07 per common share principally related to previously deferred storm costs and the reconciliation of certain ratemaking mechanisms recorded in connection with the conclusion of the Company's rate year. REPORT OF ERNST & YOUNG LLP, INDEPENDENT AUDITORS
To the Shareowners and Board of Directors of Long Island Lighting Company
We have audited the accompanying balance sheet of Long Island Lighting Company and the related statement of capitalization as of December 31, 1994 and 1993 and the related statements of income, retained earnings and cash flows for each of the three years in the period ended December 31, 1994. Our audits also included the financial statement schedule listed in the Index at Item 14(a). These financial statements and schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedule 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 of material 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 of Long Island Lighting Company at December 31, 1994 and 1993, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1994, in conformity with generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
/s/ Ernst & Young LLP
Melville, New York February 3, 1995 ITEM 9.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
Not applicable.
PART III
ITEM 10.



ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE COMPANY
Information required by Item 10 as to the Company's Executive Officers is set forth in Item 1, "Business" under the heading "Executive Officers of the Company" above. Information required by Item 10 as to the Company's Directors may be found in the Company's proxy statement for its annual meeting to be held on May 24, 1995 (the "Annual Meeting"). Such proxy statement is incorporated herein by reference.
ITEM 11.

ITEM 11. EXECUTIVE COMPENSATION
Information required by Item 11 may be found in the Company's proxy statement for the Annual Meeting. Such proxy statement is incorporated herein by reference.
ITEM 12.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Information required by Item 12 may be found in the Company's proxy statement for the Annual Meeting. Such proxy statement is incorporated herein by reference.
ITEM 13.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Information required by Item 13 may be found in the Company's proxy statement for the Annual Meeting. Such proxy statement is incorporated herein by reference.
PART IV
ITEM 14.

ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a)(1) List of Financial Statements
Statement of Income for each of the three years in the period ended December 31, 1994.
Balance Sheet at December 31, 1994 and 1993.
Statement of Retained Earnings for each of the three years in the period ended December 31, 1994.
Statement of Capitalization at December 31, 1994 and 1993.
Statement of Cash Flows for each of the three years in the period ended December 31, 1994.
Notes to Financial Statements.
(2) List of Financial Statement Schedules
Valuation and Qualifying Accounts (Schedule II)
(3) List of Exhibits
Exhibits listed below which have been filed with the Securities and Exchange Commission pursuant to the Securities Act of 1933 or the Securities Exchange Act of 1934, and which were filed as noted below, are hereby incorporated by reference and made a part of this report with the same effect as if filed herewith.
3(a) Restated Certificate of Incorporation of the Company dated November 11, 1993 (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1993.)
(b) By-laws of the Company as amended on May 28, 1991 (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1991.)
4(a) General and Refunding Indenture dated as of June 1, 1975 (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1991.)
Twenty-seven Supplemental Indentures to the General and Refunding Indenture dated as of June 1, 1975, as follows:
4(b) Indenture of Mortgage and Deed of Trust dated as of September 1, 1951 (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1987.)
Fifty Supplemental Indentures to the Indenture of Mortgage and Deed of Trust dated as of September 1, 1951, as follows:
__________________________________
*Filed herewith.
4(c) Debenture Indenture dated as of November 1, 1986 from the Company to The Connecticut Bank and Trust Company, National Association, as Trustee (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1986).
Seven Supplemental Indentures to the Debenture Indenture dated as of November 1, 1986, filed as follows:
__________________________________
*Filed herewith.
4(d) Debenture Indenture dated as of November 1, 1992 from the Company to Chemical Bank, as Trustee (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1992).
Four Supplemental Indentures to the Debenture Indenture dated as of November 1, 1992, filed as follows:
10(a) Sound Cable Project Facilities and Marketing Agreement dated as of August 26, 1987 between the Company and the Power Authority of the State of New York (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1987).
10(b) Transmission Agreement by and between the Company and Consolidated Edison Company of New York, Inc. dated as of March 31, 1989 (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1989).
10(c) Contract for the sale of Firm Power and Energy by and between the Company and the State of New York dated as of April 26, 1989 (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1989).
10(d) Capacity Supply Agreement dated as of December 13, 1991 between the Company and the Power Authority of the State of New York (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1991).
10(e) Nine Mile Point Nuclear Station Unit 2 Operating Agreement dated as of January 1, 1993 by and between the Company, New York State Electric & Gas Corporation, Rochester Gas and Electric Corporation and Central Hudson Gas and Electric Corporation (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1993).
10(f) Settlement Agreement on Issues Related to Nine Mile Two Nuclear Plant dated as of June 6, 1990 by and between the Company, the Staff of the Department of Public Service and others (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1990).
10(g) Settlement Agreement -- LILCO Issues dated as of February 28, 1989 by and between the Company and the State of New York (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1988).
10(h) Amended and Restated Asset Transfer Agreement by and between the Company and the Long Island Power Authority dated as of June 16, 1988 as amended and restated on April 14, 1989 (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1989).
10(i) Memorandum of Understanding concerning proposed agreements on power supply for Long Island dated as of June 16, 1988 by and between the Company and New York Power Authority as amended May 24, 1989 (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1989).
10(j) Rate Moderation Agreement submitted by the staff of the New York State Public Service Commission on March 16, 1989 and supported by the Company (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1989).
10(k) Site Cooperation and Reimbursement Agreement dated as of January 24, 1990 by and between the Company and Long Island Power Authority (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1989).
10(l) Stipulation of settlement of federal Racketeer Influenced and Corrupt Organizations Act Class Action and False Claims Action dated as of February 27, 1989 among the attorneys for the Company, the ratepayer class, the United States of America and the individual defendants named therein (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1988).
10(m) Revolving Credit Agreement dated as of June 27, 1989, between the Company and the banks and co-agents listed therein, with the Exhibits thereto (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1989) and as amended by the First Amendment dated as of October 13, 1989 (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1990) and as amended by the Second Amendment dated as of March 5, 1992 and as modified by a Waiver dated November 5, 1992 (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1992).
10(n) Indenture of Trust dated as of December 1, 1989 by and between New York State Energy Research and Development Authority ("NYSERDA") and The Connecticut National Bank, as Trustee, relating to the 1989 EFRBs (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1989).
Participation Agreement dated as of December 1, 1989 by and between NYSERDA and the Company relating to the 1989 EFRBs (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1989).
10(o) Indenture of Trust dated as of May 1, 1990 by and between NYSERDA and The Connecticut National Bank, as Trustee, relating to the 1990 EFRBs (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1990).
Participation Agreement dated as of May 1, 1990 by and between NYSERDA and the Company relating to the 1990 EFRBs (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1990).
10(p) Indenture of Trust dated as of January 1, 1991 by and between NYSERDA and The Connecticut National Bank, as Trustee, relating to the 1991 EFRBs (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1990).
Participation Agreement dated as of January 1, 1991 by and between NYSERDA and the Company relating to the 1991 EFRBs (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1990).
10(q) Indenture of Trust dated as of February 1, 1992 by and between NYSERDA and IBJ Schroder Bank and Trust Company, as Trustee, relating to the 1992 EFRBs, Series A (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1991).
Participation Agreement dated as of February 1, 1992 by and between NYSERDA and the Company relating to the 1992 EFRBs, Series A (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1991).
10(r) Indenture of Trust dated as of February 1, 1992 by and between NYSERDA and IBJ Schroder Bank and Trust Company, as Trustee, relating to the 1992 EFRBs, Series B (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1991).
Participation Agreement dated as of February 1, 1992 by and between NYSERDA and the Company relating to the 1992 EFRBs, Series B (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1991).
10(s) Indenture of Trust dated as of August 1, 1992 by and between NYSERDA and IBJ Schroder Bank and Trust Company, as Trustee, relating to the 1992 EFRBs, Series C (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1992).
Participation Agreement dated as of August 1, 1992 by and between NYSERDA and the Company relating to the 1992 EFRBs, Series C (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1992).
10(t) Indenture of Trust dated as of August 1, 1992 by and between NYSERDA and IBJ Schroder Bank and Trust Company, as Trustee, relating to the 1992 EFRBs, Series D (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1992).
Participation Agreement dated as of August 1, 1992 by and between NYSERDA and the Company relating to the 1992 EFRBs, Series D (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1992).
10(u) Indenture of Trust dated as of November 1, 1993 by and between NYSERDA and Chemical Bank, as Trustee, relating to the 1993 EFRBs, Series A (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1993).
Participation Agreement dated as of November 1, 1993 by and between NYSERDA and the Company relating to the 1993 EFRBs, Series A (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1993).
10(v) Indenture of Trust dated as of November 1, 1993 by and between NYSERDA and Chemical Bank, as Trustee, relating to the 1993 EFRBs, Series B (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1993).
Participation Agreement dated as of November 1, 1993 by and between NYSERDA and the Company relating to the 1993 EFRBs, Series B (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1993).
*10(w) Indenture of Trust dated as of October 1, 1994 by and between NYSERDA and Chemical Bank, as Trustee, relating to the 1994 EFRBs, Series A.
Participation Agreement dated as of October 1, 1994 by and between NYSERDA and the Company relating to the 1994 EFRBs, Series A.
10(x) Supplemental Death and Retirement Benefits Plan as amended and restated effective January 1, 1993 (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1993) and related Trust Agreement, which Trust Agreement was filed as Exhibit 10(q) to the Company's Form 10-K for the Year Ended December 31, 1990.
*10(y) Executive Agreements and Management Contracts
*(1) Executive Employment Agreement dated as of January 30, 1984 by and between William J. Catacosinos and the Company, as amended by amendments dated March 20, 1987 (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1986), December 22, 1989 (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1989), and December 2, 1991 (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1991), which amendment was restated by an amendment dated as of December 2, 1991; an Executive Employment Agreement dated as of November 30, 1994.
*(2) Executive Employment Agreement dated as of November 21, 1994 by and between the Company and Theodore A. Babcock, which agreement is substantially the same as Executive Employment Agreement by and between the Company and (1) James T. Flynn, (2) Joseph E. Fontana, (3) Robert X. Kelleher, (4) John D. Leonard, Jr., (5) Adam M. Madsen, (6) Kathleen A. Marion, (7) Arthur C. Marquardt, (8) Brian R. McCaffrey, (9) Joseph W. McDonnell, (10) Anthony Nozzolillo, (11) Richard Reichler, (12) William G. Schiffmacher, (13) Robert B. Steger, (14) William E. Steiger, and (15) Edward J. Youngling.
*(3) Indemnification Agreement by and between the Company and Theodore A. Babcock dated as of February 23, 1994, which agreement is substantially the same as Indemnification Agreement by and between the Company and (1) James T. Flynn dated as of November 25, 1987, (2) Joseph E. Fontana dated as of October 20, 1994, (3) Robert X. Kelleher dated as of November 25, 1987, (4) John D. Leonard, Jr. dated as of November 25, 1987, (5) Adam M. Madsen dated as of November 25, 1987, (6) Kathleen A. Marion dated as of May 30, 1990, (7) Arthur C. Marquardt dated as of January 21, 1991, (8) Brian R. McCaffrey dated as of November 25, 1987, (9) Joseph W. McDonnell dated as of March 18, 1988, (10) Anthony Nozzolillo dated as of July 29, 1992, (11) Richard Reichler dated as of September 30, 1993, (12) William Schiffmacher dated as of November 25, 1987, (13) Robert B. Steger dated as of February 20, 1990, (14) William E. Steiger, Jr. dated as of March 1, 1989, and (15) Edward J. Youngling dated as of November 4, 1988.
*(4) Indemnification Agreement by and between the Company and Vicki L. Fuller dated as of January 3, 1994, which agreement is substantially the same as Indemnification Agreement by and between the Company and (1) A. James Barnes dated as of January 31, 1992, (2) George Bugliarello dated as of May 30, 1990, (3) Renso L. Caporali dated as of April 17, 1992, (4) William J. Catacosinos dated as of November 19, 1987, (5) Peter O. Crisp dated as of April 23, 1992, (6) Katherine D. Ortega dated as of April 20, 1993, (7) Basil A. Paterson dated as of November 19, 1987, (8) Richard L. Schmalensee dated as of
__________________________________
*Filed herewith.
February 8, 1992, (9) George J. Sideris dated as of November 30, 1987, (10) John H. Talmage dated as of November 19, 1987, and (11) Phyllis A. Vineyard dated as of November 19, 1987.
(5) Indemnification Agreement by and between the Company and Lionel M. Goldberg dated as of April 20, 1993, (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1993) which agreement is substantially the same as Indemnification Agreements by and between the Company and Eben W. Pyne dated as of April 20, 1993, and Winfield E. Fromm dated as of April 12, 1994.
(6) Long Island Lighting Company Officers' and Directors' Protective Trust dated as of April 18, 1988 as Amended and Restated as of September 1, 1994 by and between the Company and Clarence Goldberg, as Trustee (filed as an Exhibit to the Company's Form 10-Q for the Quarterly period Ended September 30, 1994).
(7) Long Island Lighting Company's Retirement Plan for Directors dated as of February 2, 1990 (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1989).
(8) Trust Agreement for Officers dated March 20, 1987 by and between the Company and Clarence Goldberg as Trustee (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1988).
*(9) Consulting Agreement dated as of April 12, 1994 by and between the Company and Winfield E. Fromm, which agreement is substantially the same as Consulting Agreements dated as of April 12, 1994 by and between the Company and Lionel M. Goldberg and Eben W. Pyne.
*23 Consent of Ernst & Young LLP, Independent Auditors.
*24(a) Powers of Attorney executed by the Directors and Officers of the Company.
*24(b) Certificate as to Corporate Power of Attorney.
*24(c) Certified copy of Resolution of Board of Directors authorizing signature pursuant to Power of Attorney.
*27 Financial Data Schedule.
Financial Statements of subsidiary companies accounted for by the equity method have been omitted because such subsidiaries do not constitute significant subsidiaries.
(b) Reports on Form 8-K
No reports on Form 8-K were filed in the fourth quarter of 1994.
In its Report on Form 8-K dated February 1, 1995, the Company reported earnings of $2.15 per common share on revenues of $3,067,307,000 for the year ended December 31, 1994.
__________________________________
*Filed herewith.
LONG ISLAND LIGHTING COMPANY SCHEDULE II-VALUATION AND QUALIFYING ACCOUNTS
(THOUSANDS OF DOLLARS)
(1) Uncollectible accounts written off, net of recoveries.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Date Signature and Title ---- ---------------------------------
WILLIAM J. CATACOSINOS* --------------------------------- William J. Catacosinos, Principal Executive Officer, President and Chairman of the Board of Directors
JOSEPH E. FONTANA --------------------------------- Joseph E. Fontana, Controller, Principal Accounting Officer
A. JAMES BARNES* --------------------------------- A. James Barnes, Director
GEORGE BUGLIARELLO* --------------------------------- George Bugliarello, Director March 14, 1995 RENSO L. CAPORALI* --------------------------------- Renso L. Caporali, Director
PETER O. CRISP* --------------------------------- Peter O. Crisp, Director
VICKI L. FULLER* --------------------------------- Vicki L. Fuller, Director
KATHERINE D. ORTEGA* --------------------------------- Katherine D. Ortega, Director
BASIL A. PATERSON* --------------------------------- Basil A. Paterson, Director
RICHARD L. SCHMALENSEE* --------------------------------- Richard L. Schmalensee, Director
GEORGE J. SIDERIS* --------------------------------- George J. Sideris, Director
JOHN H. TALMAGE* --------------------------------- John H. Talmage, Director
PHYLLIS S. VINEYARD* --------------------------------- Phyllis S. Vineyard, Director
*ANTHONY NOZZOLILLO --------------------------------- Anthony Nozzolillo (Individually, as Senior Vice President and Principal Financial Officer and as attorney-in-fact for each of the persons indicated)
March 14, 1995
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
LONG ISLAND LIGHTING COMPANY
Date: March 14, 1995 By: ANTHONY NOZZOLILLO ---------------------------- Anthony Nozzolillo Principal Financial Officer
Original powers of attorney, authorizing Kathleen A. Marion and Anthony Nozzolillo, and each of them, to sign this report and any amendments thereto, as attorney-in-fact for each of the Directors and Officers of the Company, and a certified copy of the resolution of the Board of Directors of the Company authorizing said persons and each of them to sign this report and amendments thereto as attorney-in-fact for any Officers signing on behalf of the Company, have been, are being filed or will be filed with the Securities and Exchange Commission.
EXHIBIT INDEX -------------
Exhibit No. Description ------- ------------
3(a) Restated Certificate of Incorporation of the Company dated November 11, 1993 (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1993.)
(b) By-laws of the Company as amended on May 28, 1991 (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1991.)
4(a) General and Refunding Indenture dated as of June 1, 1975 (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1991.)
Twenty-seven Supplemental Indentures to the General and Refunding Indenture dated as of June 1, 1975, as follows:
4(b) Indenture of Mortgage and Deed of Trust dated as of September 1, 1951 (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1987.)
Fifty Supplemental Indentures to the Indenture of Mortgage and Deed of Trust dated as of September 1, 1951, as follows:
__________________________________
*Filed herewith.
4(c) Debenture Indenture dated as of November 1, 1986 from the Company to The Connecticut Bank and Trust Company, National Association, as Trustee (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1986).
Seven Supplemental Indentures to the Debenture Indenture dated as of November 1, 1986, filed as follows:
__________________________________
*Filed herewith.
4(d) Debenture Indenture dated as of November 1, 1992 from the Company to Chemical Bank, as Trustee (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1992).
Four Supplemental Indentures to the Debenture Indenture dated as of November 1, 1992, filed as follows:
10(a) Sound Cable Project Facilities and Marketing Agreement dated as of August 26, 1987 between the Company and the Power Authority of the State of New York (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1987).
10(b) Transmission Agreement by and between the Company and Consolidated Edison Company of New York, Inc. dated as of March 31, 1989 (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1989).
10(c) Contract for the sale of Firm Power and Energy by and between the Company and the State of New York dated as of April 26, 1989 (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1989).
10(d) Capacity Supply Agreement dated as of December 13, 1991 between the Company and the Power Authority of the State of New York (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1991).
10(e) Nine Mile Point Nuclear Station Unit 2 Operating Agreement dated as of January 1, 1993 by and between the Company, New York State Electric & Gas Corporation, Rochester Gas and Electric Corporation and Central Hudson Gas and Electric Corporation (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1993).
10(f) Settlement Agreement on Issues Related to Nine Mile Two Nuclear Plant dated as of June 6, 1990 by and between the Company, the Staff of the Department of Public Service and others (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1990).
10(g) Settlement Agreement -- LILCO Issues dated as of February 28, 1989 by and between the Company and the State of New York (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1988).
10(h) Amended and Restated Asset Transfer Agreement by and between the Company and the Long Island Power Authority dated as of June 16, 1988 as amended and restated on April 14, 1989 (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1989).
10(i) Memorandum of Understanding concerning proposed agreements on power supply for Long Island dated as of June 16, 1988 by and between the Company and New York Power Authority as amended May 24, 1989 (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1989).
10(j) Rate Moderation Agreement submitted by the staff of the New York State Public Service Commission on March 16, 1989 and supported by the Company (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1989).
10(k) Site Cooperation and Reimbursement Agreement dated as of January 24, 1990 by and between the Company and Long Island Power Authority (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1989).
10(l) Stipulation of settlement of federal Racketeer Influenced and Corrupt Organizations Act Class Action and False Claims Action dated as of February 27, 1989 among the attorneys for the Company, the ratepayer class, the United States of America and the individual defendants named therein (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1988).
10(m) Revolving Credit Agreement dated as of June 27, 1989, between the Company and the banks and co-agents listed therein, with the Exhibits thereto (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1989) and as amended by the First Amendment dated as of October 13, 1989 (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1990) and as amended by the Second Amendment dated as of March 5, 1992 and as modified by a Waiver dated November 5, 1992 (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1992).
10(n) Indenture of Trust dated as of December 1, 1989 by and between New York State Energy Research and Development Authority ("NYSERDA") and The Connecticut National Bank, as Trustee, relating to the 1989 EFRBs (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1989).
Participation Agreement dated as of December 1, 1989 by and between NYSERDA and the Company relating to the 1989 EFRBs (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1989).
10(o) Indenture of Trust dated as of May 1, 1990 by and between NYSERDA and The Connecticut National Bank, as Trustee, relating to the 1990 EFRBs (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1990).
Participation Agreement dated as of May 1, 1990 by and between NYSERDA and the Company relating to the 1990 EFRBs (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1990).
10(p) Indenture of Trust dated as of January 1, 1991 by and between NYSERDA and The Connecticut National Bank, as Trustee, relating to the 1991 EFRBs (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1990).
Participation Agreement dated as of January 1, 1991 by and between NYSERDA and the Company relating to the 1991 EFRBs (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1990).
10(q) Indenture of Trust dated as of February 1, 1992 by and between NYSERDA and IBJ Schroder Bank and Trust Company, as Trustee, relating to the 1992 EFRBs, Series A (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1991).
Participation Agreement dated as of February 1, 1992 by and between NYSERDA and the Company relating to the 1992 EFRBs, Series A (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1991).
10(r) Indenture of Trust dated as of February 1, 1992 by and between NYSERDA and IBJ Schroder Bank and Trust Company, as Trustee, relating to the 1992 EFRBs, Series B (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1991).
Participation Agreement dated as of February 1, 1992 by and between NYSERDA and the Company relating to the 1992 EFRBs, Series B (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1991).
10(s) Indenture of Trust dated as of August 1, 1992 by and between NYSERDA and IBJ Schroder Bank and Trust Company, as Trustee, relating to the 1992 EFRBs, Series C (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1992).
Participation Agreement dated as of August 1, 1992 by and between NYSERDA and the Company relating to the 1992 EFRBs, Series C (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1992).
10(t) Indenture of Trust dated as of August 1, 1992 by and between NYSERDA and IBJ Schroder Bank and Trust Company, as Trustee, relating to the 1992 EFRBs, Series D (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1992).
Participation Agreement dated as of August 1, 1992 by and between NYSERDA and the Company relating to the 1992 EFRBs, Series D (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1992).
10(u) Indenture of Trust dated as of November 1, 1993 by and between NYSERDA and Chemical Bank, as Trustee, relating to the 1993 EFRBs, Series A (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1993).
Participation Agreement dated as of November 1, 1993 by and between NYSERDA and the Company relating to the 1993 EFRBs, Series A (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1993).
10(v) Indenture of Trust dated as of November 1, 1993 by and between NYSERDA and Chemical Bank, as Trustee, relating to the 1993 EFRBs, Series B (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1993).
Participation Agreement dated as of November 1, 1993 by and between NYSERDA and the Company relating to the 1993 EFRBs, Series B (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1993).
*10(w) Indenture of Trust dated as of October 1, 1994 by and between NYSERDA and Chemical Bank, as Trustee, relating to the 1994 EFRBs, Series A.
Participation Agreement dated as of October 1, 1994 by and between NYSERDA and the Company relating to the 1994 EFRBs, Series A.
10(x) Supplemental Death and Retirement Benefits Plan as amended and restated effective January 1, 1993 (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1993) and related Trust Agreement, which Trust Agreement was filed as Exhibit 10(q) to the Company's Form 10-K for the Year Ended December 31, 1990.
*10(y) Executive Agreements and Management Contracts
*(1) Executive Employment Agreement dated as of January 30, 1984 by and between William J. Catacosinos and the Company, as amended by amendments dated March 20, 1987 (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1986), December 22, 1989 (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1989), and December 2, 1991 (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1991), which amendment was restated by an amendment dated as of December 2, 1991; an Executive Employment Agreement dated as of November 30, 1994.
*(2) Executive Employment Agreement dated as of November 21, 1994 by and between the Company and Theodore A. Babcock, which agreement is substantially the same as Executive Employment Agreement by and between the Company and (1) James T. Flynn, (2) Joseph E. Fontana, (3) Robert X. Kelleher, (4) John D. Leonard, Jr., (5) Adam M. Madsen, (6) Kathleen A. Marion, (7) Arthur C. Marquardt, (8) Brian R. McCaffrey, (9) Joseph W. McDonnell, (10) Anthony Nozzolillo, (11) Richard Reichler, (12) William G. Schiffmacher, (13) Robert B. Steger, (14) William E. Steiger, and (15) Edward J. Youngling.
*(3) Indemnification Agreement by and between the Company and Theodore A. Babcock dated as of February 23, 1994, which agreement is substantially the same as Indemnification Agreement by and between the Company and (1) James T. Flynn dated as of November 25, 1987, (2) Joseph E. Fontana dated as of October 20, 1994, (3) Robert X. Kelleher dated as of November 25, 1987, (4) John D. Leonard, Jr. dated as of November 25, 1987, (5) Adam M. Madsen dated as of November 25, 1987, (6) Kathleen A. Marion dated as of May 30, 1990, (7) Arthur C. Marquardt dated as of January 21, 1991, (8) Brian R. McCaffrey dated as of November 25, 1987, (9) Joseph W. McDonnell dated as of March 18, 1988, (10) Anthony Nozzolillo dated as of July 29, 1992, (11) Richard Reichler dated as of September 30, 1993, (12) William Schiffmacher dated as of November 25, 1987, (13) Robert B. Steger dated as of February 20, 1990, (14) William E. Steiger, Jr. dated as of March 1, 1989, and (15) Edward J. Youngling dated as of November 4, 1988.
*(4) Indemnification Agreement by and between the Company and Vicki L. Fuller dated as of January 3, 1994, which agreement is substantially the same as Indemnification Agreement by and between the Company and (1) A. James Barnes dated as of January 31, 1992, (2) George Bugliarello dated as of May 30, 1990, (3) Renso L. Caporali dated as of April 17, 1992, (4) William J. Catacosinos dated as of November 19, 1987, (5) Peter O. Crisp dated as of April 23, 1992, (6) Katherine D. Ortega dated as of April 20, 1993, (7) Basil A. Paterson dated as of November 19, 1987, (8) Richard L. Schmalensee dated as of
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*Filed herewith.
February 8, 1992, (9) George J. Sideris dated as of November 30, 1987, (10) John H. Talmage dated as of November 19, 1987, and (11) Phyllis A. Vineyard dated as of November 19, 1987.
(5) Indemnification Agreement by and between the Company and Lionel M. Goldberg dated as of April 20, 1993, (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1993) which agreement is substantially the same as Indemnification Agreements by and between the Company and Eben W. Pyne dated as of April 20, 1993, and Winfield E. Fromm dated as of April 12, 1994.
(6) Long Island Lighting Company Officers' and Directors' Protective Trust dated as of April 18, 1988 as Amended and Restated as of September 1, 1994 by and between the Company and Clarence Goldberg, as Trustee (filed as an Exhibit to the Company's Form 10-Q for the Quarterly period Ended September 30, 1994).
(7) Long Island Lighting Company's Retirement Plan for Directors dated as of February 2, 1990 (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1989).
(8) Trust Agreement for Officers dated March 20, 1987 by and between the Company and Clarence Goldberg as Trustee (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1988).
*(9) Consulting Agreement dated as of April 12, 1994 by and between the Company and Winfield E. Fromm, which agreement is substantially the same as Consulting Agreements dated as of April 12, 1994 by and between the Company and Lionel M. Goldberg and Eben W. Pyne.
*23 Consent of Ernst & Young LLP, Independent Auditors.
*24(a) Powers of Attorney executed by the Directors and Officers of the Company.
*24(b) Certificate as to Corporate Power of Attorney.
*24(c) Certified copy of Resolution of Board of Directors authorizing signature pursuant to Power of Attorney.
*27 Financial Data Schedule.
Financial Statements of subsidiary companies accounted for by the equity method have been omitted because such subsidiaries do not constitute significant subsidiaries.
(b) Reports on Form 8-K
No reports on Form 8-K were filed in the fourth quarter of 1994.
In its Report on Form 8-K dated February 1, 1995, the Company reported earnings of $2.15 per common share on revenues of $3,067,307,000 for the year ended December 31, 1994.
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*Filed herewith.